Engineering Briefs

9087A – 198th Street, Langley, BC Canada V1M 3B1 Telephone (604) 888-0110Telefax (604) 888-3381 E-Mail: [email protected] www.thomsontechnology.com

AUTOMATIC TRANSFER SWITCH

MANUAL OPERATION

ENGINEERING BRIEF

EB002 Rev 1 91/02/12

MANUAL OPERATION

EB002 Rev 1 91/02/12 Thomson Technology Inc.1

The ability to manually operate an automatic transfer switch has obvious merits.Since many transfer switch failures can be attributed to control failures, a manualoperating means may allow an operator to maintain electrical supply to the loadwith a minimum of disruption, even during utility power failures. Further,maintenance procedures are greatly simplified.

It is important, however, to ensure that the design of a manually operatedtransfer switch does not unnecessarily degrade system performance, integrity, orsafety. The following points should be considered:

(1) The transfer switch should not suffer a reduction of rating when operatedmanually, as opposed to electrically. For instance, it should be capable ofinterrupting the full rated load, as well as closing on to a faulted systemwhere a fault current level up to the withstand rating of the transfer switchmay occur. Failure to meet these performance levels could lead todestruction of the transfer switch should it be operated under theseconditions.

It must be recognized that, even if a transfer switch is not intended formanual switching while carrying load, there is no assurance that it will nothappen.

The simple truth is that transfer switches are regularly operated manuallywhile carrying current. This happens during commissioning, servicing,and due to operator error. Transfer switches with slow operating contacts(eg. solenoid-operated "contactor" type) are distinctly inferior whenoperated under these conditions. Consider what could happen if atransfer switch was slowly closed onto a bolted fault.

UL Standard 1008 places additional requirements on some automatictransfer switches, which have "slow operating" manual operation, inrecognition of the contact arcing problem. These requirements exceedCSA's Standard 178.

MANUAL OPERATION


To ensure that damage does not take place during switching, quick-make,quick-break contacts are required. These require a "stored-energy"mechanism, and although more costly to produce, guarantee fastoperation under all conditions. All Thomson Technology transfer switcheshave stored-energy contacts. Solenoid operated contactor type transferswitches don't have stored-energy contacts simply because the solenoidisn't strong enough to charge the springs.

(2) The transfer switch must be safe for operating personnel. If manualtransferring is attempted without the control circuits being disabled, thereshould be no possibility of injury. This may be accomplished by a meanswhich automatically disables the operating mechanism when access formanual operation is gained,or by a manual mechanism with an overriding device which will allow themanual handle to remain stationary while the mechanism is electricallyoperated.

(3) The manual operating means must be obvious, simple, and secure. Amanual handle which is small, not labelled, or not permanently attached inthe operating position (ie. one which may be lost) is not acceptable.Further, it should not be necessary for inexperienced personnel to refer tothe instruction manual to be able to quickly effect a manual transfer, sincetransfer switches are emergency devices, and a need for manualoperation would likely occur under adverse conditions.

To address these critical performance requirements, Thomson Technologytransfer switches provide:

* stored-energy contacts which always operate quickly, whether manually orelectrically initiated,

MANUAL OPERATION


* a safety switch or other means to automatically prevent the mechanismfrom harming an operator while performing manual switching withouthaving disconnected power, and

* a clearly labelled and permanently attached manual handle, which is veryeasy to operate.

ConclusionThe bottom line is that you have a transfer switch because there is a critical needto maintain power to a load. To achieve that result under all conditions, amanual handle which is safe and easy to find, and which cannot cause contactdamage, is the best.

NOTICE: This information is the property of Thomson Technology Inc. Permission is herebygiven to reproduce this document in this exact form only, without modification of any kind.

© THOMSON TECHNOLOGY INC



NEUTRAL POSITION DELAY & IN-PHASE MONITOR

ENGINEERING BRIEF

EB003 Rev 1 95/05/15



When transferring large motors and/or transformers between two sources of power whichmay not be in synchronism (i.e. the normal power source and the emergency powersource), consideration must be given to the elimination of the "bump" that is felt when theelectrical load is suddenly disconnected from the first power source and immediatelyconnected to the second power source.

When a motor that has been running on line is suddenly disconnected from its powersource, the residual voltage produced by the motor (which acts as a generator under thesecircumstances) will decrease in amplitude and frequency as the motor slows down.Although the motor may take a long time to actually stop, the voltage will decay veryquickly to safe levels. Similarly, when a transformer is disconnected from the line, time isrequired for the magnetic field to collapse.

The "bumps" are caused by the momentary flow of extremely high line current because ofan out-of-phase condition during motor transfer, and because of induced voltage transientsduring transformer transfer. The high current flow can exceed the instantaneous tripsettings of protective devices in the system and can be severe enough to trip circuitbreakers, cause damage to shafts, couplings, etc. This condition is especially pronouncedin the case of a fast-operating transfer switch, such as a solenoid operated type with allcontacts on a common shaft.

Two methods are commonly utilized to prevent the "bump" from occurring. One is theNeutral Position Delay (T.T.I. option code NDT). The other is the In-Phase Monitor method.The following is an explanation of each of these methods, along with the relativeadvantages and disadvantages.

I. IN-PHASE MONITOR

The in-phase monitor inhibits load transfer until the two power sources are in synchronism.The monitor is adjusted to signal the transfer switch to operate when the incoming powersource is within approximately ten electrical degrees of the connected power source.Depending upon the difference in frequency, the phase angle between the two powersources, and in the contact-to-contact transition time, the transfer is made at or nearsynchronism.

A. ADVANTAGES

1. Transfer of motor loads is accomplished without an appreciable power dip when thesystem is adjusted properly, when heavy transformer loads are not included.



B. DISADVANTAGES

1. Successful transfer is totally dependent upon the selection and adjustment of thegovernor in the emergency power source. A governor which is faulty, maladjusted,or has too much "droop" may prevent transfer. If the frequency is more than twocycles out of synchronism, or the connected power source is unstable, the transferswitch will remain in the emergency position indefinitely, or until the frequency iscorrected.

2. The in-phase monitor detracts from the reliability of the system because a complexelectronic component is added to an otherwise simple, straightforward controlsystem.

3. The in-phase monitor does not have control over the amount of slippage that isexperienced from the time a motor is de-energized until the transfer switch closes tothe incoming power source. A heavily loaded motor can go out of synchronismbetween the time it is de-energized until the time it is re-energized, particularly inlarger sizes of transfer switches which have longer contact-to-contact transitiontimes.

4. The in-phase monitor does nothing to prevent the "bump" that is felt when switchingtransformers at high speed because the sinusoidal line voltage wave form is notmaintained after the transformer is disconnected. The amount of the "bump" isdetermined essentially by the amount of time required for the transformer voltage todecay. This, in turn, is dependent upon the type of network supplied by thetransformer. Therefore, a high speed transfer switch with an in-phase monitor doesnothing to eliminate the "bump" that is felt when switching transformers.

5. The in-phase monitor is totally ineffective during manual transfer under load. In facta snap action transfer switch with all contacts on a single operating shaft couldpresent problems during manual transfer if the need for in-phase monitor had beenidentified, since a manual transfer would probably be out of phase.

