Friday, 16 November 2012

Plant Mothballing

Read an article in Reliable Plant newsletter today. Made me aware of some work involved prior to mothballing a plant. Good start to that area of practice anyway. :)

What You Should Do Before a Plant Closure

It’s happened … the announcement that a major portion of your facility is being closed for the foreseeable future. What do you do next?
  1. Accept the news that your plant is facing an impending plant shutdown. It is not necessarily a “knockout” for the plant or your career. Remember, in the often uneven battleground called the global marketplace, just about anything can happen. Be ready to get up and start fighting again.
  2. Designate responsibility to an individual for writing a list of possible scenarios. The individual should have enough clout to implement the chosen strategy, if necessary.
  3. Go to the top of the company and request that sufficient funds be made available to execute the initial shutdown and preservation strategy.
  4. Choose the right type of long-term equipment caretakers. Those selected are often security or ex-supervisory types rather than experienced operator/craftsmen with intimate knowledge of the equipment.
  5. Don’t allow critical components to be pirated (stolen for use elsewhere) if part of a larger plant.
  6. Remove all process materials. Even innocuous materials left in the unit in the long term will likely cost five times more than at the initial shutdown. The current operations people are familiar with all the hazards.
  7. Seek expert advice on equipment preservation resulting in not getting the best bang for the buck.
  8. Involve the hourly workforce in the shutdown and mothball plan. Almost unbelievably, our recent experience has been that if the decision to shut down at some future date has been made, then involving operators and mechanics can very much improve both the quality of the shutdown plan and its execution.
  9. Not only record but clearly and physically mark what has been done to preserve the item of equipment during deactivation. The reactivating crew (probably a different group of people) can easily miss that a filter, line blind, internal component, etc., has been removed or added with serious consequences at a future start-up.
In our experience, idle plants with small crews operating at a very relaxed tempo can be dangerous places. Make sure safety programs and routine audits are kept active to avoid accidents.
Just as with any critical situation, a long-term strategic approach coupled with a series of medium-term tactics and detailed plans are needed. You should also consider how long the shutdown is probably going to last (guesstimate) and whether the plant will most likely be restarted, sold as a complete unit or sold piecemeal.
Examine every item or class of equipment individually and write a specific initial storage/mothball technique plus a methodology for ongoing maintenance.
For the purposes of this article, let’s consider an item of equipment or a whole plant that might restart as early as six to nine months but could also be several years.
Unused plants and equipment that are properly prepared for shutdown and left in fairly good condition can retain much of their value. However, if a plant is left “as is” and allowed to deteriorate, as is normally the case, much of it can be fit only as scrap in just a matter of months. Engaging in a well-planned process of deactivation/mothballing can be worthwhile either way, whether it should ever be reactivated or just sold for its second-hand value at some future point.

Materials and Equipment You Will Need

Having a clear view of how the constant foes of galvanic/bio corrosion, mold, mildew, etc., can be mitigated if not defeated is essential. Although much will depend on local conditions, the wetter and colder situations are much more challenging in terms of handling humidity, while blowing dust is an issue for those in the high desert regions. For this article, we will consider a central United States or European location.
A useful analogy in developing a strategy is to compare what it takes to maintain fire. In the case of fire, there are three essential legs: heat, a fuel source and oxygen. Likewise, age-related deterioration involves a driving force (such as galvanic action), a conducting medium (electrolyte) and oxygen. The fundamental approach to stopping or slowing this age-related deterioration is to remove one or more of the three legs.
In simple terms, we aim to do the following:
  • Separate dissimilar metals.
  • Protect surfaces that could be attacked, even with a covering of only a few molecules thick.
  • Dry out or remove the conducting medium (electrolyte — air or gas). Corrosion cannot occur when parts are stored in environments where the relative humidity is held below 40 percent.
  • Remove any oxygen or sources of chemical or biological attack.
The materials we can use are:
  • Liquid protective waxes and liquid polyvinyl chloride (PVC) coating — These can be sprayed on any clean, dry surface to protect them. Wherever it is applied, PVC will form a tough, flexible, waterproof skin that will withstand the extremes of temperature, thermal shock, differential substrate movement and impingement even when sprayed on webbing to form a cocoon.
  • Volatile corrosion inhibitors (VCIs) — These generate protective vapors even at room temperatures. They come in a number of convenient forms, including time-release vaporizers, sprays, plastic bags and films, powders, oil additives and coatings. They are adsorbed onto the metallic surfaces of the equipment (just a few molecules thick), where they can prevent corrosion for up to two years. While most VCIs are environmentally friendly and create no safety hazards for employees, there are some that are suspected of being harmful. Most contain no toxic substances, such as nitrates or chromates. (Note: Volatile organic compounds should not be used in combination with a desiccant.)
  • Vapor space inhibitor (VSI) — This is an oily concentrate that can be added to lubricating oil systems (internal combustion engines, etc.) when equipment is not going to be completely filled.
  • Heat-shrinkable plastic films — These are ideal for enclosing individual machines that have been cleaned and dried and have internal desiccants added.
  • VCI-covered polythene films — These are used to wrap individual smaller components.
  • Chemical oxygen scavengers — These are frequently added to fresh water used to displace more corrosive liquid in systems that can’t be effectively cleaned or dried out.
  • Chemical inhibitors — These are added to liquids and chemicals and are designed to remove unwanted products while preferentially inhibiting their attack on the body of the container. (Antifreeze sometimes used in this process contains them.)
  • Desiccants — These include numerous substances (solids) that absorb water from gases (air) or liquids.
  • Biocides — These are used to prevent microbial growths in water and fuels such as gasoline and diesel fuel.
  • Light waxes — These are used as surface protectors for metals.
  • Sacrificial Anodes — These are used in tanks that cannot be drained of their contents.
The primary pieces of equipment are dehumidifiers. These are available in two forms: those that work on the refrigeration principle and those that use two-cycle rotary (wheel) heated desiccant absorption.

