Although some technologies are constantly changing, at least one has remained virtually unchanged for decades: cooling tower systems. New technology in this arena, however, has at last hit the United States—and it’s changing everything about the way many people approach process cooling. As a utility manager, you might find you want to change your approach, too.

Ecodry is a closed-loop, dry-cooling system that nearly eliminates wastewater problems and drastically lowers energy bills. It does so by completely eliminating traditional cooling towers and the typical hassles associated with them.

The current situation
For over 80 years, cooling towers have been at the center of industrial cooling despite the ongoing expense of water treatment, regular heat-exchanger cleaning, difficult cold-weather operation and substantial water and energy consumption. Traditional cooling towers rely on constant evaporation of water passing through the air, resulting in an ever-increasing concentration of contaminants and dissolved solids. Until recently, cooling tower maintenance professionals have accepted these problems as inevitable. This new system, from the Italian company Frigel, offers an alternative.

While new to North America, the Ecodry system has been proven in well over 5000 installations worldwide. The concept originated in Europe, where energy is more expensive and water quality has been a huge challenge, making the perfection of this technology imperative.

In place of a traditional cooling tower, the Ecodry features a closed-circuit fluid cooler. The water returning from the process is pumped into heat exchangers and cooled with ambient air flow. This process provides clean water at the right temperature to process machines year-round.

The closed-loop design keeps heat exchangers scale-free, minimizing the need for costly chemical consumption and disposal. The ultimate result is a modular, flexible, preengineered system that produces the lowest operating cost and highest reliability for installation anywhere.

Water savings
The endless water challenges related to cooling tower systems include high levels of consumption, chemical treating needs and disposal issues.

Over-consumption occurs as water either evaporates or is dumped down a drain. Both events are inevitable with traditional tower systems, whereas the new closedloop system described here never exposes water to the elements—making it possible to use the same clean water over and over again. The reduced water consumption, when compared to conventional cooling towers, is up to 95%.

Most facilities’ incoming process water is not what you would call ideal. That’s why, in an open cooling tower system, continuous water treatment becomes an expensive part of everyday operations. It’s common for a local chemical representative to visit a plant every couple of months to test and adjust the water. In closed-loop, dry cooling, adjustments are made up front if needed. The time and resources spent on regular testing and treating are completely eliminated.

Many facilities also are struggling with local government regulations on contaminated water disposal. These facilities face large dumping fees, fines or the need to call a service to haul away chemically treated wastewater.

This type of closed-loop system minimizes environmental impact by using the same clean water continuously and not disposing chemically treated water into the ground, lakes and streams. With evaporation virtually eliminated, the Ecodry’s technology poses the lowest risk of refrigerant gas emission into the atmosphere.

Energy savings
According to Frigel, the Ecodry system can reduce energy consumption significantly by eliminating big pump tanks and using efficient fans that only run when needed.

One of the key energy-saving components is the advanced microprocessor featuring an easy-to-use, remote interface. It not only controls functions of the system but makes the adjustments needed for the system to run at optimum efficiency. Based on ambient temperature and process water temperature, the controller adjusts fan speed and initiates evaporative functions to generate the required cooling capacity in the most efficient way possible. The microprocessor also manages the pumping stations to save energy and boost equipment longevity by controlling water pressure and pump rotation.

To power the fans, the system uses highly efficient, brushless, variable-speed DC servo motors with individual automatic speed control. These maintenance-free motors are 30% more efficient than traditional motors, feature quiet operation (less than 57 dBa), allow any fan to be changed while the equipment is running and offer increased reliability and durability. Overall, the average annual energy consumption of this closed loop system is 0.05 kWh/ton.

How the system works
Besides continuous maintenance, chemical expenses and wasted water, cooling towers also fall short of optimum performance when ambient temperatures soar above 85 F or drop below freezing.

When ambient air reaches 85 F or above, the Ecodry system automatically switches into “adiabatic” mode. Air passes through an adiabatic chamber before reaching the heat exchanger. A fine mist of tap water is “pulsed” into the incoming air stream inside the chamber and humidified air drops the water temperature to, at or below 95 F—even with ambient temperatures as high as 120 F.

