Eric Kozubal
National Renewable Energy Laboratory

Acknowledgements

The author would like to recognize the following efforts and people from NREL for their assistance in this
project:

• The Wells Fargo Innovation Incubator (IN2) program for funding the project through a competitive selection process,
• James Shelby who installed the operating systems and PTU software, and created scripts to operate and collect data on the servers,
• David Sickinger who provided insight into the operation of liquid cooled data centers and assisted in the experimental design,
• Kevin Regimbal who provided guidance and insight to the operation of liquid cooled data centers, and
• Report reviewers: David Sickinger, Jennifer Scheib, Kate Cheesbrough, Shanti Pless, and Otto VanGeet

The IN2 program would like to thank the following organizations for supporting the project by donating components and materials used in the LiquidCool Solutions LSS system:

• Intel Corporation for providing Xeon processors
• Micron Technology for providing server memory
• DSI Ventures for providing the dielectric coolant

Personnel from Intel Corporation also reviewed the content of this report

Executive Summary

LiquidCool Solutions (LCS) has developed liquid submerged server (LSS) technology that changes the manner in which computer electronics are cooled. The technology provides an option to cool electronics by the direct contact flow of dielectric fluid (coolant) into a sealed enclosure housing all the electronics of a single server. The intimate dielectric fluid contact with electronics improves the effectiveness of heat removal from the electronics. The LSS technology has the following advantages over traditional aircooled server systems:

1. Maintains a small difference between central processing unit (CPU) and memory temperatures and inlet coolant temperature, allowing for:
   1. 1. Use of higher temperature coolant
      2. Higher temperature heat recovery
      3. Ability to maintain lower electronic temperatures
2. Eliminates the parasitic cooling energy used by fans
3. Lower capital and energy costs in a building that contains a data center because the heat
   removed from the servers can:
   1. More effectively be rejected to ambient using lower cost systems
   2. Be re-used effectively as a heating source for the building.

The LSS shown in Figure 1 is encased in a liquid tight aluminum housing and was outfitted with two
windows such that the internal electronics and motherboard are visible.

OptiCool Fluid is widely used as a cooling fluid in high voltage electronic equipment and to cool electronic circuit boards.

The viscosity of OptiCool Fluid is below that of standard mineral transformer oil.  Tests and field experience show that equipment designed to operate with standard transformer oil will often operate at lower temperatures when filled with OptiCool Fluid.

OptiCool Fluid is non-corrosive and not hazardous to workers.  It can be stored, handled and processed in the same way as standard mineral oils.

OptiCool Fluid pours at temperatures down to -50 C.  It’s ideal for applications in cold environments. Being synthetic, OptiCool contains no sulfur at all.

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:

 
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.

Copyright © DSI Ventures, Inc

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.

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.

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)

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)

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:

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.

Rogers Ratios Method:

The Rogers method follows the same general procedure as the Doernenburg method,
but only three ratios are used.

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.

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)

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

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:

1. 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.
2. 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.
3. 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:

1. 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.
2. 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

1. Access the unit in accordance with owner’s regulations. Make sure that the unit is de-energized.
2. Ground all equipment (transformer, pump, tanks, etc.) to control static discharges while you are working.
3. Perform transformer insulation tests (at minimum, a “Megger” test @ 2,000 volts d.c.)
4. Discharge the transformer’s high voltage windings and cables.
5. Reground the transformer windings.
6. Drain the existing oil.
7. Allow a minimum time of one half hour for transformer oil to drain out of the core and coil.
8. 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.
9. Allow the unit to drip for 30 minutes, then vacuum or pump the remaining fluid from the bottom of the tank.
10. Replace gaskets if needed (high firepoint hydrocarbon fluids are compatible with gaskets used with conventional transformer oil)
11. If the transformer is rated for full vacuum, apply a vacuum of 30 mm Hg on the unit.
12. Begin the retrofill, with warmed Beta Fluid, if possible.
13. Filter the Beta Fluid through 5 micron filters as it is being pumped into the unit.
14. 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.
15. Perform another set of insulation tests, as in step 3. If the test value has decreased, investigate to determine the cause.
16. 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.
17. Observe the unit for leaks during this wait time.
18. Energize the unit without load.
19. Wait three hours minimum after energizing, before adding the load.
20. Apply the load.
21. On the following day, check the unit’s temperature and pressure, observe it again for leaks and perform other standard observations and checks.
22. 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.

Never before has responsible energy been more important. As economical, social, and political realities converge, smart grid technology is moving to the forefront of the industry. DSI Ventures examines the importance of Smart Grids that utilize the power of IT and environmental technology as well as the role that liquid cooling will play as these systems increase in complexity and heat management becomes more critical to success.