6. The in-phase monitor is totally ineffective if transfer to the generator source isnecessary due to a failing utility source (single phase or brown-out condition). If thetransfer switch logic senses a partial failure of a source, the in-phase monitor mustbe bypassed to allow transfer. In this case, an instantaneous out-of-phase transfercannot be avoided and may very well trip the circuit breaker that feeds the only goodpower source. Then all power is lost to the critical load.

7. If the generator fails while it is powering the load while utility source is available(during test or the time delay before returning to normal), there is no protectionagainst an out-of-phase transfer. This could also cause loss of the only remaininggood source of power needlessly (in this instance, the faster the switch transfer, themore likely there is to be a problem since there is less time for the motor field todecay).



II NEUTRAL POSITION DELAY "NDT"

The NDT design eliminates the high current surge by deliberately introducing off-time duringload transfer, thereby allowing the disconnected electrical loads to de-energize beforereconnecting them to the alternate source of power. This is accomplished by introducing atime delay between the opening of the closed contacts and the closing of the opencontacts. In fact, the inherent time it takes to complete a normal transfer with a T.T.I. motoroperated switch (approximately 1 second) is sufficient to eliminate the "bump" or currentsurge without even adding the extra time delay of NDT.

A. Advantages

1. Foolproof operation under all conditions of transfer.

2. Successful operation totally independent of the frequency of the two power sources.

3. Flexibility. For instance, when utilized in conjunction with a multiple-engine,generator control switchboard, the NDT design lends itself to load "dumping" byswitching the main contacts to an "off" position, thereby eliminating the need forseparate load dumping devices.

4. Cost is considerably lower than in-phase monitor.

5. NDT is more reliable and much easier to service than an in-phase monitor.

B. Disadvantages

1. A momentary dip in power when transferring loads between two live sources (lessthan 60 cycles unless extended by time delay relay).

CONCLUSION

In summary, the Neutral Position Delayed transfer switch is by far the most reliable methodof switching large motors and transformers because it is flexible, simple, and foolproof.Upon transfer, the user experiences only in-rush current rather than excessive line currentswhich may approach short circuit values.

POINTS OF INTEREST

1. In a lengthy technical working paper presented by I.E.E.E. entitled "Source Transferand Reclosing Transients in Motors" it was stated:

"The following are the two basic approaches to preventing damaging currents andtorques caused by interruption-reconnection incidents:

(1) Delayed reclosing or transfer, which allows time for the residual voltage of themotor(s) to decay to a level which is safe regardless of reclosing angle.

(2) In-phase transfer or reclosing, in which the transfer or reclosure is timed to



occur when the residual and oncoming system voltages are close enough inphase relation to avoid damaging transients, regardless of residual voltagemagnitude.

While both methods work quite well and are widely used, they both have advantagesand disadvantages. In many applications, delayed reclosing has the virtues ofsimplicity, reliability, and economy; on the other hand the relatively long open intervalwhich is sometimes required to permit the motor voltage to decay may beunacceptable. In-phase transfer provides the minimum service interruption, butdepends for safe operation on accurately sensing the phase relation between thetwo voltages. This requires sensitive solid state or electromagnetic relaying andcontrol logic which adds cost and complexity."

The paper further states that:

"For typical systems composed of *relatively small integral-horsepower inductionmotors and lagging-power-factor static loads, an open circuit interval of 1 second isvirtually always sufficient."*Up to 300 HP.

The committee which developed this paper comprised several prominent industrymembers, including two from Westinghouse and two from Asco.

2. As a rule of thumb, neutral position delay may be applied asfollows:

a. For motors up to 100HP - no delay required.b. For motors 100HP-300HP - specify NDT set at one second.c. For motors over 300HP - specify NDT set at two seconds.

If power factor correction capacitors are applied at the motor terminals (as opposed tocentrally on a system), further consideration may be required for delay times - consult T.T.I.

Wound-rotor motors are not suitable for either in-phase or neutral delayed transfer. Theyshould be isolated and restarted.

NOTICE This information is the property of Thomson Technology Inc. Permission is herebygiven to reproduce this document in this exact form only, without modification of any kind.

© THOMSON TECHNOLOGY INC.



OUT OF PHASE TRANSFER OF MOTOR LOADS

TECHNICAL EXCERPT

AS RELATED TO:

(1) Neutral Position Delay(2) In-Phase Transfer

Note: Portions of this excerpt which are of particular interest have been marked.

EB004 Rev 1 91/02/12



OVERLAPPING NEUTRAL CONTACTS

ENGINEERING BRIEF

EB005 Rev 0 91/02/05



Numerous articles have been written concerning the presence of dangerous voltagetransients that supposedly occur whenever the neutral conductor of an automatic transferswitch is switched from one source of power to the other without the benefit of anoverlapping neutral contact arrangement. These claims are totally unfounded.

To attribute the possibility of load damage to simultaneous switching of all powerconductors, including the neutral conductor, indicates lack of understanding of the transientphenomena attendant to the use of high speed interrupting devices. A static voltageunbalance would occur only as the result of long term neutral open conditions. Such is notthe case for a properly designed automatic transfer switch, regardless of the manufacturer.

Switching TimeIt is essential to put the circuit analysis into proper perspective with regard to contactswitching time - the most important element so often overlooked.

The duration of the switching action is so short with respect to the period of the 60 HZwaveform, that the duration of any voltage unbalance is inconsequential. A transfer switchthat is designed to switch all poles simultaneously provides a foolproof and completely safetransfer of all load conductors.

Neutral Contact Erosion

It has been stated that neutral contact arcing and erosion can result in eventualdiscontinuity at the neutral pole. This of course, is no more true for the neutral pole thanfor any of the phase poles!

It is safe to assume that if the switching device in question operated slowly enough to alloweven a close approximation of the open neutral static unbalanced conditions described, thecontacts of the switch could fail. It is a well-known fact that successful operation of anydisconnect device, especially under reactive load conditions, is extremely dependent uponrapid "make" and "break" contact action with properly supported arc extinction. Therefore,any transfer switch maker must ensure that all switching contacts are adequately rated.

Generation of Transient Voltages

In order to generate transient voltages, there is a prerequisite that the load have thecapability of storing electrical energy. Resistive load has no such characteristic, andtherefore we will consider only the case of the inductive load. The energy stored in thetransformer primary, secondary, and leakage reactances is certainly a small contributor tothe transient situation. The largest contributor to possible transient voltage generationwould be energy stored in large motor windings, or similar loads. However, inductive testssubstantiate that no appreciable voltage transients occur upon switching of inductive load.It is quite apparent that the transient voltages normally found in distribution circuits inindustrial or commercial installations are far more severe than those that might begenerated in switching the neutral.



AC Power System Transients

It is a widely accepted fact throughout the electrical and electronic industry that power linetransients occur randomly at all levels of distribution and may involve high lines as well as115 volt branch circuits. They have been observed, recorded, and documented, particularlyby manufacturers of sensitive electronic equipment which is dependent upon commercialpower for normal operation. Crest voltages as high as 2500 volts have been recorded on120 volt distribution lines. Induced voltages as high as 6KV from nearby lightning strokeshave also been observed.

Fortunately, the majority of power system loads have inherent immunity against damage topower line transients, and the remaining critical loads can usually be economicallyprotected by the manufacturer or user. Due to the immensity of modern industrial andresidential AC power system grids and the complexity of randomly distributed transient -prone loads, it is impossible for utilities do not assume responsibility for transientphenomena for the most part.

