OIL TESTING HISTORY Foreword by Corné Dames, Associate Editor in Chief Did you choose the correct oil for your transformer application? This is the one big question I am confronted with after reading through this outstanding article written by the three authors, Lance Lewand, Eileen Finnan, and Melissa Carmine-Zajac. All of them are highly respected in the industry. Interesting to see the long road oil analysis has come and the progress that has been made in the transformer oil industry, to ensure a high-quality product fit for a specific purpose. The criteria are set out to guide us to evaluate the insulating fluid when considering a fit candidate for lifetime optimization and reliability. William Stanley’s invention of the commercial transformer in 1886 and his subsequent AC electrification of Great Barrington, Massachusetts in that same year [1], pioneered the development of commercially viable electrical distribution systems. The first transformers were dry types using insulation made of cambric cloth and other cotton materials. In order to achieve higher voltages a better insulating medium was needed, and as early as 1887 [2] paraffinic mineral oil along with cotton-based materials were used to form the insulation system of early transformers. Although plentiful, early paraffinic oils would often solidify near temperatures of 4°C or lower, causing retention of heat in the windings [3] that eventually led to failure. As a result, naphthenic oils with naturally occurring low pour points became the insulating oil of choice in the early 20th century – and is still the majority of what it is used today in most countries. Oxidation of transformer mineral insulating oils occurs over time, at a rate that is dependent on the composition of the fluid and the conditions to which it is exposed while in service, such as temperature, oxygen and catalysts. Mineral oil filled transformers in the early 20th century were free breathing, which allowed a constant oxygen supply. Coupled with the poor refining practices of the time, which was a simple distillation cut of the crude that resulted in oils that were oxidatively unstable, the mineral oils in service tended to sludge and polymerize. This often resulted in solid terminal byproducts that had to be physically removed from the transformer with shovels. This caused operational headaches for utilities in that many transformer maintenance activities were engaged in to remediate oil issues. As a result, there was a need to develop tests that could determine the quality and oxidative stability of the oil.  In 1898, ASTM was formed as a forum to help industry leaders develop test methods for a variety of products including crude oil. ASTM committee D02 (then called committee N), founded in 1904 [4], was the first committee to take on the responsibility of establishing test methods for crude oil from which transformer mineral oil is refined. For some, oil is an after-thought, just another component that comes with the transformer. But oil plays a vital role as one of two main elements of the insulation system of the transformer. The very first methods did not come into existence until the decade between 1910 and 1920 and were limited to the evaluation of mostly physical characteristics; they did not address oil quality or oxidation stability. It wasn’t until the 1940s through the 1960s that oil quality and oxidation tests were established for use. In the 1950s, the ASTM D27 Committee on Insulating Fluids was established and split out of D02, and serves as the committee that produces standards for specifying, sampling and testing of insulating fluids.   Oil serves as an important heat dissipation medium hence the makeup of the oil is crucial to proper and safe operation. Poor quality or improper application can result in a host of issues, such as corrosive sulfur attack or gasket incompatibility, many of which can result in failure. Nevertheless, the problem of oxidation of transformer oils was recognized early. In 1921, Dr. Van H. Manning authored a paper entitled “The Pioneer’s Field in Petroleum Research”. In that paper, Dr. Manning listed issues to be addressed in the petroleum industry, one of which was the prevention of oxidation of mineral oils in transformers [5]. In June 1923, the Massachusetts Institute of Technology (MIT) began a research study of the mechanism of the oxidation of mineral oils and of the action of negative catalysts (inhibitors) [6]. Inhibitors were known to bind with free radicals thus terminating the propagation process of oxidation. A year later in 1924, 177 substances were tested for anti-oxygenic protection of transformer oil, and 48 appeared to have inhibitory properties. Additional investigations were undertaken both in the United States and other parts of the world which identified