By Jason D. Carr

Introduction

Today, energy policy is being driven by political, economic, market, and environmental pressures. As power is being driven by unprecedented demands worldwide, new business models and technologies are emerging to cope with these pressures while maintaining efficiencies and competitiveness. Smart Grid technology is quickly becoming recognized as the most effective way to solve these issues in multiple industries such as utilities, government, IT, and more. For example, Smart Grid technology has emerged allowing utilities to accurately manage consumer demand for power while at the same time accomplishing long-term business goals. In this paper, DSI examines the technological demands inherent in Smart Grid technologies. We examine the current Smart Grid environment and its impact on the world. Finally, we discuss the cooling issues inherent in Smart Grid environments and the important role that liquid cooling will play in this promising technology.

Smart Grid – Where We Are Today

Thomas Edison first envisioned a distributed system of power delivery late in the 19th century however a centralized system was chosen over Mr. Edison’s vision and is the method of power delivery today. The problem with the centralized system is that it is unable to economically and viably handle the enormous energy demands (see Figure 1 below) of the world today over the long-term. Serious challenges now threaten our power supply worldwide. It is our opinion that Mr. Edison’s vision must become reality and this is accomplished via Smart Grid technologies. Smart grid technologies involve more intelligent equipment, operations, transmissions, and utilization systems. This essentially means that megabytes and bits will become as important in the world of energy as megawatts and atoms. By utilizing new and existing technology, along with advances in energy, our world will be positioned to handle ever-growing power demands. Obviously, as this transformation occurs, faster and more powerful systems will be required and will entail smart cooling management.

Figure 1. US Electric Power Industry Net Generation, 2007

Sources: Energy Information Administration, Form EIA-923, “Power Plant Operations Report” and predecessor form(s) including Energy Information Administration, Form EIA-906, “Power Plant Report;” and Form EIA-920, “Combined Heat and Power Plant Report.”

Green Change

As discussed above, the current demand for power and the available supply is adversely affecting energy pricing and availability. Energy conservation is increasingly becoming an important agenda item for utilities and governmental agencies worldwide. With the notion of conservation comes the need for alternative energy sources as well as climate saving technologies. The public is increasingly pushing for green energy and this in turn is leading politicians and lobbyists to push legislative reform. This includes far-reaching initiatives such as carbon emission reductions and new energy based requirements. Consumers are seeking eco-friendly products and services while companies are increasingly being pressured to reduce pollution and environmental impact. Power consumption by servers, data centers, and other IT systems continue to grow annually. All of these issues are present today and the green movement is full-speed ahead. That being said, integration of the smart grid with renewable energy systems is still a formidable issue. While the smart grid is certainly more efficient than today’s grid, it does not integrate with renewable energy services although many companies are working to change this. Eventually, the smart grid will need to evolve and embrace the openness of renewable energy systems, which already have the capabilities to sync and integrate with many other renewable energy systems via open energy management solutions. All of these systems, as stated earlier, will require effective cooling management.

Traditional Cooling Methods

As the systems required to effectively manage the Smart Grid grow in complexity, so too will the cooling requirements. This has become apparent in the data center environment and will become even more so with the rollout of a national grid system. Liquid cooling is a viable cooling option as enhanced fluids have been introduced in recent years. One such fluid is DSI’s Opticool Fluid solution. To better understand how these enhanced fluids may be the best option for the Smart Grid, one must first understand the cooling options available today.

Air:

Traditionally, forced air has been the primary cooling choice for IT systems. Air is inexpensive, easy to move, non-toxic and a good insulator, so the circuitry being cooled does not require additional dielectric insulation. Air, however, is not very efficient in transferring heat, due to its relatively low heat capacity (specific heat). Simply put, air doesn’t hold as much heat and it therefore takes a lot of air blowing across a hot part in order to cool it. Air does not normally have any problems, though, with health, safety and the environment, nor with material compatibility.

Standard Mineral Oil:

Standard equipment oil and other mineral oils have been used in the past, but haven’t been widely used for several reasons. Although they’re efficient in transferring heat away from a circuit board, they typically have low biodegradability and there are often problems with material compatibility. Many mineral equipment oils, for example, are excellent solvents, so they have a problem with delaminating circuit boards or dissolving rubber parts. Standard mineral oils are usually not highly biodegradable, and often cause acne or other allergic reactions on the skin of those who work with it.

Fluorinated Fluids:

Fluorinated fluids, such as Freon®, are excellent heat transfer fluids. They have a very high specific heat, low viscosity and usually have good material compatibility. Fluorinated fluids are normally very expensive, however, and many have been discontinued because of concerns that their vapor can combine with ozone in the upper atmosphere, thereby depleting the ozone layer above the earth. Some fluorinated fluids can also decompose under an electric arc to create HF, hydrofluoric acid, which can be dangerously aggressive.

Vegetable Oils:

There are several vegetable oil-based fluids on the market now; their primary advantage is that they are highly biodegradable and environmentally friendly. Vegetable oils have satisfactory specific heat values, but their higher viscosity (the highest of the different liquids discussed here) often prevent them from being as efficient in heat transfer as a lower viscosity mineral oil. Most vegetable oils do not have the same oxidation resistance as mineral oils.

