Fire Resistant Transformer Oils – A Primer
Fire Resistant Transformer Oils
Fire Resistant transformer oils add a significant margin of safety to any liquid filled electrical equipment. These insulating oils are used instead of conventional mineral oil in transformers and switchgear that are located in hazardous or sensitive areas.
When is Fire Resistance Needed?
Fire resistant insulating oils are used any time the safety of electrical equipment needs to be increased. Fire Resistant fluids can be used in all equipment that would normally use conventional transformer oil. These fluids have been widely used in transformers, switchgear, and voltage regulators located:
- Inside buildings
- in government buildings or installations
- in areas of high pedestrian traffic (i.e., in crowded areas of cities)
- inside or near petrochemical or industrial sites
- in areas of frequent natural disasters (earthquakes)
- in urban electrical substations
- in mines or tunnels
Fire regulations often require extra fire protection in these locations. Using fire-resistant insulating fluids in transformers and switchgear is an excellent means of preventing fires and explosions in electrical equipment.
Fire Resistant Insulating Oils and Fire Safety:
Fire Resistant Hydrocarbon oils combine fire safety with low environmental and health risk. Since their introduction, fire-resistant hydrocarbons have been used to lower the risk of fire and explosion in hundreds of thousands of transformers and switchgear installations.
The principal advantage of the fire resistant oils is their resistance to ignition. These fluids require a tremendous amount of energy input to raise the temperature to one that will sustain a flame. This is easily shown with the fire point test.
Compare the relative flammability of fire resistant oils with conventional transformer oil:
| Fluid | Fire Point (ASTM D92), °C. |
| Conventional Mineral Oil | 145 |
| Fire Resistant Insulating Oil | >300 |
You can see the added safety margin that is provided by the fire resistant oil. This is proven in the fact that fire resistant hydrocarbon oils have a flawless safety record.
Choosing Fire Resistant Insulating Materials:
There are several considerations that should be used in choosing a fire resistant dielectric fluid. Among the most important are:
- The fluid must have excellent electrical characteristics
- The fluid must be a good cooling medium
- The fluid must be easy to handle and friendly to the environment
- Fire resistant fluids should be compatible with materials that are used with
conventional transformer oil.
Fire resistant petroleum oils are very popular for use in new equipment. They are the least expensive fire resistant oils available. Beta Fluid is a good example of this type of oil. Beta Fluid is highly refined petroleum oil with special additives. It has the same electrical characteristics as conventional transformer oil, with additional fire safety. It has good environmental qualities. Beta Fluid is compatible with conventional transformer oil and with all equipment construction materials. Beta Fluid can be used in switches, circuit breakers, and other equipment. Maintenance practices are the same as for conventional transformer oil.
Synthetic hydrocarbon fluid
Synthetic paraffin hydrocarbon fluids are widely used in new and in used equipment transformers. This process is called retrofilling. The most popular synthetic paraffinic hydrocarbon in use today is called Alpha-1 fluid. Alpha-1 Fluid is a hydrocarbon, just as petroleum oils are, but instead of being refined from crude oil, it is manufactured in a
chemical process.
Alpha-1 Fluid also has excellent electrical characteristics. Because it is synthetic, it has better cooling performance, and better flow at low temperatures. These characteristics make Alpha-1 Fluid perfect for changing the existing oil in PCB or mineral oil transformers.
The maintenance and disposal procedures for Alpha-1 Fluid are similar to those of conventional transformer oil. Alpha-1 is compatible with standard materials used to make transformers.
Use in New Equipment:
In new transformers and switchgear, fire resistant fluids can be used instead of conventional transformer oil. They are a direct replacement for conventional transformer oil. The electrical characteristics of fire resistant fluids are excellent. Because of their higher viscosity, transformers may operate at slightly higher temperatures. Extra cooling
(radiators) or larger internal cooling ducts can be used to minimize this effect.
Changing Oil in Existing Equipment:
Transformer operators sometimes want to upgrade the fire safety of existing electrical equipment. Changing the oil with a fire resistant fluid is often an easy and inexpensive way to increase the fire safety margin of the existing unit.
This is a simple procedure. In many cases, this process (called retrofilling) is simply a matter of draining the original oil and filling the unit with the new fluid.
Alpah-1 Fluid is specially made for this application because of their excellent cooling characteristics, which minimize the operating temperature of the retrofilled transformer.
Conclusions:
Fire Resistant fluids are used throughout the world in installations to minimize the risk of fire and explosion. These fluids will not ignite until they are at extremely high temperatures. They are an effective means of adding extra fire safety to electrical equipment installations and can be used in transformers and switchgear that were
designed for conventional transformer oil. Fire Resistant Hydrocarbon Oils can be use in both new equipment, or to retrofill equipment that was originally filled with conventional transformer oil.
| Fire Resistant Petroleum Fluid (Beta Fluid)Fluid |
Synthetic Fire Resistant Hydrocarbon (Alpha-1 Fluid) |
|
| Fire Point, °C | 308 | 306 |
| Pour Point, °C | -21 | -68 |
| Dielectric Strength IEC Electrodes, 2mm, kV |
56 | 56 |
| Dissipation Factor @ 20 °C., % | 0.10 | 0.06 |
| Viscosity @ 100 °C., cSt. | 12.0 | 8.5 |
| Compatible with transformer oil | yes | yes |
Copyright © DSI Ventures, Inc
Soltex Reactions Q3 – 2023
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Soltex Makes a Game-Changing Acquisition of DSI Ventures: Unveiling New Avenues in AI and Immersion Cooling
In a recent move, Soltex has officially announced its acquisition of DSI Ventures, setting the
stage for a dynamic synergy that promises to redefine the landscape of AI and Immersion Cooling.