Strategies by Equipment Class

Before considering individual techniques, make a best guess of the duration and whether it is going to be an “attended monitored” lay-up or a “walk-away” lay-up. This article is simply a guide and is not intended to be totally comprehensive and detailed.

Tanks, Pressure Vessels and Pipework

It is essential that tanks, pressure vessels and pipework be left as clean and dry as possible. Insert line blinds to create manageable zones that can be slightly pressurized (0.5 psig+) using nitrogen or dry air. Include some small flow and arrange for some simple telltale mechanism to show pressure flow and the level of humidity (indicator cards). For large enclosures, use a commercial dehumidifier of an appropriate capacity. For vessels, tanks and containments that must be kept full of liquid, some form of oxygen scavenger or anti-biological growth chemical can be used (see boilers). If a pipework system contains any traps, have its internals removed and clear all strainers.


Boilers can be laid up using either the long-term dry method or the hydrazine wet lay-up method, which involves leaving the wet side (boiler, economizer and super heater) full of feed-treated water. The feed water is dosed with 15 percent hydrazine and then pH-adjusted to raise the alkalinity to a minimum pH of 8.3. The fire side is supplied with heated air, with desiccant as a backup. Both water-side and fire-side points should have new gaskets, except for furnace hot-air entry inspection and exit points.

Pumps, Engines, Compressors and Machinery

To minimize internal corrosion, close off all vents and openings, and completely fill the casing with the manufacturer’s recommended lubricant. Alternatively, add a volatile corrosion inhibitor in the correct proportion to the lubricating oil. For large compressors, turbines, etc., first centrifuge/circulate the existing oil using a portable filtration cart through water-absorbing filter elements to remove any free water. For diesel and gasoline engines, drain the fuel systems and add biocide to the remaining fuel. To prevent external corrosion, if unpainted, one of the recommended spray-on coatings should be used (either a light wax or liquid PVC).


Maintaining the driest possible conditions for both electronics and external field devices, including sensors, transmitters and valves, can be achieved by strategic placement of desiccant packages and sealing the enclosures. This should be supplemented by placing small containers of VCI powder wherever possible. These will not adversely affect electronics. Instruments that normally would be in contact with the process materials should be removed, cleaned, protected and marked for immediate local storage.

Electrical Enclosures

Seal and insert bags or wraps of desiccants and containers of volatile corrosion inhibitors. Alternatively, heat using individual strip or built-in heaters.

Motors and Generators

Clean the exterior, grease and apply a protective covering. If completely sealed, add packets of desiccant. Lift carbon brushes from commutators/slip rings. Where sleeve-type bearings are fitted, a VSI concentrate should be added to the lubrication system.

Exercising and Monitoring

Depending on the time involved, it will be necessary to periodically exercise equipment by rotating it several times and leaving it at a different (90-degree) angle. Where humidity controls have been set, these need at least weekly monitoring. Where chemical controls are used, these should be checked every three months. Periodic monitoring of motor/generator internal resistance, as well as tank oxygen levels and humidity levels, is necessary for long-term lay-up.


In most cases, various fire-protection systems and alarms still need to be maintained and powered up. Fires are common in dried-out cooling towers. If batteries are normally used, disconnect them and smear the terminals with petroleum jelly. Vented-type lead-acid batteries should first be fully charged, then drained and flushed with distilled water.

A Final Note

A recent discussion with two major plant-dismantling/second-hand equipment vendors revealed that currently there are very few people looking for used equipment, and many idle plants are being offered for sale. They reported that when the decision to shut down comes, most companies remove anything that could present an immediate danger but essentially close the doors and walk away from millions of dollars’ worth of equipment. 

Gear Coupling reference 1

Found a useful article in Reliable Plant newsletter today in regards to couplings.

How to Achieve Gear Coupling Reliability

How to Achieve Gear Coupling Reliability


Design, Selection and Sizing

Selecting the correct coupling for the application is critical for gear coupling reliability. Use the following steps to help make the selection process easier:
  1. Choose the coupling style and design (Fast’s, Series H or Waldron; flex and rigid halves; close coupled or floating shaft; gear teeth specifications and misalignment requirements).
  2. Select the service factor (SF) from the original equipment manufacturer’s (OEM) gear coupling charts. Shock loads or variable loading can cause premature failure if adequate SF is not used. Typical service factors are in the 1.5 to 2.0 range. Some manufacturers may even specify a misalignment factor for gear coupling sizing when higher coupling misalignment is expected.
  3. Calculate application torque (T) requirements based on design brake horsepower (BHP), SF and speed.
  4. Choose a coupling with a torque capacity greater than the torque requirements. Since the service factor is already factored in, there is no reason to add additional capacity.
  5. Confirm that the coupling selected has a bore capacity greater than the actual application bore (shaft size). Frequently the maximum bore size will drive the coupling sizing process and even increase the coupling torque capacity two to three times what was previously calculated.
  6. Verify the shaft depth available for the coupling hub and compare to the actual hub depth. If the hub is too long, it must be either overhung or machined off. Since the hub to shaft engagement is the same in either method, it is preferred to have the hub machined off due to torsional effects of the overhung hub. If the hub is overhung or cut off, further examination may be necessary to determine if there is enough torque transmission capacity available. The rule of thumb is a 1-to-1 ratio for the hub length to the bore.
  7. Check a dynamic balance chart to see if the coupling needs to be balanced. High-speed gear couplings may require balancing.
  8. Ensure the coupling will fit around the equipment and guarding. This is typically something that can become an issue when there is a design modification on existing equipment. Guards that allow maintainability will encourage proper maintenance in the long run.