Needless to say, the presence of voltage transients on power line conductors is not unusualunder normal conditions, nor could it be construed as being abnormal during any routineswitching action.

Need for True 4-Pole Switching

There may be a need to switch all conductors including the neutral to preserve the integrityof GFP (Ground Fault Protection) Systems when the ground fault detection must be appliedon each source independently (as opposed to the load side of the transfer switch). It isimportant for the power system designer to select an automatic transfer switch designed toprovide symmetrical switching of the load, regardless of initial normal load voltage andcurrent balance or power factor.

Summary

1. The statement presented that neutral switching is dangerous unless accomplished with"overlapping contacts" is without foundation.

2. The assumption that erosion of a load switching contact will result in discontinuity andeventual disconnection of the neutral conductor is totally unrealistic , since the very samecriticism must be applied to the other poles in the same switch.

3. Laboratory tests using resistive load circuitry as well as highly inductive loads switchedby deliberately misaligned contacts are fully documented. Photographic proof clearly revealsthe absence of any significant transient overvoltages or overcurrents at the loads in question.



4. The magnitude of AC voltage transients found on most all industrial, commercial, andresidential power systems far exceeds anything which could be accountable to 4-pole transferswitches.

5. The neutral contact rating should have the same current and withstand capacity as thepower poles to ensure system integrity. It should be noted that, if a manufacturer employs anoverlapping neutral contact, it may be based upon cost-saving efforts, since the neutral contactis inferior to the phase contacts (it has no switching capability).

NOTICE: This information is the property of Thomson Technology Inc. Permission is hereby givento reproduce this document in this exact form only, without modification of any kind.

©THOMSON TECHNOLOGY INC.

9087A – 198th Street, Langley, BC Canada V1M 3B1 Telephone (604) 888-0110 Telefax (604) 888-3381 E-Mail: [email protected] www.thomsontechnology.com


SENSITIVE GROUND FAULT SENSING FOR SOLIDLY GROUNDED 3 PHASE/4 WIRE

TRANSFER SYSTEMS

ENGINEERING BRIEF

EB006 Rev 0 90/01/02

SENSITIVE GROUND FAULT SENSING

EB006 Rev 0 90/01/02 Thomson Technology Inc. 1

On a three phase electrical system with a distributed neutral (ie. 3 phase, 4 wire) the neutral conductor will be grounded at the source, as required to provide a fault current return path in the event of a ground fault. This fault current is not limited, and is therefore usually relatively large, and of sufficient magnitude to trip the feeder circuit breaker of the connected source due to phase overcurrent. This simple protection is typically afforded by a thermal-magnetic molded case circuit breaker. If a superior level of ground fault protection is desired, whereby the feeder breaker is required to trip on a low level ground fault, then a more sensitive ground fault sensing device must be employed. This may typically be a molded case circuit breaker with an integral solid-state ground fault sensor, operating on the "zero sequence" principal. Alternately, an external sensor may be used, in conjunction with a zero sequence C.T. Note: - A zero sequence sensor will only detect a ground fault if the neutral

is grounded on the source side of the C.T., while the fault occurs on the load side of the C.T. (ie the fault current return path, through the grounded circuit passes outside the C.T.).

A Zero sequence C.T. may be 4 separate C.T.'s connected in Zero-

sequence configuration, as in a molded case circuit breaker with internal solid-state trip.



CASE #1 On a transfer system with sensitive ground fault sensing on only one source (usually the normal source), the neutral should be grounded as shown in fig. 1. Note that the neutral system cannot be grounded in more than one place, as it would then be a parallel conductor to the ground conductor, and part of the neutral current would flow in the ground conductor.



CASE #2 On a transfer system with sensitive ground fault sensing on both source feeder breakers, it is possible to employ a four-pole transfer switch as shown in fig. 2, to prevent simultaneously grounding the neutral in more than one place. This method is relatively expensive, and has questionable merit, since a ground fault will trip the normal source breaker thus starting the generator (which sees the tripping as a power failure). When the faulted load is transferred to the generator, the generator breaker will then likely trip also. There is no benefit to a 4 pole transfer switch other than neutral isolation for ground fault sensing purposes.



CASE #3 The method of providing ground fault protection on both sources as shown in fig. 3 is very effective and requires only a 3 pole transfer switch. The disadvantage of this system is that the ground fault relays of both sources must be coordinated and installed in reasonable proximity due to the C.T. circuits.



CASE #4 An alternate method of providing for sensitive ground fault sensing on both sources, while avoiding the disadvantages of the four-pole transfer switch method, is shown in fig. 4. this is the method used by Thomson Technology to provide option "GFP" ground fault protection on T.T.I. transfer switches.



Features of Option "GFP" ground fault protection: 1) On detection of a ground fault: - the closed transfer breaker is tripped, immediately de-energizing

the load - the generator start contact circuit is interrupted & locked out,

preventing the generator from starting automatically - the transfer motor circuit is locked out - a visual lockout indicator (manually resetting this lockout returns the

controls the normal, and the transfer breaker is reset by transferring to the opposite source either manually or electrically).

2) The ground fault detector provides adjustable trip current and adjustable

tripping delay (to allow coordination with downstream breakers). 3) All "GFP" wiring is internal - no installer connections are required. Benefits of Option "GFP" ground fault protection: 1) Eliminates need for 4-pole transfer switch. 2) Prevents (unless ordered otherwise) the transfer of a faulted load to the

alternate source. 3) Employs only one ground fault sensor instead of two. 4) Reduced cost in most cases. 5) Offers good operator interface and reduces operator confusion in the

event of ground fault tripping during emergency situations. 6) Consolidates ground fault equipment into a single location. Using a 3-pole transfer switch with option "GFP" can substantially reduce system cost and complexity, while maintaining system performance. It should be considered for application where this type of protection is desirable.


CIRCUIT BREAKERSIZING

ENGINEERING BRIEF

EB007 Rev 0 87/04/09

CIRCUIT BREAKER SIZING

EB007 REV 0 87/04/09 Thomson Technology Inc.1

A) Generator Breaker Sizing

For minimal generator protection, one must consider two classes of overcurrentconditions when sizing generator circuit breakers:

1) Overload Protection (a slight overcurrent of long duration):

Typically protection is afforded by the long time tripping device (thermal elementof thermal-mag or long time in a solid-state trip breaker). Since the thermalelement’s temperature rise (or solid state equivalent) in a breaker generallyapproximates the temperature rise in the generator windings (including pre-heating and ambient temperature considerations), it will provide fairly goodprotection, if sized closely to generator output. If the thermal trip is over-sized,protection is minimal (See B).

2) Short Circuit Protection (a large overcurrent, hopefully of short duration):

Breakers with magnetic trips (or solid-state equivalent) are usually applied to giveshort circuit protection, but since the available fault current of the generator(sustained) is usually lower than the magnetic trip setpoint, they are oftenuseless. If a solid state breaker is used it may be possible to size one to trip ona short circuit, but only if it trips at less than 300% of the generators output, andif the generator has sustained short circuit output capacity (i.e. PMG, SBO, orequivalent).

A “short time” trip (i.e. an instantaneous trip that has a very short time-delay) isokay, since the generator should provide 300% current for at least 10 secondswithout damage (much longer than the trips’ time delay).