With a strategic eye on emerging markets and a wealth of combined expertise, this acquisition is
poised to open doors to a multitude of exciting possibilities. Let’s delve into the highlights of
this union and the remarkable efficiencies it brings to the table.
A Strong Foundation for Emergent AI and Immersion Cooling Markets
The merger of Soltex and DSI Ventures marks a significant milestone in the fast-evolving world of
technology. As AI continues its meteoric rise and immersion cooling gains traction as a highly
efficient cooling solution, this collaboration sets a foundation for pioneering advancements in
both fields. DSI Ventures, well-established in the industry and armed with a deep understanding of
the electric vehicle (EV), battery storage, and immersion cooling markets, perfectly complements Soltex’s innovative drive.
Expansion of Offerings
One of the most exciting aspects of this acquisition is the array of new product and service
offerings it will deliver to customers. The combined entity is primed to enhance its portfolio,
particularly in the realm of dielectric fluids. While DSI Ventures primarily supplies mineral-based
transformer fluid, Soltex introduces synthetic-based fluid for electronics, such as radio stations
and TV transformers, broadening the scope of applications. The roadmap even extends toward battery
cooling, which is increasingly crucial in the ever-expanding world of electric mobility.
Streamlining Turn Times, Boosting Availability, and Elevating Support Services
The integration of Soltex and DSI Ventures yields a range of benefits that directly impact
customers. The promise of better turn times and increased product availability emerges as a result
of the collaboration, ensuring that critical resources are readily accessible. Furthermore, the
acquisition facilitates additional support services, signifying an elevated commitment to customer
satisfaction. Although services remain unaffected, the continued Soltex expansion plans for a
separate operational building in Baytown emphasizing their dedication to refining logistical
aspects for optimal efficiency.
Charting a Bold Course Forward
This collaborative journey began on the official acquisition date, September 15th of this year. By
combining Soltex’s and DSI Venture’s strengths, expertise, and market insights, the two companies
are poised to drive innovation, redefine industry standards, and create unmatched value for their
customers. In the ever-evolving tech landscape, the acquisition of DSI Ventures
stands as a major advancement, promising a transformative future.
Soltex’s Commitment to Maintaining a Strong Presence in Canada
Soltex is committed to providing high-quality services and products to customers across North America. Recently, the company made a significant investment in Canada by acquiring a new substation transformer and tanks. This investment is part of Soltex’s ongoing efforts to maintain a strong presence in Canada and to ensure that its customers in the region have access to the best equipment and services available.
Replacing an Aging Transformer
The decision to replace the transformer was made due to its age. Typically, the lifespan of a transformer is around 25 years. However, Soltex’s unit was 36 years old and showing signs of wear and tear. The oil in the unit had started to degrade, meaning that the insulation was breaking down. This deterioration posed a significant risk to the plant’s operations and Soltex’s business continuity. If the transformer failed, it would have resulted in an extended closure of the plant and office, impacting Soltex’s customers and employees.
To mitigate this risk, Soltex decided to replace the aging transformer with a new unit. The lead time for a new transformer is 9-12 months, highlighting the importance of proactive planning to ensure minimal disruption to operations.
Collaborating with Industry Experts
Soltex partnered with KPC Power Electrical Ltd to replace the substation transformer. Soltex team members John Miron and Rob McLean worked closely with KPC Power Electrical Ltd to ensure a smooth and efficient installation. The replacement took place on January 20-22, 2023.
Soltex’s attentiveness and proactive planning approach to risk management and collaboration with industry experts have helped to ensure a successful installation and minimal disruption to operations. The company’s investment in a new substation transformer in Canada demonstrates its dedication to maintaining a strong presence in the region, ensuring the continued success of its operations, and providing high-quality services and products to its customers.
Revolutionizing Power Solutions: Soltex, Dana and Ergon Further Solidify Partnership
In June 2023, Soltex unveiled a groundbreaking truck design that showcases the collaborative efforts of Soltex, Dana, and Ergon. The launch event was attended by esteemed individuals from the companies, including John Grimes, Glenn Bohny, Joseph Massoud, Bryan De La Rosa from Soltex, Chuck Martinez, Peter Beauchemin from Dana, and Andy Holden from Ergon. This marks a significant milestone in the partnerships.
Andy Holden, a representative from Ergon, expressed his gratitude and admiration for the exceptional growth and trust that Soltex has demonstrated over the years. He stated, “Soltex has grown to become a valuable and trusted partner in the last few years. We all know that endeavors like this require a lot of help from many people, and this is another great example of what we’ve been accomplishing together. We thank you all for that commitment to Ergon and our customers.” These words acknowledge the collaborative spirit and dedication that has propelled this partnership to new heights.
The advancing technology of Insulating Oils should not be overlooked. Whether you find yourself in a cold climate or occasionally visit one, rest assured that Ergon HyVolt C50A – Canada CSA C50A Type II/IV is tirelessly working behind the scenes to ultimately provide assistance in warmth and safety in every indoor environment you encounter. Chemical solutions like these brought to life through the collaborative efforts of Soltex and Ergon, uphold the critical function of power supply regardless of the weather conditions, making our world more connected and secure.
With each milestone achieved and every innovative endeavor undertaken, the partnerships with Soltex continue to revolutionize the power industry. As we continue on this transformative journey, we eagerly anticipate the forthcoming opportunities that lie ahead, driven by the collective vision and tireless efforts of these industry leaders. The truck design launch serves as a testament to the immense potential that can be unlocked when brilliant minds and progressive companies unite in a shared pursuit of excellence. Together, Soltex, Dana, and Ergon are redefining the possibilities of power supply, creating a future where reliable energy is not just a necessity but an enabler of extraordinary achievements.