Some couplings don’t get much of a chance at a decent life due to their installation. Just like other components that experience infant mortality, often times these parts don’t die but are murdered. Certain elements of gear coupling installation must be considered if optimum reliability is to be obtained, including:
  • Hub and Sleeve Fits - Determine the type of hub fit (clearance, locational or interference). Higher speed applications should have an adequate interference fit to offset centrifugal force effects on shaft/hub contact pressures. Excessive hub interference fits can lead to hub cracks and hub failure.
  • Keys and Keyway Fits - Keyways should have a proper radius to reduce the risk for fatigue cracking. Key lengths should be measured to minimize the coupling imbalance.
  • Hub Bore - Ensure the hub bore is concentric to minimize hub runout.
  • Hub Installation - Choose proper heating methods so hub material properties are not compromised and select the proper heating magnitude for interference fit hubs so the hub slides easily on the shaft. Never use a hammer to install or remove hubs, as this can cause bearing damage.
  • Correct Coupling Gaps - If floating shafts have a small coupling gap, the shafts may impact one another under misalignment as the shaft oscillates during operation.
  • Proper Sealing - Always use proper gaskets and O-rings so the lubricant stays in the coupling.
  • Alignment - Install the coupling so misalignment stays within manufacturer limits with respect to offset, angular and axial misalignment.
  • Fastener Assembly - Choose the correct type of fasteners (fine or coarse, length, exposed, shrouded, etc.) and the proper arrangement. While standard bolts can work, they may put the threads in the shear plane. Coupling bolts need the correct preload, which is accomplished by proper bolt torque methods.
  • Lubrication - Get the right product in the right amount at the right time for optimum gear coupling reliability.

Different coupling styles have different lube and bore capacities. (Ref. Kopflex)


Perhaps the most important operating factor for a gear coupling to be reliable is lubrication. Selection of the proper lubricant is the first step. Many coupling manufacturers supply their own lubricants for their couplings. Gear couplings may either be grease- or oil-lubricated depending on the design. Oil-lubricated couplings will not dry out like grease couplings, while Fast-style couplings have smaller bore capacities.
It is fair to say that most gear couplings are grease-lubricated. Coupling greases have special properties, so general-purpose greases should never be used in gear coupling applications. Gear couplings can be subjected to very high centrifugal forces, and oil separation is a critical element of coupling greases. Since greases are comprised of oil and mostly a thickener, special considerations must be made regarding the selection and application of coupling greases.
Soap thickeners typically are heavier than the oils, so centrifugal forces tend to deposit the thickener at the gear teeth. Generally, a grease with a high oil content of high-viscosity oil and a grade 1 rating from the National Lubricating Grease Institute (NLGI) is preferred. A higher consistency grease may be considered for high-speed applications but should be avoided at low-speed applications.
Grease specifications may include speed limits or certain tests such as the K36 separation factor. Any grease will have oil separation based on time, temperature and centrifugal force. The K36 factor determines the maximum oil separation of the grease while running at 36,000 Gs. A K36 factor of 8/24 means the oil separation was 8 percent in 24 hours. In comparison, a grease with a K36 factor of 3/24 would mean that it did not separate as much as the grease with a K36 factor of 8/24.
Higher oil separation is desirable at lower speeds (lower G forces), while lower oil separation is preferred at higher speeds and higher temperatures. High-vibration equipment can also enhance oil separation and induce failures. Studies have even shown that gear coupling wear rates decrease as coupling speeds increase.
The main function of a lubricant in a gear coupling is to reduce the friction between the gear teeth as they slide against each other. The relative motion between the mating gear teeth occurs in the axial direction due to slight shaft misalignment. This motion is oscillatory, low amplitude, relatively high frequency and a function of the magnitude of angular misalignment.
This sliding axial motion between the gear teeth can generate lots of wear if lubrication is not sufficient. This is why the gear coupling lubricant plays such a critical role in the reliability and life of a gear coupling. Poor lubrication between the gear teeth generates higher friction between these teeth, resulting in gear coupling wear, heat generation and high axial loads to mating equipment bearings. The higher axial loads on the bearings will then decrease the life of the equipment.
The pump shown on the left had a dry coupling that was operating in a torque-lock condition and creating high axial forces on the equipment. The coupling was replaced without making any adjustments to the pump or motor. The only change was a coupling with good lubrication, which reduced tooth friction and decreased the axial forces from the coupling to the pump and motor. The result was a noticeable decrease in the operating temperature of the pump bearing.


Maintenance is the final factor to ensure gear coupling reliability for long equipment life. While the first three factors have more to do with a lack of knowledge, maintenance often comes down to a lack of execution. Unfortunately, this requires discipline by operations and maintenance groups as well as managerial courage to dedicate the resources to ensure that it can happen.
Typical recommendations from gear coupling manufacturers require regreasing at a minimum of 12 months. A regreasing procedure would include breaking, cleaning, inspecting and hand-packing the coupling with fresh grease. Using a grease gun typically is not recommended when the coupling has been broken and ready to receive new grease. When a gear coupling is greased through a fitting instead of hand-packing, it can result in overgreasing, and a hydraulic lock condition can occur, causing high axial forces on the equipment. A hydraulic lock condition can even make alignment difficult, as shafts may be hard to turn.