Synthetic “Petroleum” Fluids:

There are fluids that combine the best of many of the other types of oils available, without the associated drawbacks. These fluids are synthetic hydrocarbons – synthetic petroleum, if you will. Synthetic paraffinic hydrocarbons, such as isoparaffins and poly alpha olefins (PAOs) have high biodegradability, low flammability, and low toxicity. They have excellent resistance to oxidation, which makes them ideal for use as original fill fluids in electronics and industrial heat transfer systems.

Intelligent Liquid Cooling

OptiCool Fluid is a proprietary synthetic petroleum based cooling fluid specifically designed for electronic circuitry and IT systems such as those found in Smart Grid environments. With very low viscosity, OptiCool cools equipment better than petroleum or vegetable oils and has EXCELLENT heat transfer characteristics. It’s highly biodegradable – just as environmentally friendly as the vegetable oils are – and it has a service life that’s longer than petroleum.

Conclusion

Smart Grid technology is reshaping the energy marketplace. The Obama Administration’s New Energy for America plan calls for a $150 billion investment in clean energy systems, the creation of 5 million new jobs, the manufacture of 1 million plug-in hybrid vehicles by 2015, greenhouse gas emission reductions (80% reduction by 2050), and the generation of 25% of the nation’s power from renewable resources by the year 2025. Meeting these lofty goals will require enormous IT system investments across the board and along with these systems will follow the enormous cooling challenges. DSI helps solve the cooling obstacle through advanced liquid cooling solutions such as Opticool Fluid. Customers can utilize this intelligent liquid cooling solution to meet a number of strategic Smart Grid challenges including cost savings, improved heat transfer, green objectives, and more.

Notes:
“Insulating Materials for Design and Engineering Practice”; F.M. Clark
“A Study of the Relationship Between Insulating Fluid Viscosity and Equipment Cooling Performance”; Dr. D. Sundin
“Electrical Insulation”; British Institute for Electrical Engineers
Whitehouse.gov, American Recovery and Reinvestment Act, February 17, 2009

One of the most important characteristics of a good heat transfer medium is a high heat capacity, or “specific heat”.

What, exactly, is the heat capacity of a material, and how does it affect cooling of a circuit board or in a data center?  Heat capacity is an intrinsic characteristic of a material, and refers to the amount of heat, measured in joules or calories, that must be input into a material in order to raise its temperature by a certain amount.  Different materials hold different amounts of heat (again, measured in joules or calories), even when they’re at the same temperature.  Think of heat capacity as the “thermal mass” of a material, if you will.

A heat capacity means that a relatively small mass of fluid carries a large amount of energy away, per unit temperature drop.  A fluid with a lower heat capacity would need a greater temperature drop or greater flow rate with more heat exchanger surface to transfer the same amount of heat away.

A good analogy is to think of standing in 65-degree air – it’s pretty comfortable. But if you jump into a swimming pool at the same 65 degrees, the water feels really cold. That’s because air has a low heat capacity, and doesn’t hold much heat.  It doesn’t draw heat from you or transfer heat to you very well either.  The temperature of air rises a few degrees with only a few joules of energy input, so it’s not a very good heat transfer medium.  Water, however, has a high heat capacity, and can absorb a lot of energy before its temperature rises.  When you jump into the 65 degree pool, it feels much colder than the air did because the water pulls the heat away from your body more efficiently.  And so it is with heat transfer media; a high heat capacity makes for more efficient heat transfer, all other things being equal.  When using a heat transfer medium that has a low heat capacity, a lot more of the medium has to be used to pull the same amount of energy out of the circuitry.

TYLER, TX – DSI Ventures, Inc. announces the commissioning of two 230 KV Generator Step-Up (GSU) Transformers filled with Beta Fire Resistant Fluid at the new Bajio thermoelectric power plant in Guanajuato, Mexico.

Installed in 80 and 150 MVA, 230 KV transformers built by Hyosung Nantong Transformer Company, Beta Fluid was chosen for its 22 year record of fire safety, its low price and its excellent environmental record.

Beta Fluid is a fire resistant transformer oil made from petroleum base oils. Developed in 1993, Beta Fluid has been used in tens of thousands of applications worldwide to add a significant margin of safety to transformers located in hazardous locations.

“Although the majority of Beta Fluid applications are distribution or small substation transformers, Beta Fluid can be used even at the highest voltage levels, with no changes in electrical or insulation design”, stated a representative of DSI Ventures, manufacturers of Beta Fluid. “It has excellent impulse strength and the same dielectric constant as standard mineral oil. Beta uses the same Dissolved Gas Analysis and other maintenance procedures as mineral oil, which is another factor in the decision to use it in power transformers”.