Soltex: A Legacy of Growth Through Exceptional Customer Support and Value-Added Formulations
Soltex has experienced steady growth since its inception, with multiple expansions, services, and product offerings. The company acquired Chevron Phillips Chemical’s Shawinigan Black business in 2004, which became known as Soltex’s Acetylene Black (AB). Two years later, Soltex purchased a major competitor in North America, H&R (heritage Dussell Campbell), and in 2012, the company expanded its product line to include synthetic base oils, refrigeration fluids, base components, and chemical and performance additives for industrial and consumer applications.
In 2015, Soltex Canada was established through the purchase of OMG Belleville, which shortened transit times and reduced logistic costs. Following that acquisition, Soltex acquired Petroleum Chemicals and Tabler, expanding further into the Lubricant Additives and Paint and Coatings industry. Soltex continues to maintain a strong presence in Canada and in January 2023 invested in a new substation transformer and July 2023 a new tank ensuring the continued success of its operations and providing high-quality services and products to its customers.
US and Canada-Based Operations & Manufacturing
Soltex manufacturing is based in the US and Canada. Most performance chemical additives (PCA) are produced in the US. Products made in Canada are dielectric fluids, refrigeration fluids, cable flood, fill and gels, metal carboxylates, and performance additives.
In the last year, the company permanently moved the location of its company headquarters from Houston, Texas, to The Woodlands, Texas. As Soltex continues to grow, the move to the new facility provides the space and room needed to serve customers better. It also gives Soltex the opportunity to expand all teams and continue increasing product lines.
Customer Service Strength
Soltex places a high priority on customer service and employs a knowledgeable and responsive staff. The company operates warehouses and packaging operations in Houston, Texas, as well as toll manufacturers in Canada and the US. With an in-house laboratory and expertise, Soltex can provide reliable technical support and innovative problem-solving for customers with unique needs. The company’s logistics and distribution resources enable its team to provide efficiencies in warehousing and transporting products worldwide.
Soltex remains committed to providing high-quality products, exceptional customer support, innovative problem-solving, and continuous updates to the company’s infrastructure. The company vision is set on additional growth through ongoing product portfolio expansion and new business partnerships.
Soltex Employees Raise Awareness and Funds for Suicide Prevention
At its core, Soltex has always placed the utmost importance on customer service, product quality, building relationships, and fostering a company culture that highly values its employees and encourages support for its communities. In September of 2022, members of the Soltex team participated in the American Foundation for Suicide Prevention (AFSP) annual fundraiser “Out of the Darkness Walk” in Morris County, New Jersey.
According to the Centers for Disease Control and Prevention (CDC) Data & Statistics Report for 2020, suicide is the 12th leading cause of death in the United States. In 2020, 45,979 Americans died by suicide with an estimated 1.2 million more suicide attempts. Established in 1987, the AFSP is a voluntary organization that gives those affected by suicide a nationwide community empowered by research, education, and advocacy to take action against this leading cause of death.
The AFSP has local chapters in all 50 states and organizes walks across those chapters to raise awareness to help change the conversation about mental health and put a stop to this tragic loss of life.
Since 2012, Soltex has dedicated support to the AFSP’s mission to save lives. About the company’s longstanding involvement with AFSP, Soltex Vice President of Sales, Susan Kovacs says, “We understand that suicidal thoughts, much like mental health conditions, can affect anyone regardless of age, gender, or background. It is our hope that our small contributions can help raise awareness of this stigmatized, and often taboo, topic.” He also adds, “We wish to help in shifting public perception, spread hope, and share vital information to people affected by suicide. The truth is, we can all benefit from honest conversations about mental health conditions and suicide because just one conversation can change a life.”
The AFSP creates a culture that’s smart about mental health by engaging in core strategies like funding scientific research, educating the public about mental health and suicide, advocating for public policies in mental health and suicide prevention, and supporting survivors of suicide loss and those affected by suicide.
Over the last year, the Morris County Walk raised over $76,000 and the entire New Jersey chapter of AFSP has raised more than $1.1 million to date for this important cause. Soltex looks forward to participating once again for the 2023 walk in Morris County this November 2023.
Dissolved Gas Analysis Guide for Transformers Filled with Beta Fluid
Dissolved Gas Analysis Guide for Transformers Filled with Beta Fluid
Introduction
Analysis of dissolved gases in transformer dielectric oil is often the best method of detection certain problems that may eventually lead to failure of the transformer. All transformers generate different gases during normal operation. The detection and interpretation of certain key gases and gas quantity ratios allows the transformer operator to predict transformer problems. These techniques have been used with transformers filled with conventional transformer oil for years. They can now be applied to transformers filled with Beta Fluid.
In general, the solubilities and thermal decomposition products of Beta Fluid are very similar to those from conventional transformer oil. This means that the guidelines for interpretation of dissolved gas analysis (DGA) for conventional transformer oil can be followed when working with Beta Fluid.
Why Analyze Dissolved Gases?
Much in the same way that a doctor can analyze a patient’s blood to determine certain health problems, the trained transformer owner can detect problems within the transformer by analyzing gases dissolved in dielectric fluid. These problems may include localized overheating, general overheating, arcing within the transformer, and corona discharge.
In a transformer, generated gases can be found dissolved in the insulating oil, in the gas blanket above the oil or in gas collecting devices. The detection of an abnormal condition requires an evaluation of the amount of generated gas present and the rate of gas generation. Some indication of the source of the gases and the kind of insulation involved may be gained by determining the composition of the generated gases.
(1) The theory of combustible gas generation in a transformer
(2) The interpretation of gas analysis
(3) Suggested operating procedures
(4) Diagnostic techniques, such as key gases, Dornenberg ratios, and Rogers ratios
Limitations. Many techniques for the detection and the measurement of gases have been established. However, it must be recognized that analysis of these gases and interpretation of their significance is at this time not a science, but an art, subject to variability. Their presence and quantity are dependent on equipment variables such as type, brand, geometry, and the fault temperature, solubility and degree of saturation of various gases in oil, the presence of an oil preservation system; the type and rate of oil circulation; the kinds of material in contact with the fault; and finally, variables associated with the sampling and measuring procedures themselves.