Some applications require regreasing at six months to ensure good reliability. These applications may include high speeds (high G forces), high temperatures, misalignment or vibration. Smaller lube sump capacity can also be a factor in regreasing intervals. However, deciding to go longer than 12 months without grease replenishment on a gear coupling is a high-risk move that is not recommended.
Regular maintenance of gear couplings should involve special care with respect to many of the installation factors discussed previously. When inspecting gaskets and O-rings, ensure the lubricant stays in the coupling until the next maintenance task is scheduled. Grease fittings should be removed before completing maintenance. These fittings have been known to leak lubricant and can hit guarding, causing loss of lubricant. Under high centrifugal forces, the grease must be completely sealed within the coupling. Guarding should also allow enough access so it does not have to be completely removed for normal coupling maintenance.
Remember, reliability is not for the faint of heart. Most all of these factors must be executed correctly to achieve good gear coupling reliability. This is why the work of maintenance and reliability professionals is rarely ever finished.

About the Author

Randy Riddell is a senior mechanical reliability engineer for International Paper in Courtland, Ala. He is a certified lubrication specialist (CLS) by the Society of Tribologists and Lubrication Engineers and a certified level I machinery lubrication technician (MLT) by the International Council for Machinery Lubrication (ICML). He is also a certified maintenance and reliability professional (CMRP) by the Society for Maintenance and Reliability Professionals (SMRP).

Wednesday, 14 November 2012

Transformer Maintenance - Silicone Oils

This entry is an extension of Transformer Maintenance - Mineral Oils to some extend. Again, this article is not a complete guide. It gives you an overview of how complicated it is. A lot is to be considered in making an informed decision in regards to a transformer especially if it is a highly critical asset.

Silicone oil when new contains a saturated amount of oxygen. In the initial years of operations, carbon monoxide and carbon dioxide will be generated. As the transformer ages, oxygen is depleted, generation of these gasses slows and plateau off after a few years of operations assuming without any faults. The generation rates of these gases should be relatively constant from normal aging after that. Which is why it is very important to start DGA immediately and start plotting the graph curves and track these changes. Without a graph, it is almost impossible to make a judgement.

Comparison of Silicone Oil and Mineral Oil.

  1. Silicone oil-filled transformer will have a great deal more CO than normal mineral oil-filled transformers. CO comes from the oil itself and from degradation of paper insulation. It is therefore if DGA indicated little other fault in gas generation besides CO, the only way to tell for certain if CO is coming from paper degradation is through furan analysis. If other gasses are involved, there obviously is a fault and paper degradation was accelerated.
  2. Hydrogen level is generally higher comparatively to Mineral oil filled transformer.
  3. Due to "fault masking" environment with Silicone oil, DGA lost many of its fault finding capabilities. One exception is acetylene that points to an active arcing. It is then very important to continually track the gas generation rates and operating history. Records, records, records!
  4. Oxygen level will be high during new and consumed over its life by the generation of CO and CO2.
  5. Any spike in O2, CO2 and N2 after a few plateau reading would very likely indicate a leak to atmosphere.
Due to the rather infancy stage of Silicone Oil usage, these gas limit extracts are use as a reference and will change over time as the world gain more experience dealing with them. Use it with care. This is a Doble 95% Norm limits of 299 operating transformers, which are more conservative in some way than IEEE limits.

Hydrogen                              511ppm
Methane                                134ppm
Ethane                                     26ppm
Ethylene                                  17ppm
Acetylene                                  1ppm
CO                                     1750ppm
CO2                                 15480ppm
Total Combustibles              2000ppm

Keep in mind that the amount of gas is not the key. The key is the generation rate of the gasses. Refer to IEC 60599 for the generation rates. G1 rates should raised concerns along with sampling rates increased and expert opinions seeked. G2 rates should be an immediate extreme concern that the reaching the L3 - high limit of IEEE will happen very quickly. Consideration should be taken to take it offline.

A reference of physical test limits for service-aged silicone fluid
Test                                     Acceptable limits      Unacceptable values indicated         ASTM method
Visual                                  Clear free of particles        Particulates, free water                     D1524, D2129
Dielectric breakdown                     30kV                     Particulates, dissolved water                      D877
Water content max.        70ppm(Doble) 100ppm (IEEE)  Dissolved water contamination              D1533
Power Factor max@25degC         0.2                           Polar/ionic contamination                         D924
Viscosity at 25degC, cSt          47.5-52.5                    Fluid degradation contamination                  D44
Acid number                        0.1(Doble) 0.2(IEEE)  Degradation of cellulose or contamination        D974

Reference of this article:
  1. Transformers: Basics, Maintenance, and Diagnostics - Reclamation, US Department of the Interior Bureau of Reclamation, April 2005.
  2. Trial-Use Guide for the Interpretation of Gases Generated in Silicone-Immersed Transformers, IEEE P1258, 1999.

Transformer Maintenance - Mineral Oils

Transformer maintenance used to be an all or nothing practices. Note that this is by no means a complete guide. It highlights some of the more critical parameters that a maintenance personnel should take note and hopefully gives you a sufficient overview of how complicated it is. A lot is to be considered in making an informed decision in regards to a transformer especially if it is a highly critical asset.

The best thing an asset owner can do to extend its life? Limit transformer operating temperature to 95 degree C.  Conservative estimates, every increase in 6 degree C halves the life of the insulation. In the field, the rule of thumb may be up to 10 degree C. Therefore, it is crucial to maintain the temperature instruments of transformer. Over the years, the instruments will be out of calibration. Some may be repaired, others may not. It is crucial to then compensate the annunciating point and hard & soft wired cooling system set point to continue operating under the safe set point. If left unchecked and uncompensated, it will lead to shorter transformer life and premature failure of the transformer.

Below is some of the critical parameters in DGA that one should take note. Oil sampling techniques and procedures are extremely important to get an accurate DGA result. Please have appropriately trained, experienced and skilled personnel for the task. I could not emphasize enough that it is a skill set by itself taking oil sample from transformer. A lot has to be considered and thought through from the materials of drain valves, oil collection techniques, temperature constraint of sampling window, humidity of environment, transformer oil tank pressure and etc. Surgical hygiene and precision is required to avoid minute contamination! We are talking about ppm, ppb level of contamination that is sufficient to cost you thousands of dollar of unnecessary down time and repair. Please utilise trained personnel for this task.

