Dielectric Frequency Response in Measuring Moisture in Power Transformers

Progress is being made in using Dielectric Frequency Response technology in measuring moisture content within the Insulation system of power transformers. Power transformers’ Insulation “system” includes dielectric fluids or gasses (mineral oil, vegetable oil, SF6. Freon gas, etc.) and the paper insulation wrapped around nearly all conductive materials.

The high-voltage electric apparatus “industry” which includes Design/Manufacturer’s, Owners/Users and Testing Labs and Field Testing companies have uncovered definitive value in applying varied Frequencies during Design, Production, Commissioning and Field testing of high-voltage electrical apparatus. Applications have included nearly all types of equipment including circuit breakers, power cable, relays, sensors and so on.

Specifically, the ability to measure or gauge the moisture intrusion within the dielectric systems of power transformers, power cable, etc. has always been a main focus and primary goal of many of the Industries’ Testing methods. Power Factor, Insulation Resistance and Oil Analysis are the primary methodologies utilized. Besides the induced Test Voltages and Currents alone, the Industry has discovered value in varying the induced Test Frequencies also.

Normandy Machine Company – Maximize Asset Performance for Power Transformers

NEW LRT 200-3 LTC Core Exchange Assembly

Normandy Machine Company offers options in managing and maintaining critical Power Transformer Assets by extending the life of Load Tap Changers in offering LTC Core Exchange Services and Field Service Kits. Re-manufactured LTC Assemblies are available, many IN STOCK, for immediate Exchange.

Utilizing 21st Century machining and materials technology deliver higher quality assemblies and components which deliver higher quality performance. Increased RELIABILITY maximizes your Asset Management performance allowing you to meet or exceed your Company’s Asset Management goals.

Your Power Transformers will now meet or exceed RELIABILITY and PERFORMANCE expectations. NMC removes the LTC as the “weak link”. NMC Field Supervisory experts are available to assist your personnel in transitioning your LTC Core Exchange or Field Service Kit while providing much needed Field Training for your Station Technicians and Mechanics.



Why Perform Maintenance & Testing on Electrical Equipment?


The value of Maintenance is always questioned. Fundamentally, though, it reflects the quality of an organization, their commitment to employee safety and overall operational integrity.



EMPLOYEE SAFETY – general industry and commercial compliance issues required for your employees to understand electrical safety and are trained in electrical safety procedures, methodologies and proper use of all related equipment up to the most current Industry requirements. If these tasks are documented as part of an ongoing Maintenance and Safety Program; Owners, Management, Facility Managers or Plant Managers can be relatively assured that they are  in compliance with applicable NFPA 70B and OSHA 29CFR1910 regulations.

PRODUCTION – The underlying facts relative to achieving and maintaining minimum Operations reliability and productivity are typically required from your Company’s management, owners and stakeholders.

If an incident were to occur with the electrical distribution system at an Industrial or Manufacturing facility resulting in a recordable OSHA accident, the aforementioned regulations will be referred to in determining the levying of any penalties, fines, litigation or any other actionable items recommended moving forward.

Manufacturers do not warranty their equipment over (1) year. Any implied performance or lack thereof will refer back to the Manufacturers Operating & Instruction manuals which will clearly state that beyond the standard (1) Year Warranty, the manufacturer’s require testing and maintenance to be performed on the equipment at recommended intervals (typically annually).

Performing and documenting regularly scheduled:

  1. Testing and Maintenance on your Plant’s electrical distribution system
  2. Conducting electrical safe practices for your Plant’s Operating and Maintenance personnel

Reference documents:       NFPA 70B; 70E and OSHA 29CFR1910

New developments include NFPA 70E-2014 Arc Flash requirements. This requires equipment Labeling, proper PPE and Training of Plant personnel. It begins with an accurate One-Line Diagram. To accomplish this, the Data Gathering can be performed during Maintenance (this will verify existing One-Line or allow the composition of an accurate One-Line). Subsequent Engineering Study calculations are performed which generate the Labeling. Finally, the purchase of the PPE determined by the Study should be purchased for Plant personnel and Training in the proper use thereof, then is performed.

Mark S. McCloy  monkey_power

Standard for Shielded Power Cable Diagnostic Testing Methodologies

Standard for Shielded Power Cable Diagnostic Testing Methodologies


The advancement and evolution of the development and use of Partial Discharge as the technology to monitor and alarm the insulation integrity of both electrical power apparatus, accessories and the entire power systems’ Assets continues to gain credibility, accuracy and reliability. The ability to monitor an Owner’s Assets of this significance; continuously, without outage interruption has enormous value – is self-evident.

The most cost-effective applications continue to be power transformers, Iso-Phase Bus and all rotating equipment – and most applicable accessories. Regarding shielded power cable, though, the most practical, pragmatic approach for this application is the use of off-line, Tan Delta Diagnostics, Withstand or the very popular combination – Monitored Withstand Field Tests, which achieve significant, objective and reliable results that have proven to deliver real value to the Owners of significant power cable Assets.


For purposes of efficiency; we will address the application of shielded, solid-dielectric insulated power cable through 38KV; underground residential, network, bus-tie, station get-away, overhead, direct bury and associated applications. Additionally, we will only address Tan-Delta (Dissipation Factor and related Power Factor) and Partial Discharge technologies. There are other methods outlined in IEEE Std 400-2012; Std 400.2-2013; Std 400.3-2006 which we will use as the guide basis of this paper. Diagnostic Testing can be defined as Non-Destructive, meaning it does not induce undetected defects in a defect-free cable system and does not intentionally cause a failure during the test. A destructive test is defined as a test which (a) requires that a defect produce a fault during the test, and/or (b) produce substantial cable system degradation which goes undetected during the test.