DGA interpretation is not an exact science, as there is a lack of positive correlation between laboratory data and field experience.
The result of various ASTM investigations indicates that the analytical procedures for gas analysis are difficult, have poor precision, and can be wildly inaccurate, especially between laboratories. Before taking any major action with a transformer, take a second sample to make sure that its analysis agrees with that of the first sample.
This guide is an advisory document. It provides guidance on specific methods and procedures to assist the transformer operator in deciding on the status and continued operation of a transformer that exhibits combustible gas formation. However; operators must be cautioned that, although the physical reasons for gas formation have a firm technical basis, interpretation of that data in terms of the specific cause or causes is not an exact science, but is the result of empirical evidence from which rules for interpretation have been derived.
References The following references should be used in conjunction with this guide:
ASTM D3613 Method for Sampling Gas from a Transformer:
ASTM D3612 Test Methods for Analysis of Gases Dissolved in Electrical Insulating Oil
by Gas Chromatography
ASTM D6117, Methods for Sampling Electrical Insulating Oils for Gas Analysis and
Determination of Water Content
ASTM D923, Method of Sampling Electrical Insulating Oil from a Transformer
Differences Between Dissolve Gas Analysis with Mineral Oil and with Beta Fluid
Gas Solubility: As the data below shows, the solubility of various gases in Beta Fluid is very similar to that in conventional transformer oil. In almost every case, the difference between the two fluids is less than 10%, which is well within the error inherent in extraction and analysis methods. This means that the gases, once generated in a transformer, will be soluble in Beta Fluid to the same extent that they are in mineral oil, and that the same analysis techniques can be used.
| Ostwald Coefficients for Beta Fluid | ||||||||
| Component Gas | Beta | Mineral Oil | ||||||
| Hydrogen | H2 | 0.054 | 0.0558 | |||||
| Nitrogen | N2 | 0.081 | 0.0968 | |||||
| Oxygen | O2 | 0.150 | 0.179 | |||||
| Carbon Monoxide | CO | 0.118 | 0.133 | |||||
| Carbon Dioxide | CO2 | 1.13 | 1.17 | |||||
| Methane | CH4 | 0.410 | 0.438 | |||||
| Ethane | C2H6 | 2.62 | 2.59 | |||||
| Ethylene (ethene) | C2H4 | 1.79 | 1.76 | |||||
| Acetylene (ethyne) | C2H2 | 1.39 | 1.22 | |||||
Gas Generation in Beta Fluid:
The primary differences between the analysis of dissolved gases produced in Beta Fluid and with mineral oil are in the solubilities of the gases in the oil. Testing has shown that the causes for generation of various gases are the same, whether the fluid in question is conventional transformer oil or Beta Fluid. Overheated cellulose, for example, will generate the same quantity and type of gases, whether in Beta Fluid or mineral oil. The generation of acetylene in the presence of arcing will be the same with both fluids. It is only the generation of lower molecular weight carbon oxides that
any appreciable difference between the two fluids is evident.
General Theory of Gas Generation
The two principal causes of gas formation within an operating transformer are thermal and electrical disturbances. Conductor loss due to loading produce gases from thermal decomposition of the oil and solid insulation Gases are also produced from
the decomposition of oil and insulation exposed to arc temperatures. Generally; where decomposition gases are formed by ionic bombardment, there is little or no heat associated with low energy discharge and corona.
Decomposition of Cellulose. The thermal decomposition of oil-impregnated cellulose insulation produces carbon oxides (CO, CO2) and some hydrogen or methane (H2, CH4). The rate at which they are produced depends exponentially on the temperature and directly on the volume of material at that temperature. Because of ale volume effect, a large, heated volume of insulation at moderate temperature will produce the same quantity of gas as a smaller volume at a higher temperature.
Decomposition. Mineral oils, including Beta Fluid, are mixtures of a wide range of hydrocarbon molecules. The decomposition of these molecules starts with the breaking of carbon-hydrogen and carbon-carbon bonds. Active hydrogen atoms and hydrocarbon fragments are formed. These free radicals can combine with each other to form gases, molecular hydrogen, methane, ethane, or can recombine to form new, condensable molecules. Further decomposition and rearrangement processes lead to the formation of products such as ethylene and acetylene. These processes are dependent on the presence of individual hydrocarbons, on the distribution of energy and temperature in the area of the fault, and on the length of time during which the oil is thermally or electrically stressed.
Application to Equipment: As stated above, all transformers generate gases to some extent at normal operating temperatures. But occasionally a gas-generating abnormality does occur within an operating transformer such as a local or general overheating, dielectric \problems, or a combination of these-In electrical equipment, these abnormalities are called faults. Internal faults in Beta Fluid produce the gaseous byproducts hydrogen (H2), methane (CH4), acetylene (C2H2), ethylene (C2H4), and ethane (QC2H6). When cellulose is involved in the overheating, the faults produce methane (CH4), hydrogen (H2), carbon monoxide (CO) and carbon dioxide (CO2). Each of these types of faults produce certain gases that are generally
combustible. The total of all combustible gases may indicate the presence of any one or a combination of thermal, electrical, or corona faults. Certain combinations of each of the separate gases determined by chromatography are unique for different temperatures. Also, the ratios of certain key gases have been found to suggest fault types. Interpretation by the individual gases earl become difficult when there is more than one fault, or when one type of fault progresses to another type, such as an electrical problem developing from a thermal condition.
Establishing Baseline Data. Establishing a reference point for gas concentration in new or repaired transformer – and following this with a routine monitoring program is a key element in the application of this guide. Monitoring the health of a transformer must be done on a routine basis and can start anytime, not just for new units
In general, daily or weekly sampling is recommended after start-up, followed by monthly or longer intervals Routine sampling intervals may vary depending on application and individual system requirements.