other possible materials that could suppress oxidation [6]. Researchers in Russia [7,8], France [9] and England were embarking on a similar path at about the same time. However, those were not the only issues to overcome. Viscosity was a well-known factor that dictated the ability of the oil to dissipate heat from the windings and thus oils with lower viscosities became desirable. Corrosive sulfur was another issue of concern with oils at the time as it caused corrosion of the copper and silver components it was in contact with, leading to failure of the transformer. Probably one of the most overlooked issues, which is still persistent today, is the interaction of the oil with the materials of construction of transformers, including gaskets, coatings, paints and other materials. The effects were a mutual problem with the oil causing the components to degrade, which resulted in leached material from the components contaminating the oil leading to compromised chemical, electrical and physical properties. For some, oil is an after-thought, just another component that comes with the transformer, but it plays a vital role as one of two main elements of the insulation system (the other being the cellulosic insulation) of the apparatus and it further serves as an important heat dissipation medium. Hence the makeup of the oil is crucial to proper and safe operation. Poor quality or improper application can result in a host of issues, such as corrosive sulfur attack or gasket incompatibility, many of which can result in failure, and so it must be selected with care and diligence. And once selected, the oil needs to be monitored over the life of the apparatus, not only to ensure the oil quality is maintained so it can continue to serve its intended purpose, but also as a means of evaluating the operation of the transformer itself, through diagnostic tests such as dissolved gas-in-oil analysis (DGA), and the condition of the other main insulating component – paper, through such chemical markers in the oil as furanic compounds and alcohols. As a result, standards were devised and published to ensure transformer oils meet certain minimum characteristics. These standards and the tests that comprise them can be used to compare products and to evaluate the consistency of a product from year to year. Probably one of the most overlooked issues, which is still persistent today, is the interaction of the oil with the materials of construction of transformers, including gaskets, coatings, paints and other materials. One of the earliest specifications was the Canadian standard CSA-C50 [10] published in 1938, but it was not until 1961 that Doble Engineering company published a truly comprehensive standard called “Transformer Oil Purchase Specification (TOPs)” [11]. Other major specifications for new mineral insulating oils, ASTM D3487 [12] and IEC 60296 [13], were not published until the 1970s. All of these standards undergo regular revisions and are still published today and have many tests in common, but there are distinct and important differences. Thus, the user must be able to navigate these specifications, understand the significance of the tests, and decide which is most suitable for a given application. Detailed oil specifications should be part of new transformer specifications and the product delivered should be tested to verify specifications are indeed satisfied. Any purchase of oil should have the same specifications met to ensure only compatible products that meet standards are introduced into the transformer during its lifetime. A good product and a consistently refined product are of ultimate importance. Evaluating oil to these published standards can help ensure such a product is selected. Detailed oil specifications should be part of new transformer specifications and the product delivered should be tested to verify specifications are indeed satisfied. Any purchase of oil should have the same specifications met to ensure only compatible products that meet standards are introduced into the transformer during its lifetime. A good product provides the right mix of electrical characteristics required by the insulation system, the lack of corrosive sulfur (responsible for attacking the copper and silver in transformers and causing copper sulfide deposition in the paper), good oxidation characteristics so the oil lasts the lifetime of the apparatus without sludging or degrading rapidly, and appropriate flow characteristic (as defined by pour point and viscosity) for operation in the intended climate and to meet heat dissipation needs. In addition, it is important to assess the actual chemical makeup of the oil as this has an impact on compatibility with other materials of construction in the transformer. For example, if a user decides to change out a high aromatic oil with a low aromatic oil, the gaskets will contract, and leaks will develop which can be costly to remedy. Knowledge of additives is another important factor to consider and a good product should have nothing added that has not been mutually agreed on with provider and end user. Most modern specifications include a limit for furanic compounds, oil-soluble compounds used as an indirect measure of the condition of the cellulosic insulation in a transformer. 