Transformer life is the life of the insulation. And the insulation degrades very rapidly with the presence of moisture and oxygen. Oxygen reading can be taken from DGA result. 3500ppm (volume ppm) or less should be brand new benchmark, 7000ppm should be a trigger to take action. Oxygen only comes from leaks and deteriorating insulation.

Insulation moisture of around 2% moisture by dry weight from DGA is the trigger point to begin degassing work and bring it back down to less than 1% at a cost of few cents per litre. It is far more cost effective to control moisture content from the outset. Average rate of water contamination in transformer with open-breathing conservators is around 0.2%/year. Membrane sealed conservator preservation system is around 0.03-0.06% per year. Water contamination will lead to swelling of insulation. Upon removal of moisture, the insulation will shrink back and loosening the clamp force of the core and coil. It is better to keep moisture level in check frequently than to suffer the consequences of repair. Note that water is distributed equally in the transformer when new. However, after some time of operation, it will congregate to cooler region, usually the lower one third of the insulation. Note down the sampling oil temperature (temperature at the bottom of transformer) and that should be able to assist in calculation of Moisture by Dry Weight to assist in decision making later. In the event that the lab does not provide M/DW percentage, refer to IEEE62-1995 - Myers Multiplier vs Temperature method. Then proceed to recheck with General Electric nomogram method which will give slightly higher reading. Do not make a dry out decision on a single DGA reading, it should be based on trends over a period of time. Once confirmed twice that W/DW is more consistently higher than 2% and oil is 30% saturated or more, arrange dry out as soon as possible.

Interfacial Tension should be determined along with the DGA. Good clean oil comes in on IFT number of 40-50 dynes per centimeter of travel of the wire. Oil needs to be urgently reclaimed at 25 dynes per centimeter, as sludge will start forming around 22 dynes per centimeter. Acid number also provides an indication of sludge formation. Acid number 0.4 is where sludging begins. Based on the data collected and published in AIEE transactions in 1955, you should hit the IFT limit 3-4 years before you reach that acid number anyway. The curve published seems to indicate the IFT number should cross with the acid number around the 0.2 mark making that the most cost effective point to carry out the reclaim. Useful to keep the acid number behind your mind in case IFT number is not indicating too much. Keep in mind acid buildup also accelerates insulation degradation and attacks the cellulose of the paper. Brand new oil should contain practically no acid as they are formed through the oxidation of insulation and oils as the transformer ages.

As mentioned before, oxygen inhibitor is a key item to extending life of transformers. Commonly used inhibitor is ditertiary butyl paracresol (DBPC). It acts as a sacrificial anode and oxygen would attack the inhibitor instead of the cellulose insulation. It will eventually be used up and should be tested for its presence. Ideal amount of DBPC is 0.3% by total weight of the oil. 0.1% reading is the trigger point to carry out re-inhibitation on the oil.

When cellulose insulation decomposes due to overheating, organic compounds are also formed. These chemical compounds are called furanic compounds or furans. Furans testing is to be included as part of DGA. It provides a reliable indicator for paper deterioration. Healthy transformer furans level should be non detectable or less than 100ppb. It is important to trend this reading. With thermally upgraded paper, Total Furans reading exceeds 1000ppb, the transformer has an estimated 40% life remaining. 1600ppb indicates a high risk of failure, where 2500ppb is essentially end of life. With non-thermally upgraded paper, 2200ppb of 2FAL is considered as excessive aging danger zone with 40% life remaining. 3800ppb carries a high risk of failure with 7300ppb is effectively end of life. Testing is completed for five different furans with different causes by different problems. The more common known causes are listed below:

  • 5H2F (5-hydroxymethyl-2-furaldehyde) caused by oxidation (aging and heating) of paper.
  • 2FOL (2-furfurol) caused by high moisture in the paper
  • 2FAL (2-furaldehyde) caused by overheating
  • 2ACF (2-acetylfuran) caused by lightning (rarely found in DGA)
  • 5M2F (5-methyl-2-furaldehyde) caused by local severe overheating (hotspot)

Along with the DGA, Dielectric Breakdown Voltage, 1mm gap, D1816 should be specified, and it should return a minimum of 28kV result. D877 is not as sensitive ti dissolved water and should not be used with oils for Extra-HV equipment. Dielectric breakdown tests do not replace specific tests for water content. (D1816, D877 and etc are all testing standards specified by ASTM)

DGA should be conducted regularly to confirm the trend. Any abnormal spike should be re-sample and tested to confirm the spike prior to determining cause and action. The above practices would allow the transformer to reach its designed life without too much issues (est 40 Years) provided the basic cleaning regime are covered and small corrective maintenance activities carried out without delay. Dynamic rating equipment for transformer is highly recommended.

Reference of this article:
  1. Transformers: Basics, Maintenance, and Diagnostics - Reclamation, US Department of the Interior Bureau of Reclamation, April 2005.
  2. Transformer Mid-Life Refurbishment - Prevention or Cure? - Kenneth J.Budin, Wilson Transformer Co. Pty. Ltd. TechCon 2001 paper.
  3. IEEE C57.12.90 - 1999
  4. IEEE 62 - 1995

Transformer Maintenance - Tests

If generation of ethylene, ethane and perhaps methane in the DGAs indicates a poor connection, winding resistance should be checked. Turns ratio, sweep frequency response analysis (SFRA), Doble tests or relay operations may give indications that dc testing is warranted. Winding resistances are tested in the field to check for loose connections on bushings or tap changers, broken strands, and high contact resistance in tap changers. Results are compared to other phases in wye-connected transformers or between pairs of terminals on a delta-connected winding to determine if a resistance is too high. Resistance can also be compared to the original factory measurements or to sister transformers. Agreement within 5% of the comparisons is considered satisfactory.

