Archive | Electrical Test


3:54 pm
April 13, 2017
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Add Electrical Motor Testing to Your PdM Toolkit

This predictive approach offers reliability benefits that time-based maintenance can’t.

Left. A 700-hp, high-voltage stator is being tested after undergoing rewind and the vacuum-pressure-impregnation process.

Left. A 700-hp, high-voltage stator is being tested after undergoing rewind and the vacuum-pressure-impregnation process.

Numerous studies have tried to establish guidelines for creating plant reliability and efficiency. Depending on which research is cited, the bottom line is that between 65% and 75% of all motor failures are mechanical in nature. For that reason, vibration analysis, a cornerstone of any predictive-maintenance (PdM) program, would appear to provide the “biggest bang for the buck” in pinpointing possible problems. Still, while an aggressive vibration-analysis program may accurately predict most mechanical issues, it can’t diagnose the 25% to 35% of motor failures that are due to electrical weaknesses and faults. That’s why electrical testing is so important.

To put it simply, the insulation system within a motor is the unit’s “heart”—and nothing but a series of electrical tests can fully evaluate the health and integrity of that heart. Comprehensive evaluation involves the use of static-testing and dynamic- monitoring technologies. To understand the benefits, it’s important to know why and how motors degrade.

Motor degradation

Various factors, including the initial quality of a motor’s insulation, affect the pace at which it degrades. Since heat is the main enemy of all insulation materials, maintaining a cool, dry environment will increase motor life.

Many things contribute to excessive heat. Typically, the situation is acerbated by a combination of issues that individually wouldn’t create a problem. High ambient temperature, numerous restarts, starting under heavy loads, slight misalignment, some unbalance with the supply voltage, and contamination, all contribute to the heat a motor experiences.

Another issue affecting the life of a motor’s insulation system is starting and stopping. In fact, most plant-floor personnel have, at some point in their careers, heard the old saying that “if you don’t want your motor to fail, don’t start it, and if it’s running, don’t stop it.”

Startup and, to some extent, shutdown of a motor, are generally the most stressful times in the unit’s life. Contactor and breaker “bounce” at startup can generate voltage spiking four or five times greater than the operating voltage. The initial in-rush of AC voltage, pushed by as much as eight or 10 times the nameplate current, “attacks” the insulation and greatly affects the early turns. This startup current causes the motor’s windings to flex or breathe and allows the copper magnet wire to rub and abrade. Because there are only about 1 1/2 mils of insulation baked on the magnet wire, over time it will deteriorate, resulting in arcing during starting and stopping. The appearance of arc is a sign that the insulation is basically at the end of its life. The wearing away of that thin insulation film, in turn, is the beginning of the end for many motors.

Screen Shot 2017-04-13 at 10.37.56 AMOnce arcing has begun, it occurs during every startup, and often during shutdown. It may continue for weeks or even months before it creates a failure. Eventually, though, it will create a carbon path and short out a portion of the windings. These shorted turns will then act as the secondary side of a transformer with voltage and current being induced by the rest of the circuit.

Keep in mind that the ratio of good turns to shorted turns will dictate how severe and how quickly a failure will occur. When shorted turns occur, however, a motor will fail within minutes. Thus, it’s imperative to find weak turn insulation before it becomes a hard-welded fault. If not detected in time, a few weak turns will carry an exponential amount of current that is induced by the transformer effect and quickly burns through the slot-cell liner to ground in the laminations. The result is often a damaged core with a large hole that will always make the rewound motor less efficient and run hotter.

Finding the weak turn insulation and taking the motor out of service before a short occurs provides two valuable benefits:

• Plant-floor personnel are in control of the motor. They decide when a unit is to be removed from service, which minimizes or eliminates unscheduled downtime, emergency repairs, and lost production.

• Since the motor in question still has a good core, a reputable repair shop can rewind it using better materials and parts and tighter balance specifications than when it was first installed.

In practical terms, the site gets a “new” motor back from the shop (not a patched-up one).

The predictive route

A strong PdM strategy can allow personnel to make realistic predictions regarding the useful life expectancy of their motors. The unfortunate fact is that a motor begins (and continues) to weaken and deteriorate from the moment of its very first startup. If it operates in high ambient temperatures, with some misalignment and voltage imbalance, and experiences numerous starts under a heavy load, its life will be short. Given these conditions, a motor that should last, say 20 years, will probably fail in two or three. While correcting some of those issues could prolong the life of the unit, keeping tabs on the health of its insulation could provide greater payback.