Recognition of a Gassing Problem-Establishing Operating Priorities. Much information has been acquired over the past 20 years on diagnosing incipient fault conditions in transformer systems, both with oil cooling, or in Beta Fluid. This information is of a general nature but is often applied to very specific problems or situations. One consistent finding with all schemes for interpreting gas analysis is that the more information available concerning the history of the transformer and test data, the greater the probability for a correct diagnosis the health the unit.
Interpretation of Gas Analysis
Thermal Faults
The decomposition of all mineral oils, including Beta Fluid, produces relatively large quantities of the low molecular weight gases, such as hydrogen and methane, and trace quantities of the higher molecular weight gases ethylene. As the fault
temperature in Beta Fluid increases, the hydrogen concentration exceeds that of methane, but now the temperatures are accompanied by significant quantities of high molecular weight gases, first ethane and then ethylene. Al the upper end of the temperature range, increasing quantities of hydrogen and ethylene and traces of acetylene (C2H2) may be produced. In contrast with tile thermal decomposition of Beta Fluid, the thermal decomposition of cellulose and other solid insulation produces carbon monoxide (CO), carbon dioxide (C02), and water vapor at temperatures mach lower than the decomposition of oil and at rates exponentially proportional to the temperature. Because the paper begins to degrade at lower temperatures than the Beta Fluid, its gaseous byproducts are found at normal operating temperatures in the transformer.
Electrical Faults – Low Intensity Discharge
Low Intensity discharge such as partial discharge or intermittent arcing produces mainly hydrogen with small quantities of methane and acetylene. As the intensity of the discharge increases, the acetylene and ethylene concentrations rises significantly.
Electrical Faults; High Intensity Arcing. As the intensity of the electrical discharge reaches arcing or continuing discharge proportions that produce temperatures from 700 ~C to 1800 “C, the quantity of acetylene produced becomes pronounced.
Suggested Operating Procedures Utilizing the Detection and Analysis of Combustible Gases
There are several methods of interpreting Dissolved Gas Analysis data in transformersfilled with Beta Fluid. The following are the methods that are recommended by Dielectric Systems, Inc.
Evaluation of Transformer Condition Using Individual and TDCG Concentrations:
Following the suggestion of IEEE Standard C57.104, a four level criterion has been developed to classify risks to transformers when previous dissolved gas history for a given transformer is unknown.
Refer to Table One (below) for concentrations of gases that correspond to the conditions set forth below:
Condition 1
TDCG below this level indicates that the transformer is operating in a satisfactory manner. If you find that any individual gas concentration exceeds the specified level, you should investigate further.
Condition 2
TDCG within this range indicates greater than normal combustible gas concentrations. Any individual combustible gas exceeding specified levels should be investigated. You should check to see that a trend may be present.
Condition 3
TDCG within this range indicates a high level of decomposition. Any single combustible gas exceeding these levels should be investigated immediately. You should take immediate action to establish a trend, as faults are probably present.
Condition 4
TDCG within this range indicates excessive decomposition of Beta Fluid and cellulose. Continued operation could result in failure of the transformer.
| Table One: Dissolved Gas Concentrations |
||||||||
| Status | H2 | CH4 | C2H2 | C2H4 | C2H6 | CO | CO2 | TDCG |
| Condition 1 | 100 | 120 | 35 | 50 | 65 | 350 | 2500 | 720 |
| Condition 2 | 101-770 | 121-400 | 36-50 | 51-100 | 66-100 | 351-570 | 2500-4000 | 721-1920 |
| Condition 3 | 701-1800 | 401-1800 | 51-80 | 101-200 | 101-150 | 570-1400 | 4001-10000 | 1921-4630 |
| Condition 4 | >1800 | >1000 | >80 | >200 | >150 | >1400 | >10000 | >4630 |
The condition for a particular transformer is determined by finding the highest level for individual gases or the TDCG in Table 1.
Transformers less than a year old usually contain levels of gases that would fall well below Condition 1, and do not contain detectable levels of acetylene. Therefore, the degree of concern in the example would be much higher for a one month old transformer than for a twenty year old unit.
Determining the Transformer Condition and Operating Procedure with Total Combustible Gases (TCG) in the Gas Space Table 2 indicates recommended initial sampling intervals and operating procedures for various levels of TCG (expressed in percent)
| TCG Level, % | TCG Rate, %/day | Sampling Interval | Operating Procedure | |
| Condition 4 | >=5 | >.03 | Daily | Remote from service |
| Condition 4 | >=5 | .03-.01 | Weekly | Remote from service |
| Condition 4 | >=5 | <.01 | Weekly | Exercise caution, analyze for individual gases, plan outage |
| Condition 3 | <5 to >=2 | .03-.01 | Weekly | Exercise caution, analyze for individual gases, plan outage |
| Condition 3 | <.01 | <.01 | Monthly | Exercise caution, analyze for individual gases, plan outage |
| Condition 2 | <2 to >=0.5 | >.03 | Monthly | Exercise caution, Analyze for individual gases, Determine load dependence |
| Condition 2 | <2 to >=0.5 | 0.03-0.01 | Monthly | Exercise caution, Analyze for individual gases, Determine load dependence |
| Condition 2 | <2 to >=0.5 | <0.01 | Quarterly | Exercise caution, Analyze for individual gases, Determine load dependence |
| Condition 1 | <.5 | >.03 | Monthly | Normal Operation |
| Condition 1 | <.5 | .03-.01 | Quarterly | Normal Operation |
| Condition 1 | <.5 | <.01 | Annual | Normal Operation |
Determining the Transformer Condition and Operating Procedure with TDCG,dissolved gas in the oil Table 3 indicates recommended initial sampling intervals and operating procedures for various levels of TDCG (expressed in ppm)
| TDCG Level, ppm | TDCG Rate, ppm/day | Sampling Interval | Operating Procedure | |
| Condition 4 | <=4630 | <30 | Daily | Remove from service |
| Condition 4 | <=4630 | 10-30 | Daily | Remove from service |
| Condition 4 | <=4630 | <10 | Weekly | Exercise caution, analyze for individual gases, plan outage |
| Condition 3 | 1921-4630 | <30 | Weekly | Exercise caution, analyze for individual gases, plan outage |
| Condition 3 | 1921-4630 | 10-30 | Weekly | Exercise caution, analyze for individual gases, plan outage |
| Condition 3 | 1921-4630 | <10 | Monthly | Exercise caution, analyze for individual gases, plan outage |
| Condition 2 | 721-1930 | <30 | Monthly | Exercise Caution Analyze for individual gases Determine load dependence |
| Condition 2 | 721-1930 | 10-30 | Monthly | Exercise Caution Analyze for individual gases Determine load dependence |
| Condition 2 | 721-1930 | <10 | Quarterly | Exercise Caution Analyze for individual gases Determine load dependence |
| Condition 1 | <720 | >30 | Monthly | Normal Operation |
| Condition 1 | <720 | 10-30 | Quarterly | Normal Operation |
Evaluation of Possible Faults by the Key Gas Method
The four general fault types have a tendency to produce a unique gas that indicates the fault type. While not as precise as the other methods, the “Key Gas Method” is often used as an indication of which fault type to examine in greater detail. The Key Gas Analysis method for use in Beta Fluid follows the method that is used with conventional
transformer oil.