Diagnostic Testing of high voltage electrical power equipment and conductor can be divided into two categories. On-Line (or energized) and commonly referred to as Level 1 (non-invasive; on-line) Diagnostics and Off-Line (de-energized); both methodologies require experienced, trained personnel in Safe electrical practices within a high voltage environment.

Partial discharge diagnostic testing has proven to be effective as a permanent, on-line monitoring technology in switchgear, bus and transformer applications; utilization of RFI bandwidth allows for an overall “umbrella” or pre-locating application as a system. Additionally, the use of portable, Level 1 Diagnostic PD detection for large, power transformers, lightening arrestors and rotating equipment is developing into a reliable methodology and technology, as directed by the pre-locate of the RFI signatures. Both permanent and portable Level 1 applications are beginning to establish objective, known recorded values over many years of use and many test subjects; with the resulting reliable, useful operational diagnostic information as the goal; unfortunately, there remains contention regarding detailed, objective diagnostic PD levels generated by the installed Cable System and most notably the Accessories. Off-Line PD will not measure any water-tree defects, only Splices and Terminations (Accessories).

Cable application of On-Line PD measures and records noise along the length of the conductor, allowing identification of “where in the cable length” the appreciable discharges are located. Tan-Delta (Dissipation Factor) measures and records the tangent angle of the entire cable length (test specimen).

Tan Delta Testing for Shielded Power Cable – What Is Tan δ, Or Tan Delta?

Tan Delta, also called Loss Angle or Dissipation Factor testing, is a diagnostic method of testing cables to determine the quality of the cable insulation. This is done to try to predict the remaining life expectancy and, in order to prioritize cable replacement and/or injection. It is also useful for determining what other tests may be worthwhile.

How Does It Work?

If the insulation of a cable is free from defects, like water trees, electrical trees, moisture and air pockets, etc., the cable approaches the properties of a perfect capacitor. It is very similar to a parallel plate capacitor with the conductor and the neutral being the two plates separated by the insulation material.

In a perfect capacitor, the voltage and current are phase shifted 90 degrees and the current through the insulation is capacitive. If there are impurities in the insulation, like those mentioned above, the resistance of the insulation decreases, resulting in an increase in resistive current through the insulation. It is no longer a perfect capacitor. The current and voltage will no longer be shifted 90 degrees. It will be something less than 90 degrees. The extent to which the phase shift is less than 90 degrees is indicative of the level of insulation contamination, hence quality/reliability. This “Loss Angle” is measured and analyzed. Below is a representation of a cable. The tangent of the angle δ is measured. This will indicate the level of resistance in the insulation. By measuring IR/IC (opposite over adjacent – the tangent), we can determine the quality of the cable insulation. In a perfect cable, the angle would be nearly zero. An increasing angle indicates an increase in the resistive current through the insulation, meaning contamination. The greater the angle, the worse the cable, as a system.


The overall power-factor test for cable insulation is confined largely to lengths of cable that come within the current limits of the Doble test set being used; however, regardless of the length of cable, Hot-Collar tests may be applied to all types of potheads.

Tabulations of power-factor data for cables are provided in the Cables and Accessories Section of the Doble Power Factor Test-Data Reference Book; valuable additional information is included in the Doble Reference Book on Cables and Accessories and in Doble Conference Minutes (refer to Indexes of Minutes). Some typical power-factor data for common cable-insulation systems is as follows:

Paper 0.5 to 1.0% @ 20°C
Cross-Linked Polyethylene 0.05 to 0.10% @ 20°C
Ethylene/Propylene Rubber 0.50 to 1.0% @ 20°C
Rubber (and Kerite) 3.0 to 5.0% @20°C
Varnished Cambric 4.0 to 8.0% @ 20

Note: Modern cable has a relatively flat power-factor versus temperature relation. The power factor of old cables made around 1920-1930 may increase more rapidly with increase in temperature.





Cables which do not have a metallic sheath or grounded shield but are installed in metallic conduit may have power factors somewhat higher than the values listed above and in the Doble Power-Factor Test-Data Reference Book.

Cables which do not have a metallic sheath or grounded shield and are installed in fiber or other forms of nonmetallic conduit may have normal power factors considerably higher than the values listed above because of the poor dielectric circuit to ground. Grounding adjacent cables will improve the dielectric circuit when testing cables of this type. Ungrounded-specimen tests between unshielded cables in the same conduit may be used to confine the test primarily to the cable insulation, excluding the duct material.

Tests performed with either the 2.5- or 10-kV Doble test sets will usually detect the presence of moisture in the cable insulation; however, multi-voltage tests (at least up to the line-to-neutral voltage) should be performed. “Tip-up” in power factor with increase in test potential is indicative of losses due to ionization. In general, cable that has a power factor noticeably above that of similar-type cables or an appreciable “tip-up” in power factor should be investigated for moisture and/or corona deterioration.

Results of the Hot-Collar tests (loss/current) are graded largely by comparison of data taken on similar type potheads. Abnormally high dielectric loss and current usually indicate the presence of moisture. Increases in losses with increased test potential indicate the presence of voids. Below-normal test currents indicate the absence of compound or oil.