Preventive maintenance (PM) efforts are clearly important when it comes to a plant’s motor fleet. For example, in facilities where contamination is an issue, PM routines to reduce its effect on motor life are a must. Whenever possible, however, a PdM strategy that leverages as many proven predictive tools as possible should replace preventive activities. After all, to develop a complete picture of a patient’s health, a physician will typically perform a battery of tests. Your site’s motors deserve similar treatment.

Fortunately, state-of-the-art equipment and methodologies are available to identify early issues before they lead to catastrophic failure(s). Routine testing and trending will detect weaknesses long before they can propagate into an insulation failure. To design this type of PdM program, site personnel need to identify the motors that are most critical to the operation and, in turn, those that are the most problematic. This information will indicate which tests need to be performed and how often.

Many independent testing organizations have detailed specific test parameters, proven to provide sufficient data for the technician to evaluate the immediate health of the insulation. To ensure the capture of accurate data, it’s important that those guidelines be strictly followed. For more information on testing parameters and requirements, refer to IEEE (Institute of Electrical and Electronic Engineers,, IEC (International Electrotechnical Commission,, EPRI (Electric Power Research Institute,, and EASA (Electrical Apparatus Service Association,

Low-voltage testing, comprised of capacitance, inductance, and resistance tests, provides some useful information, but will not provide early warnings regarding turn insulation. A complete set of tests that will provide the predictive information you need include:

Winding-resistance test: This test will verify that all three phases are similar and all internal connections are tight. It uses a Kelvin bridge and injects about 12 VDC at approximately 7 A into the windings. One poor connection will lead to unbalanced current and uneven heating.

Megohm test: After passing the winding-resistance test, a megohm test is run to measure insulation resistance. The test uses a low-current DC voltage that depends on the nameplate voltage of the motor. A polarization index test (PI), which is an extended megohm test, may provide important information about the insulation if it is old, cracked, or brittle.

High-potential test: If the winding-resistance and megohm tests are acceptable, a high-potential (HiPot), or step-voltage, test may be performed. This test uses increased voltage to create electrical stresses on internal insulation cracks. This can reveal aging or physically damaged insulation. The HiPot test is usually conducted at an elevated level that is at least twice the line voltage plus 1,000 V. EASA and other testing organizations recommend even higher test-voltage levels. The HiPot test may not be appropriate for in-service motors that display low megohms during the megohm test.

Surge test: Once the above tests are satisfactorily completed, a surge test is performed. Since more than 80% of all winding failures begin as a turn-to-turn weakness that can only be detected by a surge test, it is the most important static-testing method. Surge testing applies pulses through a large capacitor at ever-increasing voltage levels and monitors the reaction as the voltage is discharged into a motor’s windings. The purpose is to re-create the spiking that occurs at startup. Doing so requires the capacitor to “fire off” each pulse at a very fast rise time. The intention is to locate weak turn insulation before it has a chance to become a hard-welded fault that leads to a quick failure.

Value proposition

Adding electrical testing of motors to your site’s PdM toolkit puts personnel in the reliability driver’s seat with regard to these units. The value proposition is clear: Routine testing and trending provides sufficient data to make a diagnosis regarding the ability of a motor to remain in operation or to determine if it needs attention. Being in control, i.e., being able to specify when a motor is pulled from service and sent out for repairs, is the essence of predictive maintenance—and an enormous benefit. MT

Information in this article was supplied by Timothy M. Thomas, senior electrical engineer, Hibbs Electromechanical Inc., Madisonville, KY ( Email him at


9:20 pm
January 13, 2017
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Choose to Fuse (And Why)

Designed as sacrificial devices in electrical systems, fuses protect costlier components in those systems from the damaging effects of overcurrent. They can also make control systems UL- and NEC-compliant.

Designed as sacrificial devices in electrical systems, fuses protect costlier components in those systems from the damaging effects of overcurrent. They can also make control systems UL- and NEC-compliant.

Fuses are sacrificial devices that help protect costlier components in an electrical system from the damaging effects of overcurrent. (They can also help make control systems UL- and NEC-compliant.) To be sure, there are many other solutions for protecting electrical gear from overcurrent, including circuit breakers and protective relays. Information from Cumming, GA-based AutomationDirect (, though, lists 10 reasons why end users also should consider fusing.

— Jane Alexander, Managing Editor

Overcurrent protective devices that have tripped are often reset without first investigating the cause of the fault. Electromechanical devices may not have the reserve capacity to open safely when a second or third fault occurs. When a fuse opens, it’s replaced with a new fuse, meaning the protection level is not degraded by previous faults.