The pulsed water evaporates instantly, cooling the air before it impinges on the cooling coils that carry the process water. The coil fins remain dry, thus the term “dry cooling.” To ensure consistent cooling, an advanced control panel continuously adjusts the amount of water sprayed.

Units can deliver heat loads of 17 tons or can be daisychained to deliver capacity up to 3500 tons.

Avoiding freezing
What happens if ambient air dips below 32 F when the plant is not running or a power outage occurs? The Ecodry system’s copper pipes are automatically drained by gravity to protect the unit and avoid icing. Furthermore, it is done without the need for valves, antifreeze or any manual interaction with the system at all. The self-draining process provides completely safe operation in extreme weather conditions.

This function also allows the system to be used for applications where contact with glycol is not tolerated. For facilities in cold-weather climates, partial glycol supplement is an option if the user requests it. It’s not preferred, however, because pure water has the best heat-transfer properties.

For colder weather, Frigel’s technology includes builtin freeze protection that monitors ambient and return water temperatures. In a pure-water system, if the leaving water temperature drops below the setpoint, the controller halts the pumps circulating to the outdoor heat exchanger (made entirely of non-corrosive copper, aluminum, bronze and stainless steel) and the Ecodry automatically drains its water back to an indoor reservoir. The central system then circulates cool water from its indoor tank until it becomes sufficiently warmed to permit sending it outdoors again to the heat exchanger.

Central chiller replacement
The closed-loop system also can be used in conjunction with chiller/temperature control units (Microgels) for individual control of chilled or heated water at each process machine. A single set of uninsulated pipes supplies the process water without heat loss to the chiller/ temperature control unit at each machine. These units offer high flow, precise temperature control and a builtin valve that provides automatic “free cooling” when ambient temperatures are lower than process setpoint.

“This setup is really great. In the winter we get free cooling because we’re sending water outside to cool down to temperature,” said Steve Streff, president of SK Plastics, whose company uses Frigel’s technology (see sidebar below). “Sometimes, the compressors don’t even run because the water’s already cool enough. So, we’re saving money and energy on several fronts.”

Free cooling means using the closed-loop fluid cooler or other non-refrigeration cooling methods in place of the chiller/refrigeration method. The Ecodry can provide free cooling to a variety of processes/devices based on process setpoint and local ambient conditions. This can save up to 80% on energy costs and improve processes the water is serving because of the precise water temperature delivered at individual process machines. This can have quite a positive impact on productivity. UM

Fans are designed to be capable of meeting the maximum demand of the system in which they are installed. Quite often, though, the actual demand varies and may be much less than the designed capacity.

The centrifugal fan imparts energy into air by centrifugal force. This results in an increase in pressure and produces airflow at the outlet of the fan. An example of what a typical centrifugal fan can produce at its outlet at a given speed is shown by the curve in Fig. 1. This curve is a plot of outlet pressure in static inches of water versus the flow of air in cubic feet per minute (CFM). Standard fan curves usually will show a number of curves for different fan speeds and include fan efficiency and power requirements. These are useful for selecting the optimum fan for any application, and are required to predict fan operation and other parameters when the fan operation is changed.

The system curve in Fig. 2 shows requirements of the vent system on which the fan is used. A plot of “load” requirement independent of the fan, it indicates the pressure required from the fan to overcome system losses and produce airflow. The intersection of the fan and the system curve is the natural operating point. It is the actual pressure and flow that will occur at the fan outlet when this system is operated. Without external influences, the fan will operate at this point.

Many systems require operation at a wide variety of points. There are several methods used to modulate or vary the flow (or CFM) of a system to achieve the optimum points. These include:

• Cycling (as done in home heating systems)—This produces erratic airflow and is unacceptable for commercial or industrial uses.
• Outlet dampers (control louvers or dampers installed at the outlet of the fan)—To control airflow, they are turned to restrict the outlet, thus reducing airflow.
  
• Variable inlet vanes—By modifying the physical characteristics of the air inlet, the fan’s operating curve is modified, which, in turn, changes airflow.
  
• Variable frequency drives (VFDs)—By changing the actual fan speed, the performance of the fan changes, thus producing a different airflow.

By changing the airflow or the fan speed, the system or fan curves are affected, resulting in a different natural operating point—and, possibly, a change in the fan’s efficiency and power requirements.