Partial Discharge Testing for Shielded Power Cable

Wikipedia states:

Partial Discharge (PD) is a localized dielectric breakdown of a small portion of a solid or liquid electrical insulation system under high voltage stress. While a corona discharge is usually revealed by a relatively steady glow or brush discharge in air, partial discharges within an insulation system may or may not exhibit visible discharges, and discharge events tend to be more sporadic in nature than corona discharges.

IEEE states:

A partial discharge is an electrical discharge (formation of a streamer or arc) that does not bridge the entire space between two electrodes. The discharge may occur in a gas-filled void within the extruded cable insulation, at the interface between a shield protrusion and the insulation, at a shield skip, at the boundaries of a contaminant, or at the tip of a well-developed water tree when a cable is subjected to moderately high voltage. Partial discharges can also occur in a cable termination, in a joint, in air, or within a cable.

Partial discharge tests. There are several methods for detecting and measuring PD. Some methods involve de-energizing, disconnecting, and powering the cable from a special voltage source, while other methods allow the cable to remain energized at normal line voltage. Both methods will detect and measure partial discharge in Pico Coulombs (PC). The authors of the IEEE study on water trees state that electrical trees will likely progress to failure quickly, so PD testing would be more valuable if performed in conjunction with dissipation factor/power factor (DF/PF) testing. We will address On-Line Partial Discharge Diagnostic Testing only.




Of course, all Field Testing can be influenced by elevation, temperature and humidity.


Proper Asset Management should always employ trending over time of the Test activity.

The following IEEE Paper (significant NEETRAC influence) explains concisely.

Interpretation of dielectric loss data on service aged polyethylene based power cable systems using VLF test methods

The more targeted approach requires an assessment of the health of cable systems. It is increasingly common for the assessment of aged cable systems to be made through the application of diagnostic measurements. A recent study has shown that Very Low Frequency (VLF) Tan δ is the most commonly deployed cable system diagnostic. The practical use of this technique has been supported by the international standards IEEE Std. 400-2001 and IEEE Std. 400.2-2004. A key part of these standards is the guidance provided to a user that is detailed in the “Figures of Merit”.

These enable users to identify cable systems that are more likely to fail in service near term. To aid these decisions a series of criteria have been developed. The benefit of the criteria described here is that the process for their determination is rational, reproducible, and transparent. The outcomes are supported by a probabilistic assessment of service performance.

Published in: IEEE Transactions on Dielectrics and Electrical Insulation (Volume: 20, Issue: 5, Oct. 2013) Page(s): 1699 – 1711 Date of Publication: 21 October 2013
Print ISSN: 1070-9878 ; INSPEC Accession Number: 13849660
DOI: 10.1109/TDEI.2013.6633700
Publisher: IEEE; Sponsored by: IEEE Dielectrics and Electrical Insulation Society



References and Bibliography

IEEE Std 400-2012; Std 400.2-2013; Std 400.3-2006
IEEE Power Engineering Society; NEETRAC
EC&M Oct 2003
NETA World 2006
Doble Engineering
High Voltage Inc.

Repair or replace? The stakes are extremely high.

Knowledge Base

High Voltage Electrical Power Equipment Assets Condition-based Maintenance in Asset Management


Repair or replace? The stakes are extremely high when utilities pose the question about highly engineered products and expensive machinery that generate, transmit and distribute power to thousands, or even millions of people and businesses. As the industry continues to mature, how each utility approaches the “repair or replace question” is becoming a more crucial business practice specifically because it directly impacts the value of its assets and overall profitability of the utility in the short term – as well as into the future. Fortunately, there are effective business processes and tools to walk utilities through the question and reach that critical answer. This paper explores those business processes and tools along with the numerous factors utilities need to consider when answering the repair or replace question.

An age-old (and young) question

The repair or replace question, and how to best answer it, is coming to the forefront for utilities as their assets and employees age. “In many cases, you’re dealing with aging infrastructure, and you have the tribal knowledge walking out the door as well as new personnel coming in who don’t know the equipment,” said Mark McCloy, Senior Associate at Legacy Power Solutions LLC, Cincinnati, Ohio.

As more utility assets reach the end of their projected lifecycles, utilities will increasingly need to address the repair or replace question. The substantial post-World War II industrial boom meant significant growth in base infrastructure, especially electric utilities. Most of this equipment is now in the aging part of its lifecycle. “The average age of the equipment that utilities have out on the grid is about 40 years old,” said Chris Brown, Group Leader of Substation Asset Management, Transmission Substations for LGE-KU a PPL Company. “A lot of assets out there are 50, 60 years old.”

For example, according to the U.S. Commerce Department, the utility industry reached a peak in new U.S. transformer installations around 1973. At that time, the United States added about 185 GVA of power transformers. Today, that equipment is about 37 years old. With lower capital spending on new or replacement transformers, the average age of the U.S. transformer fleet continues to increase. (As does the load as new is deferred)

So the repair or replace question is coming up more often with aging assets, but answering that question is becoming increasingly complex with an aging workforce and the struggle to attract younger employees to the utility industry. You’ve likely heard it before, but the United States is home to an aging population and the utility industry is no exception. In fact, according to the U.S Bureau of Labor Statistics, the 2009 median age of utility industry employees is 45 years old, or about 7.5 percent higher than the median age for all employed people in the United States. The utility industry is facing the loss of some it’s most experienced and knowledgeable employees.