Fault Type: Thermal decomposition of Beta Fluid</h4)
Principal Gas: Ethylene
Characteristics: Decomposition products include ethylene and methane, along with small quantities of hydrogen and ethane.
Fault Type: Thermal decomposition of Cellulose
Principal Gas: Carbon Monoxide
Characteristics: Decomposition products of cellulose include CO and CO2. If the cellulose is saturated with Beta Fluid, the decomposition products will include hydrocarbon oxides (as above)
Fault Type: Corona –partial discharge:
Principal Gas: Hydrogen
Characteristics: Corona discharges produce hydrogen and methane. If the corona
occurs in cellulose, the gas profile will also include CO and CO2
Fault Type: Arcing
Principal Gas: acetylene
Characteristics: Arcing always generates large amounts of acetylene and hydrogen. Carbon oxides may be present if the fault involves cellulose. Carbon may be present in the oil.
Evaluation of Possible Faults by the Rogers and Doernenburg Ratios
Many people believe that the use of ratios of gas concentrations, rather than the concentrations themselves, give a more accurate indication of possible faults inside the transformer. These ratios were developed with European data by Rogers and
Doernenburg, and usually require a significant level of gases to be present in order to be used.
The following ratios are used:
Ratio 1 (R1): CH4/H2
Ratio 2 (R2) C2H2/C2H4
Ratio 3 (R3) C2H2/CH4
Ratio 4 (R4) C2H6/C2H2
Ratio 5 (R5) C2H4/C2H6
Doernenburg Ratio Method, Step 1
Collect gas sample from the headspace, above the oil level in a transformer
Doernenburg Ratio Method, Step 2
Check for validity of the method. In order for the ratio methods to be considered valid, at least one of the gas concentrations of H2, Ch4, C2H2 and C2H4 must be at least twice the L1 value (below) and one of the other three gases exceeds the values for limit L1, the transformer is considered faulty.
Also, at least one gas concentration in each ratio must exceed the L1 values given
below:
| Dissolved Gas | L1 Value, ppm |
| Hydrogen | 100 |
| Methane | 120 |
| Carbon Monoxide | 350 |
| Acetylene | 35 |
| Ethylene | 50 |
| Ethane | 65 |
Doernenburg Ratio Method, Step 3
Assuming that the ratio analysis is valid for this transformer, check each ratio in order
R1, R2, R3, and R4
Doernenburg Ratio Method, Step 4
If all succeeding ratios for a specific fault fall within the values given in Table 3, the suggested diagnosis is valid.
| Doernenburg Ratios for Key Gases | ||||||||
| Indicated Fault Diagnosis | Ratio 1 | Ratio 2 | Ratio 3 | Ratio 4 | ||||
| Thermal Decompostion | 0.1- 1.0 | 0.75 – 1.0 | 0.1 – 0.3 | 0.2 – 0.4 | ||||
| Corona | 0.01 – 0.1 | Not significant | 0.1 – 0.3 | 0.2 – 0.4 | ||||
| Arcing | 0.1 – 1.0 | 0.75 – 1.0 | 0.1 – 0.3 | 0.2 – 0.4 | ||||
Rogers Ratios Method:
The Rogers method follows the same general procedure as the Doernenburg method,
but only three ratios are used.
| Ratio 2 | Ratio 1 | Ratio 5 | Suggested Diagnosis |
| <0.1 | 0.1- 1.0 | <1.0 | Unit Normal |
| <0.1 | <0.1 | >1.0 | Corona |
| 0.1 – 3.0 | 0.1 – 1.0 | >3.0 | Arcing |
| <0.1 | 0.1 – 1.0 | 1.0 – 3.0 | Low Temperature Overheating |
| <0.1 | >1.0 | 1.0 – 3.0 | Overheating <700C |
| <0.1 | >1.0 | >3.0 | Thermal >700C |
Conclusion
This Guide provides methods of analysis and interpretation of gases generated in transformers filled with Beta Fluid. The procedures and rules that are used to analyze these gases are identical to those that are used with conventional transformer oil. Tests have shown that the types and quantities of gases that are produced by various types of faults in Beta Fluid are the same as those which are produced in conventional transformer oil. The solubilities of gases in Beta Fluid are within 10%, in most cases, of the solubility values for the same gases in transformer oil.