Fuses typically are the most cost-effective means of providing overcurrent protection. This is especially true where high fault currents exist or where small components, such as control transformers or DC power supplies, need protection.

randmHigh interrupting rating
With most low-voltage current-limiting fuses (< 600 V) having a 200,000-A interrupting rating, users are not paying a high premium for a high-interrupting capacity.

Fuses have no moving parts to wear out or become contaminated by dust or oil.

North American standards
Tri-National Standards specify fuse performance and the maximum allowable fuse Ip and I²t let-through values. Peak let-through current (Ip) and I²t are two measures of the degree of current limitation that is provided by a fuse.

Component protection
The high current-limiting action of a fuse minimizes or eliminates component damage.

Extended protection
Overcurrent-protective devices, with low-interrupting ratings, are often rendered obsolete by service upgrades or increases in available fault current. Updated NEC and UL standards are fueling the need to install potentially expensive system upgrades to non-fused systems.

Fuses can be easily coordinated to provide selectivity under overload and short-circuit conditions.

Minimal maintenance
Fuses do not require periodic recalibration. That is not the case with some electromechanical overcurrent-protective devices.

Long life
As a fuse ages, the speed of response will not slow down or change. A fuse’s ability to provide protection will not be adversely affected by the passage of time. MT

Fuses 101

Fuses consist of a low-resistance metal or wire that is used to close a circuit. When too much current flows through the low-resistance element of the fuse, the element melts and breaks the circuit. This keeps the excessive current from continuing down the circuit to more expensive equipment.

For more information on a range of automation-related topics and solutions, including current-limiting fuses that meet UL and NEC codes, visit or


7:34 pm
June 13, 2016
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Upgrading Legacy Power Systems

Upgrading to new equipment requires careful analysis and planning to avoid extended downtime.

Upgrading to new equipment requires careful analysis and planning to avoid extended downtime.

A Q & A with Danita Knox, GE Energy Connections.

When’s the best time to upgrade a power system? According to Danita Knox of GE Energy Connections, Atlanta, it can vary. Consider the following situations as ideal opportunities:

  • if a facility had or is planning a significant expansion that might affect overall power-system loading
  • if a recent arc-flash study revealed significant incident levels or danger of exposure for electrical workers or operators
  • if personnel are having difficulty locating replacement and spare parts for the site’s electrical system
  • if plant personnel desire better monitoring of the overall power system.

Once the decision has been made to move forward on an upgrade, what’s next? We asked Knox for some insight into what facilities can do to make these projects go smoothly.

MT: What trends in power-system upgrades are you seeing among older installations?

Knox: One trend involves customers replacing older electromechanical relays, meters, and trip units with newer digital “smart” equivalents. This provides a single, multi-function device that incorporates communications (local and network), event logging, and monitoring (graphical screens and remotely using web tools). Critical applications include upgrading to smart switchgear offerings that feature built-in monitoring, diagnostics, redundancy, and remote-control capabilities.

Facilities are also adding devices to their power systems that help locate workers further away from the equipment they operate. This is done, in some cases, by adding remote racking devices to existing breakers or using robot-type devices to operate equipment from a safe distance. We’re seeing more sites updating old fused devices, such as a load interrupter switch, with faster-operating vacuum breakers and relay equivalents that reduce arc-flash incident levels.

Finally, with limited budgets for large capital projects in many plants, it’s essential for them to find ways to extend the life of their existing equipment. To that end, facilities are often looking at retrofit options.

MT: What tips do you have for sites that are embarking on a power system upgrade?

Knox: Ideally, it helps to start with a comprehensive arc-flash study. This can provide remediation suggestions on how to reduce arc-flash exposure levels and improve personnel and equipment safety. To begin an arc flash study, an operation needs an accurate schematic or diagram of the facility. Plant personnel familiar with the electrical system can usually collect the information needed to build this diagram. An accurate schematic also provides critical information that can be a great tool to develop safe and proper LOTO (lock-out/tag-out) practices.

With a thorough arc-flash study, plant operators can then evaluate multiple options that help define steps to start upgrading a power system. Upgrade projects can be prioritized into smaller projects, depending on employee exposure, process needs, available outage periods and budget constraints.

If you’re going to replace old gear with new equipment, such as this ground and test device for Magne-Blast switchgear, be sure to test all critical components prior to the outage. Photo: GE

If you’re going to replace old gear with new equipment, such as this ground and test device for Magne-Blast switchgear, be sure to test all critical components prior to the outage. Photo: GE

MT: To get management buy-in, what’s the best way to estimate the return on investment (ROI) and benefits of an upgrade?