As an alternative, a generator may be equipped with an undervoltage shutdown.Single phase sensing should be adequate, as all phases will collapse on a solidshort circuit. This is a low cost but effective method of protection, and does notrequire a generator with fault current sustaining capability.

Caution must be exercised when attempting to sense short circuits with a currentsensing relay because:- the generator may not have sustained short circuit output.- if the generators output voltage is used to power the current sensing relay,

that voltage will not be available during a short circuit condition, and the relaymight not operate.

B) Breaker Sizing Example (for long-time trip)

Suppose the generator is rated at 313 amps output. The breaker should be a 300A (asopposed to a 350A) because:



1) If the generator is loaded to 350A (which will likely occur in one leg only, thus notcausing an engine overload), heat generated in the generator winding would be:

350 350313 X 313 X 100% = 125% of rated thermal

capacity, i.e. likely burnout.

or even worse, if loaded to 1.2 X 350A.(i.e. the current at which the breaker would trip in 1-2 hours), then:

420 420313 X 313 X 100% = 180% of rated thermal

capacity, i.e. definite burnout.

2) If a 300A trip is chosen, you can still load the generator at 100% at:

313300 X 0.8 = .835 PF

Therefore is PF = .835 or higher, you are not limiting the genset’s (as opposed tothe alternator’s) output.

C) The “80% Rule” & Standby Generator Breakers

1) Thermal Mag - technically (according to code) the maximum continuous current is80%, but you must consider:(a) The generator is a standby, therefore it is not continuous.(b) The generator is not likely to run at 100% load @ PF = 0.8.

Note - using an oversize frame will not help, since the trip is the limiting factor, e.g. a600AF/400AT is continuous rated 320A.

2) Solid State Trip (i.e. no heat-producing thermal element) - which is also rated 100%(some are not), then there is no problem.

CONCLUSION: - The “80% rule” is not useable on a standby unless you use a100% rated solid-state trip breaker.

D) Breakers for A Generator Which Must Provide Overload

1) “Continuous” Rated:

A generator with an overload rating of 10% for one or two hours (i.e. “continuousrated”) can generally be used with a standard thermal-mag or solid state breaker.



The breaker should be rated for approximately full load current. Since the breakerwill typically trip in 1 - 2 hours at 110% load, it allows the reserve capacity of thegenerator to be used, but will trip if it is run continuously at overload.

2) “Standby Rated:

A generator with no overload rating (i.e. rated as “standby” or “continuous standby,with no overload, for duration of outage”) is generally not able to be protected by astandard thermal-mag or solid state breaker of any description. Since the breakermust be sized to handle the full load current continuously, and since the breaker willonly trip on some overload (which the generator cannot supply) it is apparent thatprotection is not possible. In this case either:

(a) the breaker must be sized for the normal continuous rating, which will preventthe generator from running continuously at the standby rating, or;

(b) other means must be used to protect the generator (e.g. high windingtemperature shutdown), or;

(c) it must be deemed acceptable to have no real protection (in the case of astandby unit, this may be a consideration).

NOTE - This information is generalized, and is provided for general consideration only.Specific applications should be considered in depth to determine required protection.


MARINE GENERATORSWITCHBOARDS

TYPICAL ADDITIONAL REQUIREMENTS

ENGINEERING BRIEF

EB012 REV 1 86/02/08

MARINE GENERATOR SWITCHBOARDS - TYPICAL ADDITIONAL REQUIREMENTS


Due to the generally more critical application of a generator set in a marine environmentas opposed to an industrial location, certain extra provisions must be allowed for in thedesign of associated switchgear. These additional provisions for a typical installation,as required by the different governing authorities (Canadian Coast Guard, Lloyd’sRegister, ABS, etc.) are briefly stated as follows:

1. SWITCHBOARD ENCLOSURES must be equipped with:a) a handrail to aid a person operating the equipment in a rough sea.

b) a door detent to hold the door in an open position for servicing in a movingvessel.

c) an insulating floor mat, as required for larger installation, so that a personworking inside the switchboard may not receive a shock should he contacta live part.

d) a drip shield to prevent water from above running in the panel.

e) a panel light to illuminate the switchboard.

2. CIRCUIT BREAKERS must be plug-in so that a defective breaker may bechanged quickly and without the serviceman contacting live parts in the eventpower had to be maintained during changeout. Breakers must also haveundervoltage release to disconnect loads which may be damaged by low voltage.Breakers (as well as load cables, bus bars, contactors, etc.) must be oversizedby 25%.

3. All generator and shore breakers must have breaker position lights (i.e. On &

OFF). 4. KILOWATT METERS must be provided so that the operator will not overload the

generator set. 5. Voltmeters, ammeters, and frequency meters must have red lines to indicate

danger zones. 6. OVERLOAD RELAYS are required so that the electrical current flowing from he

generator will not be excessive, causing generator damage. Overload relayscause the circuit breaker to trip if the generator is in danger.

MARINE GENERATOR SWITCHBOARDS - TYPICAL ADDITIONAL REQUIREMENTS


7. PHASE SEQUENCE INDICATORS are required for three phase shore lines,

which are connected to different sources from time to time, so that an incorrectphase sequence can be detected and will not cause all motors to run backwards.A PHASE SEQUENCE CHANGEOVER SWITCH must be provided to selectproper sequences. On single phase systems, a polarity light is required toindicate reversal of neutral and ground conductors.

8. A “SHORE POWER ON” light is needed to verify connection to a live source. A

shore power voltmeter is required to ensure shore supply is the correct voltage. 9. GROUND FAULT LIGHTS c/w test switch, located on each load bus, to

annunciate a ground fault in the ship’s electrical system. 10. Special grades of wire (switchboard type TBS or SIS) to prevent chafing due to

vibration and insulation failure during overcurrent fault conditions. 11. COPPER must be used exclusively - aluminum connectors and bus bars are not

permitted. 12. Approval by governing authority CCCG, Lloyd’s Register, etc to ensure

standards have been adhered to, as evidenced by the stamp in the switchboard.Preliminary approval must be obtained on the proposed design beforecommencement of manufacture.

NOTE: The above is a general overview only. Some installations may requirespecial considerations. For instance, paralleling usually required stored-energy type generator circuit breakers. For a full explanation ofrequirements, refer to governing authority standards and/or regulations.

9087A – 198th Street, Langley, BC Canada V1M 3B1 ! Telephone (604) 888-0110Telefax (604) 888-3381 ! E-Mail: [email protected] ! www.thomsontechnology.com

“PG-UPT®”

PG-UPT® - PARALLEL GENERATION UNINTERRUPTED POWER TRANSFER

ENGINEERING BRIEF

EB013 REV 0 91/05/21

PG-UPT® PARALLEL GENERATION UNINTERRUPTED POWER TRANSFER


Many facilities have automatic backup generator sets and load transfer switches which will

provide standby electrical power in the event of loss of normal utility power.

When utility power first fails, the load becomes de-energized until the generator has started

and the transfer switch has transferred the load from the utility supply to the generator.

Since transfer switches are generally "break before make", the load will also become briefly

de-energized while the load is being returned to the utility supply. The load is also briefly

de-energized if the load is transferred to and from the generator during testing procedures.

Load de-energization, in many installations, is deemed undesirable, even if short. It causes

disruption of equipment and may impact upon persons present. Although it is not generally

possible to avoid load de-energization upon initial utility failure, it is feasible to prevent de-

energization in the other instances described.