Outlet dampers
The outlet dampers affect the system curve by increasing the resistance to airflow. The system curve can be stated as:

P = Kx (CFM)²

Where:
P is pressure required to produce a given flow in the system
K is a function of the system that represents the resistance to airflow
CFM is the airflow desired

The outlet dampers affect the K portion of this formula. The diagram in Fig. 3 depicts several different system curves indicating different outlet damper positions. Note that the power requirements for the type of system shown in Fig. 3 gradually decrease as flow is decreased (as shown in the Fig. 4).

Variable inlet vanes
This method modifies the fan curve so that it intersects the system curve at a different point. A representation of the changes in the fan curve for different inlet vane settings is shown in Fig. 5. The power requirements for this method decrease as airflow decreases, and to a greater extent than the outlet damper (as shown in Fig. 6). Variable frequency drives (VFDs) The VFD method takes advantage of the change in the fan curve that occurs when the speed of the fan is changed. These changes can be quantified in a set of formulas called the affinity laws.

Where:
N = Fan speed
Q = Flow (CFM)
P = Pressure (Static Inches of Water)
HP = Horsepower

Note that when the flow and pressure laws are combined, the result is a formula that matches the system curve formula – P = K x (CFM)².

Substituting (Q₂/Q₁)² for (N₂/N₁)² in the first equation gives us:

The quantity P₁/(Q₁)² coincides with the system constant, K. As depicted in Fig. 7, this means that the fan will follow the system curve when its speed is changed. As the fan speed is reduced, a significant reduction in power requirement is achieved (as shown in Fig. 8).

The variable speed method achieves flow control in a way that closely matches the system or load curve. This allows the fan to produce the desired results with the minimum of input power.

Energy savings
Clearly, not all methods for modulating or varying flow are appropriate for a given fan system. How can you be sure that the method you are using is the right one? More importantly, how can you be sure it is the most efficient? Whatever your chosen method is for modulating or varying flow, it may be easier than you thought to estimate its power consumption and associate a cost of operation with it. To accomplish this, an actual load profile and a fan curve are required (as shown in Figs. 9 and 10).

The following simple analysis of the variable speed method compared to the outlet damper method shows how energy savings are calculated.

Using the fan curve in Fig. 10, assume the selected fan is to be run at 300 RPM and that 100% CFM is to equal 100,000 CFM as shown on the chart. Assume the following load profile.

For each operating point, we can obtain a required horsepower from the fan curve. This horsepower is multiplied by the percent of time (divided by 100%) that the fan operates at this point. As shown in the following table for the outlet damper method, these calculations are then summed to produce a “weighted horsepower” that represents the average energy consumption of the fan.

Similar calculations are done to obtain a weighted horsepower for variable speed operation. However, the fan curve does not have enough information to read all the horsepower values for our operating points. To overcome this problem, we can use the formulas from the affinity laws.

The first point is obtained from the fan curve. 100% flow equals 100% speed equals 35 HP. The flow formula Q₂/Q₁ = N₂/N₁ can be substituted into the horsepower formula, HP₂/HP₁ = (N₂/N₁)³ to give us:

When Q₁ = 100% and HP₁ = 35 HP, Q₂ and HP₂ will have the following values:

As shown in the following variable speed method table, we now have sufficient information to calculate the weighted horsepower. Comparing the results of the two methods of control indicates the difference in power consumption.

In order to obtain a dollar value of savings, the kilowatt-hours used must be known. To calculate this, multiply the horsepower by 0.746 and then multiply the result by the hours that the fan will operate in a period of time. This would typically be for a month. Your results would look like the following example table at the bottom of the page.

This simple example shows a cost saving of more than $700 per month by using a variable speed method. Note that the example is very basic and does not consider motor and drive efficiency. Still, many organizations would consider that amount of monthly energy savings on a single fan system—or anything close to it—to be significant. Would yours? UM

Sharon James is an application engineer with Rockwell Automation. E-mail him directly at: sjames@ra.rockwell.com

We’re all familiar with the monthly budget review meeting. This is when the general manager sits down with department heads to compare the latest month’s financial results to the organization’s operating budget. A common, well-intentioned business habit, it also has the potential to be quite damaging. That’s because the actual-to-budget review process focuses on the past at the expense of the future. Much like trying to steer a car by looking in the rear-view mirror, it is a big reason why organizations often fail to take meaningful control of their energy costs.