Knox: Often the need to upgrade is based on some failure or electrical incident that has caused downtime, equipment damage, or, worst-case scenario, employee injury.

When you look at the cost associated with downtime and/or injury, it’s fairly easy to calculate ROI if the project is done in a phased approach. Some trip unit, relay, and breaker upgrades can be done under the threshold of a maintenance budget.

MT: Are there any budget-friendly ways to upgrade a legacy system?

Knox: Yes, there are. It’s important to look at upgrade options that solve the most problems with minimal disruption to plant operations and equipment.

Consider, for example, if a single upstream breaker/relay combination in the facility can reduce arc-flash exposure for downstream feeder breakers without upgrading each breaker. Does the site have unused spare breakers that can be rotated out with a local service shop for upgrades that can later be installed during a short outage?

If a plant is updating old relays and meters, it should get new doors with new components prewired. This allows a shorter outage while equipment is being replaced. Also, “replacing the guts” in the existing compartment in a field outage can help reduce upgrade costs, assuming the new equipment has been pre-determined to fit the compartment and it can be easily wired. MT

Danita Knox is senior product manager for Power Delivery Services within GE Energy Connections, headquartered in Atlanta.

Steps to a Successful Power-System Upgrade

According to GE’s Danita Knox, as a site prepares for a power-system upgrade, it’s important to identify and select a reputable vendor that’s experienced, trained, and knowledgeable in designing this type of complex project. A power-system upgrade includes these steps:

  • Budgeting for hardware, software, and labor.
  • Development of a project schedule and careful outage planning for the upgrade.
  • Design of the system and procurement of all components prior to the outage.
  • Labor and logistics planning for the outage to ensure that work is completed on time.
  • Testing of all critical components prior to the outage.
  • Failure mode and effects analysis to plan for challenges during the outage and prepare solutions or workarounds.
  • Site safety and work policy that includes LOTO (lock-out/tag-out) training and documentation.

“During the upgrade,” Knox said, “an experienced project manager with a background in power systems is indispensable. Many facilities operate continuously with infrequent planned outages. Careful planning and execution is required to maximize work and re-energize systems in a timely manner.”

Knox advises creating a detailed schedule and work procedures early on, including planning types of labor and required skill-sets and procuring all materials well in advance. “Regarding procurement,” she cautioned, “be careful to consider smaller items, such as personal protective equipment and installation components. If these small details are missed in outage planning, they can create schedule slippage, safety risks, or technical errors while limiting the amount of work accomplished.”


3:08 pm
January 13, 2015
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All in a Day’s Work


Two Schneider Electric facility engineers share their tips for ensuring the safety, efficiency and reliability of a site’s electrical system.

By Jane Alexander, Managing Editor

The infrastructure of a typical commercial or industrial facility is a complex network of electrical, electronic, process and control, automation and building-management systems. Some facilities include critical power and cooling systems as part of that infrastructure. And when something goes wrong, there’s typically one go-to person. Whether his/her title is facility engineer (as used in this article), manager or director, this individual has a full plate. For example, following is a partial list of job responsibilities listed in a recent online job posting for a Lead Facility Engineer:

  • Ensure adherence to safety policies and procedures
  • Monitor buildings, grounds and equipment for safety and functionality
  • Maintain data center systems
  • Perform routine maintenance tasks
  • Troubleshoot, evaluate and recommend system upgrades
  • Order parts for maintenance and repairs
  • Request proposals for work that is to be outsourced
  • Supervise shift personnel; support training initiatives
  • Oversee maintenance reporting activities
  • Supervise and audit contractors
  • Ensure accurate and timely completion of work order requests
  • Serve as on-call facility manager, as needed

As Facility Engineers for Schneider Electric with more than 20 years of combined service, Kirk Morton and Keith Smith perform many of the functions listed above. Morton is responsible for the daily operations of a 100,000-sq.-ft. office building with 400+ employees, while Smith oversees operations at one of Schneider Electric’s manufacturing facilities. While many of their day-to-day tasks are similar, Smith’s industrial facility naturally has more systems and requirements to address than Morton’s office building. These include compressed air systems, crane and hoist inspections and load tests, processed water/wastewater treatment and site storm- water prevention plans.

