Facility Maintenance Procedure

This documentation shall detail the procedure related to works and documentations of maintenance team in PT Eins Trend, Purwakarta, Jawa Barat. Procedure related to works and documentation in this work shall be put together from Power Generation and Transmission best practice and PT Eins Trend corporate industrial standard.
Scope of Work
The scope of work of this procedure shall be maintenance procedures on specific utility items as follows:
1. Generator Sets c/w Diesel Engines
2. Step Down Transformers
3. Boilers (Tubeless Steam Generators)
4. Pumps (Centrifugal Pumps)
5. Electric Motors
6. Compressors (Screw Type Compressors)
7. Tanks (Atmospheric Storage Tanks)
Industrial Standards
Generators
General: Generators and their associated wiring and equipment shall also comply with the applicable provision of Industrial Standards of IEC 34-1.
Location: The Generators shall be inside the Generators House which is suitable for safe and efficient operation.
Marking: Each generator shall be provided with a nameplate giving the maker’s name, the rated frequency, power factor, number of phases, the rating in kilowatts and kilovolt amperes, the normal volts and amperes corresponding to the rating, rated revolution per minute, insulation system class and rated ambient temperature or rated temperature rise and time rating.
Voltage Regulator: this automatic voltage regulator (AVR) is incorporated into the Stamford Permanent Magnet Generator (PMG) system and is fitted as standard to generators of this type.
The PMG provides power via the AVR to the main exciter, giving a source of constant excitation power independent of the generator output. The main exciter output is then fed to the main rotor, through a full wave bridge, protected by a surge suppressor. The AVR has in-built protection against sustained over-excitation, caused by internal or external faults. This de-excites the machine after a minimum of 5 seconds.
Over voltage protection is built in and short circuit current level adjustment is an optional facility.
Over current protection: Constant Voltage Generators, constant voltage generators, except AC generators exciters, shall be protected from overloads by inherent design circuit breakers, fuses, or other acceptable over current protective means suitable for the conditions of use.
Ampacity of Conductors: The Ampacity of the phase conductors from the generators terminals the first over current device shall not be less than 115 percent of the nameplate current rating of the generator. It shall be permitted to size the neutral conductor to 70% of the load on the ungrounded conductors.
Conductor that must carry ground fault currents shall not be smaller than specified by generator manufacturer.
Protection of Live Parts: Live Parts of generators shall not be exposed to accidental contact where accessible to unqualified persons.
Guards for Attendants: Suitable insulation mats or platforms shall be provided so that attendant cannot readily touch live parts unless standing on mats or platforms.
Windings and Electrical Performance:
The generator stators are wound to 2/3 pitch. This eliminates triplen (3rd, 9th, 15th…) harmonics on the voltage waveform and is found to be the optimum design for trouble free supply on non-linear loads. The 2/3 pitch design avoids excessive neutral currents sometimes seen with higher winding pitches, when in parallel with the mains. A fully connected damper winding reduces oscillations during paralleling. This winding, with the 2/3 pitch and carefully selected pole and tooth designs, ensures very low waveform distortion.
Terminals and Terminal Box: The generator feature a main stator with 6 ends brought out to the terminals, which are mounted on the frame at the non-drive end of the generator. A sheet steel terminal box contains the AVR and provides ample space for the customer’ wiring and gland arrangements. It has removable panels for easy access.
Bushings: Where wires pass through an opening in an enclosure, conduit box, or barrier, a bushing shall be used to protect the conductors from the edges of an opening having sharp edges. The bushing shall have smooth well rounded surfaces where it may be in contact with the conductors. If used where oils, grease or other contaminants may be present, the bushing shall be made of material not deleteriously affected.
Parallel operations of Generators: Obviously changing from one unit to another or connecting a generator in parallel with others must be carried out in such a manner that line disturbances do not occur, nor must users of electric energy be conscious of a power plant change. The process is called synchronizing.
Before a generator is connected to, or put on, a line that is already being served by one or more units, the following conditions must be fulfilled:
1. The effective voltage of the incoming machine must be approximately equal to the bus bar voltage, in this case +/- 0.5% X 380V
2. The frequency (f = P x rpm/120) of the incoming machine must be exactly the same as that of the bus bars, in this case 0.1Hz/sec on 50Hz
3. The phase sequence of the three phases of the incoming machine must be the same as that of the bus bars. This means that if the bus bar voltage VAB is 120O ahead of VBC, and VBC is 120O ahead of VCA, then the incoming machine must have its three phases connected to bus bars A, B and C, so that VAB is 120O ahead of VBC, and VBC is 120O ahead of VCA, here we use L1-L2-L3 terminology.
4. Phase-angle (Phasor); With condition 3 fulfilled, it is necessary that at the instant when paralleling switch is closed, voltage VAB of the incoming machine must be in phase opposition to the bus bar voltage VAB; under this condition, the voltages VBC and VCA of the incoming machine and the bus bars will also be in phase opposition. This implies that there will be no circulating current between the windings of the alternators already in operation (the bus bars) and the incoming machine, in this case +/- 10O
And last the circuit breaker closing time is 50ms.

Fault Finding, MX321 & MX341 AVRs
Ensure engine-starting circuits are disabled before commencing service or maintenance procedures. Isolate any anti-condensation heater supply.
Note: Before commencing any fault finding procedures examine all wiring for broken or loose connections.

No voltage build-up when
starting set 1) Check link K1&K2 on auxiliary terminals. Follow Separate Excitation
2) Test Procedure to check machine and AVR.
Voltage very slow to build
Up Check setting of ramp potentiometer. MX321 only

Loss of voltage
When set running First stop and restart set. If no voltage or voltage collapses after short time, follow Separate Excitation Test Procedure.
Generator Voltage high
followed by collapse 1) Check sensing leads to AVR.
2) Carry out Separate Excitation Test Procedure.
Voltage unstable, either on
no-load or with load 1) Check speed stability.
2) Check “STAB” setting. Refer to Load Testing section for procedure.
Low voltage
On-load 1) Check speed.
2) If correct check “UFRO” setting.
Excessive voltage / speed
Dip on load Switching 1) Check governor response. Refer to generating set manual.
2) Check “DIP” setting.
Sluggish recovery on load
switching Check governor response. Refer to generating set manual.

Separate Excitation Test Procedure
Important: The resistances quoted apply to a standard winding. For generators having windings or voltages other than those specified refer to factory for details. Ensure all disconnected leads are isolated and free from earth.
Important: Incorrect speed setting will give proportional error in voltage output.

Checking the Permanent Magnet Generator (PMG)
Start the set and run at rated speed.
Measure the voltages at the AVR terminals P2, P3 and P4. These should be balanced and within the following range: 50Hz generators - 170-180 volts. Should the voltages be unbalanced stop the set, remove the PMG sheet metal cover from the non-drive end bracket and disconnect the multi-pin plug in the PMG output leads. Check leads P2, P3, and P4 for continuity. Check the PMG stator resistances between output leads. These should be balanced and within +/-10% of 2.6 ohms for the 4 pole generators. If resistances are unbalanced and/or incorrect the PMG stator must be replaced. If the voltages are balanced but low and the PMG stator winding resistances are correct - the PMG rotor must be replaced.

Checking Generator Windings and Rotating Diodes
This procedure is carried out with leads F1 & F2 (X and XX) disconnected at the AVR or and using a 12 V dc supply connected to leads F1 & F2 (X and XX).
Start the set and run at rated speed.
Measure the voltages at the main output terminals U, V and W. If voltages are balanced and within +/-1% of the generator nominal voltage, go to section on ‘Balanced Main Terminal Voltages’
Check voltages at AVR terminals 6, 7 and 8. These should be balanced and between 170-250 volts.
If voltages at main terminals are balanced but voltage at 6, 7 and 8 are unbalanced, check continuity of leads 6, 7 and 8. Where an isolating transformer is fitted (MX321 AVR) check transformer windings. If faulty the transformer unit must be replaced.
If voltages are unbalanced, refer to the section on ‘Unbalanced Main Terminal Voltages’.
Balanced Main Terminal Voltages
If all voltages are balanced within 1% at the main terminals, it can be assumed that all exciter windings, main windings and main rotating diodes are in good order, and the fault is in the AVR. Refer the section for the ‘AVR Function Test’.
If voltages are balanced but low, there is a fault in the main excitation windings or rotating diode assembly.