While the organization as a whole attempts to make money, department directors are primarily concerned with spending money for materials, labor, utilities, support services and the like. The monthly budget review is a discussion of variances—particularly those instances where spending is on a pace to exhaust funds before the end of the fiscal year. Top management provides annual performance incentives that focus on this year’s budget outcomes, not those of future years. Thus, a preoccupation with this year’s budget may be at the expense of potential savings that can accrue for years to come.

While history typically provides useful insight, it also can obscure future potential. Consider the following “rear-view mirror” approach to moving forward.

Let’s say a facility has yet to adopt energy-efficient technologies, behaviors and procedures. This means that it habitually buys more energy than is actually needed, because waste is built into its operations. The budget account for energy, then, is inflated to accommodate these inefficiencies. For example, energy losses add up to about 40% of the total energy delivered to U.S. manufacturing facilities as a whole. Stated differently, the typical manufacturing facility must inflate its energy procurement budget by a factor approaching two-thirds to account for energy that is both used and wasted.

A possible solution
Break down annual energy expenses into two separate line items. One represents the value of energy that actually will be applied to perform useful work. The second line item represents energy that will be wasted. How do you allocate energy expenditures into these categories? The answer is to conduct an energy audit that thoroughly evaluates energy inputs, uses, losses and potential consumption improvements. While industry averages are generally helpful, the most reliable indication of any single facility’s energy flow depends on a proper energy audit—the more thorough the better. Without distinguishing between energy applied and energy wasted, department directors often conclude that they “don’t have the money for energy improvements.”

The account for energy waste (a budget artifact directly related to past performance) is, in reality, an account from which energy improvements should be budgeted. The energy waste line item also brings attention and urgency to the issue at each and every monthly budget review.

Managers can use the “energy waste” account to either MAKE energy savings or BUY energy that ends up being wasted. Dollars from the “energy waste” account are devoted to energy improvement projects when the cost to save a unit of energy is less than its purchase price per unit. This is one line item that actually forces managers to look forward, and not in the rear-view mirror, when planning energy consumption. UM

Updated weekly, Christopher Russell’s energy management blog can be found at http://energypathfinder.blogspot.com

Chrisopher Russell, Principal, South River Facility Management

Procurement, budgeting and finance people will be the first-line in dealing with electric utility deregulation. Companies need to develop strategies for making the best use of the many procurement options that are available in deregulated power markets.

Finance people will lead the pursuit of tax deductions and credits that apply to certain energy improvements such as lighting, heating, air conditioning, and building structural systems. Finance people also set the criteria for evaluating energy-related investments.

Engineers will monitor emerging technologies and standards. Companies will ask: What are these technologies? Which ones will provide value for me? How shall I evaluate them? Engineers will also design, commission, and monitor new energy-using equipment and systems.

Operations managers will rethink the dozens of staff decisions made each day, across plant floors or office spaces. Machine operators and office workers are largely unaware of how their everyday choices impact the energy bill. Solutions begin with increased staff awareness of their energy use.

Human resource professionals need to inventory their staff training needs, then seek appropriate training opportunities. Maintenance workers and machine operators need to learn "best practice" techniques that save money and boost reliability.

Environmental, health and safety professionals need to monitor emerging regulations. Compliance with these regulations puts many dollars at stake in the form of potential fines and penalties. Note that an energy management agenda will closely overlap safety and emissions compliance strategies.

Marketing and corporate strategy people need to understand the opportunities posed by "sustainable" business practices. Energy efficiency is a component of sustainable business practices. Sustainability is also the key to developing new products and services and winning new customers. Look at Wal-Mart: they force their suppliers to squeeze as much waste as possible from their production costs. Companies that sell their products to Wal-Mart (and many other like-minded firms) are aware of this trend and have a strategy ready for it. Failure to adapt to this trend is to risk losing business.

Needless to say, an organization needs to coordinate these many players so that they are not working at cross-purposes. This is essentially the role of an energy manager.