The "PG-UPT" system is designed to perform an uninterrupted transfer switching function

by using the "make before break" method in conjunction with sophisticated electronic

controls which ensure that the two sources are synchronized at the instant of transfer.

Additional circuitry provides for extensive automatically and manually initiated modes of

operation, as well as ensuring adequate protection of the utility's system during periods of

interconnection.

PG-UPT provides additional benefits by allowing "peak shaving" which can drastically

reduce utility electricity charges, as well as the ability to test the generator set at any load

level by utilizing the site load. As with uninterrupted load transfer, peak shaving and load

testing are accommodated without any impact to the facility's electrical system.

A typical PG-UPT system would comprise two electrically-operated power switching devices

such as stored-energy air circuit breakers, and associated control devices.



P G-U P P G-U P P G-U P P G-U P T F E A T U R E ST F E A T U R E ST F E A T U R E ST F E A T U R E S

* 3 MODES OF OPERATION:INTERRUPTED TRANSFER - Break-Before-Make TransferUNINTERRUPTED TRANSFER - "Bumpless" TransferPARALLEL GENERATION - For Peak Shaving or Testing

* "SOFT" POWER TRANSFERRINGPrevents electrical & mechanical transients during transfers.

* UTILITY INTERCONNECTAll protective devices and features required to satisfy utility interconnectregulations are provided.

* TEST AT FULL LOADDuring parallel generation mode, the generator may peak shave or be testedat any load level up to 100% (assuming adequate site loading availability).

Export of power to the utility grid is automatically prevented.

* VAR CONTROLCorrect VAR sharing and Power Factor control between the generator andutility sources is provided.

* KW CONTROLPrecise KW load controls maintain generator at:

- required capacity in standby generation- preset maximum during parallel generation, with override toautomatically prevent export of power- necessary level to ensure zero-transient load transfer

* METERINGAllows operator to observe loading on both generator and utility.

* MANUAL CONTROLSAllows operator to manually select system operation for service or emergencyprocedures.

* RETROFITTINGMost installations that have electrically-operated separate power transferdevices are readily convertible to PG-UPT operation.



TYPICAL PG-UPT SYSTEMONE-LINE DIAGRAM

(PG-UPT is a registered trademark of Thomson Technology Inc.)


“UPT” TRANSFER SYSTEMS

OUTLINE OF FEATURES

UPT - UNINTERRUPTED POWER TRANSFER

PG-UPT® - PARALLEL GENERATION UNINTERRUPTED POWER TRANSFER

ENGINEERING BRIEF

EB014 REV 1 91/06/03

UPT TRANSFER SYSTEM - OUTLINE OF FEATURES


Thomson Technology uninterrupted power transfer systems allow load to be transferredbetween two live sources without any loss of power to the electrical load. Furtherenhancements of this technology allow peak shaving and generator testing at full load.

Uninterrupted power transfer systems are available in three standard configurations.

LEVEL 1 - BASIC UPT TRANSFER SWITCH

- Two Power Transfer air circuit breakers- Transfer Controls c/w overlapping ability- Relative phase angle sensor- Mode selector switch (interrupted transfer/uninterrupted transfer)

LEVEL 2 - MANUAL PG-UPT® TRANSFER SYSTEM

- As per Level 1 - Basic UPT- KW sharing, droop type- KVAR sharing, droop type- Utility wattmeter- Controls for manual synchronizing- Mode selector switch (interrupted transfer/uninterrupted transfer/parallel generation)- Generator reverse power protection

LEVEL 3 - AUTOMATIC PG-UPT® TRANSFER SYSTEM

- As per Level 1 - Basic UPT- KW sharing, automatic using KW load controller- KVAR sharing, automatic using VAR controller- Utility interconnection protection relays- Utility input power wattmeter- Controls for manual and automatic synchronizing- Automatic synchronizer- Mode selector switch (interrupted transfer/uninterrupted transfer/parallel generation)- Generator reverse power protection



Advantages of TTI Basic UPT Transfer Systems overContactor Type "Closed-Transition" Transfer Switches:

* MORE SERVICEABLE - TTI UPT uses drawout stored-energy power aircircuit breakers for switching, which are readilyremoved for servicing. One may be removed whilethe other is still in service. As well, they may beinterchanged.

* HIGHER RATING - TTI UPT has a true interrupting rating and anexcellent short time rating, allowing excellentsystem coordination. Closing/ withstand ratingsare available to very high levels.

* FASTER - TTI UPT transfers faster, thus reducingperiod of source paralleling and load disturbance,typically by a factor of five.

* OVERCURRENT - TTI UPT allows incorporation of overcurrentPROTECTION protection, and may allow deletion of a

separate generator circuit breaker.

* SAFE MANUAL OPERATION- TTI UPT can be manually transferred withoutopening the enclosure, and without damagingitself if manually transferred while carrying load.

* BETTER INTEGRITY - TTI UPT provides two totally separate andredundant power circuit breakers, each in itsown barriered compartment. This means that ifone should fail or suffer severe damage, the otherone can still operate, providing power to the load.



Advantages of Manual PG-UPT® over Basic UPT:

* PARALLEL GENERATION - Means that the generator may be operatedcontinuously in parallel with the utility to providepeak shaving and load testing up to full load.

* REDUCED SYSTEM - The PG-UPT parallels the two sources when they TRANSIENTS phase angle), thus reducing system transients.

This is a great improvement over "closed transition" transfer switches, which may parallel thetwo sources when they are only approximately in phase.

* NO POWER INTERRUPTION- Parallel generation assures that if the generatorfails during load testing, the load will not beinterrupted even momentarily. With basic UPT orclosed-transition transfer switches, power to theessential load is lost until a transfer to utility poweroccurs.

Advantages of Automatic PG-UPT® over Manual PG-UPT:

* SIMPLER OPERATION - Automatic synchronizing and precise KW andKVAR control allows the operator to automaticallyeffect a load test, and to precisely calibrate desiredloading parameters without the possibility of drift.

PG-UPT®

is a registered trademark of Thomson Technology Inc.


“PEAK PLUS”

GENERATOR-UTILITY INTERCONNECTCONTROL SYSTEM

ENGINEERING BRIEF

EB015 Rev 0 95/07/01

“PEAK PLUS” CONTROL SYSTEM


DESCRIPTION OF SYSTEM

The “Peak Plus” system is designed to allow the generator set to be paralleled with the utilitysupply for Peak Shaving and/or testing operations. Sophisticated electronic controls ensurethat the two sources, phases and voltage are matched prior to synchronizing. Additionalcircuitry provides for extensive automatically and manually initiated modes of operation, aswell as ensuring adequate protection of the utility’s system during periods of interconnection.

The “Peak Plus” system is comprised of the following components:• Electrically operated drawout, 100% rated air circuit breakers• Protective relays• Utility/Generator instrumentation• Automatic synchronizer• Engine governor controller loadsharing module• VAR/Powerfactor control• Peak Plus 500 transfer controller

Existing local generator set controls utilized in conjunction with Peak Plus system are:- Auto start/stop controller- Engine electronic governor controller- Generator automatic voltage regulator

SEQUENCE OF OPERATIONThe synchronizing system will have two basic modes of operation, one completely automaticand the second manually operated. The two position selector switch (25CS) will initiateoperation as follows:

AutoThe generator automatically synchronizes to the utility supply and closes thegenerator/utility tie circuit breaker.