Check Rectifier Diodes
The diodes on the main rectifier assembly can be checked with a multi-meter. The flexible leads connected to each diode should be disconnected at the terminal end, and the forward and reverse resistance checked. A healthy diode will indicate a very high resistance (infinity) in the reverse direction, and a low resistance in the forward direction. A faulty diode will give a full deflection reading in both directions with the test meter on the 10,000 ohms scale, or an infinity reading in both directions. On an electronic digital meter a healthy diode will give a low reading in one direction, and a high reading in the other.

Replacement of Faulty Diodes
The rectifier assembly is split into two plates, the positive and negative, and the main rotor is connected across these plates. Each plate carries 3 diodes, the negative plate carrying negative biased diodes and the positive plate carrying positive biased diodes. Care must be taken to ensure that the correct polarity diodes are fitted to each respective plate. When fitting the diodes to the plates they must be tight enough to ensure a good mechanical and electrical contact, but should not be over tightened. The recommended torque tightening is 4.06 - 4.74Nm (36-42 lb in).

Surge Suppressor
The surge suppressor is a metal-oxide varistor connected across the two rectifier plates to prevent high transient reverse voltages in the field winding from damaging the diodes. This device is not polarized and will show a virtually infinite reading in both directions with an ordinary resistance meter. If defective this will be visible by inspection, since it will normally fail to short circuit and show signs of disintegration. Replace if faulty.

Main Excitation Windings
If after establishing and correcting any fault on the rectifier assembly the output is still low when separately excited, then the main rotor, exciter stator and exciter rotor winding resistances should be checked (see Resistance Charts), as the fault must be in one of these windings. The exciter stator resistance is measured across leads F1 & F2 (X and XX). The exciter rotor is connected to six studs, which also carry the diode lead terminals. The main rotor winding is connected across the two rectifier plates. The respective leads must be disconnected before taking the readings.
Resistance values should be within +/-10% of the values given in the tables at the back of this manual.

Unbalanced Main Terminal Voltages
If voltages are unbalanced, this indicates a fault on the main stator winding or main cables to the circuit breaker.
Note: Faults on the stator winding or cables may also cause noticeable load increase on the engine when excitation is applied.
Disconnect the main cables and separate the winding leads U1-U2, (U5-U6), V1-V2, (V5-V6), W1-W2, (W5-W6) to isolate each winding section.
Note: Leads suffixed 5 and 6 apply to 12 wire windings only.
Measure each section resistance - values should be balanced and within +/-10% of the value given at the back of this manual
Measure insulation resistance between each phase and each phase to earth
Unbalanced or incorrect winding resistances and/or a low insulation resistance to earth indicates defective or contaminated windings. See Winding condition in the Service Section.
Cleaning the windings requires specialist equipment and is therefore beyond the scope of this manual.

Excitation Control Test
AVR Function Test
Remove exciter field leads X & XX (F1 & F2) from the AVR terminals X & XX (F1 & F2).
Connect a 60W 240V household lamp to AVR terminals X & XX (F1 & F2).
Set the AVR VOLTS control potentiometer fully clockwise.
Connect a 12V; 1.0A DC supply to the exciter field leads X & XX (F1 & F2) with X (F1) to the positive.
Start the generating set and run at rated speed.
Check that the generator output voltage is within +/- 10% of rated voltage.
Voltages at P2, P3, P4 terminals can be found in the data section of this manual
If the generator output voltage is correct but the voltage on 7-8 (or P2- P3) is low, check auxiliary leads and connections to main terminals.
The lamp connected across X & XX should glow for approximately 10 seconds and then turn off. Failure to turn off indicates faulty protection circuit and the AVR should be replaced. Turning the "VOLTS" control potentiometer fully anti-clockwise should turn off the lamp.
Should the lamp fail to light, the AVR is faulty and should be replaced.
Important After this test turn VOLTS control potentiometer fully anti-clockwise.
To reset the voltage, start the generating set and run on no-load at nominal frequency. Slowly turn VOLTS control potentiometer clockwise until rated voltage is reached.

Procedure for Insulation Testing
1. Disconnect all electronic components, AVR, electronic protection equipment etc. Ground the RTD's (Resistance Temperature Detection devices) if fitted.
2. Short out the diodes on the rotating diode assembly. Be aware of all components connected to the system under test that could cause false readings, or be damaged by the test voltage.
3. Carry out the insulation test in accordance with the ‘operating instructions’ for the test equipment.
4. The measured value of insulation resistance for all windings to earth and phase to phase should be compared with the guidance given above for the various 'life stages' of a generator. The minimum acceptable value is 1.0 Megohm on a 500V megger.
If low winding insulation is confirmed, one or more of the methods, given below, for drying the winding should be carried out.

Methods of Drying Out Generators:
1. Cold Run
In the case of a generator in otherwise good condition that has not been run for some time, and has been standing in damp, humid conditions a simple procedure may suffice. It is possible that simply running the generator set unexcited – AVR terminals “K1” “K2” open circuit - for a period of say 10 minutes will sufficiently dry the surface of the windings and raise the IR to greater than 1.0 Megohm, and so allow the unit to be put into service.
2. Blown Air Drying
Remove the covers from all apertures to allow the escape of the water-laden air. During drying, air must be able to flow freely through the generator in order to carry off the moisture. Please direct hot air from two electrical fan heaters of around 1 – 3 kW into the generator air inlet apertures. Ensure the heat source is at least 300mm away from the windings to avoid over heating and damage to the insulation.
Apply the heat and plot the insulation value at half hourly intervals. The process is complete when the parameters covered in the section entitled, ‘Typical Drying-Out Curve’, are met. Remove the heaters, replace all covers and re-commission as appropriate. If the set is not to be run immediately ensure that the anti-condensation heaters are energized, and retest prior to running.

Short Circuit Method:
Ensure the generator is safe to work on, initiate all mechanical and electrical safety procedures pertaining to the generator set and the site.
Caution: The short circuit must not be applied with the AVR connected in circuit.
Current in excess of the rated generator current will cause damage to the windings.
1. Bolt a short circuit of adequate current carrying capacity, across the main terminals of the generator. The shorting link should be capable of taking full load current.
2. Disconnect the cables from terminals “X” and “XX” of the AVR.
3. Connect a variable dc supply to the “X” (positive) and “XX” (negative) field cables. The dc supply must be able to provide a current up to 2.0 Amp at 0 - 24 Volts.
4. Position a suitable ac ammeter to measure the shorting link current.
5. Set the dc supply voltage to zero and start the generating set. Slowly increase the dc voltage to pass current through the exciter field winding. As the excitation current increases, so the stator current in the shorting link will increase. This stator output current level must be monitored, and not allowed to exceed 80% of the generator’s rated output current.
6. After every 30 minutes of this exercise: Stop the generator and switch off the separate excitation supply, measure and record the stator winding IR values, and plot the results. The resulting graph should be compared with the classic shaped graph. This drying out procedure is complete when the parameters covered in the section entitled 'Typical Drying-Out Curve' are met.
7. Once the Insulation Resistance is raised to an acceptable level - minimum value 1.0 Megohm the dc supply may be removed and the exciter field leads “X” and “XX” re-connected to their terminals on the AVR.
8. Rebuild the generator set, replace all covers and re-commission as appropriate.
9. If the set is not to be run immediately ensure that the anti-condensation heaters are energized, and retest the generator prior to running.
Typical Drying Out Curve
Whichever method is used to dry out the generator the resistance should be measured every half-hour and a curve plotted as shown








1) Y axis = Resistance
2) X axis = Time
3) One Megohm limit






The illustration shows a typical curve for a machine that has absorbed a considerable amount of moisture. The curve indicates a temporary increase in resistance, a fall and then a gradual rise to a steady state. Point ‘A’, the steady state, must be greater than 1.0 Megohm (If the windings are only slightly damp the dotted portion of the curve may not appear).
For general guidance, expect that the typical time to reach point ‘A’ will be around 3 hours.
Drying should be continued after point “A” has been reached for at least one hour.