At the same time, on top of utility struggles to attract younger workers, these younger workers just don’t have the same level of knowledge about utility assets as their more experienced counterparts. “Sometimes they see the risks of exposure to equipment, so they don’t get near it. They may say, ‘I’m not working on that stuff,’” said McCloy. With experienced personnel leaving the industry and fewer young employees coming onboard, utilities must have effective methods in place to address the repair or replace question with a smaller, less experienced workforce.


Other complexities

On top of age issues, other complexities push utilities to look at the repair or replace question more closely. These complexities include:

  • Cost of failures: With an increasingly digital and subsequently electricity dependent economy, the economic costs associated with outages are important. For example, Lawrence Berkeley National Laboratory estimates that electric power outages and blackouts cost the United States about $80 billion annually. How much downtime can utilities and the economy afford?
  • Ability to build new infrastructure: With the greenhouse gas (GHG) pressures impacting new generation and the increasing difficulty of siting new transmission infrastructure, utilities are facing challenges with building new assets. This means that utilities will have to use existing infrastructure to its fullest.
  • Changing customer needs and demands: Despite the current economy, demand for electricity will continue to increase in the coming years. Customer expectations and needs for energy are changing, which could significantly impact today’s infrastructure. For example, what will happen when millions of electric vehicles hit the road? Will today’s infrastructure be able to handle those changes in demand?

Key factors in the repair or replace decision

When faced with these many factors, utilities must develop more sophisticated business processes and tools to better maintain existing assets and prioritize new asset investments. The traditional “rip and replace” approach will no longer work for most assets, whether transformers, medium voltage switchgear, high voltage breakers, or a host of newer technologies coming on line. Before discussing these more sophisticated approaches, it is important to examine some of the factors to consider when answering the repair or replace question.

Risk, reliability and cost

No matter what the asset, its assessment should account for the fundamentals of risk, reliability and cost. The first two factors, risk and reliability, go hand-in-hand according to Brown. “What is the risk if you don’t maintain it properly? You’ll eventually have a failure and you’ll have a problem,” he said. “It could cost much more than a planned replacement, especially if it is a catastrophic failure. It may also mean that customers are going to have an outage,” which ultimately impacts the reliability of a utility’s network. Then there is cost. Key cost considerations, according to Brown, include:

  • Deferred maintenance. “Let’s say you’re supposed to do maintenance every five years, but decide to implement a Condition based Maintenance Program,” Brown said. “A company will now apply their Maintenance dollars, and in fact stretch it, by applying intelligent operating and maintenance data and formulating it into Operating and Performance intelligence; minimizing risk and investing into critical equipment application and performance.”
  • Capital or operations and maintenance expense. “Typically if utilities get a new piece of equipment they would capitalize it, and then it only ends up costing them a certain percentage of that per year over whatever period of time they capitalize it,” he said. “They would like to capitalize that cost if they can, because it spreads it out over a longer period of time. If it’s expense money, the wiser we invest it, the better. So you spend within budget and enhance the shareholders equity. There are new modern options to live within budget and still maintain a sound system for customers.”
  • Replace or maintain. “The other approach from a cost standpoint is to say, ‘this piece of equipment is getting pretty old, do I replace it? Do I continue to maintain it or, could I in fact upgrade it to something that is even better in terms of ratings than what we have?’” said Brown. “A lot of the equipment that might be 20, 30, 40 years old is fundamentally very sound, and it could be rebuilt at a lower cost than replacing it, and essentially have a new life in front of it. So utilities have that option to rebuild breakers or rewind a transformer with new insulation that could last another 30 years or so, just like a new unit should.”

On top of these fundamental factors, there are numerous other factors to consider when looking at whether you should repair or replace an asset. Such factors include:

  • What is the criticality of this circuit and associated assets?
  • What System Ratings and Performance need to be considered?
  • What is the length of time that the asset will be out of service?
  • What is the availability of replacement parts?
  • What safety issues are involved?

With the length of time out of service, it is important to consider how much time it would take to replace an asset versus upgrading or repairing it. “If you take an asset that is 40 to 50 years old and replace it, how many days can you afford to take it offline?” said McCloy in reference to switchgear. “It could take weeks or even months, which means lost revenue streams. Upgrading an asset could take it down for just hours.” On the transformer side, Kenneth Hill, Senior Engineer, Distribution Substation at KU, a PPL company; pointed out that “with a failure, the lead time can be 15 to 18 months for a new transformer, whereas a remanufacture could run just 12 – 16 weeks.”

At the same time, a repair may be faster than a replacement, but what if the asset is so old that parts are obsolete and that performance has become an issue? “Sometimes the repair of older breakers is not a viable option,” said McCloy. “It’s not so much the parts availability, but the “system” needs and requirements in the form of higher interrupting ratings or faster clearing times; the change-out/replacing of older Oil Circuit Breakers with new SF6 Puffer Breakers are being performed on wholesale levels amongst utilities nationwide at this time.”

On top of reliability and replacement equipment concerns, safety upgrades also need to be considered. “You may not be able to replace switchgear, but you can upgrade the safety of it,” McCloy said. “You can’t completely eliminate safety risks, but you can take action to upgrade the safety of that equipment, such as Arc Resistant designs with Remote Racking operations”.

How do you make these decisions?