ManualThe synchroscope, sync lights and manual sync check relay are enabled (automaticsynchronizing is inhibited).

System Paralleling transfer operation will be controlled by separate selector switches.



43CS PEAK SHAVE OPERATION SWITCH

AUTOThe generator set will automatically start and synchronize to the utility supply when aremote signal is issued by the building management system. The generator’s load levelmay be manually or automatically set as selected by the loading control switch. Whenthe remote signal is opened, the generator will ramp it’s load down, trip off line,cooldown, then stop.

OFFPeak shave operation is disabled. Note: The generator set will still automatically startupon a utility power failure provided the load control panel is set for automaticoperation.

MANThe generator set will start/stop as controlled by pushbuttons located on the front of thepanel. Synchronizing and loading may be automatic or manual subject to other switchpositions.

43LC LOAD CONTROL SWITCH

AUTOThe generator set will automatically assume a load level as determined by theautomatic loading controller. The generator load level set point is adjustably set from apanel mounted rheostat.

MANThe generator’s load level is set manually via panel mounted potentiometer “Generatormanual load adjust”.

GLA - GENERATOR LOAD ADJUST POTENTIOMETERThe generator’s load may be manually set via potentiometer provided the load control switch(43LC) is in the manual position.



COMPONENT DESCRIPTION

SWITCHBOARDSingle vertical section to be free standing, dead front, cubicle size as indicated,completely metal enclosed, self supporting structure, 90” high. Breaker will be locatedin the lower compartment.

Barriered metering and control sections will have a metal backboard. The controlsection shall incorporate metering, switching, protective relaying and control devices.Ventilation openings will be provided where required.

The switchboard will be provided with lifting hooks and built-in angles or channels tofacilitate bolting to the floor. Exterior and interior steel surfaces will be properly cleanedand finished with enamel paint - color ASA 61 grey. Backboards will be painted white.

The bussing, where necessary, will be tin-plated copper of sufficient size to limittemperature rise to 65°C and rated to withstand available fault current during shortcircuit condition. Switchboard will bear CSA label C31.

UTILITY INTERCONNECT BREAKERBreaker will be drawout air circuit style minimum 42KA rms symmetrical at 600 Volt with100% continuous rating. Three drawout positions - Test, Disconnect and Withdrawnwill be provided. Breaker will have 120VAC electrical operation with 24VDC shunt tripand 120VAC close coils.

Breaker will have microprocessor based integral current sensor with long time, shorttime, and instantaneous trip functions. Breaker control switch (52CS) will be supplied toprovide manual trip control at any time, and closing control provided the permissivesync logic is satisfied.

AC INSTRUMENTATIONAnalog indicating type, 4-1/2, 1% accuracy, flush panel mounting

Generator• Voltmeter, Ammeter, Frequency Meter, Powerfactor, Kilowatt• Voltmeter and Ammeter four position control selector switches



Utility• Voltmeter, Frequency Meter, Kilowatt , Powerfactor• Voltmeter four position control selector switch

PROTECTIVE RELAYINGA Utility grade protection system will be provided. The relays will be flush mounted onthe utility cabinet door. The protective relays are permitted to function only when thegenerator set is closed to the bus. Relays provided will be Basler BE-1 series asfollows:

• BE1-32U - Utility reverse power• BE1-27/47/59 - Negative Sequence/Under/Overvoltage• BE1-81O/U - Under/Over Frequency• BE1-25 - Sync Check

A Generator reverse power relay will be separately provided to protect the generatorfrom reverse power should the engine lose power while in the parallel generation mode.This industrial grade relay will be internally mounted and annunciated with the PP-500controller.

SYNCHRONIZING/INTERCONNECT CONTROL

Auto Synchronizer (25)This unit automatically monitors and controls the generator speed (frequency) to matchthe phase relationship between the generator set and utility service during uninterruptedsystem paralleling. The synchronizer provided will be a Woodward type SPMA.

VAR/Powerfactor ModuleThis unit controls the Kilovar load (i.e. Powerfactor) of the generator when in the parallelgeneration mode in conjunction with the generator voltage regulator.The VAR/PF controller provided will be a Basler model SCP-250.

Sync Check Relay (25A)This relay provides backup protection to the automatic synchronizer. Whensynchronizing, both ASU and 25A relays must initiate a breaker close signal prior to abreaker closure.



Generator Load Sensor The generator load sensor control provides the load sharing capability for the engine

governor controller Woodward model 2301A. The load sensor provided will be aWoodward type 2500.

SynchroscopeAllows monitoring of phase relationship between the normal and generator supplyduring uninterruptable transfer operation.

Programmable Logic ControllerThe programmable logic controller (PLC) monitors and controls the utilityinterconnect synchronizing operation. System operating mode is based on inputsfrom the control switches 25CS, 43CS and 43LC.The PLC monitors the status condition of the breakers, associated protective relaysand transfer switch(es) in the system and provides interconnect breaker operationcommands based on the inputs monitored.The PLC will control the generator Kilowatt soft loading and unloading whenconnected bus in parallel with the utility. The bumpless power transfer will becontrolled to near zero power level during periods before and after closing andopening of the interconnect breaker.

PP 500 ControllerThe PP 500 controller is used in conjunction with the PLC to provide an operatorinterface for the Utility Interconnect Control Scheme. A mimic bus showing theoperator and transfer switch status is provided. Separate indicator lamps providevisual indication for the following functions:Operating Mode

• Synchronizing - Green• Parallel with Utility - Green

System Alarm• Generator Reverse Power - Red• Utility Fail in Parallel Mode - Red• Fail to Synchronize - Red• Control Power Available - Green

Lamp test and fault reset push buttons are provided.


POWER TRANSFER SCHEMES

PG-UPT(Parallel Generation - Uninterrupted Power Transfer) &

CTTS (Closed Transition Transfer System)

ENGINEERING BRIEF

EB017 Rev 1 98/02/17


EB017 REV 1 98/02/17 1 Thomson Technology Inc.

INTRODUCTION

There are many applications where power continuity is important for life safety oreconomic reasons. These applications require two independent sources of power. Inthe event of a failure or abnormality of the utility supply, the vital load is transferred tothe alternate source.

Ideally, this transfer would cause no interruption to the load and would involve no majortransients. It is possible to accomplish such a transfer where the application requiresabsolute continuous, “no-break” power at all times. To do so, requires that both sourcesof power be continuously available.

Most standby or emergency power sources consist of on-site engine-generators thatare started upon failure of the normal source. There will always be a break in power tothe load until the alternate source becomes available. Typically, there will be a shortbreak in power anytime the load is switched, even if both power sources are available.These breaks normally occur during testing of the system and upon re-transfer of theload to its utility supply when power is restored. Since load interruptions are sometimesinconvenient, there is interest in eliminating these interruptions during transfer whenboth power sources are available. Such systems can be provided to do so safely.

Recently, systems consisting of modified transfer switches (closed transition transfer) ortransfer switches with paralleled contactors have been proposed as an economical wayto accomplish “no-break” switching during test and retransfer. As attractive as theseschemes may appear, they require an understanding of the serious safety and reliabilityissues. These systems may cause increased power system voltage transients duringthe transfer of power. Transfer switching schemes which have been modified toprovide closed transition transfer may also jeopardize the complete installation andshould be reviewed carefully to ensure compliance with applicable CSA/UL standardsand local utility authorities.