If winding resistances are to be compared to factory values, resistance measurements will have to be converted to the reference temperature used at the factory usually 75deg C. Formula to use:

                                                                            Ts + Tk
                                                           Rs = Rm ------------
                                                                            Tm + Tk
Rs  =  Resistance at the factory reference temperature (found in transformer manual)
Rm =  Resistance you actually measured
Ts  =  Factory reference temperature (usually 75deg C)
Tm =  Temperature at which you took the measurements
Tk  =  Constant for the particular metal the winding is made from: 234.5deg C for copper, 225deg C for aluminium.

Note that it is very difficult to determine winding temperature in the field. Phase resistance comparison between each other or sister transformer of similar temperature are usually sufficient. Do ensure temperature are equalized within the windings after de-energization.

Core insulation resistance and core ground test is used if an unintentional core ground is suspected. Ethane and/or ethylene and possibly methane would flag up in DGA. These gases may also be present if there is a poor connection at the bottom of a bushing or a bad tap changer contact. This test is only necessary if winding resistance test did not pick up anything on all connections and tap changer contacts. If it is to be Megger-ed, use 1000V Megger. 1000MOhm min is expected on new transformer, service aged transformer should read greater than 100MOhm. 10-100MOhm reading is an indicative of deteriorating insulation between core and ground. 10MOhm is sufficient to cause destructive ciculating currents and not recommended to be return to service so as to Zero Ohm. "Burning off" using dc or ac current is possible but extremely risky. Do not perform without consultation from manufacturer and with others experienced in this task. DGA should be conducted before and after the burn off.

Doble testing is highly recommended to determine the condition of a transformer, because it can detect winding and bushing insulation integrity and problems in the winding and core. The Doble test set should also include the Insulation Power Factor test, results should not exceed 0.5%@20degC. From my personal experience with Doble equipments, their software do track the history provided the maintenance personnel store that history and load them up for analysis. Doble as a company in general have been very easy to dealt with from my experience.

Capacitance test should also be conducted. They are a meaqsurements between HV & LV windings, HV & ground, LV and ground. Values changes as transformer ages, events occur such as lightning strikes, through faults, indication of winding deformation and structural problems such as displaced wedging and winding support.

Excitation current test is to be carry outto detect short-circuited turns, poor electrical connections, core de-laminations, core lamination shorts, tap changer problems and other possible core and winding problems. Results are often compared between phases. Please consult Doble manual and support for result interpretation. Rule of thumb, on the two higher currents with excitation less than 50mA, differences between the two high currents should be less than 10%. Excitation of more than 50mA would close the difference down to less than 5%. In general, if there is an internal problem, these differences will be greater. Again, trend the results.

Bushing should be tested using Doble Power Factor testing on a scheduled basis. Deterioration will be evident from the trend. 90% of bushing failures may be attributed to moisture ingress, evidenced by an increasing power factor trend.

Other than that are the common stuff such as winding temperature gauge, pressure relief valve, bucholz relay, conservator bladder and breather, cooling fans, cooling oil flow, cooling oil isolation valves, cooling fan motor, oil leaks, and etc. DGA should also specify for dissolved metals and metal particle count for metals if transformer cooling runs on oil pump bearings. There is a risk of flashover inside the tank resulting catastrophic failure.

If there is an opportunity to carry out internal inspection, DP test can be carry out by sampling the center phase with a pair of tweezers. Center phase is usually the hottest most part of a transformer. New insulation DP value would be between 1000 to 1400. At 500DP, it is around 60-66% of life remaining. At 300DP, 30% of life remaining. 200DP is end of life.

Most cases, an internal inspection does more harm than good. Therefore a good reason has to be established prior to opening up a transformer. Good reasons such as listed below are justifiable:

  • Extensive testing shows serious problems.
  • Unexplained relay operation takes the transformer offline, and testing is inconclusive.
  • Acetylene is being generated in DGA (indicating active arcing)
  • Ethylene and ethane are being generated in sufficient quantities to cause grave concern. Indicating bad connection on bushing bottom or tap changer, circulating currents, additional core ground or static discharges.
  • A core ground must be repaired, or an additional core ground has developed which must be removed.
  • Vibration and ultrasonic analysis indicate loose windings that are generating gasses from heat caused by friction of the vibrating coils; loose wedges must be located and replaced.
  • CO2/CO ratio are very low (2 to 3), indicating severe paper deterioration from overheating. Cooling must be checked carefully before opening the transformer.
  • Furans are high indicating excessive aging rate; a DP test must be carry out.
  • Metal particle count is above 5000 in 10ml of oil taken specifically for metal particle count.

You would noticed that these reasons are justifiable as any further delay may result to catastrophic failure. Which the maintenance personnel should ask, is there a point packaging a DP test if the issues are already that severe. The slight additional cost and work is up to individual site to justify.

Reference of this article:
  1. Transformers: Basics, Maintenance, and Diagnostics - Reclamation, US Department of the Interior Bureau of Reclamation, April 2005.

Friday, 9 November 2012

LV Motor Maintenance

Motor maintenance are split into Predictive and Preventive.

1. Motor bearing lubrication. Typically motor frame size D180 inclusive and below are sealed for life bearings. Anything larger are greased as frequent as every 1000hrs. Refer to their respective manual for accurate greasing requirements.

2. Cooling fins and fans clean up. Frequency depends on operating environment. In generally clean environment, 4-8 yearly is acceptable. Increase accordingly to its operating environment. Note that in particularly post OH/ outage, plant will have bits and pieces of wrapping papers and plastics. That tend to get suck onto the ventilation guard of the fans blocking up cooling path. Thus I recommend performing this work post OH.