The analysis of gases in transformers, and their use in prediction of possible faults is an inexact science. This guide should be used as an advisory document only. The transformer users is urged to contact the equipment manufacturer for more detailed information.
Lab Test Report: The Effect of Blending Beta Fluid with R-Temp Fluid
DSI Ventures, Inc.
Laboratory Test Report
“The Effect of Blending Beta Fluid with R-Temp Fluid”
Report Number 075-957-303
December 2004
Purpose:
The purpose of this laboratory investigation is to determine the characteristics of blends of dielectric fluids. Specifically, this experiment evaluated the physical, electrical, and chemical properties of blends of Beta Fluid with R-Temp® Fluid.
Experimental Procedure:
A laboratory blend was made of the two fluids by combining 2000 ml of Beta Fluid with 2000 ml R-Temp Fluid (both liquids measured at 20°C.) The blend was heated to 85o°C. and mechanically agitated for 30 minutes to ensure complete mixing. The blend was then cooled overnight to room temperature before testing.
Testing was performed per ASTM Standard Test Methods as set forth in 1993 Annual Handbook of Standards, Section 10.03 (Electrical Insulating Liquids and Gases). All tests were performed by the Quality Control laboratory at DSI’s manufacturing facility.
Test Results:
Results of the tests are shown in Table One.
Conclusions:
The results of the tests show that the fluids are miscible when mixed at 50% v/v. No incompatibilities were noted. All test results were well within the accepted ranges.
Both R-Temp and Beta Fluids are paraffinic petroleum fluids manufactured from lubricant base stock oils. On a molecular level, both fluids are similar. Because both fluids are 100% hydrocarbon-based, miscibility and compatibility would be expected.
Long chain paraffinic hydrocarbons, such as Beta Fluid and R-Temp Fluid , are compatible with nearly all materials used in the construction of electrical equipment. They exhibit very little “solvency” action, and therefore may be used with a wide range of plastics, varnishes, papers, tapes, and wire insulation. Generally, any material that can be used with conventional transformer oil can be used successfully with long-chain paraffins. DSI recommends that all materials be tested for compatibility in conjunction with one another before use in transformers.
The data from this experiment show that mixtures of Beta Fluid and R-Temp Fluid can be successfully used as an electrical insulating fluid in electrical equipment when the equipment construction materials are compatible with either fluid used alone.
References:
1. “Insulating Materials for Design and Engineering Practice”, Vol 2; F.M. Clarke; 1959, Wiley & Sons.
2. “Insulating Liquids: their Use, Manufacture, and Properties”; A.C.M. Wilson, 1980, IEE Press (London)
| Table One Results of Laboratory Testing |
||||||||
| Property | R-Temp Fluid | Beta Fluid | 50/50 Blend |
|||||
| Appearance | dark yellow | light yellow | dark yellow | |||||
| Viscosity, cSt. @ 100°C.: |
12.6 | 12.1 | 12.2 | |||||
| Dielectric Strength ASTM D877, kV: |
44 | 43 | 43 | |||||
| Power Factor, % @ 100°C.,: ASTM D924 |
0.10 | 0.13 | 0.10 | |||||
| Permittivity @ 20°C.: ASTM D924 |
2.2 | 2.2 | 2.2 | |||||
| Neutralization Number, mgKOH/g: ASTM D974 |
0.01 | <0.01 | 0.01 | |||||
| Spec. Gravity ASTM D1298 |
.87 | .87 | .87 | |||||
| Flash Pt, °C.: | 280 | 275 | 275 | |||||
| Fire Pt, °C.: ASTM D92 |
306 | 306 | 306 | |||||
R-Temp® Fluid is a registered trademark of Cooper Power Systems, Inc.
Beta Fluid is a registered trademark of DSI Ventures, Inc.
Copyright © 2004-2009 DSI Ventures, Inc. All rights reserved
Retrofilling Mineral Oil Transformers With Beta Fluid
Retrofilling Mineral Oil Transformers with Beta Fluid
DSI Ventures, Inc.
Transformers originally filled with conventional transformer oil can be retrofilled with a fire-resistant oil to increase the fire safety margin of these units. Electrical service and repair companies have discovered this to be a valuable service to offer their customers. This paper discusses the reasons why transformer owners are retrofilling their units and gives guidelines to observe when performing this procedure.
Why are Transformers Being Retrofilled?
Transformer owners are choosing to retrofill their units for a variety of reasons. The common denominator between them is the need to increase the fire safety of the transformer. Because of changing circumstances, building owners and utilities are often being advised by their insurance companies or attorneys to protect their buildings or to reduce their exposure to potential liability of explosion or fire.
Some of the most common reasons are:
- Expanding a building: When a building is expanded or remodeled, a transformer that was once a safe distance from exterior walls may now be too close to use conventional transformer oil.
- Changing regulations or fire codes: As building codes and insurance regulations change, transformers may be reclassified or be required to meet more stringent fire protection guidelines.
- Liability exposure: Transformers located near public roads or walkways may present an exposure to a potential liability that the owner would like to reduce.
Many times, a building owner will be faced with the requirement of constructing a barrier or enclosure around a padmounted transformer. Changing the dielectric fluid from conventional mineral oil to a fire resistant fluid is often a far less expensive option that may be acceptable to the regulatory parties involved. Retrofilling the transformer with a fire resistant fluid is an easy way to increase the fire safety margin of the unit, lowering the risk of fire or explosion.
Retrofill Fluids
Fire resistant oils are defined as having a fire point of at least 300°C. This is significantly higher than the typical 160°C. fire point of conventional transformer oil.