It should be noted that as winding temperature increases, values of insulation resistance may significantly reduce. Therefore, the reference values for insulation resistance can only be established with windings at a temperature of approximately 20°C.
If the IR value remains below 1.0 Megohm, even after the above drying methods have been carried out correctly, then a Polarization Index test [PI] should be carried out.
If the minimum value of 1.0 Megohm for all components cannot be achieved, rewinding or refurbishment of the generator will be necessary.
Caution: The generator must not be put into service until the minimum values are achieved.
After drying out, the insulation resistances should be rechecked to verify the minimum resistances quoted above are achieved. On re-testing it is recommended that the main stator insulation resistance is checked as follows:
Separate the neutral leads
Ground V and W phase and megger U phase to ground
Ground U and W phase and megger V phase to ground
Ground U and V phase and megger W phase to ground
Caution: The generator must not be run if the minimum insulation value of 1.0 Megohm is not obtained.
Air Filters
Air filters for the removal of airborne particulate matter (dust) are offered as an addition to the standard build option. The filter elements do not remove and must not be allowed to get wet.
The frequency of filter maintenance will depend upon the severity of the site conditions. Regular inspection of the elements will be required to establish when cleaning is necessary.
Caution: Do not charge filters with oil.
Warning: Removal of filter elements enables access to LIVE parts. Only remove elements with the generator out of service.
Air Filter Cleaning Procedure:
1. Remove the filter elements from the filter frames, taking care not to damage them.
2. Invert the filters dirty side down and agitate to remove particles of dirt.
To remove stubborn particles low-pressure air can be used, in the reverse direction of flow, to force out stubborn particles.
If necessary use a soft brush to gently brush off any remaining dirt particles.
3. Clean the sealing gaskets and surrounding area.
4. Visually check the condition of the filter elements and sealing gaskets, replace as necessary.
5. Ensure that the filter elements are dry before putting them back into service.
6. Carefully replace the filter elements

Transformers
The word transformer is intended to mean an individual transformer identified by a single nameplate. This procedure is intended specifically for the 2 X 2500 KVA main step down 20/0.4kV power distribution transformers located next door to the generator sets.
Tank Ground: The first electrical connection made must be to ground the transformer tank. This connection is made from the tank ground pad to a permanent low-impedance ground. The tank ground must also be connected to the system ground.
External Electrical Connection: Make only the connections and operate only at the voltages authorized by the information on the transformer name plate. The available transformer neutrals should be connected to the system neutrals. Each lead and connection not in-use should be insulated from ground and from all other leads and connections.
Tap Changer: The tap changer must not be operated while the transformer is energized.
Venting: Always release any possible pressure in the tank by carefully venting the pressure-relief valve before attempting to remove hand-hole covers or similar covers, including relief diaphragms and shipping covers (when used).
Insulation Oil Level: Oil must be at the proper level before voltage is applied to the transformer.
HV and LV Bushing: Remove all dirt and foreign material from all bushings before placing the unit in service. Do not operate beyond the manufacturer’s rating.
Over current protection: over current protection of transformers shall comply with (a), (b), or c(c) below. The secondary over current device shall be permitted to consist of not more than six circuit breaker or six sets of fuses grouped in one location. Where multiple over current devices are utilized the total of all the device ratings shall not exceed the allowed value of a single over current device. If both breakers and fuses are utilized as the over current device, the total of the device ratings shall not exceed the allowed for fuses.
Maximum rating or setting for over-current device
Primary Secondary
20,000 Volts 6300 Volts 400 Volts
Transformer Rated Impedance Circuit Breaker Setting Fuse Rating Circuit Breaker Setting Fuse Rating Circuit Breaker Setting or Fuse Rating
Not More than 6% 600% 300% 300% 250% 250%
More than 6% and not more than 10% 400% 300% 250% 225% 250%

Transformer Internal Inspection
De-energize the transformer before attempting any internal inspection. Always release any pressure in the tank.
If the transformer must be opened for internal inspection, take proper precautions to prevent the entrance of moisture and other foreign matter into the transformer.
Clean off the tank cover before removing the hand-hole cover.
For access, remove the hand-hole cover. Place the hand-hole gasket bolts and washers in storage for reuse.
Examine the underside of the cover for signs of moisture.
Look inside the transformer for broken leads and loose parts. If any bushings are damaged, repair or replace them through the hand-hole, as described below.
If internal damage is suspected, the following procedure is recommended.
1. Remove the tank cover; lower the liquid to the top of the core, and carefully inspect the interior to note if any damage has occurred.
2. Take an oil sample from the bottom of the tank. If moisture is found inside the tank, arrangements should be made to dry the transformer.
3. After inspection and any repairs, refill the unit with dry insulating liquid to the 25° C level. Fill very slowly in a vacuum chamber. Hold a partial vacuum on the unit (up to –3 psig) for four hours after refilling. Do not use the tank as a vacuum chamber.
a. If the unit cannot be filled under vacuum, fill it through the hand-hole, directing the flow of oil so that aeration of the liquid is prevented. For instance, direct a slow flow of the liquid against the upper tank wall.
b. If a vacuum is not available, the unit should be allowed to sit for at least 24 hours before it is tested or energized.
c. Tilt the unit during filling to prevent entrapment of air in the coils and insulation.

Transformer Bushing Maintenance
De-energize the transformer before attempting bushing maintenance. In most cases, the high-voltage bushings may be changed by removing the bushing hardware and carefully pulling the bushing out. Access to the internal lead allows it to be disconnected. Replace the bushing and carefully insert it back in its hole on the tank.
The low-voltage bushing may be replaced externally by removing the clamps and pulling the bushing out of its hole. The lead hardware may be removed and the bushing changed. Be sure to reinstall the hardware in the original sequence.
The gasket must be located so that it will seal properly and not be damaged during repair to the unit. The gasket and bushings may be reused if they are undamaged. After repairs have been completed, refill the unit with dry insulating liquid to the 25° C level, if necessary.

Parallel Operation of Transformers
Several important conditions must be fulfilled if two or more transformers are to operate successfully in parallel to deliver a common load. These important conditions are:
1. The voltage ratings of both primaries and secondaries must be identical. This obviously implies that the transformations ratios are the same
2. The transformer must be properly connected to with regard to polarity. (Phasor must be the same) e.g. Dyn5 to Dyn5 parallel operation.
3. The equivalent impedances should be inversely proportional to the respective KVA ratings
4. The ratio of the equivalent resistance to the equivalent reactance (Re:Xe) of all transformers should be the same.

Boiler (Tubeless Steam Generator)
Samho SVS-1000 Diesel Steam Generator is designed for years of trouble-free performance. It has the 2HP gun-type burner delivering 14 GPH steam. The discharge pressure is 4.5 bar at the tank outlet and 3 bar at the steam header. The purpose of the steam is for clothes pressing (ironing) works in the factory.
To establish a good preventative maintenance program, the boiler maintenance technician or engineer must familiarize themselves with these simple rules.
1. The use of substandard chemical boiler cleaning compounds voids all warranties and should not be used. Some compounds can/will damage the incoloy sheathing of the heating elements. A reputable water treatment-engineering firm should be consulted regarding pre-treating or conditioning the boiler feed water.
2. Daily blow down at pressure is essential for ideal boiler performance. Extended periods of operation may require more frequent blow down. If the boiler is not equipped with an automatic blow down, in order to safeguard the heating elements, it is recommended to turn both the main disconnect switch and the boiler switch to the off position before manually blowing down the boiler.
3. The sight glass should be checked frequently to assure the boiler has adequate water.
4. The sight glass should be checked daily for damage (i.e. scratches, erosion, leaks etc.) The sight glass should be replaced if damaged.
5. A monthly inspection should be made of the internal wiring. Open the access door and check all electrical connections for tightness. Replace any wires that show signs of damage.
NOTE: The electrical power must be shut off during this maintenance procedure.
6. Heating element mounting bolts should be checked and tightened to a torque of 22 ft.-lbs. If there are indications of steam leaks from an element, replace the element gasket.
7. A monthly check for leaks should be made; any loose or damaged fittings should be tightened or replaced.
8. Every four months the boiler float control should be checked for proper operation. The lower equalization column can be examined visually and manually to see if is clear and clean. If there are signs of scale or mineral deposit buildup the float control must be disassembled and cleaned.
One of the lower heating elements should be removed. If scale or mineral deposits have begun to form all elements should be removed cleaned and reinstalled using new element gaskets.
Operating and high limit pressure control operation should be checked. Pressure controls should be removed and cleaned if necessary. Water feed supply check valves should be inspected and replaced if necessary.
9. If the boiler is equipped with an electronic auxiliary low water cut-off every four months the probe should be removed and checked for deposits. The probe should be cleaned and reinstalled.