FAST POWER RESTORATIONMost loads can tolerate a short break in power. Hospital emergency power systems, forinstance, are designed to handle short power breaks as long as power is restored tovital circuits within ten seconds. Loads requiring fast restoration are supplied by engine-generator sets which start upon failure of the normal supply and a transfer switch which



transfers the vital load from its utility supply to the alternate source when it becomesavailable. The key factor in these systems is maximum reliability. A momentaryinterruption is acceptable. A sustained or prolonged interruption is not!

Maximum Reliability Requires:• That the load must be quickly and reliably transferred if a power source is available.• That the switching of the load must be done in such a manner as not to jeopardize

the source to which it is being transferred.• That any system disturbance encountered must be predictable and reproducible so

that all equipment and personnel can be preprogrammed to restore normaloperation quickly and reliably after a transfer.

TRANSFER SYSTEM

Open TransitionThe conventional transfer of a critical load between power sources isaccomplished with a double-throw transfer switch arrangement. Historically,transfer switches have been designed with a positive mechanical interlock thatabsolutely prevents both sources being closed to the load at the same time.Since the sources are un-synchronized, paralleling them could cause seriousequipment damage and failure of the system.

There will always be a break in power until the alternate source is available. Allloads connected to the system must be provided with automatic controls, torestart or reclose the load to the power source when restored.

Consideration should be given to the manner in which the load is returned to thenormal source. In most instances, it is desirable to have a short time delaybefore retransferring the load automatically in order to assure that the utilitysupply is going to remain available. There will be a break in the power to the loadduring retransfer, but this will be minimal since both sources are available.However, the break will always occur with the use of a conventional transferswitch.

Parallel Generation - Uninterrupted Power Transfer (PG-UPT)Closed Transition Transfer Switch (CTTS)



When testing a system (no actual power loss) and when returning the load to itsnormal source, both power sources are available, and it is possible toaccomplish a “no-break” transfer.

All “no-break” transfer schemes involve paralleling of the two sources for someperiod of time. Since conventional transfer switches have mechanical interlocksto positively prevent paralleling of the two sources, they cannot be used. It isnecessary, therefore, to either:• Replace the transfer switch with paralleling circuit breakers and controls (PG-

UPT).• Provide a modified transfer switch that has overlapping contacts some of the

time (closed transition transfer).• Parallel the transfer switch contacts with contactors.

PG-UPT (Parallel Generation - Uninterrupted Power Transfer)This requires replacing the transfer switch with two electrically interlocked circuitbreakers, synchronizing controls, some type of power transfer control, and a fullcomplement of protective relaying for both sources.

If only one power source is available, the circuit breakers operate in a “break-before-make” configuration, the same as a conventional transfer switch (butwithout the positive mechanical interlock). If both power sources are available(test and retransfer), the synchronizing controls bring the alternate sourceengine-generator into synchronism with the normal utility source, parallel them,and gradually shift the load from one source to the other.

Full protective relaying is necessary in order to protect both the utility sourceand the generator source and to provide immediate disconnection of a failingsource.Utilities require permission to parallel with their lines and are generally quite strictin demanding protective relays. Protective relaying is just as important to theengine-generator, since the tremendous fault current available from the utilitycan destroy the engine-generator in the event of an abnormality.

This type of system can provide a “no-break” transfer during test and returntransfer to normal.



CTTS (Closed Transition Transfer Switch)The idea of using a closed transition transfer switch to accomplish “no-break”transfer is now being actively promoted. In the event of a power failure, thistransfer switch operates in a conventional “break-before-make” mode. However,during test and retransfer, the sources are paralleled (make-before-break) duringthe transfer operation. To accomplish this, the mechanical interlock has beenremoved. Relays are provided to check the relative phase relationships and therelative voltage and frequencies of the two sources. When the voltage andfrequency are within approximately 5% and the phase relationship withinapproximately 15%, a signal is given which causes both sets of contacts of thetransfer switch to be closed to the load at the same time, paralleling the twopower sources. After a brief period, one side of the switch is opened, leaving theload connected to the other source. The transfer thus occurs with no apparentbreak in power. No active synchronizing controls or protective devices for eithersource are provided.

Generally, the cost of such a system should be lower in comparison to trueparalleling controls. However, utility approval, system integrity and potentialliability must be considered.

These systems do not employ any active synchronization, and there is no way toautomatically adjust the voltage or frequency of either source. There is no powertransfer control to gradually transfer the load between the two sources. Thesudden application or removal of large block loads from the engine-generators,as they are paralleled with a utility, can cause transients between the twosources and system disturbances. The magnitude of these disturbancesdepends upon the size of the load and the dynamic characteristics of the system,but they can be detrimental to a sensitive load.

Since the positive mechanical interlock has been removed from the transferswitch, the electrical controls must prevent paralleling the sources under someconditions (when one source has failed or is failing) but also permit it underothers.

Anytime on-site power generation is paralleled with a utility, approval of the utilitymust be obtained. Proponents of Hybrid schemes suggest protective relaying is



not necessary (since the sources are only in parallel for a short duration, i.e.: 100milliseconds).

Many utility engineers, believe paralleling with the utility, regardless of the periodof time of the interconnection, requires full utility protective relaying to preventdamage to their system. As a minimum, local utility approval will be for eachapplication, CTTS or PG-UPT. We feel if a utility were to agree to unprotectedparalleling for as little as 100 milliseconds, they would hold the owner of theequipment liable for all damage to their system if paralleling should occur for alonger time.

In the event of a utility failure, an on-site power source, paralleled with the utilitygrid, even momentarily, could energize utility lines and cause bodily harm ordeath to utility personnel.

Incorrect paralleling of an on-site generator with the utility can result indestruction of the engine-generator itself.

Liability problems arise from the fact that no protective devices are provided toprotect and isolate the paralleled power sources in the event of an abnormality.

SUMMARYConventional open transition transfer switches offer a proven reliable method oftransferring between two power sources. The power interruption that occurswith conventional transfer switches may not be acceptable in some applications.Two options are available on systems that cannot tolerate any power interruption,PG-UPT & CTTS. PG-UPT is an active synchronizing method with protectiverelaying, is CSA certified and meets typical utility company approvalrequirements. CTTS is a lower cost, passive synchronizing system that requiresCSA certification and local utility approval.



BENEFITS OF TRANSFER SWITCH WITH PG-UPT SYSTEM:“Soft” Loading and UnloadingUpon return of utility power, the PG-UPT System provides not only a “Bumpless”transfer, but also provides a “Soft” (slow ramp down) unloading of the generator. Thissame “Soft” loading feature is utilized in a test or Peak Shaving mode, thus eliminatingundo stresses on the engine-generator.

Active SynchronizationPG-UPT parallels the two incoming sources when they are accurately synchronized(both frequency and phase angle), not just when the sources are approximately “inphase”.

Peak ShavingPG-UPT can be used for continuous peak shaving, if desired.

Load TestingPG-UPT allows testing the generator set at any level up to the building load, withoutany interruption or switching transients.

More ServiceablePG-UPT may use draw-out type stored energy air circuit breakers for switching, whichmay be simply removed for servicing.