3. Alignment check should be perform on annual or 2 yearly basis particularly when new as the foundation sinks into place. It can later be extended to 4 yearly or as required based on VA.

4. VA is to be performed monthly, 3 monthly or 6 monthly depending on criticality of the motor. That should also pick up a range of other failure modes.

5. Terminals and glands is to be inspected 2 yearly in extreme processing operating environment, 5 or 10 yearly in a clean factory environment.

6. Thermography to be carried out monthly to check for anomalies and hot spot on motor and connections.

1. Measurement and trending of insulation resistance. For motor rated below 1000V, it is measured with a 500Vdc megger. (TECO manual extract)

2. In accordance with IEEE-43 clause 9.3 standards at the time of writing, the formula to calculate an acceptable limit is:

                      R => [ (Rated Voltage (V)/ 1000) + 1 ] x 10MegOhm

3. I recommend performing Motor Circuit Analysis (MCA) commencing with 2 years interval until sufficient data for trending (3-5 points), before extending to 4 years interval or more. It is a quick easy NDT that gives fairly good reliable indication of motor health whether it will survive another 2 or 4 years, or till your next available replacement opportunity.

4. On HV motors, I also recommend installing partial discharge monitoring equipment. Especially critical motors, it is better to go online PD monitoring. Trending data should indicate the deterioration rate of PD. Maintenance personnel should start taking concern and planning shall the PD deteriorates at a rate of double every 6 months or any anomalies.

Tuesday, 6 November 2012


I will continue to expand this list as my blog entry grows! :)

AM - Asset Management

AS - Australian Standard

BSI - British Standards Institution

CMMS - Computerized Maintenance Management System

EPC - Engineering, Procurement and Construction (have their own labour for construction)

EPCM - Engineering, Procurement and Construction Management (does not have their own labour for construction)

HV - High Voltage (AS3000 definition)

ISO - International Organization for Standardization

LV - Low Voltage (AS3000 definition)

MCA - Motor Circuit Analysis

MTBF - Mean Time Before Failure

MTTR - Mean Time To Repair

MV - Medium Voltage

NDT - Non-Destructive Testing

OEM - Original Equipment Manufacturer

OH - Overhaul

OPEX - Operating Expenditure

PAS - Publicly Available Specification

PD - Partial Discharge

VA -Vibration Analysis


Ah! Failed equipment! Why? Wear! Wear & tear! We have all heard that frequent enough. When I first started my career as an engineer, I accepted that as a form of failure mode so to speak. Things wear, components wear after use, and it is acceptable. Am I right?

No! Wear is NOT a failure mechanism. It is far from being a failure mechanism. A failure mechanism can be dealt with through some form of maintenance (not replacement). It is an overly vague term to be used as a failure mechanism. It is exactly like seeing a failure notification in CMMS that says equipment is f*cked! It does not add any value at all. As a maintenance personnel, you cannot tell anything out of that notification. As a reliability analyst, there is no useful data for you to analyse.

I came across a failure mechanism list developed by a consultant for their clients. In there, was Wear. Caused pointed towards cavitation, rubbing, fretting, abrasion and erosion. Lets dwell deeper on what is wrong about that.

Cavitation itself is a failure mechanism, and it is caused by insufficient head pressure. A pump specification will give you head required to prevent cavitation becoming an issue up to its useful life probably around the 15-20 years mark depending on manufacturer. To design cavitation out totally, make sure there's a good 30-50% more head that it needs be on top of the recommended head on specification sheet. Rubbing and fretting are again failure mechanism, they are likely caused by improper design or installation. Abrasion and erosion are again failure mechanism that are likely caused by improper material use or highly abrasive material handling. The failure mechanisms all have individual cause and different way to manage. Is it clearer now that wear is not suitable to be used as a failure mechanism? It is incapable of pin pointing a method to "fix" wear.

Wear is a consequence of a failure mechanism due to a cause. Wear by itself is not a failure mode. It can be use as a simplified technical term for the business minded management team to understand, but it should never exist in the technical team itself. If you are a manager to a technical team, use your words concisely as a technical person. It drives the maintenance culture which affects the reliability bottom line. Excellent maintenance culture is 50% of a high reliability plant, and a reliable plant, is a safe plant.

Till then, stay reliable, stay safe.

Friday, 2 November 2012

Bearing Failure reference 1

I subscribed to a reliability newsletter from machinery lubrication. Read this article in the email today and find it a good basic guide to bearing failure.

5 Ways to Prevent Bearing Failures


The accurate diagnosis of a bearing failure is imperative to prevent repeat failures and additional expense. Rolling bearings are precision machine elements found in a wide variety of applications. They are typically very reliable even under the toughest conditions. Under normal operating conditions, bearings have a substantial service life, which is expressed as either a period of time or as the total number of rotations before the rolling elements or inner and outer rings fatigue or fail. According to research, less than 1 percent of rolling bearings do not reach their expected life.

You must be aware of the radial internal
clearance (RIC) and maintain the proper
RIC that was established in the
original design.

Premature Bearing Failure

When a bearing does fail prematurely, it usually is due to causes that could have been avoided. For this reason, the possibility of reaching conclusions about the cause of a defect by means of studying its appearance is very useful. It’s most important to correct the causes and prevent future failures and the costs that follow.
Most bearing failures such as flaking, pitting, spalling, unusual wear patterns, rust, corrosion, creeping, skewing, etc., are usually attributed to a relatively small group of causes that are often interrelated and correctable. These causes include lubrication, mounting, operational stress, bearing selection and environmental influence.

