Archive | January, 2007


6:00 am
January 1, 2007
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Leak Detection: The Science And The Art

Fluids are always looking for a way out of a system. Whenever they find one, you end up with a leak. Whether it’s major or minor in scope, it’s sure to be a drain on your efficiencies and profits.


There’s both science and art when it comes to leak detection in industry. It’s science because leak detection is an engineering issue that requires very sophisticated tools and systems. It’s an art because successful leak detection is a matter of training, experience and management emphasis.

One of the country’s leading experts in all of this is Alan Bandes of UE Systems, based in Elmsford, NY. In a recent “Tech Tips Newsletter,” he notes that a good leak detection program in any company or any plant should involve walkarounds. “If you don’t perform a walk-around prior to performing a survey, “there will be a lot of potential unexpected problems regarding accessibility, equipment used and route planning.Maintenance management should encourage inspectors to perform a walk-around for the sake of efficiency and effectiveness,” he says.

What Bandes and other experts are warning against is too much reliance on automation–and not enough on management programs and planned surveys by trained maintenance personnel. As Allan Rienstra, of SDT North America, in Cobourg, Ontario, puts it, “The foundation of any leak management program is training. Ultrasound leak inspection is simple science, but like anything there are tricks to the trade that need to be learned.”That’s why SDT and UE , as well as others in the business offer extensive training to their customers and prospects. “Other ways to keep up,” adds Rienstra, “include attending industry conferences and reviewing consumer-based web sites.” Bandes’ newsletter is available on the Internet, as is SDT’s monthly Ultrawave Technology Report.

Some tech trends
While training and management emphasis are crucial for a successful leak detection program, there are some clear technology developments that maintenance experts need to watch in coming years.

“The technology is moving toward enhancing existing products with specialized features to improve leak detection activities,” says UE’s Bandes. “Ultrasound is used predominantly in the mid- to grossranges of leak detection where leak rates range from 1 x 10-3 std cc/sec on up. To assist on the fringes of detection, new specialized probes have been produced such as UE’s Close Focus Module which enhances low-level emissions making leaks near the low-end threshold more detectable.”

What about leak detection in areas where accessibility is difficult?

“New flexible probes have been developed that can be bent and manipulated at odd angles,” Bandes explains. That includes leaks in distant spots, like pressurized cables in ceilings. “Parabolic microphones,” he notes, “are used to pinpoint these leaks at greater distances than with standard scanning modules.”

What about special situations that require permanent or fixed monitoring?

According to Bandes, the industry is supplying remote mountable transducers that can be set for alarming if leaks either occur or exceed set threshold levels. Some of these specialized remote sensors are configured to detect leaks in valves with a 4-20 mA or 0-10V DC.Heterodyned output can be configured to send information to a control panel where the information can be viewed or recorded,” adds the UE executive.

Other companies in the business such as Monarch Instrument, of Amherst, NJ, SPM, in Marlborough, CT, and Whisper Ultrasonic Leak Detector, of East Syracuse, NY, also offer products for leak detection programs–and are constantly developing new ones for ever-more accurate and sensitive devices for leak detection.

Greenhouse gas quotas
SDT’s Rienstra notes other trends.”There’s a changed point of view in manufacturing regarding compressed air leak detection,” he says. “Compressed air leak management was predominantly done for energy efficiency because of the high cost of energy required to compress air. Average systems have between 30 and 35% leakage, if there is no program in place.A leak management program targets leak rates under 10%.”

As Rienstra noted in his article in the December 2006 UTILITIES MANAGER supplement to MAINTENANCE TECHNOLOGY, manufacturers are still after those energy savings (the challenge), but there is also a win because less energy consumption means fewer greenhouse gas emissions. In some countries companies have a greenhouse gas emission quota. If they are able to operate under that quota, they can save on emissions and even sell their leftover quota to others (the opportunity).

Agreeing with Bandes, Rienstra notes that there are two aspects here for maintenance management to consider: training and “the gadgets” (the art and the science). “We are all gadget-driven, he says. “Flexible wand sensors, parabolic dishes with laser pointers and extended distance sensors help make the leak inspector more efficient and provide him with extra levels of safety.”

Rienstra adds that leak calculators reflect another growing technical trend. His company will be releasing one this year that allows users to plug in the decibel level of a found leak. The calculator will then process all the data required to assign a dollar value to that leak.

Systematic approach and training
Of course, not all leaks are the same in terms of detection and control. Is it a specialized gas, compressed air, steam? What type of system or systems are to be monitored?