So far, we’ve discussed numerous factors to consider with the repair or replace question, but what other factors do you need to consider? In what order should you consider these factors? And which factors should you consider for each type of asset? We’ve discussed the “what” of the repair and replace question, so now let’s look at the “how” of addressing the question and the factors that feed into it. The how requires more sophisticated business processes and tools that utilities can use to help them effectively answer the repair or replace question. These business processes and tools first look broadly at a utility’s asset fleet to prioritize asset investment and maintenance needs, and then focus in on prescriptive approaches for specific assets.

A holistic approach: Fleet assessment

Determining whether to repair or replace an asset starts with looking beyond the individual asset. With only so much funding to go around for maintenance and investment, utilities must first step back to prioritize where funding will provide the most value. For example, according to Brown, if utilities spend the same maintenance dollars for each transformer, “when 90 percent of the transformers are fine, they may be overspending on healthy assets. With the 10 percent that actually have problems, they are neglecting those transformers. Companies should be putting more dollars into that 10 percent and getting a better return; thus the development and implementation of a holistic, Condition/Performance-based maintenance Program versus the old, time-based approach.

Maintaining assets at regular intervals, regardless of their condition has become an unattainable and untenable approach. Traditional time-based maintenance techniques rely on the failure occurring in a statistically predictable fashion, but predicting failure is difficult. A multi-year study of various complex machines completed by the airline industry showed that only 11 percent of failures fell within a definite “wear out” period and 89 percent of failures occurred randomly. Ultimately, since most failures of complex machines occur in a random manner, companies cannot accurately predict them using statistical failure data alone. Therefore, whether in the airline or utility industry, companies must understand the actual condition of each asset; applying, implementing and incorporating significant data into useful operational and performance INFORMATION to guide critical maintenance guidelines, scopes and timeframes PLUS critical Capital Asset replacement and upgrade purchases.

Identical assets can vary health-wise based upon their maintenance, operation and environment. “We manage the life of a transformer dependent on how hard we run them and how well we maintain them,” said Hill at KU. “Think about the analogy of an old lady who just drives her car to church. Her car may be 40 years old, but it looks brand new.” Environment can also play a significant role. Assets facing harsher environments whether more heat, salt or storms, for example typically fare worse than the same asset in a less harsh environment.

On top of asset operation and maintenance, design can impact an asset’s longevity. As Brown noted, “design and age of the design has some influence on how long an asset will last. Like humans with good DNA and bad DNA, you can have really good designs and not so good designs.”

Another factor that can vary between assets is their criticality. For example, in the case of high voltage breakers, McCloy recommends that utilities “look at where their critical points are on the system. In many cases, we’re talking about breakers in key transmission substations that feed critical loads or breakers outside of power plants.”

Given the varying conditions and criticalities of assets, a fleet assessment is a process and tool that can determine the health and longevity of individual assets, and then use that information to prioritize investments across a group of assets. According to Brown, this involves inspecting “all or a percentage of equipment a utility has, if they are concerned that some equipment is at risk. A fleet assessment can determine what needs to be done and how quickly. It helps companies prioritize how to spend money and ensures people focus spending where it needs to be focused.”

Getting specific: Condition-based maintenance

Once utilities undertake a fleet assessment, they can then drill down and focus on individual assets and their needs. Brown likened this approach to a doctor’s assessment and treatment plan. “It is like a company that is concerned about their key management,” he said. “The company may offer annual assessments for these employees, where a doctor does a complete workup, looking at things like blood samples and EKGs. One person may have a heart problem and would be put on a specific prescription or health regimen, but that plan won’t apply to all managers.”

As mentioned earlier, time-based maintenance approach has proven inadequate for determining cost- effective maintenance for individual assets. Monitoring an asset through condition-based maintenance processes will enable companies to assess each asset’s individual health and develop appropriate diagnosis and treatment plans. This approach will also assist utilities with reaching critical maintenance, repair and replace decisions. To better illustrate how the condition-based approach and decision-making process can help companies answer the repair or replace question, the following table points out key considerations for three assets: high voltage breakers, low voltage and medium voltage switchgear, and transformers.

The first two considerations in this table can help utilities understand and state the problem impacting an asset:

  1. Key data points. Different assets have different health indicators. In the case of transformers it may be oil temperature, but for breakers it may be number of operations and faults. For each data point, there may be multiple values to track. For example, companies should pay attention to both high and low operation numbers with breakers. If a high voltage breaker doesn’t operate that much and sits in a static state, its seals will be exposed to more pressure on one side versus the other, which can lead to uneven wear and potential problems.  Bearing lubrication is not dispersed and operating linkages will tend to freeze up causing a slow or inoperable breaker.
  2. Determine the optimum repair/replace window. This is certainly not an exact science, but it comes back to understanding the key data points and what data values indicate a potential problem. By under- standing these values for each asset, it can help a utility identify which assets are at a greater risk of failure and enable the utility to take action.

Once a problem has been identified, the next considerations help utilities take the proper steps toward finding a solution for the identified problem.

Table: Key considerations for utility assets


Repair vs. replace: As the table demonstrates, the cost and complexity of addressing the repair or replace question depends upon an asset’s size, type, age and application. However, when looking at the repair or replace decision for a variety of assets, Brown, Hill and McCloy agreed that companies should consider today’s advanced, condition-based maintenance practices and programs. An intelligent, pro-active maintenance program can defer the more costly repair or replace question for many years.