Morton and Smith also are responsible for outsourcing various services, for managing outsourced/contracted employees, and for ensuring contractors follow safety standards in place at the worksite (facility managers, not contractors, retain ultimate responsibility for plant safety). While the traditional reason for outsourcing is to enable an organization to focus on its core competency, there can be others, as reflected in the following four models:

  • The company needs contractors to help meet operational/productivity requirements.
  • Contractors with a specific skill set are needed to perform specific tasks.
  • A company uses contractors for projects.
  • A company uses contractors to act as consultants, i.e., Managed Services.

Reliable power is paramount

Morton and Smith agree that a reliable power system is at the heart of safe and efficient operations. Per Schneider Electric requirements for all of its locations, both have implemented preventive maintenance programs at their individual sites. Their programs follow the recommendations of NFPA 70B and requirements of NFPA 70E:

A well-administered Electrical Preventive Maintenance program: reduces accidents, saves lives and minimizes costly breakdowns and unplanned outages. Impending troubles can be identified, and solutions applied, before they become major problems requiring more expensive, time-consuming solutions.

Source: NFPA 70B-2013 Ed., Section 4.2.1

When it comes to their sites’ respective electrical infrastructures, Morton and Smith may deal with different systems, but their overall focus is on reliability. “We really don’t have any issues in our commercial office space,” says Morton. “The meters and monitoring equipment are our own and very reliable, as is our switchboard. In addition, we have a reliable back-up source for our data room.”


Smith’s manufacturing operation doesn’t have issues with its electrical systems either, thanks to its robust generator and battery backup capable of providing redundant power. Still, he emphasizes, any maintenance and repair activities must be scheduled and performed to accommodate work schedules. “And departmental workloads must be considered.”

Unfortunately, some facility personnel may not be knowledgeable or adequately trained in the specific equipment or power distribution systems that comprise the electrical infrastructure at their sites. With regard to preventive maintenance of an operation’s electrical system, special skills and knowledge are required, which is why this work is often outsourced. Based on their own responsibilities with regard to electrical work, Morton and Smith offer the following tips for other facility managers:

0115f2-31. Qualifying electrical workers

Due to the increasing complexity and interconnectivity of today’s electrical systems, few companies have the in-house experience to service all of a facility’s electrical components. Facility management needs to ensure that electrical workers are qualified, as defined by OSHA and NFPA 70E, to work on the specific equipment that is to be maintained. This applies to in-house staff, as well as third-party contractors. Fundamental require-
ments include:

  • A complete understanding of equipment, the required work scope and electrical hazards present.
  • Proper use of personal protective equipment (PPE), tools, shielding and test equipment as well as precautionary techniques.
  • Discipline and decision-making skills to determine risk and ability to maintain a safe work environment.

For maintenance and testing activities, an in-depth interview of potential electrical service providers is suggested, and applicable references should be obtained. Ask questions up front relative to Field Personnel Competency Training to determine product knowledge. Morton and Smith say it’s important to learn about the service provider’s safety training program. As noted, the company that outsources the work is responsible for workplace safety, whether the maintenance worker is an employee or a contractor.

2. Outsourcing electrical work

Morton and Smith point out that if a site elects to outsource its electrical work, its facility engineer(s) still have several crucial responsibilities:

Facility engineers should obtain and maintain all of the operations and maintenance manuals that accompanied the original electrical equipment. If any have been discarded, misplaced or lost, the original equipment manufacturer (or their representative) should be contacted and replacement copies requested. These documents are often available online and can be searched by the manufacturer’s name and electrical equipment identification.

Facility engineers must be clear regarding the specific equipment they desire to have cleaned, inspected, maintained, serviced and tested, as well as be clear regarding each piece of electrical equipment that is to be removed from service for inspection, maintenance or testing.

Before any electrical maintenance program is initiated or contracted, facility management should provide exact, detailed and up-to-date one-line diagrams of the entire electrical-power-distribution system. These records should also indicate the specific location, room number, floor or area location where each piece of electrical power distribution equipment can be found. If this documentation is not available or is out of date, the services of a licensed professional electrical engineer should be contracted and commissioned to create and maintain current electrical one-line diagrams and equipment name-plate data.

The facility’s needs for temporary electrical power must be met during a scheduled maintenance interruption. Facility engineers should ensure the availability of a temporary power source.

3. Ensuring safe, efficient, reliable electricity

Both Morton and Smith agree that having a preventive maintenance program in place helps mitigate the risk of unplanned downtime. They also recommend a battery back-up as well as back-up generator capabilities, because even with regularly scheduled preventive maintenance, all facilities will experience unplanned electrical outages from time to time.  MT


2:48 pm
November 4, 2014
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ROI From Improved Emergency Power Protection


Leveraging best practices in maintenance with state-of-the-art monitoring technologies and remote services will keep your UPS systems in compliance, reliable and available.