Moreover in accordance with Peraturan Pemerintah we shall also comply with these guidelines:
a. All parts of the steam system, except the boiler shall comply with standards and regulation approved by GOI otherwise stated in writing by the department manager
b. Installation of steam generation, distribution and utilization shall not endangered workers and environment alike.
c. If there is any development or any alteration to the system, it shall be retested as per regulation.
d. If any of the boiler needs to be opened and cleaned or repaired and the rest of the boiler are still in operation, then lines leading into and from the boiler shall be disassembled and then blind flanged.
e. All steam and hot water distribution system shall be properly insulated in order to prevent hazard to workers and equipments working near and around them.
f. Every steam lines shall be added with bleeder to remove condensate.

Water Pretreatment
The extent of pretreatment depends upon the source of the raw water used. Well water usually requires simple filtration. Raw water from surface source such as river or lake, on the other hand, requires more elaborate pretreatment. The first step is clarification, in which the water is chlorinated to prevent biofouling of the equipment. The suspended solids and turbidity are then made to coagulate by special chemicals and by being brought together by a slow agitation in the middle of the clarifier vessel (chlorination that oxidizes organic matter also help them coagulate). The coagulated matter then settles by gravity in the clarifier and is removed.
In the next step, the clarified water, depending upon its hardness and alkalinity undergoes softening. Hardness, the chief source of scale in heat exchangers, boilers and pipelines is caused by the presence of calcium (Ca) and magnesium (Mg) salts containing Ca2+ and Mg2+. Alkalinity is mostly bicarbonate HCO3- but is also carbonate and hydrate. Softening is usually done in a cold process using lime/soda ash. Lime, calcium hydroxide Ca(OH)2, precipitates calcium bicarbonate as calcium carbonate CaCO3 and magnesium salts as Magnesium Hydroxide Mg(OH)2 according to,
Ca(OH)2 + Ca2+(HCO3-)2 → 2CaCO3↓ + 2H2O
2Ca(OH)2 + Mg2+(HC)3-)2 → 2CaCO3↓ + Mg(OH)2↓ + 2H2O
(CaOH)2 + Mg2+(SO4-) → Mg(OH)2↓ + CaSO4
The soda ash, sodium carbonate Na2CO3, is added to react with calcium chloride and calcium sulfate to form calcium carbonate
Na2CO3 + CaSO4 → CaCO3↓ + Na2SO4
The products, calcium carbonate and magnesium hydroxide, are insoluble in water and settle to the bottom of the vessel. In softening, calcium, magnesium and carbonate alkalinity are reduced to a few 10 ppm each. A problem of sludge removal, however, arises. Environmental regulations do not permit the sludge to be discharged. Instead it is dewatered, either in a settling basin or by thickeners and centrifuges. The water is then discharged to its source or recycled.
The next step in pretreatment is filtration, which further removes residual suspended solids and turbidity. Filtration can be done under gravity or pressure, although the latter is preferred. Various filter media are used, sand being the most common. The pressure difference across filtering medium is an indication of solid accumulation. When it reaches a given limit, the solids are removed from the bed by backwashing and are discharged to waste. Further filtration by activated charcoal may be necessary to absorb organics and remove residual chlorine from the chlorination process.
Blow Down
Blow down lines periodically remove a portion of the water from the drum where concentration increase because of steam flashing. This water is replaced by pure feed water. The blow down is then cooled and treated for reuse. A common treatment uses cartridge filters to remove suspended solids, notably iron and copper oxides, through the use of demineralizers. Condensate polishers maybe indicated in some cases.
A daily blow down is an essential part of boiler operation. It is the best and most important part of preventative maintenance you can give your boiler and will add years of life to the unit. Make sure a blow down schedule is established and followed regularly.
Pre-treating the boiler feed water may reduce mineral accumulation enough to allow a daily blow down to be sufficient.
Manual blow down instruction
1. At the end of the working day, while boiler is still operating, turn boiler main switch to the “OFF” position, close water supply valve and open disconnect switch.
2. If blow down valve is plumbed into a blow down tank, the boiler can be discharged at operating pressure.
3. If the blow down valve is not plumbed into a blow down tank, consult with local plumbing codes regarding boiler discharge.
4. When discharge is complete and boiler is drained, close the blow down valve, open the water supply valve, turn boiler main switch to “ON” position and close disconnect switch.
5. When refilling is complete, turn off the boiler unless further operation is needed.
6. If boiler is equipped with a “Manual Re-set Auxiliary Low Water Cut-off” (as required in some institution) the re-set button must be pushed before the boiler will begin developing steam. Do not push re-set button until the boiler has refilled with water.

Centrifugal Pump
The word pump in here refers to the 5 (five) centrifugal water supply pumps at pump house behind the generator house at PT Eins Trend factory.
Working Mechanism of a Centrifugal Pump
A centrifugal pump is one of the simplest pieces of equipment in any process plant. Its purpose is to convert energy of a prime mover (an electric motor or turbine) first into velocity or kinetic energy and then into pressure energy of a fluid that is being pumped.
The energy changes occur by virtue of two main parts of the pump, the impeller and the volute or diffuser. The impeller is the rotating part that converts driver energy into the kinetic energy. The volute or diffuser is the stationary part that converts the kinetic energy into pressure energy.
Note: All of the forms of energy involved in a liquid flow system are expressed in terms of feet of liquid i.e. head.
Generation of Centrifugal Force
The process liquid enters the suction nozzle and then into eye (center) of a revolving device known as an impeller. When the impeller rotates, it spins the liquid sitting in the cavities between the vanes outward and provides centrifugal acceleration. As liquid leaves the eye of the impeller, a low-pressure area is created causing more liquid to flow toward the inlet; Because the impeller blades are curved, the fluid is pushed in a tangential and radial direction by the centrifugal force. This force acting inside the pump is the same one that keeps water inside a bucket that is rotating at the end of a string. Figure A.01 below depicts a side cross-section of a centrifugal pump indicating the movement of the liquid.
Figure A.01: Liquid flow path inside a centrifugal pump

Conversion of Kinetic Energy to Pressure Energy
The key idea is that the energy created by the centrifugal force is kinetic energy. The amount of energy given to the liquid is proportional to the velocity at the edge or vane tip of the impeller. The faster the impeller revolves or the bigger the impeller is, then the higher will be the velocity of the liquid at the vane tip and the greater the energy imparted to the liquid.

This kinetic energy of a liquid coming out of an impeller is harnessed by creating a resistance to the flow. The first resistance is created by the pump volute (casing) that catches the liquid and slows it down. In the discharge nozzle, the liquid further decelerates and its velocity is converted to pressure according to Bernoulli’s principle.