2-furfual is the main compound used for diagnostic purposes, but it can also be used in refining of transformer oil during a solvent extraction process. If not properly removed prior to use, it may lead to an incorrect evaluation of the cellulose insulation as indications of overheated or aged paper insulation in a transformer. Specifications should also contain any other specific requirements. For example, applications such as cables, bushings and some transformers, may require the use of a negative gassing tendency oil. For those that purchase transformers and other apparatus outside of their home country, knowledge of international standards and products is very important. The apparatus will contain residual oil from factory testing or depending on the size, may come fully filled. Knowing which oil product was used along with the qualities of that oil is essential in making sure no unwanted oil characteristics are transferred over to the new electrical apparatus. For transformers, approximately 7% to 10% of the factory test oil remains in the apparatus when drained after factory testing is completed, and if this retained oil is problematic, it can be enough to contaminate acceptable new oil used to fill the apparatus during commissioning. From 2001 to 2007, this very scenario played out and caused severe, to the point of failure, corrosive sulfur contamination in new apparatus around the world.  In these cases, the original test oil used at the factory was corrosive or in some cases was provided for commissioning on site as part of a turnkey project. These incidents highlight the importance of specifications containing test methods and limits that are rigorous enough to ensure suitable product is provided. Additionally, a detailed and comprehensive oil specification must be a part of the purchase process for transformers and updated on a regular basis. Oils come from different crude sources which are processed using a variety of refining methods, so the chemical makeup of the end products will differ even though all may meet the same functional specification. Identifying changes in delivered product is easier when one with consistent properties is used. Along with satisfying specifications, consistency of product should be considered. Oils come from different crude sources which are processed using a variety of refining methods, so the chemical makeup of the end products will differ even though all may meet the same functional specification. Identifying changes in delivered product is easier when one with consistent properties is used. It should also be noted that the chemical makeup of an oil can also impact gas formation under certain conditions; Dissolved Gas Analysis (DGA) is widely used as a diagnostic tool and knowing how an oil behaves in the equipment on a system from year to year can eliminate an unknown when diagnosing potential issues. Specification testing of oil products can be undertaken periodically to monitor consistency. Oil surveys of transformer oils are available where oil products are compared year-to-year and results tracked. Doble Engineering Company has been performing such surveys either semi-annually or annually since 1953. In the early days, reports were specific for oxidation tests only, as that was the main issue at that time. Current testing is much more comprehensive with 30+ tests being incorporated and provides the user with a detailed analysis for each of the submitted oils. Oils are solicited from refiners around the world and then tested to Doble TOPS and ASTM D3487 specifications and the data along with the analysis of that data is then published. Utilities have used the report as the primary selection criteria of the oils to be considered for purchase. In conclusion, insulating mineral oils should be selected on a quality basis, the ability to withstand oxidation, the characteristics which are needed and overall consistency of a product from year to year. Detailed oil and transformer specifications should be used to ensure suitable quality product is provided. References [1] Laurence A. Hawkins, William Stanley (1858 – 1916) – His Life and Work, The Newcomen Society in North America, New York, 1951 [2] H.R. Sheppard, “Century of Progress in Electrical Insulation 1886 – 1986,” IEEE Electrical Insulation Magazine, Sept. 1986, Vol. 2, Issue 5, pp. 20-30 [3] George A. Von Fuchs, “Performance of Inhibited Transformer Oils,” ASTM Symposium on Insulating Oil, STP95-EB/Oct, 1949 [4] G. Totten, “A Timeline of Highlights from the Histories on ASTM Committee D02 and the Petroleum Industry,” in ASTM Standardization News, June 2004 [5] Van H. Manning, “The Pioneer’s Field in Petroleum Research,” Petroleum Section, American Chemical Society, 1921 [6] “Section 4, Oxidation Inhibitors for Transformer Oils,” in Reference Book on Insulating Liquids, Gases and Materials, A Project of the Doble Client Committee on Insulating Fluids, PN 500-0333, 72A-1971-01 Rev. B 7/04, Watertown, MA [7] D3. B. G. Tychinin and N.A. Butkov, “Neftyanoe I Slantsevoe Khozyaistovo, No. 1”, 1925 [8] D4. B. G. Tychinin and N.A. Butkov, “Neftyanoe I Slantsevoe Khozyaistovo, No. 8”, 1924 [9] D5. C. Moureau and C. Dufraisse, “Sur l’autoxidaton: les antioxigènes,” Compes Rendus, Vol. 174, p. 258, 1922 [10] CSA-C50, “Mineral Insulating Oil, Electrical for Transformers and Switches,” Canadian National Standard, October, 2014 [11] “Transformer Oil Purchase Specification,” Doble Engineering Co, Marlborough, MA, March 2017 [12] ASTM D3487, “Standard Specification for Mineral Insulating Oil used in Electrical Apparatus,” ASTM, West Conshohocken, PA, 2016 [13] IEC 60296, Edition 5, “Fluids for Electrotechnical Application – Mineral Insulating Oils for Electric Apparatus,” International Electrotechnical Commission, Geneva 20, Switzerland, 2020 Lance R. Lewand Lance R. Lewand received his Bachelor of Science degree from St. Mary’s College of Maryland. He is actively involved in professional organizations including the American Chemical Society. He is a representative of the U.S. National Committee for TC10 of the International Electrotechnical Commission (IEC) and ISO TC28, ASTM D-27 since 1989, Chair of ASTM Committee D-27, sub-committee chair 06 on Chemical Tests, secretary of the Doble Committee on Insulating Materials, and a recipient of the ASTM Award of Merit for Committee D-27. Mr. Lewand is the Technical Director for the Doble Insulating Materials Laboratory. Since joining Doble in 1992, he has published over 75 technical papers pertaining to testing and sampling of electrical insulating materials and laboratory diagnostics. Eileen Finnan Eileen Finnan is currently Director of Field Services, part of the Global Professional Services Group at Doble Engineering Company, providing operation management of field testing and remote services to clients. She also participates in cross-functional teams to deliver in-depth condition assessments of critical electrical assets and large-scale fleet assessment services. Her previous roles include Manager at Doble Engineering Material Laboratory which specializes in routine and specialized testing on insulating fluids from electric power equipment. Eileen received her Bachelor of Science degree in Physics and Chemistry from Trinity College in Dublin, Ireland. Share this article

PROTECTION AND CONTROL COMMISSIONING
Foreword by the Editor in Chief
When we first came across the RMS Energy team, I was impressed by their passion and purpose as it relates to protection and controls. This article is a prime example of that, relating to commissioning of systems. Enjoy. During the past decade, the energy industry has undergone major transformations in infrastructure redevelopment and the introduction of game-changing advancements in power systems technology. With these major leaps forward, the important process of protection and control commissioning, which verifies, documents and places into service newly installed or retrofitted electrical power equipment and systems, has become increasingly critical. Yet, the push for these advancements has created something of an unfortunate and unforeseen gap in the industry. Many qualified personnel who truly understand protection and control commissioning are becoming harder to find due to retirement of the aging workforce and a smaller number of young professionals entering to replace them. This reduction in experience and knowledge in some quarters occurred as the technology vastly improved, while training and certification programs for technicians substantially lagged behind. In fact, what used to take seven to 10 years of intense education, mentoring and final certification have been compressed into just a few years as a way to catch up. This has created a production line of less qualified technicians who may not possess the required knowledge or comprehension of the commissioning process and the very equipment that needs inspection. Deep understanding of protection and control standards, NERC, new technologies, a reconfigured power grid system and the equipment itself, are requirements among technicians necessary to be proficient and accurate in their commissioning work.