“What are the acceptable leak rates?” asks Bandes. “The first thing to do is to establish a baseline. Know what is going on with the system right now,” he advises. “Is the system performing as required? Companies should set a workable goal. For example, if compressed air leaks are the issue, review the use of compressed air; are there alternative technologies that can replace the use of air in some areas? Who will perform the leak survey? Above all,” he cautions,”these inspectors should have training, so training should be on the check-off list.”

Consider, too, the cost of a typical leak and how many you project in your plant: 10, 100, 1000? Walk through the system with a diagram or create a map of the system during the walk-through process. Ask what type of equipment will be needed: sophisticated or basic ultrasonic instruments? “The answers,” Bandes explains, “will be determined by the complexity of the system.”

A method of recording and reporting leak survey results, including costavoidance figures, should also be created. In addition, there should be a method of follow-up to assure the leaks are repaired properly. “Routes should be created that are manageable. Leak detection does not stop at the survey,” warns Bandes. “It should be routinely incorporated into maintenance planning.”

Educating employees can be a particularly cost-effective way to cut down on leaks. Explain to them the importance of your leak detection program and why they should report leaks when they notice them. Explain that the misuse (of air) can be very costly, and train them in the proper use of it.

Don’t feel as though you have to reinvent the wheel, either.When it comes to educating personnel on leak detection, you’ll find that there are numerous resources available through manufacturers of machinery, ultrasonic equipment suppliers and consultants. The U.S. Department of Energy also has information on its Web site for download.

Biggest leak detection mistakes
While leak detection seems a simple enough task, there are pitfalls. “The biggest mistake I see is venturing into a leak detection program without any strategy or written goals,” warns Rienstra. “Without team leaders,” he continues, “without training, without a guideline for how they will present their successes to upper management, any leak detection program is doomed to failure.”

According to Rienstra, as far as techniques go, far too often an inspector does his/her job and leaks are found and tagged, but there is no strategy in place to make sure things get fixed. If the goal is energy savings and greenhouse gas reduction, then the leak has to be fixed to save. “A found leak never saved a penny,” he says.

Bandes of UE adds, “The most common mistakes are lack of planning, lack of communication and insufficient training. Any program, whether it is leak detection or predictive maintenance, requires the support of management.” Don’t just start a program without planning it thoroughly. Bandes suggests the that you heed the following checklist:

  • Communicate with management and those who will be part of the program.
  • Explain the program, the methods and the goals.
  • Think through strategies of detection and route creation, reporting and recording results.
  • Have some plan for follow-up on repairs and carefully choose the instruments to be used in relation to the type of system to be inspected.

Remember that without the training of inspection personnel, your whole program can fail. To be successful, personnel need to know the effective methods for locating leaks, as well as how to work with competing ultrasounds in loud environments.

The science and the art
The science of leak detection gets more and more accurate and sophisticated every year. “Manufacturers are always looking for ways to increase the threshold of sensitivity (find smaller and smaller leaks). Probably the most important development aside from that would be software that maps out the inspection process and allows for accountability from the inspector to the repair,” says Rienstra. In other words, more and more automation is on the horizon for leak detection.

And, he adds, all leak detection is basically “dollar driven.”He notes, for exampler, that energy in California costs close to five times what it costs in other parts of the country. “You think compressed air leaks aren’t issues in that competitive state?”

The art of leak detection, however, is best summed up in the need for training and management emphasis and involvement. Bandes reminds us how vital it is to communicate with management. Leak detection and control have always been important engineering and production issues. These days, though, it is also too costly an issue (and an increasingly significant social issue as well).Any program to stop leaks is now too important to try to implement without management involvement, strategy, planning and (one more time) TRAINING.

No leak detection program will ever be perfect, but you can get closer and closer to perfect by concentrating on both the science and the art of it.

George Weimer is a professional writer based in Cleveland OH.

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6:00 am
January 1, 2007
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Reducing Hot-Spot Temperatures in Transformers

In this real-world study from the power gen sector, researchers tested external oil coolers and ultra pure mineral oil to determine their effectiveness on hot spots, and, ultimately, equipment reliability

Over the past several years, Consumers Energy (“Consumers”) has come to rely strongly on external oil coolers to delay scheduled transformer capacity increases, or to cool transformers that experience marginal high top-oil temperatures. A transformer experiencing a top-oil temperature of 90 to 100 C or more would be a likely candidate for such an installation. These types of external coolers are installed in close proximity to the transformer using flexible hoses that are typically connected to existing 11/2″ taps near the top and bottom of the transformer.

Now that Consumers has acquired more than 20 oil coolers, questions frequently are being asked regarding the effectiveness of these units in actually limiting the loss of insulation life. Although the cooler reduces the oil temperature, there is a concern that it may be disrupting the natural convective oil flow inside the transformer and the hot-spot cooling effect may not be as great as expected or indicated by the top oil temperature.