Look for the following characteristics when choosing which fire resistant fluid to use:
- Choose a hydrocarbon fluid. There are several hydrocarbon fire-resistant fluids on the from which you can choose. Silicone-based fluids have not traditionally been used in oil retrofill jobs because of problems that may arise as residual oil leaches out of the core and coil of the transformer and mixes with the silicone fluid. Hydrocarbon fluids mix easily with this residual oil without any foaming or dielectric problems. In addition, hydrocarbon fluids are biodegradable. Beta Fluid is 100%2 hydrocarbon, and is completely compatible with conventional transformer oil and materials of construction that are used with transformer oil.
- Choose a fluid with lower viscosity: When comparing fluids, pay particular attention to the viscosity of the retrofill fluid. As the transformer was designed to be cooled with conventional transformer oil, it will run warmer with a thicker fire resistant fluid. Choosing a fluid with the lowest viscosity possible will minimize this problem.
Transformer Cooling
Transformers that were designed for use with conventional transformer oil will run warmer when filled with a fire resistant oil. This is because of the higher viscosity of the high firepoint fluids. Table One shows the characteristics of Beta Fluid, compared with those of conventional conventional transformer oil. Typically, a transformer designed for conventional oil will run 4-8 oC. warmer after being retrofilled with a fire resistant fluid.
Residual Transformer Oil
A successful retrofill job depends on removing as much of the original fill transformer oil as possible. A small amount of transformer oil will remain in the unit, saturated in the porous paper and wood components. The majority of this residual oil will be replaced by the Beta Fluid within six months after the unit is retrofilled.
Mixtures of residual transformer oil and Beta Fluid will have good electrical characteristics. Because transformer oil is more flammable than the fire resistant oil, the mixture will have a lower fire point than the fire resistant fluid would by itself. If a 300 oC. firepoint is required, a second full or partial retrofill may be considered when the equilibrium between the two fluids has been established (approximately six months). Approximately 50% of the units retrofilled will require a second drain and fill procedure because of the lowered firepoint of the mixture.
Retrofill Procedure
The procedure to retrofill conventional mineral oil with Beta Fluid is relatively simple and straightforward.
These are some of the key points to be used in retrofilling electrical equipment originally filled with PCB fluids or conventional transformer oil. This list should be used as a guideline; it is not intended to be a complete list of all procedures that may need. Of course, all work should be done in accordance with applicable regulations and good engineering practice.
Key Steps in Retrofilling
- Access the unit in accordance with owner’s regulations. Make sure that the unit is de-energized.
- Ground all equipment (transformer, pump, tanks, etc.) to control static discharges while you are working.
- Perform transformer insulation tests (at minimum, a “Megger” test @ 2,000 volts d.c.)
- Discharge the transformer’s high voltage windings and cables.
- Reground the transformer windings.
- Drain the existing oil.
- Allow a minimum time of one half hour for transformer oil to drain out of the core and coil.
- Using a small pump and hoses, manually flush the interior of the unit with warm Beta Fluid (5% of the unit’s oil volume is recommended) The procedure will be easier if the Beta Fluid is warmed to at least 100oF. Be sure to flush down the core and coil if possible. Try to wash as much of the original fluid as possible out of the unit. Discard this flush fluid and replace the manhole as soon as possible.
- Allow the unit to drip for 30 minutes, then vacuum or pump the remaining fluid from the bottom of the tank.
- Replace gaskets if needed (high firepoint hydrocarbon fluids are compatible with gaskets used with conventional transformer oil)
- If the transformer is rated for full vacuum, apply a vacuum of 30 mm Hg on the unit.
- Begin the retrofill, with warmed Beta Fluid, if possible.
- Filter the Beta Fluid through 5 micron filters as it is being pumped into the unit.
- Wait before performing the next insulation tests. This gives air bubbles an opportunity to rise to the top of the fluid. The wait time is dependent on the fluid’s temperature. Four hours wait time at a fluid temperature of 50-80oC. is recommended.
- Perform another set of insulation tests, as in step 3. If the test value has decreased, investigate to determine the cause.
- Wait again before to energizing the unit. This gives the retrofill fluid time to saturate any porous materials that may have become dry during the process. The wait time is dependent on the temperature of the retrofill fluid. Twenty four hours wait time is recommended.
- Observe the unit for leaks during this wait time.
- Energize the unit without load.
- Wait three hours minimum after energizing, before adding the load.
- Apply the load.
- On the following day, check the unit’s temperature and pressure, observe it again for leaks and perform other standard observations and checks.
- After the retrofill, follow standard maintenance intervals and procedures. Pay close attention to possible leaks from any old gaskets that were not replaced.
Conclusion
Retrofilling a transformer from conventional mineral oil to Beta Fluid can significantly increase the fire safety of electrical equipment. Transformer service companies can solve problems for their customers by performing this procedure, thus providing a valuable service.
Transformers that were designed to use conventional transformer oil will run slightly warmer with fire resistant fluids. Choosing a hydrocarbon based fluid with low viscosity will ensure that this temperature rise is kept to a minimum.
When performing a retrofill, remove as much of the residual transformer oil as possible. Transformer oil that leaches from the paper and wood in the unit will mix with the Beta Fluid, possibly lowering the fire point. The fluid should be tested in six months to determine if additional work is needed.
| Table One Typical Properties of Dielectric Fluids |
||||||||
| Property | Conventional Transformer Oil |
Beta Fluid | ||||||
| Viscosity, cSt. @ 100°C: |
3.0 | 12.0 | ||||||
| Pour Point, °C.: ASTM D97 |
-40 | -18 | ||||||
| Dielectric Strength: ASTM D877, kV: |
30 | 40 | ||||||
| Power Factor, % @ 100°C.,: ASTM D924 |
0.01 | 0.01 | ||||||
| Spec. Gravity ASTM D1298 |
0.86 | 0.87 | ||||||
| Flash Pt, °C. | 145 | 280 | ||||||
| Fire Pt, °C. | 160 | 308 | ||||||