Therefore, the head (pressure in terms of height of liquid) developed is approximately equal to the velocity energy at the periphery of the impeller expressed by the following well-known formula:

A handy formula for peripheral velocity is:



This head can also be calculated from the readings on the pressure gauges attached to the suction and discharge lines.
One fact that must always be remembered: A pump does not create pressure, it only provides flow. Pressure is a just an indication of the amount of resistance to flow.
Pump curves relate flow rate and pressure (head) developed by the pump at different impeller sizes and rotational speeds. The centrifugal pump operation should conform to the pump curves supplied by the manufacturer. In order to read and understand the pump curves, it is very important to develop a clear understanding of the terms used in the curves.
Understanding Centrifugal Pump Performance Curves
The capacity and pressure needs of any system can be defined with the help of a graph called a system curve. Similarly the capacity vs. pressure variation graph for a particular pump defines its characteristic pump performance curve.
The pump suppliers try to match the system curve supplied by the user with a pump curve that satisfies these needs as closely as possible. A pumping system operates where the pump curve and the system resistance curve intersect. The intersection of the two curves defines the operating point of both pump and process. However, it is impossible for one operating point to meet all desired operating conditions. For example, when the discharge valve is throttled, the system resistance curve shift left and so does the operating point.




Figure: Typical system and pump performance curves

Developing a System Curve
The system resistance or system head curve is the change in flow with respect to head of the system. It must be developed by the user based upon the conditions of service. These include physical layout, process conditions, and fluid characteristics. It represents the relationship between flow and hydraulic losses in a system in a graphic form and, since friction losses vary as a square of the flow rate, the system curve is parabolic in shape. Hydraulic losses in piping systems are composed of pipe friction losses, valves, elbows and other fittings, entrance and exit losses, and losses from changes in pipe size by enlargement or reduction in diameter.
Developing a Pump Performance Curve
A pump's performance is shown in its characteristics performance curve where its capacity i.e. flow rate is plotted against its developed head. The pump performance curve also shows its efficiency (BEP), required input power (in BHP), NPSHr, speed (in RPM), and other information such as pump size and type, impeller size, etc. This curve is plotted for a constant speed (rpm) and a given impeller diameter (or series of diameters). It is generated by tests performed by the pump manufacturer. Pump curves are based on a specific gravity of 1.0. Other specific gravities must be considered by the user.
Normal Operating Range
A typical performance curve (Figure D.01) is a plot of Total Head vs. Flow rate for a specific impeller diameter. The plot starts at zero flow. The head at this point corresponds to the shut-off head point of the pump. The curve then decreases to a point where the flow is maximum and the head minimum. This point is sometimes called the run-out point. The pump curve is relatively flat and the head decreases gradually as the flow increases. This pattern is common for radial flow pumps. Beyond the run-out point, the pump cannot operate. The pump's range of operation is from the shut-off head point to the run-out point. Trying to run a pump off the right end of the curve will result in pump cavitation and eventually destroy the pump.
In a nutshell, by plotting the system head curve and pump curve together, you can determine:
• Where the pump will operate on its curve?
• What changes will occur if the system head curve or the pump performances curve changes?
Requirements for Consistent Operation
Centrifugal pumps are the ultimate in simplicity. In general there are two basic requirements that have to be met at all the times for a trouble free operation and longer service life of centrifugal pumps.
The first requirement is that no cavitation of the pump occurs throughout the broad operating range and the second requirement is that a certain minimum continuous flow is always maintained during operation.
A clear understanding of the concept of cavitation, its symptoms, its causes, and its consequences is very much essential in effective analyses and troubleshooting of the cavitation problem.
Just like there are many forms of cavitation, each demanding a unique solution, there are a number of unfavorable conditions which may occur separately or simultaneously when the pump is operated at reduced flows. Some include:
• Cases of heavy leakages from the casing, seal, and stuffing box
• Deflection and shearing of shafts
• Seizure of pump internals
• Close tolerances erosion
• Separation cavitation
• Product quality degradation
• Excessive hydraulic thrust
• Premature bearing failures
Each condition may dictate a different minimum flow low requirement. The final decision on recommended minimum flow is taken after careful “techno-economical” analysis by both the pump user and the manufacturer.
The consequences of prolonged conditions of cavitation and low flow operation can be disastrous for both the pump and the process. Such failures in hydrocarbon services have often caused damaging fires resulting in loss of machine, production, and worst of all, human life.
Thus, such situations must be avoided at all cost whether involving modifications in the pump and its piping or altering the operating conditions. Proper selection and sizing of pump and its associated piping can not only eliminate the chances of cavitation and low flow operation but also significantly decrease their harmful effects.
Pump Operation and Maintenance
Predictive and Preventative Maintenance Program
This overview of Predictive and Preventative Maintenance (PPM) is intended to assist the pump users who are starting a PPM program or have an interest in the continuous improvement of their current programs.

There are four areas that should be incorporated in a PPM program. Individually each one will provide information that gives an indication of the condition of the pump; collectively they will provide a complete picture as to the actual condition of the pump.
Pump Performance Monitoring
There are six parameters that should be monitored to understand how a pump is performing. They are Suction pressure (Ps ), discharge pressure (Pd), flow (Q), pump speed (Nr ), pumpage properties, and power. Power is easiest measured with a clip on amp meter but some facilities have continuous monitoring systems that can be utilized. In any event, the intent is to determine the BHP of the pump. When using a clip on amp meter the degree of accuracy is limited. It should not be used to determine the efficiency of the pump. Clip on amp meters are best used for trouble shooting where the engineer is trying to determine the operating point of the pump.

The most basic method of determining the TDH of the pump is by utilizing suction and discharge gauges to determine PS and Pd. The installation of the taps for the gauges is very important. Ideally, they should be located normal to the pipe wall and on the horizontal centerline of the pipe. They should also be in a straight section of pipe. Avoid locating the taps in elbows or reducers because the readings will not indicate the true static pressure due to the velocity head component. Avoid locating taps in the top or bottom of the pipe because the gauges can become air bound or clogged with solids.

Flow measurements can be difficult to obtain but every effort should be made to do so, especially when trouble shooting. In some new installations permanent flow meters are installed which make the lob easier. When this is the case, make sure the flow meters are working properly and have been calibrated on a regular schedule. When flow meters are not installed, pitot tubes can be used. Pitot tubes provide a very accurate measure of flow, but this in an obtrusive device and provisions must be made to insert the tube into the piping. The other method of determining flow is with either a doppler or transitime device. Again, provisions must be made on the piping for these instruments, but these are non-obtrusive devices and are easier to use than the pitot tube. Caution must be exercised because each device must be calibrated, and independent testing has shown these devices are sensitive to the pumpage and are not 100% accurate.

An accurate power measurement reading can also be difficult to obtain. Clip on tap meters are the most common tool available to the Field Engineer who is trouble shooting a pump problem. In most cases this has proven to be accurate. However, as previously mentioned, this tool must be used and applied properly. Clip on tap meters are not accurate enough to determine the actual efficiency of a pump. If accurate horsepower readings are necessary, a torque shaft must be installed but is not very practical in an actual field installation and lends itself to use in a laboratory environment much better. In some critical installations where the user has provided a permanent power monitor, these have varying degrees of accuracy and they must be understood up front. Finally, the properties of the pumpage must be known to accurately determine the actual pump performance. Pumpage temperature (TP), viscosity, and specific gravity (S.G.), must be known.
When all of the above parameters are known, it becomes a simple matter of calculating the pump performance. There are instances when it proves to be a very difficult if not an impossible task to determine all of the above parameters in the field, therefore, the Field Engineer must rely on his or her ability to understand where a compromise must be made to get the lob done. The basic document the Field Engineer must have is the pump performance curve. With this it can be determined where the pump is performing in some cases without all of the information.
Pump Vibration and Bearing Analysis
Vibration analysis is the cornerstone of all PPM programs. Perhaps the question asked most often is “What is the vibration level that indicates the pump is in distress?” The answer is that there is no absolute vibration amplitude level that is indicative of a pump in distress. However, there are several guidelines that have been developed as target values that enable the analyst to set alarm levels. Also many users have developed their own site criteria that are used as a guideline. Institutions such as the Hydraulic Institute and API have developed independent vibration criteria. Caution should be exercised when applying the published values. ..Each installation is unique and should be handled accordingly. When a machine is initially started, a baseline vibration reading should be taken and trended over time.
Typically, readings are taken on the motor outboard and inboard bearing housings in the vertical and horizontal directions and on the pump outboard and inboard bearing housings in the vertical and horizontal directions. Additionally, an axial vibration measurement is taken on the pump. The inboard location is defined as the coupling end of the machine. It is critical that when the baseline vibration measurement is taken that the operating point of the pump is also recorded. The vibration level of a pump is directly related to where it is operating and in relation to its Best Efficiency Point (BEP). The further away from the BEP, the higher the vibrations will be. See the following chart for a graphical representation of vibration amplitude- vs. - flow.