Under normal conditions, the temperature gradient between the top and bottom of a transformer produces an internal oil circulation that acts to remove heat from the coils through convection. An external cooler can diminish this normal temperature gradient, resulting in reduced convective currents and, in theory, create pockets of stagnant oil and induce local overheating. To avoid this situation, some utilities have reportedly removed OEM-installed oil pumps from transformers where there has been no internally directed oil flow.

Equipment description
Study One…
transformerThe transformer selected for Study One was a unit being rewound for Consumers by Siemens Westinghouse of Hamilton, Ontario. This 5/6.25 MVA circular-core unit was originally manufactured by Allis Chalmers in 1952. Design changes by Siemens Westinghouse increased the OA rating to 6 MVA and the FA rating to 7.5 MVA. Six Luxtron fiber optic sensors were implanted near the top of the transformer’s secondary coils—two in each winding with one located between the first and second disk and one between the second and third disk. The sensors were installed as near to the mid-point of the disks as feasible and in contact with the copper conductor. These locations are thought to closely represent the transformer’s hot-spot location. All other temperatures recorded in this study were taken from standard thermocouples.

A 50 kW external oil cooler was obtained from Unifin of London, Ontario. This cooling unit consists of a 1 HP Cardinal pump, two 4.0 HP fans and a heat exchanger. The pump used by Unifin is designed for a variety of applications,with the desired oil flow for a given application achieved by throttling the flow with a valve on the discharge side of the pump.Nominally, this combination of components is rated by Unifin for a flow rate of 20 GPM, but the pump can produce a much higher flow, as was observed in this study.

Study Two…
The transformer selected for Study Two was a unit being rewound for Consumers by Ohio Transformer of Tallmadge, Ohio. This 5 MVA base circular-core transformer was originally manufactured by GE in 1963.

Six FISO fiber optic sensors, two per phase, were implanted in the coils of the transformer and a FISO Nortech-6 monitor was installed to record the readings. The hotspot locations were determined by the design team at Ohio Transformer, and the sensors were installed during the rewind process. All other temperatures recorded in this study were taken from standard thermocouples.

A 100 kW external oil cooler was obtained from SD Myers. This cooling unit consists of a 3 HP pump, 5.0 HP fans and a heat exchanger. The cooler is mounted on a portable trailer and includes hoses configured with check valves and quick connect fittings. The desired oil flow is achieved by throttling the flow with a valve on the discharge side of the pump.Nominally, this combination of components is rated by SD Myers for a flow rate of 50 GPM, with a capability of removing 340,000 BTU/hr.

An industry standard mineral oil and an ultra pure mineral oil manufactured by Petro-Canada with the trade name of Luminol were obtained from Ohio transformer. The transformer was first filled with standard mineral oil, tested, drained, refilled with Luminol, and then retested to obtain the efficiency comparison between the insulating oils used in combination with and without the external auxiliary oil cooler.

Study conditions and results


Study One…
Heat runs were initially conducted on the Allis Chalmers transformer (which had undergone design changes and was being rewound by Siemens Westinghouse) at the OA and FA ratings and then at 150% of the FA rating, or 11.25 MVA.While still at the 11.25 MVA level, the oil cooler was connected and temperatures were recorded until temperature stabilization was achieved. The cooler’s oil flow rate maintained for the initial run was 45 GPM. The observed temperature differential between the cooler’s inlet and outlet was consistently about 10 C degrees.

One of the fiber optic sensors stopped working early in the first heat run. The instrument displaying the fiber optic temperatures is capable of displaying four readings at a time. The temperatures recorded were taken one each from the outside windings and two from the center phase winding.

The warmest hot-spot temperature recorded while loaded to 11.25 MVA, and without the cooler operational, was 112 C on the center phase winding.When temperature stabilization was reached after the cooler was operational, this temperature had been reduced to 100 C. The magnitude of this temperature reduction was fairly consistent across all the sensors.

At the end of the first heat run with the cooler connected, the pump flow rate was increased to its maximum (estimated to be about 60 to 65 GPM) for one hour.No appreciable change was noted in the hotspot temperatures as a result of this, although there was a reduction of two degrees in the top-oil and average-oil rise temperatures. Had the test continued at this higher flow rate for a longer period, it is expected that the hot-spot temperature would have registered a similar decline.

The flow rate was then reduced to 20 GPM for a four-hour period. This resulted in an increase in the hot spot temperatures of approximately 4 C degrees.