By Jane Alexander, Managing Editor

Because uninterruptible power supply (UPS) units and their batteries must function properly during unplanned outages, a compromised emergency power system can mean serious trouble. At this critical time, batteries supply power to digital control systems and emergency lube oil pumps, enabling automatic controls to do their job.

In applications like oil and gas, petrochemical and power generation, dead batteries that prolong power interruption can cause dangerous chemical-process instability, damage to equipment or, in some cases, the shutdown of a facility. Damaged equipment could take months and millions to repair, while lost power production could be more expensive and lead to fines and penalties. For example, in a recent case regarding the 2011 blackout in the southwest United States, a public power entity agreed to pay a $12 million civil penalty for its role in the outage.

According to Wally Vahlstrom, Director of Technical Services for Emerson Network Power’s Reliability Services group, a proper preventive maintenance program can help a plant avoid those types of costly incidents and, in turn, provide several added benefits.

Benefit: battery-testing compliance

Every emergency power system contains life-limited components that should be maintained according to recommendations from the Institute of Electrical and Electronics Engineers (IEEE), manufacturer specifications and as required by the North American Electric Reliability Corporation (NERC). Batteries are no exception. In the event of a power outage, a single bad cell in a battery string could compromise the entire backup system and leave a plant without protection.

While UPS battery manufacturers may market their batteries with a 10-year design life or life span, actual battery service life could be much shorter due to the external factors that cause degradation. Several effects that can shorten battery life include:

  • Frequent discharge cycles
  • High or improper room temperatures
  • High or low charge voltage
  • Excessive charge current
  • Manufacturing defects
  • Loose connections
  • Strained battery terminals
  • Poor and improper maintenance

In reality, batteries lose capacity in as little as three years. According to IEEE, the “useful life” of a UPS battery ends when it can no longer supply 80% of its rated capacity in ampere-hours. At this point, because the aging process accelerates, a battery should be replaced.


Benefit: increased battery life

Because of the many factors that can affect the useful life of a UPS battery, it is important that—as soon as it is placed into service—a battery be maintained with a program that identifies system anomalies and provides information that trends end-of-life. Through this type of maintenance program, plant owners and operators can get the most out of their investment in these critical assets.

Batteries that are beginning to fail cause an imbalance that adversely affects the life of other batteries in the string and should be removed from service. Moreover, when UPS battery replacement is needed, time is critical—especially in light of the financial impact an extended or unplanned outage can have on an organization. In a concerted effort to increase its system reliability, the public power entity cited in the above-referenced blackout expects to invest at least $20 million in battery storage facilities within its transmission operations area.


An increase in the number of annual preventive maintenance visits increases mean time between failure rates.

Benefit: maximized system reliability

To avoid UPS battery failure, the best practice is an approach that includes integrated battery monitoring and preventive maintenance (PM). In Emerson Network Power’s data analysis of more than 450 million operating hours for more than 24,000 strings of UPS batteries, the impact of regular preventive maintenance on reliability was clear. The analysis revealed that the mean time between failures (MTBF) for units that received two PM service visits a year is 23 times better than those that received no PM visits.

Furthermore, operations with battery monitoring systems installed at their sites had a reduced rate of outages due to bad batteries. While outages still occurred, the incidents were isolated to cases where customers were either not watching their system or did not know how to properly analyze the data provided by the monitor. This revealed the need for experts to correctly monitor the alarm data and properly maintain those systems.

Benefit: improved system availability

The ideal UPS battery maintenance program is one that uses monitoring in conjunction with remote services. Teams responsible for managing critical infrastructure are essentially able to augment their staff with a remote services solution that includes data acquisition, equipment trending, monitoring alert management, maintenance and remote diagnostics, as well as parts and service-personnel dispatch.

The latest technology, such as that used in Albér battery-monitoring products, can identify potential problems by tracking critical parameters like cell voltage, overall string voltage, current and temperature. Periodic tests of the battery’s internal resistance can also verify a battery’s operating integrity. For a UPS, technology can be embedded and allow, for example, continuous monitoring of multiple unique parameters. At defined intervals—or at the activation of a critical alarm—the monitoring device will communicate to a remote system engineer and provide alarm details, allowing immediate corrective action.