The engineer must also look at the frequency where the amplitude is occurring. Frequency identifies what the defect is that is causing the problem, and the amplitude is an indication of the severity of the problem. These are general guidelines and do not cover every situation. The spectrum in the chart is a typical spectrum for a pump that has an unbalance condition. Bearing defect analysis is another useful tool that can be used in many condition monitoring programs. Each component of a roller bearing has its own unique defect frequency. Vibration equipment available today enables the engineer to isolate the unique bearing defects and determine if the bearing is in distress. This allows the user to shut the machine down prior to a catastrophic failure. There are several methods utilized but the most practical from a Field Engineering perspective is called bearing enveloping. In this method, special filters built into the analyzer are used to amplify the repetitive high frequency signals in the high frequency range and amplify them in the low frequency part of the vibration spectrum. Bearing manufacturers publish the bearing defect frequency as a function of running speed which allows the engineer to identify and monitor the defect frequency. Similar to conventional vibration analysis, a baseline must be established and then trended. There are other methods available such as High Frequency Detection (HFD) and Spike Energy but the enveloping technology is the latest development.
It is a common practice to monitor bearing temperature. The most accurate method to monitor the actual bearing temperature is to use a device that will contact the outer race of the bearing. This requires holes to be drilled into the bearing housings which is not always practical. The other method is the use of an infrared 'gun' where the analyst aims the gun at a point on the bearing housing where the temperature reading is going to be taken. Obviously, this method is the most convenient but there is a downside. The temperature being measured is the outside surface of the bearing housing, not the actual bearing temperature. This must be considered when using this method.
To complete the condition monitoring portion of a PPM program, many users have begun an oil analysis program. There are several tests that can be performed on the lubricant to determine the condition of the bearing or determine why a bearing failed so appropriate corrective action can be taken. These tests Include Spectrographic Analysis, viscosity Analysis, Infrared Analysis, Total Acid Number, Wear Particle Analysis and Wear Particle Count. Most of these tests have to be performed under laboratory conditions. Portable instruments are now available that enable the user to perform the test on site.
Pump System Analysis
Pump system analysis is often overlooked because it is assumed the system was constructed and operation of the pumps is in accordance with the design specifications. This is often not the case. A proper system analysis begins with a system head curve. System head curves are very difficult to obtain from the end user and, more often than not, are not available. On simple systems, they can be generated in the field but on more complicated systems this can't be done. As has been stated previously, it is imperative to know where the pumps are being operated to perform a correct analysis and this is dependent on the system.
A typical system analysis will include the following information; NPSHA, NPSHR, static head, friction loss through the system, and a complete review of the piping configuration and valving. The process must also be understood because it ultimately dictates how the pumps are being operated. All indicators may show the pump is in distress when the real problem is it is being run at low or high flows which will generate high hydraulic forces inside the pump.
Conclusion
A PPM program that incorporates all of the topics discussed will greatly enhance the effectiveness of the program. The more complete understanding the engineer has of the pumping system, the more effective the PPM program becomes.

Electric Motor
Maintenance and Troubleshooting of Electric Motors
SCHEDULED ROUTINE CARE

Introduction
The key to minimizing motor problems is scheduled routine inspection and service. The frequency of routine service varies widely between applications.

Including the motors in the maintenance schedule for the driven machine or general plant equipment is usually sufficient. A motor may require additional or more frequent attention if a breakdown would cause health or safety problems, severe loss of production, damage to expensive equipment or other serious losses.

Written records indicating date, items inspected, service performed and motor condition are important to an effective routine maintenance program. From such records, specific problems in each application can be identified and solved routinely to avoid breakdowns and production losses.

The routine inspection and servicing can generally be done without disconnecting or disassembling the motor. It involves the following factors:

Dirt and Corrosion
Wipe, brush, vacuum or blow accumulated dirt from the frame and air passages of the motor. Dirty motors run hot when thick dirt insulates the frame and clogged passages reduce cooling air flow. Heat reduces insulation life and eventually causes motor failure.

Feel for air being discharged from the cooling air ports. If the flow is weak or unsteady, internal air passages are probably clogged. Remove the motor from service and clean.

Check for signs of corrosion. Serious corrosion may indicate internal deterioration and/or a need for external repainting. Schedule the removal of the motor from service for complete inspection and possible rebuilding.

In wet or corrosive environments, open the conduit box and check for deteriorating insulation or corroded terminals. Repair as needed.

Lubrication
Lubricate the bearings only when scheduled or if they are noisy or running hot. Do NOT over-lubricate. Excessive grease and oil creates dirt and can damage bearings. See "Bearing Lubrication" for more details.


Heat, Noise and Vibration
Feel the motor frame and bearings for excessive heat or vibration. Listen for abnormal noise. All indicate a possible system failure. Promptly identify and eliminate the source of the heat, noise or vibration. See "Heat, Noise and Vibration" for details.

Winding Insulation
When records indicate a tendency toward periodic winding failures in the application, check the condition of the insulation with an insulation resistance test. See "Testing Windings" for details. Such testing is especially important for motors operated in wet or corrosive atmospheres or in high ambient temperatures.

BEARING LUBRICATION
Introduction
Modern motor designs usually provide a generous supply of lubricant in tight bearing housings. Lubrication on a scheduled basis, in conformance with the manufacturer's recommendations, provides optimum bearing life.

Thoroughly clean the lubrication equipment and fittings before lubricating. Dirt introduced into the bearings during lubrication probably causes more bearing failures than the lack of lubrication.

Too much grease can over pack bearings and causes them to run hot, shortening their life. Excessive lubricant can find its way inside the motor where it collects dirt and causes insulation deterioration.

Many small motors are built with permanently lubricated bearings. They cannot and should not be lubricated.

Oiling Sleeve Bearings
As a general rule, fractional horsepower motors with a wick lubrication system should be oiled every 2000 hours of operation or at least annually. Dirty, wet or corrosive locations or heavy loading may require oiling at three-month intervals or more often. Roughly 30 drops of oil for a 3-inch diameter frame to 100 drops for a 9-inch diameter frame is sufficient. Use a 150 SUS viscosity turbine oil or SAE 10 automotive oil.

Some larger motors are equipped with oil reservoirs and usually a sight gage to check proper level.
(Figure 3) As long as the oil is clean and light in color, the only requirement is to fill the cavity to the proper level with the oil recommended by the manufacturer. Do not overfill the cavity. If the oil is discolored, dirty or contains water, remove the drain plug. Flush the bearing with fresh oil until it comes out clean. Coat the plug threads with a sealing compound, replace the plug and fill the cavity to the proper level.

When motors are disassembled, wash the housing with a solvent. Discard used felt packing. Replace badly worn bearings. Coat the shaft and bearing surfaces with oil and reassemble.



Figure 3 Cross Section of the Bearing System of a Large Motor

Greasing Ball and Roller Bearings
Practically all ball bearing motors in current production are equipped with the exclusive PLS/Positive Lubrication System. PLS is a patented open-bearing system that provides long, reliable bearing and motor life regardless of mounting position. Its special internal passages uniformly distribute new grease pumped into the housing during re-greasing through the open bearings and forces old grease out through the drain hole. The close running tolerance between shaft and inner bearing cap minimizes entry of contaminants into the housing and grease migration into the motor. The unique V-groove outer slinger seals the opening between the shaft and end bracket while the motor is running or is at rest yet allows relief of grease along the shaft if the drain hole is plugged. (Figure 4)

The frequency of routine greasing increases with motor size and severity of the application as indicated in Table 1. Actual schedules must be selected by the user for the specific conditions.