0107_equipmentdesign_img4Study Two…
Heat runs were conducted on the GE transformer (that was being rewound by Ohio Transformer) at the OA and FA ratings and then at 150% of the FA rating, or 10.5 MVA, initially with the transformer filled with standard industry mineral oil and then repeated after draining the oil and re-filling with Luminol.While at the 10.5 MVA level and after the temperature stabilized, the oil cooler was connected and temperatures were recorded until they stabilized again. The cooler’s oil flow rate maintained for this study was 24 GPM.

The average hot-spot temperature recorded while loaded to the FA rating of 7 MVA, and without the cooler operational, was 92 C, using standard oil, and 87 C, using Luminol after stabilizing.When
temperature stabilization was reached after the cooler was operational, this temperature was reduced to 83 C, using standard oil, and 80 C, using Luminol. The magnitude of this temperature reduction was fairly consistent across all the sensors. The observed temperature differential between the cooler’s inlet and outlet varied between 8 and 14 C degrees, using standard oil, and between 11 and 18 C degrees, using Luminol.

The load was increased to the 10.5 MVA level, the oil cooler was connected, and temperatures were recorded until temperature stabilization was achieved. At this point, it was observed that the average hot-spot temperature of 140 C, in both cases, had been reduced to 127 C, using standard oil, and 115 C, using Luminol. The magnitude of this temperature reduction was fairly consistent across all the sensors. The observed temperature differential between the cooler’s inlet and outlet varied between 12 and 15 C degrees, using standard oil, and between 21 and 28 C degrees, using Luminol. (See Tables I & II and Figs. 2, 3, 4, 5, 6, 7.)







This study substantiates the benefit of employing an external oil cooler and the added benefit of using an ultra pure mineral oil (Luminol) in reducing a transformer’s hot spot temperature, thus preserving the life of the unit’s paper insulation. The relatively large internal oil quantities and large heatexchange surfaces of the transformers in this study result in relatively low internal oil and hot-spot temperatures.

Conversely, for a more modern unit with higher design temperatures, the expected temperature reduction with an external oil cooler could be even more impressive. However, the possibility of disrupted internal convection currents or diversion of oil from the transformers’ own radiators also would seem to be more likely because of the characteristically lower internal oil volumes. Consequently, a lower oil flow rate in the external cooler might be needed to avoid disrupting the transformer’s normal internal cooling pattern.

The transformer in Study One contained 1,920 gallons of oil, or 0.32 gallons per OA rated kVA, and the transformer in Study Two contained 1,300 gallons of oil, or 0.26 gallons per OA rated kVA. In a spot check of six transformers recently purchased by Consumers Energy, the lowest amount of oil found was 0.205 gallons per OA kVA rating. The SD Myers transformer maintenance guide reported in 1981 that some transformers had as little as 0.02 gallons per kVA.

In light of the significant variations in transformer oil volumes, flow to the external cooler may need to be tailored for the particular transformer involved. Besides possibly needing to modify the internal oil-cooling pattern, there also is a concern for creation of a vortex at the top hose connection. This would lead to air being sucked in and air bubbles being injected into the bottom of the transformer. A minimal oil level above the top hose connection must be maintained to avoid this or other possible measures must be adopted. MT

Noel Staszewski is a senior engineer in the Network Services Department of Consumers Energy.He has over 25 years of engineering experience in asset management and equipment maintenance in the utility industry, combined with additional experience in technology and product development, evaluation, reliability engineering and failure analysis of electronic components and systems in the automotive and computer industries. Telephone: (810) 760-3237; E-mail:

Mike Walker, a registered Professional Engineer in Michigan, spent 33 years in a number of engineering positions with Consumers prior to retiring in 2003. Since then, he has worked as an independent contractor for various companies. E-mail:

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6:00 am
January 1, 2007
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The Maintenance/Production Partnership: Part II


Ken Bannister, Contributing Editor

Role definition is crucial if both Maintenance and Production departments are to strike an accord and work in an autonomous, yet cohesive manner to deliver a high-quality product in a waste-free, cost-effective manner. Virtually every major management philosophy and methodology in practice today recognizes and fosters the integral relationship between the Maintenance and Production departments. Zero inventories-based Just In Time (JIT) and Lean-manufacturing methods would not be possible without high levels of equipment reliability and availability, driven by active operator involvement in the maintenance process.

Autonomous operator-based maintenance is foundational to the Total Productive Maintenance (TPM) philosophy, and is a cornerstone of the Reliability Centered Maintenance (RCM) methodology, both of which heavily utilize operator input to design, implement and continuously improve equipment maintenance reliability strategies. Increasing reliability and throughput requires Maintenance and Production to work together on a two-pronged management and hourly workforce level.