Long-term maintenance needs: Whether utilities decide, to maintain, repair or replace, they can expect some variation with ongoing maintenance. A key factor here is design differences between new and old equipment. Newer or upgraded equipment may be designed with fewer moving parts and lower maintenance technologies, so they may not require as much ongoing care as equipment made with older technologies.


  • Every company and every asset is different and there are many different factors influencing how best to approach the repair or replace question. As noted, questions could include:
  • What “System” design or demand changes have been implemented and what affect has there been on your current Equipment Performance and Ratings requirements?
  • Will today’s infrastructure be able to handle projected or anticipated future changes in system demand or performance?
  • What is the length of time that the asset will be out of service?
  • What safety issues are involved?
  • A repair may be faster than a replacement, but what if the asset is so old that parts aren’t readily available?
  • Is your Company truly “vested” in an intelligent, condition-based, asset management Program and are the results truly being captured and acted upon?
  • Capital versus Operations & Maintenance budget considerations?

When facing such questions, utilities should seek out tools and business processes that first look broadly at a utility’s asset fleet to prioritize asset investment and maintenance needs, and then focus in on prescriptive approaches for specific assets. These tools and business processes will ultimately enable utilities to prioritize asset maintenance and investment needs, identify asset problems, determine the appropriate action to address those problems, and successfully address the repair or replace question.

Mark S. McCloy
Legacy Power Solutions 2017

Contributors include:

Energy Central
LGE-KU, a PPL Company

WHITE PAPER: EPC Switchgear Specialists deliver significant savings in time and money

Engineering, Procurement & Construction Services for Medium Voltage Metal-Clad Switchgear Replacement


“EPC Switchgear Specialists deliver significant savings in time and money”




This Paper will address new Project Engineering, management and execution choices in today’s specialized services business environment. Furthermore, we will touch upon new manufacturing technologies and the decision-making process for the replacement of installed, medium-voltage (2400V through 38kV), metal-clad switchgear and circuit breakers in a draw-out construction; relative to electrical power distribution systems typically found at utility power plants, Industrial and Manufacturing facilities.

The combination of the aging of this critical infrastructure equipment and the addition of new equipment and systems, on the service bus, causing increased power loading on the electrical distribution system is addressed. More importantly the safety, operational, compliance and environmental aspects brought on by NERC/FERC, OSHA/NFPA and EPA regulatory pressures have motivated many Owners to budget and Plan for the replacement of this original, medium-voltage, metal-clad switchgear equipment.

Furthermore, we will address safety compliance, environmental issues, technical specifics and project management decisions that can positively affect your Companies’ approach to a cost-effective remedy in replacing this existing, aged, Draw-out, metal-clad switchgear via a unique, engineered adaptation of new, Arc Resistant gear into existing systems with minimal impact on existing primary and secondary connections. Safety Hazards, reliability/Performance, Compliance and Environmental issues include the integrity and compliance of equipment performance and Operator exposure during Racking Operations which include NFPA 70E Arc Flash compliance; equipment reliability performance during the Racking Process; Exposure to asbestos (EPA) during Maintenance and Inspections on air-magnetic circuit breakers; Short Circuit Fault clearing capabilities and conditions affecting the integrity of the switchgear bus system, circuit breakers and overall electrical distribution system integrity and compliance. The engineering standard technical basis will rely upon ANSI accredited IEEE C37.20.7 for Type 2C arc-resistant switchgear.

Achieving these aforementioned goals with Cost-Savings and Project Timely Completion – EFFICIENCIES – are featured and defined.


The profile basis of this Paper will be electric utility, coal-fired power plants (250+MW); Auxiliary Unit 4kV Switchgear with (17) bays; the Owner is significantly concerned with the following:

Operator/Electrician’s direct exposure to Arc Flash energies during the Racking Process
The operational integrity and reliability of the Racking System components
The increase Loading on the Service Bus due to the addition of motors and distribution panels installed for previous emissions control equipment and the (in)ability for the existing circuit breakers to clear a short-circuit Fault condition
Spare parts and existing sub-assemblies’ operational integrity and reliability
Potential exposure to friable asbestos to their Electricians and Maintenance personnel when performing Inspections, testing and maintenance on their air-magnetic circuit breakers


Significant utility generating units’ often have system outage windows of four (4) to five (5) weeks. Typically, not enough time to complete any significant construction project or major equipment replacement. Setting aside appreciably more outage time can cost appreciably more money. Traditional tactics would include multiple decisions and significant planning – all which would require key Plant and/or Corporate resources. Critical issues such as the writing of equipment and installation Specifications or contracting of an Architectural & Engineering Firm; decide and determine the A&E’s Project Management Role; will the A&E hire and manage the General Contractor; the Electrical Contractor; the Third-Party Testing/Commissioning Company, and the equipment Manufacturer? As the Owner, the decision whether to pre-purchase all major Capital Equipment Assets is important, as well as managing the inter-action and planning between Plant Site personnel and any Contractor(s).

Other, traditional “wholesale” approaches incorporate the “demolition” of this type of equipment in a brute-force, tear-it-out manner. Without the deliberate, engineering evaluation conducted by Specialists and shared with the Owner; tremendous cost-efficiencies are not only overlooked – but additional, significant costs are piled-on needlessly. Economies of scale can be realized through project completion (time) and significant cost savings (dollars).

Major unit outages can run twenty-four (24) weeks or more; but are targeted for major Equipment Replacement/Restoration such as Turbine Generators, Boilers, etc. A concurrent, significant Asset Replacement would represent unique logistical challenges that are better off avoided.