Forward-thinking companies respond to energy risk by changing they way they use energy. They often begin by rethinking their work habits and procedures. They quickly discover that energy use is as much a human issue as it is mechanical. To ignore the human component of energy cost-control is to invite business risk. A lack of awareness begets a lack of accountability. And without accountability, companies have no effective response to energy risk.

Christopher Russell is recognized by the Association of Energy Engineers both as a Certified Energy Manager and a Certified Energy Procurement Specialist. As the director of industrial programs at the Alliance to Save Energy from 1999-2006, he documented and evaluated energy management practices at dozens of facilities and today continues to advise end users and others on the planning and promotion of industrial energy programs. Updated weekly, his energy management blog can be found at http://energypathfinder.blogspot.com

Much effort and attention has focused on educating people about the existence, significance and function of green roofs. What's next in terms of maintenance is equally important to protect a green roof investment.

Do I really have to bring the lawn mower up to the roof?" asked the facility manager after his company had just installed a 4000 sq ft green roof.

The direct answer is "No." But, regular maintenance is just as important to green roofs as to any other roofing system.

With vegetated roofs having gained strong public interest in the United States over the last decade, there is widespread appreciation for the intricacies involved in building a green roof. Now, though, facility managers, engineers and others interested in and/ or involved with this emerging technology have new questions, including: "How do I maintain my green roof once it's installed? "

Green roofs are living systems. Thus, regular and proper maintenance, on an ongoing basis, is vitally important in order for them to survive and succeed. This is especially crucial in the first two years after a green roof installation. In fact, green roofs must be attended to much more frequently in the first two years. Furthermore, because such a system is a roof environment, all safety precautions and OSHA regulations still need to be implemented.

The initial cost for installation of a green roof can be one-and-a-half to two times the cost of a traditional roof. With proper maintenance, however, a green roof can double the life expectancy of a roof. Add to that the cost savings for heating and cooling a green building and, amortized over the life of the roof, green ones—if properly maintained—come out on top economically.

Once installed, property management staff can be left a bit perplexed as to what to do, or who to hire to carry out the job of green roof maintenance safely and correctly. Green roof installers are often a good place to start. Some of them offer green roof maintenance as part of the recommended ongoing preventive maintenance that is imperative to the care of any roof system.

If your organization is considering a green roof for your facility—or if you've already installed one—here are some things you'll want to keep in mind going forward.

Green roof maintenance 101
Types…

There are two basic types of green roofs—extensive and intensive.

Extensive green roofs are lightweight veneer systems with thin layers of drought-tolerant, self-seeding vegetated roof covers requiring little or no irrigation or fertilization after establishment. They are built when the primary desire is for an ecological roof cover with limited human access.

On extensive green roofs, vegetation should grow to cover the soil surface, usually within two years after it is installed. Extensive vegetated roofs generally have three to six inches of engineered growing media and are designed to be self-sustaining over time. Drought tolerant plants, usually succulents, are planted and grow quickly over the soil surface. Most of the succulents—Sedum—have adventitious roots, meaning they can form new roots at the stems and leaves. Cutting back healthy plant material, distributing across the bare areas of the roof and irrigating for a few weeks is an economical method of re-establishment.

Engineered growing media is comprised of lightweight aggregates and minimal amounts of organic matter. The growing media is designed to be lightweight, not decay over time, and needs little amending to provide adequate nutrients to plant material.

The vegetated system can be walked on from time to time, but should not be used in a highly recreational setting. Walkways made of pavers or gravel ballast may be installed to guide maintenance workers to mechanical equipment.

Many times, the primary reason extensive green roofs are integrated into the building is to capture storm water. Calculations are done on a project basis to satisfy local ordinances, or to apply for green building, such as LEED, incentives. In this instance, it is important for as much of the roof to be covered with vegetation as possible. Overall, green roofs can retain and detain 60-100% of rainfall.

Intensive green roofs are more elaborately designed roof landscapes, such as roof gardens and underground parking garage roofs that are intended for human interaction. The growing media starts from about 8-12" and can range to 15' or more, depending on the loading capacity of the roof and the architectural and plant features that the building owner desires. Maintenance will need to be more frequent, resembling the needs of a typical ground landscape.