By combining monitoring with remote services, plant managers can define escalation plans that are executed upon any alarm condition. Your chosen service partner should have critical infrastructure experts available to support monitoring efforts 24/7 to improve overall system availability.  MT

Wally Vahlstrom is Director of Technical Services for the Electrical Reliability Services business of Emerson Network Power. For more information, visit


8:29 pm
July 8, 2014
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Two New Industrial Infrared Cameras Feature Wireless Connectivity and Easy Viewing

Screen Shot 2014-07-08 at 3.19.16 PMFluke Corporation has expanded the Fluke Connect system with its new Ti90 and Ti95 Infrared Cameras featuring wireless connectivity. According to the company, the  Ti90 and Ti95 deliver best-in-class image quality with up to 84% better spatial resolution (of handheld industrial infrared cameras priced $1000- $2000), thus allowing technicians to conduct infrared inspections from a safer distance without compromising accuracy. Their 3.5-inch color LCD screens are up to 32% larger than competitive models and offer adjustable brightness for easy viewing in most conditions.

These new cameras come with an extensive SD memory system, including a removable 8 Gb SD memory card or 8 Gb wireless SD Card. This feature allows technicians who share cameras to simply swap SD cards at the end of their shifts instead of needing to download images onto their PC before turning the camera over to the next technician.

AutoBlend and Picture-in-Picture modes are available in the included SmartView reporting software that lets technicians easily perform analyses and image adjustments/enhancements.

About Fluke Connect
The Fluke Connect system allows maintenance technicians to wirelessly transmit measurement data from their test tools to their smart phones for secure storage on the cloud and universal team access from the field. More than 20 Fluke tools connect wirelessly with the app, including digital multimeters, infrared cameras, insulation testers, process meters and specific voltage, current and temperature models.

Fluke Connect ShareLive video call allows technicians to collaborate with others, letting them see the same images and measurements, and get approvals for repairs without leaving the field.

The Fluke Connect app can be downloaded for free from the Apple App Store and the Google Play Store.


8:59 pm
July 1, 2014
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Remote Circuit-Breaker Racking Mitigates Arc Flash Hazards


Fig. 1. Cascade Steel Rolling Mills, McMinnville, OR

A steel plant’s remote racking systems offer a safe alternative to manually racking circuit breakers by keeping operators outside the flash-protection boundary.

By Tim Burttram, Plant Electrical Engineer, Cascade Steel

With the threat of an arc flash incident at circuit breakers, distance can be an operator’s best friend. That’s one of the facts that led Cascade Steel to evaluate the latest offerings in remote circuit-breaker racking technology. The mill wanted a remote racking system that was quick and easy to deploy. Wasting money on a piece of equipment that electricians and maintenance personnel wouldn’t use wasn’t feasible.

Founded in 1968, Cascade Steel Rolling Mills is a state-of-the-art steel-manufacturing facility that takes recycled metal and turns it into high-quality finished steel products. Located in McMinnville, OR, the company’s electric arc furnace (EAF) mini-mill produces a wide range of hot-rolled products such as reinforcing bar (rebar), coiled reinforcing bar, wire rod, merchant bar and other specialty products (Fig. 1).

Like other industrial operations, Cascade Steel is tasked with safeguarding its workers, equipment assets and the environment. Any company that generates, transmits, distributes or uses electricity at high, medium or even low voltages has an obligation to protect its personnel from hazards such as arc flash and others that might occur in switchgear equipment.

Breaker racking issues

Arc flash hazard mitigation is at the top of every plant or mill’s electrical-system-safety list. Employers must ensure that their electrical-system workers go home at night by understanding arc flash risks and the latest technologies designed to minimize them.

The simple act of manually racking a circuit breaker, with an operator positioned in front of the device, creates an arc flash hazard. Parts break or don’t line up. Equipment malfunctions. Even with the best personal protective equipment (PPE), plant and mill workers are still going to get hurt in some way if things go badly.

Fig. 2. NFPA70E is the basis for  Cascade Steel’s electrical safety program.

Fig. 2. NFPA70E is the basis for
Cascade Steel’s electrical safety program.

At the Cascade Steel site, plant personnel recognize the NFPA70E standard as the basis for their electrical safety program. This standard requires that to work on electrical apparatus with elevated energy levels, electricians must de-energize upstream equipment to avoid the potential for an arc flash. This means opening and closing circuit breakers, and eliminating power to various areas of the melt shop or rolling mill—a potentially dangerous situation for both human and equipment assets (Fig. 2).

Why remote racking?