All-the-while the Plant Operators and Electricians continue to be faced with significant safety, operational and compliance issues and the Plant/Corporate Engineer watches the system loading capacity dwindle.


The introductions of new technologies, such as vacuum bottles as the interrupting medium in medium-voltage circuit breakers, have delivered significant improvements to the operations, reliability and safety in today’s medium-voltage switchgear and circuit breakers. Furthermore, the application of Standards in Designs, such as Horizontal Racking Operations and Remote Racking Designs has dramatically improved Safety and Reliability. The latest improvement is the design and construction of Type 2 Arc Resistant Switchgear; providing an appreciable, “first-line” defense and control of arc flash energy potential within the switchgear System.

Recent, past methods and considerations represented a mere “band-aid” to these mounting challenges. Replacement Doors, Roll-In Replacement Circuit Breakers, Remote Racking systems and “fast-acting” Instantaneous Relays reflect a piece-meal approach which never fully addresses all of the issues. Put all of these “components” together and design them into Type 2 Arc Resistant Switchgear structure – now you have the complete, engineered Equipment Package.

Project Management and execution; utilizing a single-point of contact via an Engineer, Procure and Construct (EPC) Company can provide Project efficiencies. Consideration to taking the EPC concept a step further will produce greater efficiencies. Combining the engineering, procurement, project management and overall project resources of a traditional EPC with the experience, knowledge and laser-focus of a Switchgear Specialist, would be a combination that could deliver tremendous results. EPC Switchgear Specialist represents the complete Service Provider Package high-level Solution.


Basis Installation – Unit 1 and the existing, indoor switchgear (Bus 1B) with (17) Compartments and (15) 4160V; air-magnetic, draw-out circuit breakers with stored-energy mechanisms; traditional switchgear construction with metal doors, mounted Relays, Indicating lights, analog gauges, SB switch, external control circuit fuse block and door hasp/handle.

EPC Switchgear Specialist refers to only one Company, one point of contact, one Project Team, and “one Engineer of Record”. There are no layers of authority and organizations that bog down the decision-making process, impede Project expediency or accumulate field change orders – a significant economy of scale.

Design Review process begins by reviewing the Plants’ existing, installed equipment Drawings, Prints, Diagrams, Schematics, and Elevations. Key areas and issues are identified; approaches, methods and solutions are designed into the Project. New, Arc Resistant Switchgear manufacturing detail is then superimposed or redlined onto the existing detailed drawings; the complete recreation onto AutoCad (or equal) provides the first draft of “As Built” drawings. Confirmation is acquired through the detail review and thorough evaluation by EPC and Owner’s Project and Staff Engineering. Often, the Manufacturer is invited to assist in the melding of the new equipment detail into the existing Plant facilities. It is not uncommon to find 5kV class Service Bus to become overloaded due to emission controls and monitoring equipment and now, Engineering Fault and Load Studies uncover the need for 350MVA Rated circuit breakers and Service Bus. Additionally, system condition monitoring via metering and communications is asked for; zone isolation for fast acting Trips for maintenance and Protection schemes are being asked for.

Planning, scheduling and construction review process employs the Owner’s Project Team, Project Engineer and Plant Representative(s); and the EPC Switchgear Specialist Team which would include the Safety Director, Project Engineer, Project Manager, Field Supervisor, Material Manager and Manufacturers’ conformance representative.

New Type 2C Arc Resistant Switchgear is proposed per ANSI/IEEE C37.20 engineering standards. Type 2C Switchgear is widely considered to be the safest solution on the market to ensure personnel and property safety in the event of a fault and ensuing arc flash. In the event of an arc flash, Type 2 Switchgear is designed with a plenum at the top of the equipment to direct all energy away from the Operator/Personnel exposure Area; isolating damage to the faulted compartment only. All gases, ionized copper, panel debris and projectiles are funneled up and away – to a safe area.

This Type 2C Arc Resistant Switchgear will be manufactured to the exact footprint of the existing switchgear; confirmed through Drawing and Elevation Review and by double-checking the integrity of the Drawings versus Installation through a detailed and thorough Site visit at the Plant during the Design Review process. Another very important aspect of the Design Review at the Plant Site will include detailed Inspection of all power cable and accessories. This process will insure the integrity of the existing power cable system and the determination of accessory integrity such as terminations, lightening arrestors, ground/shield conductors and connections – the overall ability of the power cable system to be reconnected in an expedient manner with no compromise to the performance integrity of the existing power cable system. This approach shall eliminate the risk of inflicting any damage to the existing power cable system during the Project and assure the operational integrity after re-connection. Eliminating the need of replacing, splicing, bending and stretching NEW or existing power cable systems, including cable tray, duct and piping provides significant COST and TIME savings and efficiencies during the course of a Project of this magnitude.

The project schedule has been designed to allow ample time to complete all tasks within a four (4) week outage window. EPC will staff the onsite project work with ample personnel to complete the installation and commissioning. All personnel shall be safety trained to Client requirements and directed by an on-site EPC Project Manager via Owner/Project Manager with extensive background in similar project scopes. EPC will require a long track record of performing similar scope projects with other Investor Owned Utility Power Plants, Industrials and Manufacturing Facilities.