Aesthetics and usage…
Visually, one should expect the green roof to behave similarly to the landscape of the surrounding area. For example, the plants will go dormant in the winter around the same time the tree canopy loses its leaves. Some plants will die back and others are evergreen, but colors change to dark reds and browns. In the spring, growth will resume with warm days and rain showers, and plants will bloom throughout the growing season.

One matter that should be resolved between the owner and the facility staff ahead of the planting of the green roof is the expectations of the vegetated roof, including usage (as in, who will be visiting the roof).

A roof system that is only visited by roofers and mechanical crews providing periodic maintenance will not need to be maintained as frequently for aesthetics as one that is viewed daily through office windows or entertains frequent visitors.

Extensive systems may be designed with a specific pattern, often achieved from a bird's eye view. For example, representation of a theme for the building or client may be incorporated in the design. Many succulent plants are aggressive growers in this setting, and more frequent maintenance is imperative to achieve the desired aesthetic goals.

Irrigation…
A newly installed green roof should be maintained monthly, as necessary. Temporary irrigation should be available for the first few months, and should saturate the system at least two or three times a week. Thereafter, irrigation should be weaned, with the intent that the vegetation will remain self-sustaining within the first year.

During hot and dry spells, the system should receive water. While irrigation seems counter-intuitive in a roof designed to capture and detain stormwater, irrigation is mandatory in order to have a healthy and functioning green roof system long-term.

Plant and media concerns…
Initially planted and allowed to fill in over time, there is an opportunity for unwanted plants to germinate, grow and seed themselves on the roof. For projects in temperate climates, weed pressure begins in early spring and continues throughout the year, including winter. In small green roofs, hand weeding may be the fastest and most effective method of removal. However, for larger projects, protocols should be agreed upon for use of alternative weed management techniques or approved chemicals.

Approved growing media is comprised of approximately 20% organic matter. Over time, German green roofs have shown the organic content is reduced to 7%. Within the first several years, additional fertilizer should be applied. The FLL German standards, as well as ASTM, recommend a very low rate of application, using slow release fertilizers. Commercially available organic fertilizers are an option.

Seasonal issues…
The growing media should be evaluated to ensure proper drainage throughout the green roof system, and off the roof. Yearly pH testing will tell when the growing media should be amended with lime. One sign that the green roof is too acidic is the presence of moss. It is up to the owner whether to keep the moss. It is probably harmless, and can create a lush green color in the cool season, but it may not be desired by the roof owner.

Spring responsibilities include broadcasting with a slow-release fertilizer. Removing leaves and branches is recommended, but not necessary. Periodic weeding in the summer season will keep weed pressure low. In preparation for winter, irrigation water lines on green roofs need to be drained and cleaned before a freeze. During a mild winter, weeds should be pulled before they are allowed to flower and set seed.

In summary
Green roof maintenance is as critical to the success of a green roof as plant selection, climate and other installation criteria. Without regard for the care or maintenance of a green roof once it has been installed, building and facility managers may not be adequately prepared to protect their building's asset long term. Moreover, they may not be able to reap the inherent benefits associated with green roofs and the role they play in sustainability. UM

Angie Durham is a green roof specialist with Magco, Inc. For more information on green roofs, contact her directly through Tecta America Corp. Telephone: (866) 832-8259; or visit www.tectaamerica.com or www.greenroof.com

Located in the heart of Phoenix, AZ, St. Joseph's Hospital and Medical Center is a 520-bed, not-forprofit hospital that provides a wide range of health, social and support services with special advocacy for the poor and underserved.

"St. Joe's" is a nationally recognized center for quality tertiary care, medical education and research.

Founded in 1895 by the Sisters of Mercy, St. Joe's was the first hospital in the Phoenix area. It has come a long way since it opened with 24 private rooms—each opening up onto a porch. With tens of thousands of annual admissions, emergency room visits and outpatient/inpatient surgeries—not to mention thousands of babies delivered each year—St. Joe's water demands clearly are critical to its operations.

Specifically, this bustling institution requires an effi- cient way to maintain the availability of hot water pressure in its growing complex of buildings. Like all healthcare facilities, the system needs to be operational 24-hours-aday and downtime has to be kept to a minimum. That's not always been easy.

As the hospital has expanded over the years, the water service for new facilities has simply been tied into the existing lines supplied by two outdated sets of pumps—one each for cold water and hot water service.