During scheduled greasing, remove both the inlet and drain plugs. Pump grease into the housing using a standard grease gun and light pressure until clean grease comes out of the drain hole.

If the bearings are hot or noisy even after correction of bearing overloads (see "Troubleshooting") remove the motor from service. Wash the housing and bearings with a good solvent. Replace bearings that show signs of damage or wear. Repack the bearings, assemble the motor and fill the grease cavity.

Whenever motors are disassembled for service, check the bearing housing. Wipe out any old grease. If there are any signs of grease contamination or breakdown, clean and repack the bearing system as described in the preceding paragraph.



Figure 4 Cross Section of PLS Bearing System (Positive Lubrication System)

HEAT, NOISE AND VIBRATION

Heat
Excessive heat is both a cause of motor failure and a sign of other motor problems.

The primary damage caused by excess heat is to increase the aging rate of the insulation. Heat beyond the insulation's rating shortens winding life. After overheating, a motor may run satisfactorily but its useful life will be shorter. For maximum motor life, the cause of overheating should be identified and eliminated.

As indicated in the Troubleshooting Sections, overheating results from a variety of different motor problems. They can be grouped as follows:
WRONG MOTOR: It may be too small or have the wrong starting torque characteristics for the load. This may be the result of poor initial selection or changes in the load requirements.

POOR COOLING: Accumulated dirt or poor motor location may prevent the free flow of cooling air around the motor. In other cases, the motor may draw heated air from another source. Internal dirt or damage can prevent proper air flow through all sections of the motor. Dirt on the frame may prevent transfer of internal heat to the cooler ambient air.

OVERLOADED DRIVEN MACHINE: Excess loads or jams in the driven machine force the motor to supply higher torque, draw more current and overheat.

Table 1 Motor Operating Conditions
Motor
Horsepower Light
Duty(1) Standard
Duty(2) Heavy
Duty(3) Severe
Duty(4)
Up to 7-1/2
10 years 7 years 4 years 9 months
10 to 40
7 years
4 years
1-1/2 years
4 months

50 to 150
4 years
1-1/2 years
9 months
3 months

Over 150 1 year 6 months 3 months 2 months


Light Duty: Motors operate infrequently (1 hour/day or less) as in portable floor sanders, valves, door openers.
Standard Duty: Motors operate in normal applications (1 or 2 work shifts). Examples include air conditioning units, conveyors, refrigeration apparatus, laundry machinery, woodworking and textile machines, water pumps, machine tools, garage compressors.
Heavy Duty: Motors subjected to above normal operation and vibration (running 24 hours/day, 365 days/year). Such operations as in steel mill service, coal and mining machinery, motor-generator sets, fans, pumps
Severe Duty: Extremely harsh, dirty motor applications. Severe vibration and high ambient conditions often exist.
EXCESSIVE FRICTION: Misalignment, poor bearings and other problems in the driven machine, power transmission system or motor increase the torque required to drive the loads, raising motor operating temperature.

ELECTRICAL OVERLOADS: An electrical failure of a winding or connection in the motor can cause other Windings or the entire motor to overheat.

Noise and Vibration
Noise indicates motor problems but ordinarily does not cause damage. Noise, however, is usually accompanied by vibration.

Vibration can cause damage in several ways. It tends to shake windings loose and mechanically damages insulation by cracking, flaking or abrading the material. Embrittlement of lead wires from excessive movement and brush sparking at commutators or current collector rings also results from vibration. Finally, vibration can speed bearing failure by causing balls to "brinnell," sleeve bearings to be pounded out of shape or the housings to loosen in the shells.

Whenever noise or vibration is found in an operating motor, the source should be quickly isolated and corrected. What seems to be an obvious source of the noise or vibration may be a symptom of a hidden problem. Therefore, a thorough investigation is often required.

Noise and vibrations can be caused by a misaligned motor shaft or can be transmitted to the motor from the driven machine or power transmission system. They can also be the result of either electrical or mechanical unbalance in the motor.

After checking the motor shaft alignment, disconnect the motor from the driven load. If the motor then operates smoothly, look for the source of noise or vibration in the driven equipment.

If the disconnected motor still vibrates, remove power from the motor. If the vibration stops, look for an electrical unbalance. If it continues as the motor coasts without power, look for a mechanical unbalance.

Electrical unbalance occurs when the magnetic attraction between stator and rotor is uneven around the periphery of the motor. This causes the shaft to deflect as it rotates creating a mechanical unbalance. Electrical unbalance usually indicates an electrical failure such as an open stator or rotor winding, an open bar or ring in squirrel cage motors or shorted field coils in synchronous motors. An uneven air gap, usually from badly worn sleeve bearings, also produces electrical unbalance.

The chief causes of mechanical unbalance include a distorted mounting, bent shaft, poorly balanced rotor, loose parts on the rotor or bad bearings. Noise can also come from the fan hitting the frame, shroud, or foreign objects inside the shroud. If the bearings are bad, as indicated by excessive bearing noise, determine why the bearings failed. (See Troubleshooting Problems D and L.)

Brush chatter is a motor noise that can be caused by vibration or other problems unrelated to vibration. See Troubleshooting Problem M for details.

WINDlNGS
Care of Windings and Insulation
Except for expensive, high horsepower motors, routine inspections generally do not involve opening the motor to inspect the windings. Therefore, long motor life requires selection of the proper enclosure to protect the windings from excessive dirt, abrasives, moisture, oil and chemicals.

When the need is indicated by severe operating conditions or a history of winding failures, routine testing can identify deteriorating insulation. Such motors can be removed from service and repaired before unexpected failures stop production. See "Testing Windings".

Whenever a motor is opened for repair, service the windings as follows:
Accumulated dirt prevents proper cooling and may absorb moisture and other contaminants that damage the insulation. Vacuum the dirt from the windings and internal air passages. Do not use high pressure air because this can damage windings by driving the dirt into the insulation.

Abrasive dust drawn through the motor can abrade coil noses, removing insulation. If such abrasion is found, the winding should be re-varnished or replaced.

Moisture reduces the dielectric strength of insulation which results in shorts. If the inside of the motor is damp, dry the motor per information in "Cleaning and Drying Windings".

Wipe any oil and grease from inside the motor. Use care with solvents that can attack the insulation.

If the insulation appears brittle, overheated or cracked, the motor should be re-varnished or, with severe conditions, rewound.

Loose coils and leads can move with changing magnetic fields or vibration, causing the insulation to wear, crack or fray. Re-varnishing and retying leads may correct minor problems. If the loose coil situation is severe, the motor must be rewound.

Check the lead-to-coil connections for signs of overheating or corrosion. These connections are often exposed on large motors but taped on small motors. Repair as needed.

Check wound rotor windings as described for stator windings. Because rotor windings must withstand centrifugal forces, tightness is even more important. In addition, check for loose pole pieces or other loose parts that create unbalance problems.

The cast rotor rods and end rings of squirrel cage motors rarely need attention. However, open or broken rods create electrical unbalance that increases with the number of rods broken. An open end ring causes severe vibration and noise.

Testing Windings
Routine field testing of windings can identify deteriorating insulation permitting scheduled repair or replacement of the motor before its failure disrupts operations. Such testing is good practice especially for applications with severe operating conditions or a history of winding failures and for expensive, high horsepower motors and locations where failures can cause health and safety problems or high economic loss.

The easiest field test that prevents the most failures is the ground-insulation, or &127megger," test. It applies DC voltage, usually 500 or 1000 volts, to the motor and measures the resistance of the insulation.

NEMA standards require a minimum resistance to ground at 40 degrees C ambient of 1 megohm per KV of rating plus 1 megohm. Medium size motors in good condition will generally have megohmmeter readings in excess of 50 megohms. Low readings may indicate a seriously reduced insulation condition caused by contamination from moisture, oil or conductive dirt or deterioration from age or excessive heat.

One megger reading for a motor means little. A curve recording resistance, with the motor cold and hot, and date indicates the rate of deterioration. This curve provides the information needed to decide if the motor can be safely left in service until the next scheduled inspection time.