Operator-based maintenance
Operator-based maintenance can be implemented through the following three-step approach designed to promote confidence in both parties:

Step 1: Commence with a revised work acceptance procedure.Whenever Production calls in a machine problem, guide the caller(s) to disclose their name, the machine #/description, location, area of the problem (component or system) and a primary sense STILL (Smell, Touch, Intuition, Look, Listen) analysis of what the problem is believed to be.Operators instinctively know when their equipment is not running in the “sweet spot,” but they are rarely asked for their opinion(s). This step simplifies and speeds up the pre-planning process and allows the scheduler to more accurately dispatch the correct resources the first time.

Step 2: Allow and encourage operators to be part of the testing, start-up and acceptance after repair completion.

Step 3: Introduce Reliability Centered Maintenance (RCM). Choose a suitable RCM pilot and always include the relevant equipment operator and supervisor as part of the RCM analysis team when performing the FMEA analysis and condition-based maintenance work tasks. Use a perimeter-based maintenance approach in which the equipment is set up for rudimentary preventive and condition

monitoring checks while running. These checks can include temperature, flow, throughput, fill level, pressure and filter cleanliness-set up in an interactive “Go/No Go” style that lends itself perfectly to a regular operator check. This type of “Go/No Go” check only requires paperwork in the form of a work request when a “No Go” state is in effect.

Take, for example, a pre-RCM PM work order that might have instructed a maintainer to check and record all gauge pressures. This would not just be a waste of maintenance resources-the maintainer also would have to know the upper and lower safe operating window (SOW) limit for every gauge if a situation were to be immediately averted.

Recording every good pressure in the CMMS history also is meaningless and a waste of resources when it comes to input of the data. Marking each gauge with the SOW allows any person viewing the instrument to tell if the needle is in the safe or “Go” position between the lines, in which case no further action is required or taken. If, however, the needle is outside the SOW mark lines, or in a “No Go” state, the operator contacts the supervisor who immediately raises a work request for Maintenance to attend the pending situation. Because of the RCM FMEA analysis, Maintenance knows right away what the problem root cause could be and activates a planned work order in response to the event condition

RCM, which advocates autonomous maintenance work by operators (Total Productive Maintenance – TPM), is a perfect catalyst in building and cementing autonomous operator maintenance as a first-level maintenance approach, wherein the operator becomes the true machine guardian on a daily basis. Once a comfortable maintainer/operator working relationship is established, more complex PM-styled tasks, such as lubrication and filter changeouts, can be engineered into the operator-based maintenance program. In Fig. 1, operator-based maintenance is shown dovetailing into the core element of the maintenance process.


Maintenance/production management alignment
Aligning the Maintenance and Production management teams to work in partnership is achieved through communication and an understanding of each other’s goals and objectives. In the process, the parties work collaboratively in the planning and scheduling of the production equipment uptime and downtime activities.

As both departments own the equipment in different ways, both compete for “alone” time with the equipment. Unfortunately, if both agendas are not harmonized, the equipment will suffer and both departments will lose.

The interactive input/output information required of both departments in order to prepare and schedule weekly forecasts and daily work schedules effectively is depicted in Fig. 2. In both cases, monthly and weekly schedule forecasts are being built on an ongoing basis, and being used as “best guesstimates” for assessing and managing resource requirements. From these forecasts come the daily schedules that are usually 70% to 95% accurate–and which should be just flexible enough to allow for minor unforeseen changes. To synchronize these daily schedules, both Maintenance and Production must agree, through the RCM process, what point in an asset’s condition dictates an uncontested responsive event in which both the Maintenance and Production planning and scheduling departments will work together in the asset’s interest alone.


The Maintenance department can further assist the Production staff by providing a series of documents that include: a daily equipment condition report spelling out any triggered alarm conditions and found “No Go” exceptions that require planning and scheduling; a status report of unfinished or “carryover” work from a previous day or shift; a report-driven form with the fault codes marked on the work orders to show the percentage of non-maintenance-caused equipment failures (i.e., operator error, loading errors or jamming, overloading, etc.); and an equipment availability report. The Production department can further assist the Maintenance staff through the provision of a report detailing any pending product changeover or retooling event from which Maintenance can take the forced downtime opportunity to plan and schedule backlog or pending work on that equipment. Production will also assist Maintenance by providing reports on raw material problems, equipment incidents and any work requests. Getting together on a daily basis allows the information transfer and the setting of an almost fixed daily schedule. The product of this is equipment reliability and availability that translates directly into sustainable throughput and quality!

Ken Bannister is lead partner & principal consultant for Engtech Industries, Inc. Telephone: (519) 469-9173; e-mail:


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