One simply needs to look at the new processes and advances in relay equipment to get a view of how things have changed in commissioning services. The baseline of protection and control standards has always revolved around electromechanical relays, the true marvels of technology that are as old and dependable as those who invented or improved upon them, like Tesla and Edison. These protective relays work between normal and expected operating conditions and the inevitable system faults that come with any power distribution system. The tried-and-true electromechanical relays detect power system conditions and provide a measured and appropriate fault response with repeatability and reliability during decades of in-service time. The energy industry is moving forward at warp speed on technological and infrastructure changes. Yet, the push for these advancements has created a major gap among the resources that provide protection and control commissioning services on power systems, which boils down to lack of training and system knowledge. Electromechanical relays are still considered to be amazing technology, and those who invented them are responsible for the kind of reliability and safety that our power systems enjoy today. Deep understanding of protection and control standards, NERC, new technologies, a reconfigured power grid system and the equipment itself, are requirements among technicians necessary to be proficient and accurate in their commissioning work. The Reliability of Electromechanical Relays
There are myriad faults that can be detected by electromechanical relays. Over voltage, under voltage, differential faults and distance sensing for line protection are just a few that will generate the fault condition necessary for the relays to take action. ANSI and IEEE have standardized relay function codes such as “50/51,” which speak the power engineers’ language for instantaneous overcurrent (50) and time overcurrent (51), signaling a command to trip a circuit breaker when line current becomes excessive, avoiding severe overheating or even fire.
This dependable relay technology hasn’t changed much, as it has been the foundational workhorse for decades; that is, until the advent of solid state and micro-processor-based relays. With all the change in the power industry, the major downside of electromechanical relays has become the limitations of its inherent single-element functionality, which is designed to detect faults for only one particular element. This limited functionality simply requires that far too many relays must perform the fault functions needed to ensure that today’s more advanced and complex power distribution systems continue operating at peak efficiency.
Another drawback of electromechanical relays is that they require periodic testing and calibration. These relays depend upon mechanical motion, so maintenance on the relays themselves is required to produce accurate and reliable core operations, such as opening a circuit breaker or tripping a lockout device when needed.
The bottom line is that power systems can run a long time without a fault ever occurring. But with power systems, an industry axiom is that trouble is always brewing. When the time comes for a failure, and it will come, a dependable relay or series of relays are necessary in order to accurately detect the fault, act upon it, and perform the function needed that avoids system damage and costly outages.

Solid State and Microprocessor Relays
The creation of solid-state relays, which don’t rely on mechanical motion, was a step forward in replacing the mechanical motion of its predecessor. But the industry did not dwell too long on solid-state relays, because they also required calibration and maintenance.
It was not until the microprocessor became more affordable and dependable that the industry witnessed bigger leaps forward in protection and control. These digital marvels leave the analog world behind, with their ability to rely on more accurate and sustainable digital technology that perform multi-function protection protocols, putting the proverbial “many eggs into one basket.” Of course, with so many functions embedded into a single relay, a rare failure of such equipment can produce wider scale and less contained damage compared to electromechanical relays.
Microprocessor relays include a flexible selection of parameters that make them an easier application in the power system, and the provision of more accurate data. There are three important parameters available in such relays, including response characteristics, sensitivity, and selectivity.
Response characteristics are now a family of curves allowing for a variety of customized characteristics that can be monitored and measured. The selection of parameters can provide sensitivity for a wide range of operating conditions, and selectivity needed to prioritize response between protective elements and upstream and downstream devices. These microprocessor relay protocols are major advantages within today’s complex and more advanced power system solutions.
The complex digital algorithms needed to realize these multi-functional benefits now require another level of understanding for the technician to attain.  These attributes, along with the programmable logic elements and the complex communication technologies within microprocessor relays, allow for intricate networking and reporting capabilities and demand a working knowledge in many technical realms.
Integration of supervisory control and data acquisition (SCADA) also creates a large pipeline of collected data. Operators are no longer flying blind when such integration provides critical data on operating currents, fault oscillography, power factor, min/max data and other critical parameters.
Required in any successful commissioning effort is complex and up-to-date testing equipment, including multiple independently controlled voltage and current channels; independent phase relationship control of all channels; and accurate reporting of results as the test is being conducted. Starting with a Good Plan
A good commissioning plan begins with the realization of the benefits of the power systems in play. To realize reliability and predicted response, technicians must test not only the relays involved, but also the system in which they reside. This is often where industry resources lag, because operating a test set is very different from the essential aspects of understanding what the test set is actually doing while performing a test on a particular relay or relay element.