The megger test indicates ground insulation condition. It does not, however, measure turn-to-turn insulation condition and may not pick up localized weaknesses. Moreover, operating voltage peaks may stress the insulation more severely than megger voltage. For example, the DC output of a 500-volt megger is below the normal 625-volt peak each half cycle of an AC motor operating on a 440-volt system. Experience and conditions may indicate the need for additional routine testing.

A test used to prove existence of a safety margin above operating voltage is the AC high potential ground test. It applies a high AC voltage (typically, 65% of a voltage times twice the operating voltage plus 1000 volts) between windings and frame.

Although this test does detect poor insulation condition, the high voltage can arc to ground, burning insulation and frame, and can also actually cause failure during the test. It should never be applied to a motor with a low megger reading.

DC rather than AC high potential tests are becoming popular because the test equipment is smaller and the low test current is less dangerous to people and does not create damage of its own.

Cleaning and Drying Windings
Motors which have been flooded or which have low megger readings because of contamination by moisture, oil or conductive dust should be thoroughly cleaned and dried. The methods depend upon available equipment.

A hot water hose and detergents are commonly used to remove dirt, oil, dust or salt concentrations from rotors, stators and connection boxes. After cleaning, the windings must be dried, commonly in a forced-draft oven. Time to obtain acceptable megger readings varies from a couple hours to a few days.

Air Compressor, Screw Type



The rotary screw air compressor has become the most popular source of compressed air for industrial applications. A major reason is its simple compression concept.
Air enters a sealed chamber where it is trapped between two contra-rotating rotors. As the rotors intermesh, they reduce the volume of trapped air and deliver it compressed to the proper pressure level. This simple compression concept, with continuous contact cooling, allows the rotary screw air compressor to operate with temperatures approximately one half that generated by a reciprocating compressor. This lower temperature enables the rotary screw air compressor to operate in a "fully loaded" continuous duty cycle 24 hours per day, 365 days per year, if necessary.
Its ability to operate for extended periods of time makes the rotary compressor ideal for demanding industrial applications.
Make sure the compressor's output matches the pounds-per-square-inch requirements of the tool to be used. Check and change the oil regularly. After a day of use, empty the air tanks and drain any water build-up inside the tank through the drain tap at the bottom of the tank.

Maintenance operation Daily Weekly Monthly Hourly
Drain air tanks
Check crankcase oil level
Check fittings and airlines
Check hydraulic fluid level
Inspect and clean air intake filters
Clean and operate safety valves
Clean cooling fins on radiator/cooler
Inspect check valve
Replace Separator Cartridge 12
Inspect and clean compressor valves 6
Replace hydraulic filter 6
Replace air filters/oil filter/compressor oil 3
Tighten all fittings and fasteners 3
Check all electrical connections 3
Inspect and clean air check valve 250


Atmospheric Storage Tank for Diesel Fuel

Here are what the experts are saying about the issues and the proper maintenance that should be followed for diesel fuels:

Contamination of fuel by water and dirt entering the fuel as a result of careless fuel handling may cause poor diesel engine performance. Extreme care must be exercised. Fuel-tank caps, dispensing nozzles and hoses should be kept clean to eliminate potential sources of contamination. Regularly removing water from storage tanks, vehicle fuel tanks, and filter bowls is important. Dry storage systems will reduce fuel emulsion problems, injection system corrosion and microbial growth.
How does water get into diesel fuel and what problems can it cause?
Water gets into diesel fuel storage and vehicle tanks in several ways – by condensation of humid air, during transportation from refineries to service stations, by leakage through faulty fill pipes or vents and by careless handling. Water can cause injector nozzle and pump corrosion, microorganism growth and fuel filter plugging with materials resulting from the corrosion or microbial growth. Both vehicle and storage tanks should be checked frequently for water and drained or pumped out as necessary. In extreme cases, biocides may be required to control microorganism growth.
Regularly removing the water is the most effective means of preventing this problem; however, small quantities of alcohol may be used on an emergency basis to prevent fuel line and filter freeze-ups. Cleanliness refers to the absence of water and particulate contamination. This characteristic is important because dirt and water can plug fuel filters in your engine and cause severe damage to your fuel injection system because of the close tolerances within fuel pumps and injectors. All diesel engine manufacturers equip their engines with fuel filters to protect the fuel delivery system. You should replace these filters according to the manufacturer's recommendations. Some manufacturers also provide filters with drain valves and recommend periodic draining of any water that may accumulate from condensation and careless handling in storage or vehicle tanks.

Water in a fuel storage tank can cause operational problems
Tank maintenance is an essential part of any successful premium diesel or heating oil program. As little as 0.01% (100ppm) water in a fuel storage tank; can cause operational problems. Water cannot be completely eliminated from distillate fuels. It can get into the fuel at various stages as it progresses through the distribution network from the refinery to the end-user. Water can get into the fuel during its production, when the hot fuel is in contact with process water. Most of this water is removed in the stripping units at the refinery and more will separate as the fuel cools, but still, some water remains in solution with the diesel. This entrained water may cause a haze in distillate fuel.

Most of the water present in fuels will drop out as it is heavier than the fuel and will sink to the bottom if given time. The temperature of the fuel has an impact on its water-shedding tendencies as well. Warmer fuel can hold more water in suspension than can colder fuel. Water can also be introduced during transportation and storage of the fuel as well. Sea-going vessels can sometimes introduce water into distillate fuel, which can then drop out into storage tanks. Tanks themselves have inherent problems at roof seals and vent pipes which can allow rain water to seep into the system. During fuel withdrawals, tanks can breathe in large volumes of humid air. Moisture in the air will condense when the ambient temperature falls, collecting in tank bottoms. This is particularly prevalent in the spring and fall when the day-night temperature fluctuations can be extreme.
As you can see, there are numerous ways in which the water can get into the fuel storage and delivery system, now let's look at the problems it can cause.

In cold weather, many water-related problems are incorrectly attributed to the fuel. Water in tanks can freeze 20oF - 30oF above the temperature at which fuel-related problems begin (cloud point). Ice crystals can build up on filters, restricting flow and compromising performance. They can also restrict fuel flow in tank pumping lines.

In warmer weather, the presence of water in tanks may encourage the growth of fungi or bacteria which live in the tank water bottoms and feed on the fuel. Under the power of a microscope, these bugs look like deep-sea creatures. To the naked eye, these bugs show up as slimy mats of substance that can be any color from green to black. Under ideal conditions, these bacteria can double in number in as little as four hours. When left unchecked, they can be drawn out through suction lines and plug filters. In addition, the by-products of their fuel consumption are very acidic and can cause pitting and decay in tank bottoms. Many tanks go unchecked for years, accumulating water from any number of sources. When fuel inventory is low, water bottoms can be stirred up during deliveries, and if not allowed to settle out, can be suctioned out into a transport truck or into a diesel vehicle's tank.

Water also causes corrosion in storage tanks and engine systems. The by-products of this corrosion, including scale and rust, can all lead to filter plugging or injector fouling and can help make a stable emulsion.

Fuel injection pumps are often times lubricated only by the fuel they are pumping and are, therefore, very susceptible to seizing if water gets into them. These high-pressure pumps are not at all tolerant of dirt, debris and organic deposits, all of which can be carried into them with water. The barrel and plunger clearance is often times only 1-2 microns. This tight tolerance is necessary to maintain fuel injection pressures and ensure minimal leakage past the plunger shaft.
The Solutions

Ideally, storage tanks should be checked with a stick treated with water-finding paste prior to every delivery. Many tanks are, however, difficult to gauge for water due to limited access.

Underground tanks can settle to one side and unless you are checking at the low end, you can get a misleading indication of how much water is present. Most tanks have more water than can be easily detected so err on the side of caution.

All water should be drained from storage tanks periodically. The frequency will depend on the ease of removal, volume of fuel throughput and tolerance of water-related problems. It is not always an easy task, but tanks should never go more than 6 months without having bottoms removed.

Be sure to remove water and bottoms until the product being removed is "clear and bright". Remember, emulsions being held stable at the bottom of the tank due to sediment or biological growth can cause problems just as bad as if you were pumping straight water.