EPC Switchgear Specialist Project Team members will conduct all required Owner Safety and Access Training and Certifications. Engineers and service technicians possess the skills and knowledge to safely test, evaluate, service and recondition electrical apparatus. Employees are Drug Free and OSHA safety trained. Any analysis and engineering recommendations will be provided by a State Certified Professional Engineer, electrical engineer.

Site specific Construction labor will be staffed by EPC Switchgear Specialist directly employed engineers, project managers and technicians during the course of this project, unless approved otherwise by Owner.

Concrete foundations appear to be able to be reused in their current condition.

The installation is based upon reusing all load side conductors. If cable is to be supplied, spliced or routed additional material and work scope will apply. Design objectives allow all cables to match up to the new sections with no modifications. Terminations are assumed to be reused, no termination kits are supplied. Applicable control wiring cabling systems can be minimally modified or affected without performance integrity compromise.

Field Function testing of the relays and breakers is included in this scope.

Field Engineering and Field Project Management are included in the Field Technical Services breakout documents. Design Engineering is represented in the Engineering breakout documents.

All mains and feeders will be circuit breakers.

EPC will include the Owner provided coordination and system modeling and curves with Power Analytics (or approved equal) software. Only the protective relays that are provided as part of this proposal are included. EPC will coordinate the relays supplied with their corresponding upstream protective devices and downstream protected loads. This service will be provided according to Client Standards. Client will provide all existing information available to direct (assist) in this modeling.

EPC will supply all project schedules utilizing a mutually agreed upon Project Management software package.


Compartment structures, cell structures, plenums, circuit breakers, doors, devices, bus systems, sensors and associated components will be inspected, pre-tested, pre-assembled and organized into a “kit” format previous to shipment to the Site. This process will be made available for Witness Inspection and Review to the Owner.

All Assemblies, systems and components will be Witness Inspected and Tested (again) at the Site; component level and System Assembled.

All engineering data shall show equipment as specified and ordered. Engineering data, as listed below, shall be supplied electronically as listed:

  • Master Drawing Index
  • System single line drawing
  • Section view drawing
  • 3-phase elementary
  • Schematic diagrams
  • Nameplate drawing
  • Instrument layout
  • Bills of material
  • Acceptance testing documents and reports
  • Final relay setting files will be provided in documentation package; based upon existing Protective Device Settings or as provided by the Owner

Drawing Requirements

  • AutoCAD Version 2007 or greater supplied for all drawings.
  • Electronic drawing PDF format files for approval shall be supplied.
  • Structural Drawings, with critical dimensions, showing:
    • Arrangement.
    • Plan, front view, and elevation section views.
    • Required clearances for opening doors and for removing breakers.
    • Bus Duct connection diagrams for main breakers and tie breakers.
    • Incoming and outgoing power cable terminator positions.
    • Grounding connections.
    • Weight of equipment.

Drawings shall indicate all equipment, but only such equipment, as is actually in the scope of supply. All user connection and interface points shall be clearly marked, including primary and secondary cable entrances and connection points, installation details, generic interframe assembly and generic connection details for shipping splits.

Elementary Three-Line and One-Line Diagrams

  • Three line diagrams, with ANSI device function numbers used throughout, shall show all:
    • Instrument transformers.
    • Relays.
    • Meters and meter switches.
    • Breakers and other pertinent devices.
  • One line diagram(s), showing overall Power System, predicated on existing, accurate Power System One-Line.

Schematic Diagrams

  • Schematic diagrams shall be furnished for the electrically operated breaker / relay control scheme.
  • Each schematic diagram shall show all control devices and device contact, each of which shall be labeled with its proper ANSI device function number.
  • Each schematic diagram shall show device and terminal block terminal numbers for customer connections.
  • Provide control switch development tables.
  • Detailed Connection (Wiring) Diagrams showing, submitted for record only:
  • Approximate physical location of all items in each unit.
  • All wiring within each unit.
  • All interconnecting wiring between units.
  • Identification of all terminals, terminal blocks, and wires.
  • Provide one set of drawings shipped with the equipment for start-up use.


  • Safety
  • Reliability
  • Compliance
  • Savings


Employee and Operations achievements are delivered NOW. Providing worker Safety should not wait; Arc Resistant Switchgear Replacement by an EPC Switchgear Specialist can be budgeted, planned and executed without delay without any excuses. NFPA and OSHA Safety issues relative to medium-voltage switchgear are eliminated. System Reliability improvements via new technologies; Type 2 Arc Resistant Switchgear; Vacuum Bottle Interrupters; Intelligent Electrical Devices/Relays communicate system conditions and coordinate Protection, Control and Communications. Regulatory Compliance issues are completed, installed and on-line. Environmentally, all asbestos arc-chutes will be disposed of. NERC/FERC Compliance requirements – now and in the future – are met. Significant Cost Savings are realized utilizing a single, laser-focused Partner in an EPC Switchgear Specialist. Extensive Planning; Speed in Design Review and Scheduling; Speed in the Decision-Making process; Speed of Execution / Installation – all without COMPROMISE – equals significant COST SAVINGS.


Today’s Utility Power Plants, Industrial and Manufacturing Facilities are faced with a barrage of significant regulatory, safety, environmental, operational and technological pressures to keep their Plants and Facilities safe and cost efficient. As technologies and systems advance, so do the Project Management, Engineering and Service Providers – as Specialists. Leveraging Specialists, as partners, assures that your Company maintains a leadership position in safety, compliance and leading-edge technologies in the most cost-effective manner possible.