History has shown there is no better protection against a potentially deadly arc flash incident than a safe working distance between the operator and the switchgear. This approach has clear advantages over flash suits designed only to decrease exposure to burns; it also minimizes the risks posed by airborne projectiles often associated with arc blast fatalities.

To reduce hazards to employees, many mill sites are installing remote circuit-breaker racking systems that allow operators to safely rack breakers from a remote location. Remote racking systems offer a safe alternative to manually racking circuit breakers and reduce the requirement for service personnel to wear a full-body arc flash hazard suit for protection. Designed to remove operators from close proximity to the breaker that’s being racked, these systems permit the insertion and removal of electrical devices while the operator is outside the flash-protection boundary.

Following its evaluation of remote racking options, Cascade Steel chose the Safe-T-Rack system from Remote Solutions LLC. This system places a protective barrier of up to 150 feet between the operator and the energized breaker. It also differs substantially from common “land-based” systems that must either be moved to the breaker location on a cart or affixed to a large base with a motor-driven mast.

Some users find land-based racking systems cumbersome: They can weigh hundreds of pounds and aren’t very portable. With this type of system, the operator must properly finesse the device to the face of the work on the circuit breaker compartment, register the X/Y/Z coordinates relative to the racking points and then secure the tool. This procedure can take up to 20 minutes per breaker, and also introduces human-performance concerns. Tool-alignment problems can result in physical damage to the circuit breaker, rendering it unserviceable.

Conversely, the remote racking device that Cascade Steel chose is easily operated with switchgear elevated above the ground. It includes fail-safe mechanisms to keep personnel from misapplying it to the wrong breaker. It also includes specific attachments and software to address particular racking parameters such as torque and breaker travel. The switchgear-based racking apparatus can be mounted on the breaker itself or on the breaker-compartment door so it can be registered correctly to the racking points.

To date, Cascade Steel has installed remote racking apparatus on every rackable breaker in its mill, regardless of voltage level. The company is now working to obtain remote racking for three additional 480-volt, molded-case SPB rackable breakers.

How the system works

With a switchgear-based tool alignment philosophy, the operator uses the switchgear as a reference, aligning the remote racking apparatus only once. The device includes the exact racking point coordinates for a given circuit breaker design, and is affixed to the breaker compartment door to allow all racking tool pieces to be easily loaded or mounted. The racking point coordinates are fixed so that any time a mill worker mounts dry brackets, for example, the center point for the tool is aligned for insertion directly at the racking screw.

Fig. 3. Example of a switchgear-based tool-alignment philosophy, where the switchgear is used as a reference for the remote racking device, aligning it only once. Exact racking point coordinates are included for individual circuit-breaker designs.

Fig. 3. Example of a switchgear-based tool-alignment philosophy, where the switchgear is used as a reference for the remote racking device, aligning it only once. Exact racking point coordinates are included for individual circuit-breaker designs.

“Human factors” engineering also establishes a “chain of rejection” to minimize human error. This enables technicians to consistently handle racking applications on multiple breakers of various configurations (Fig. 3).

A touchscreen human-machine Interface (HMI) for “closed-door” racking also benefits mill operators. Redundant digital drives with battery backup provide fail-safe racking in the event of a power failure. Real-time breaker travel indication and user controls include an emergency stop at any time during racking, manual start/stop, and automatic retrieval and recovery of a circuit breaker.

Fig. 4. With a switchgear-based remote racking system, mills gain a safe, reliable and user-friendly alternative to manually racking breakers.

Fig. 4. With a switchgear-based remote racking system, mills gain a safe, reliable and user-friendly alternative to manually racking breakers.

A torque limiter for different manufacturers’ breakers found throughout the mill counts the number of turns as well as displaying real-time travel position. The system stimulates all OEM breaker interlock systems and automatically operates and monitors positive interlock.

In addition, tilt-angle monitoring allows operators to track the pitch and roll of a breaker during racking to minimize potential equipment damage. Should the device detect an out-of-level situation, it will stop the racking process. Over-torque protection is also provided for the racking motor should the shutters not open or if the breaker becomes bound in the racking process. This consistent process will extend the life of switchgear.

Some facilities make a big investment in a cart-based remote circuit-breaker racking system, only to find it goes unused. This means the operation has wasted its money and not accomplished its objective of getting workers out of the danger zone.

With a switchgear-based remote racking system, sites gain a safe, reliable and user-friendly alternative to manually racking breakers, which reduces the requirement for operators to wear a full-body arc flash hazard suit for protection. They can rack a breaker properly by its original design and insert and remove the equipment while remaining outside the flash-protection boundary (Fig.4). MT