Proper Lubrication

The purpose of lubricating a bearing is to cover the rolling and sliding contact surfaces with a thin oil film to avoid direct metal-to-metal contact. When done effectively, this reduces friction and abrasion, transports heat generated by friction, prolongs service life, prevents rust and corrosion, and keeps foreign objects and contamination away from rolling elements.
Grease typically is used for lubricating bearings because it is easy to handle and simplifies the sealing system, while oil lubrication is more suitable for high-speed or high-temperature operations.
Generally, lubrication failures occur due to:
  • Using the wrong type of lubricant
  • Too little grease/oil
  • Too much grease/oil
  • Mixing of grease/oil
  • Contamination of the grease/oil by objects or water

Grease Service Life

In addition to the normal bearing service life, it is also important to take into consideration the normal grease service life. Grease service life is the time over which proper bearing function is sustained by a particular quantity and category of grease. This is especially crucial in pump, compressor, motor and super-precision applications.

Mounting and Installation of Bearings

In the mounting and installation process, it is critical to use proper tools and ovens/induction heaters. Employ a sleeve to impact the entire inner ring face being press fit. Also, verify the shaft and housing tolerances. If the fit is too tight, you will create too much preload. If the fit is too loose, you will generate too little preload, which may allow the shaft to rotate or creep in the bearing. Don’t forget to check for proper diameters, roundness and chamfer radius.
Be sure to avoid misalignment or shaft deflection. This is particularly significant in mounting bearings that have separable components such as cylindrical roller bearings where successful load bearing and optimal life are established or diminished at installation.
You must also be aware of the radial internal clearance (RIC) and maintain the proper RIC that was established in the original design. The standard scale in order of ascending clearance is C2, C0, C3, C4 and C5. The proper clearance for the application is important in that it allows for the challenges of lubrication, shaft fit and heat.
Keep in mind that a proper film of lubricant must be established between the rolling elements. Reducing internal clearance and impeding lubricant flow can lead to premature failure. With regards to shaft fit, it is inevitable that there can be a reduction in the radial internal clearance when the bearing is press fit. Also, in the normal operation of bearings, heat is produced, which creates thermal expansion of the inner and outer rings. This can reduce the internal clearance, which will reduce the optimal bearing life.

Causes of failure in rolling bearings

Operational Stress and Bearing Selection

Generally, it is the exception to find a bearing that has been improperly designed into an application. However, factors within the larger application may change. If loads become too high, overloading and early fatigue may follow. If they are too low, skidding and improper loading of the rolling elements occur. Early failure will follow in each situation. Similar issues arise with improper internal clearance.
The first sign of these issues will be unusual noises and/or increased temperatures. Bearing temperatures typically rise with start-up and stabilize at a temperature slightly lower than at start-up (normally 10 to 40 degrees C higher than room temperature). A desirable bearing temperature is below 100 degrees C.
There are typical abnormal bearing sounds that reveal certain issues in the bearing application. While this is a subjective test, it is helpful to know that a screech or howling sound usually indicates too large an internal clearance or poor lubrication on a cylindrical roller bearing, while a crunching felt when the shaft is rotated by hand normally suggests contamination of the raceways.
Operational stresses in the application can impact bearing life as well. It is essential to isolate vibrations in associated equipment, as they can cause uneven running and unusual noises.

Environmental Influence

Even with the best design, lubrication and installation, failures will occur if the operating environment is not taken into consideration. While there are many potential issues, the primary ones include:
  • Dust and dirt, which can aggressively contaminate a bearing. Special care should be given to using proper sealing techniques.
  • Aggressive media or water. Once again, sealing is key. The use of specialty-type seals that do not score the shaft is recommended.
  • External heat. The ambient operating temperature mandates many choices in radial internal clearance, high-temperature lubricants, intermittent or continuous running and other factors that affect bearing life.
  • Current passage or electrolytic corrosion. If current is allowed to flow through the rolling elements, sparks can create pitting or fluting on the bearing surfaces. This can be corrected by creating a bypass circuit for the current or by using insulation on or within the bearing. This should be an inherent design consideration in applications such as wind turbines and all power-generating equipment.
Remember, the first step in the overall prevention of bearing failure lies in the consideration of bearing technologies that are most suitable to the application with regard to specifications, recommendations, maintenance strategies, fatigue life and wear resistance of the bearing. Premature bearing failure within a proper application is typically attributed to one or more of the causes discussed (lubrication, mounting, operational stress, bearing selection or environmental influence), which can and should be corrected in order to avoid future bearing failures and additional cost.

About the Author

Steven Katz is the president of Emerson Bearing, a provider of bearings to OEMs (original equipment manufacturers) and MRO (maintenance, repair and operations) markets in the United States and internationally. For more information, contact 800-225-4587 or

Thursday, 1 November 2012

Asset Management

An overview of Asset Management can be easily found on the internet. It started from PAS55 Part 1 and Part 2 developed under BSI. ISO took that as a reference and beginning to develop ISO55000 series that are very similar to PAS55 in many aspects.

In short, it is a plan that details the work from cradle to grave for an asset. Ideally, a capital project should have a competent Asset Management or Reliability team involved since the feasibility studies stage. Multiple times have I walked into plant that have no idea what they are doing, and how they are performing in relation to the target business objectives. AM Plan is laid out just for that purpose, to meet the expectations and business objectives right from the start.

In a nutshell, it is slightly more detailed than a car servicing logbook. Each components/ equipment came with a designed operating life and maintenance is scheduled to extend its useful economic life until replacement is inevitable. Apply that detailed planning onto a full blown process plant, and that is AM in a nutshell, extremely simplified version.

I have been involved in steel manufacturing industry, petrochemical industry, power generation industry and recently joined consulting in the area of Asset Management. Hopefully, I would share some information in the future that would benefit all of interested readers! :))