Technicians who are new to the field or have not had the proper indoctrination into the inner workings of a modern commissioning process will be challenged to create an accurate and positive outcome in even the most basic commissioning projects. For example, while a relay test system (RTS) can be run for an overcurrent test, a complex power scheme that includes differential protection, energy calculations, and other factors needs to clear through a comprehensive plan to ensure the plan is both solid and valid.  This authentication of commissioning plans comes with comprehensive knowledge and deep understanding of the relays and how they relate to complex power systems. Operating a test set is very different from the essential aspects of understanding what the test set is actually doing while performing a test on a particular relay or relay element. Without this knowledge set, the accuracy of the test is relying on the test itself, with little to no input from the technician to guide the analysis toward a comprehensive and successful conclusion of the commissioning project.
Understanding Elements of Proper Commissioning
To conduct proper commissioning on any power system, a full understanding of the following elements is essential for a positive and accurate outcome: Zones of Protection Current Transformer Characteristics:
a. Saturation curves b. Accuracy class considerations c. System burden considerations
Breaker response and timing Redundancy for enhanced reliability Functional testing – programmable logic elements Trip equations SCADA systems:
a. Communications capabilities b. Fiber networks c. Site DSC considerations  
A solid commissioning plan will include a physical checkout from point to point. Testing of wiring and its configurations is the first step in any good plan, to ensure wiring is properly installed. Today, utilities have control houses prebuilt offsite and subsequently dropped into place, a major step in efficiency for both time and money. However, this is where assumptions get made – that wiring is predestined for proper installation. But nothing could be further from the truth. Wiring is where things go wrong both early and often, and not checking every single point and connection upfront will substantially hamper any proper commissioning plan. Any industry resource that conducts thorough and accurate protection and control commissioning and adheres to proper protection and control standards will employ technicians and other experts who have the proper years of experience to accommodate for the more complex power systems we have today. Conclusion
Any industry resource that conducts thorough and accurate protection and control commissioning and adheres to proper protection and control standards will employ technicians and other experts who have the proper years of experience to accommodate for the more complex power systems we have today. Commissioning companies must not only recruit the right people and pay them appropriately, but also invest in ongoing development and training to ensure every commissioning job takes on the best and most accurate commissioning approach.
Ensuring the proper outcome of a commissioning project has various aspects that include the right testing equipment and plan, coupled with technicians who have the experience and knowledge to apply to ensure protection and control standards are achieved. It’s only a matter of time when the industry catches up and starts to churn out more qualified technical personnel; but until that time, choosing a commissioning partner based on their technicians’ expertise and knowledge base is a critical aspect to ensuring the safety and reliability of modern complex power systems. Ken L’Esperance
Ken L’Esperance, P.E., has 40 years of experience in the energy industry. He has held many upper-level engineering positions and owned his own engineering consulting company from 1987 to 2014. He is currently the director of the engineering services division of RMS Energy Co., LLC. Ken has his NETA Level IV certification from the International Electric Testing Association (IETA) and is certified on 138 kV, 69 kV, 13.8 kV, 4.16 kV, 480 V, and 208Y/120-volt systems, including designing, testing, commissioning, and troubleshooting. He holds a Bachelor of Science in Electrical Engineering from Michigan Technological University. Jeff Hardin
Jeff Hardin, electrical engineer, is a dedicated technical leader with nearly 20 years of experience in the energy industry. He is experienced in utility design and operations and has extensive training on NERC standards, NETA testing standards and NFPA 70E standards. He has held many senior level positions for consulting firms and a utility, and currently serves as vice president of sales and estimating for RMS Energy Co., LLC. Jeff has a Bachelor of Science in Electrical Engineering from the University of Kentucky. Share this article

This article was originally published in the March 2021 issue of the From Specification to Commissioning magazine.

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