With its water service requirements increasing, the medical center began experiencing problems as a result of the hot water booster‘s inability to keep up with the cold water booster in terms of pressure. Depending on the varying needs during the day, the hot water system pressure fluctuated so much that it was causing damage on multiple showerheads and valves. In addition, maintenance on the existing pumps was becoming intolerable.

According to Michael Marquez, a technical sales representative for Quandna, Inc., a Phoenix-based fluidhandling solution provider and distributor for ITT, St. Joe's was having to do quite a bit of maintenance on the old pumps. "The pumps have been rebuilt numerous times because they were constantly running overspeed and way off the curve," he notes. "Additionally, the medical center maintenance people would sometimes have to be sent to the booster set to turn on another pump to maintain hot water pressure."

Plug and play solution
It was clear that St. Joe's really needed a booster pump system that could keep up the pressure for the hot water no matter what the facility requirements were. Quadna's team of application specialists proposed a design—created specifically for the hospital—that would achieve these goals and serve as a drop-in replacement. The replacement system also needed to be functional quickly, as the medical center could not be without hot water for more than four hours.

To more effectively accommodate the hospital's fast-paced growth, Quadna selected ITT's Goulds Pumps brand SSV high-pressure, vertical multistage pumps combined with ITT's PumpSmart® PS200 control system. Quadna manufactured a custom-designed booster pump skid to house the three pumps and their control systems. The pumps, which are combined to optimize their capabilities, offer the medical center optimal high pressure, in a mechanically friendly, space-saving design.

The new system also met St. Joe's requirements to connect efficiently with the medical center's existing piping system, as well as for elevator weight and the proper dimensions to pass through doorways. When the skid was installed in February 2007, the "plug and play" system became fully functional in just a couple of hours, minimizing the amount of time the hospital went without hot water. Other characteristics of this pump system include a design to handle variable pressure drops. The pressure set point can be modified for future system requirements and the intelligent pump controllers automatically adjust to changes in system conditions.

Low costs/high efficiency
Equipping each pump with the PumpSmart control system was done to meet the medical center's concerns for a system with low total life-cycle costs. PumpSmart's intelligent flow system works with any pump. The product utilizes a smart variable frequency drive (VFD) controller and proprietary control software to provide advanced process control, enhanced reliability through failure prevention, reduced life cycle costs and, according to the manufacturer, significantly lower energy costs—up to 65%.

"PumpSmart will provide the hospital with great energy savings," says Marquez. "The medical center is on a strict budget. When you consider that it was running the old pumps at full speed, the savings provided by this type of intelligent control system will be significant."

The PS200 model offers process control and pump protection in one easy-to-use package for virtually every industrial process. With preprogrammed applications such as pressure, flow and level control, setup is quick and easy. The PS200 is capable of coordinating efforts between other PS200 controllers as well as existing constant speed pumps.

"I am a big fan of these systems," Marquez continues. "A skid, equipped with a PumpSmart system, allows the user to cut down on management and maintenance. Maintenance people don't have to be sent out to the pumps to change the pressure—which is what has been done previously. This control system also has the ability to automatically rotate the pumps out as needed."

One less headache
With its new reliable PumpSmartequipped pumps and their low life-cycle costs, St. Joe's now can face future expansion plans and the varying demands of patient care with fewer things to worry about. There are enough headaches involved with operating a major medical center—trying to ensure adequate hot water service 24/7 should not be one of them.

ITT Goulds Pumps
Seneca Falls, NY

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:

EXPENSE = PRICE times QUANTITY

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 http://www.eere.energy.gov/ 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.

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). 

Will you conduct an energy audit?

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

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

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

 Will your staff be responsive to energy awareness training?

 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.

crussell@energypathfinder.com

Leaking 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. That'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: www.sdtnorthamerica.com

(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.)

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.

The 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. E-mail:rlpiekarz@ra.rockwell.com Internet: www.rockwellautomation.com

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

In 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: roddy_yates@baldor.com

As 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…
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: dwillems@cleaver-brooks.com

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.

Unraveling 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. The 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.

Reference

1. Energy Information Administration ( http:// www.eia.doe.gov/cneaf/electricity/epm/ 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: www.standardalloys.com

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.

There 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:

Conclusion
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: burgergary@hotmail.com