Higher RatingPG-UPT has a time “interrupting” rating and excellent short-time rating, allowing propersystem coordination. Very high closing/with-stand ratings are available.

ProtectionBoth the generator and utility are protected by the relays incorporated into the systemas required by the utilities.


AUTOMATIC SYNCHRONIZING(PARALLEL OPERATION)

ENGINEERING BRIEF

EB018 Rev 0 96/05/17

AUTOMATIC SYNCHRONIZING (PARALLEL OPERATION)


Basic Principles:

1 Automatic synchronizing of a generator consists of electrically “coupling” thegenerator output to another source of electrical energy and operating thegenerator such that its output adds to the other source.

2 Automatic synchronizing can encompass a wide variety of conditions suchas:

a) Two or more equal or similar-sized generators which, whenparalleled to each other, will operate as though they were one largergenerator. This is the most common application and reason forparallel operation.

b) Two or more unequal-sized generators which are operated in parallelas though they were one larger generator. This is also a commoncondition.

c) Generator systems (which may consist of two or more individually-paralleled generators) which are operated in parallel with anotherelectrical system which, by comparison, is infinitely large. This is thecase of operation in parallel with the normal electrical utility source.This is commonly done for on-site peak shaving, bottom shaving orcogeneration systems. It may be done momentarily in some specialcases.

Benefits of automatically-synchronized (paralleled) systems:

1 Economy

An existing distribution system may not lend itself to being split into severalsections and handled by separate non-paralleled units. When the loads areexpected to expand substantially, the initial investment is minimized byinstalling one smaller generator set, and then adding more sets in parallelas the loads increase.

2 Reliability

When a part of the emergency load is deemed very critical, it may bedesirable to have more than one generator capable of being connected tothat load. When there is a normal source outage, all generators in thesystem are started.

The probability of having a generator start and achieve nominal voltage andfrequency is increased according to the number of sets available. The firstset ready to handle the essential load does so. As the other generators are



running and connected to the bus, the remaining loads are connected indeclining order of priority.

Types of Systems:

There are two types of paralleling systems:

a) Sequential parallelingIn sequential paralleling, the engine/generator sets are connected tothe bus in a predetermined order. The lead engine is connected tothe bus first. When the engine/generator selected as number 2 isready to be connected, a synchronizer is connected between theoutput terminals of generator 2 and the bus. Then the generator is insynchronism, its paralleling circuit breaker is closed, connecting it tothe bus. Usually, a restriction is imposed to limit the time thecontrols will consume in attempting to synchronize and parallel a setto the bus before reconnecting the controls to the next set insequence.

b) Random parallelingRandom access permits simultaneous synchronizing of each set tothe bus. The random access method is faster than sequentialparalleling but more expensive. Codes mandating emergency loadsto be reconnected within ten seconds may require the method ofoperation. With diesel or natural-gas-driven engine/generator sets, itis reasonable to expect that the emergency bus will be establishedwithin the ten-second limit in a random access system, because anyone of the generators can be first on line.

c) Dead field paralleling

d) Utility paralleling

Synchronizing Basics:

1) To successfully synchronize a generator to a bus requires some degree ofinstrumentation to tell the operator what the phase relationships arebetween the two sources. The simplest is two voltmeters connected to readvoltage between the same phases of the incoming generator and the bus.

When the two sources are in phase and at equal voltage, both Va and Vbwill read 0 volts. (The third phase will also be the same since, if any twoare correct, the third must be correct.) When the phases are 180° out ofsync, the voltmeters will read 2 x normal system voltage. As the phases goin and out of sync the voltmeters will drift from 0 to 2 x to 0 at a rate whichdepends on the slip frequency (frequency difference). The breaker closure



must occur when the voltage difference is at, or very near, 0. Otherwiseeach source will be subjected to extreme currents and forces which willdamage the equipment. Out of sync voltage differences (and resultantforces) increase rapidly with increasing phase to phase mismatch angles.In general the forces are acceptably small if the phase angles are withinabout ± 15° of true synchronism.

2) Two synchronizing lights can be used in place of voltmeters. When thelights are out, the phases are synchronized. When the phases drift out ofsync, the lights will come on due to the voltage difference. It is usual to usethree lights to cater to the possibility of one burned bulb. Bulbs must berated for 2 x voltage.

3) A synchroscope is a pointer-type meter which incorporates the twovoltmeter movements with a single pointer. The pointer moves to a circularposition dependent on the voltage difference. At zero volts it will be locatedat top dead centre. The synchroscope position is representative of voltagedifference, not phase displacement angle. Any area within about 30° to 45°of top dead centre represents a fairly small voltage differencecorresponding to a fairly small phase-to-phase displacement. Asynchroscope will rotate at the slip frequency rate.

4) All of the foregoing are instrumentation devices which will allow an operatorto observe when synchronism occurs and to initiate breaker closureaccordingly. The operator must adjust the incoming generator speed (andvoltage if necessary) to obtain synchronized conditions).

5) For automatic systems, an automatic device must be used to obtainsynchronized conditions and initiate breaker closure at the proper time.There are a wide variety of automatic synchronizers available to interfacewith various types of governors. The synchronizer can also be utilized tomatch voltages as well as speed.

Protection devices:

1) When a synchronous generator is connected to an external electricalsource, it is capable of acting as though it were an electric motor. In thecase of generator sets operating in parallel, if the engine output power failsfor any reason, such as shutdown, the generator will motor the engine atbus frequency. The required power, usually about 10 to 20% of ratedpower, will be provided by other machines. To prevent this occurrence, allparalleled generators must be fitted with a reverse-power relay. The relayis set to open the generator breaker at about 5 to 10% reverse power.



2) The generator breaker must be rated to withstand and interrupt theavailable fault currents from the load bus. This may require special breakerconsiderations when paralleling to an infinite bus.

3) There are many additional protective devices which can be applied to singleor parallel-operated generators. Particular application considerations willdetermine the requirements.

Technical considerations for automatically-synchronized systems:

1) The generator output must be the same as the bus; that is:– Same number of phases– Same phase to phase voltage– Same phase rotation (e.g. ABC or ACB)

2) The generator and bus AC waveforms must be in identical phaserelationship at the time of breaker closure to connect them. This is calledthe in phase or synchronized condition. Note that if the phase rotationsare the same, then the B to B and C to C relationship will be identical tothe A to A relationship. If the phase rotations are opposite thensynchronism of all 3 phases can never be achieved. If the breaker isclosed to connect the two sources based on only one phase being insynchronism, major damage can immediately occur.

3) Only when the two sources are inphase or synchronized (each phasevoltage matched, phase rotation matched and phase angles matched) canthe two sources be connected together.

4) Once the two sources have been connected together they will remain insynchronism no matter what (unless the breaker(s) open and disconnectone of the sources). The two sources are effectively “geared” together byelectrical forces.

5) If the two sources are two equal generator sets, say for example 2 x 500kWe as soon as they are in parallel, the system should now behave asthough it were a single 1000 kW generator.

6) The key to parallel operation is to make the system behave as it should.The challenge comes from the fact that the “single” generator has tworegulator exciters and two governor systems. The characteristics of the twomachines must be matched for the “whole” system to function correctly.

7) The voltage and frequency controls of a paralleled generator not onlycontrol voltage and frequency.

(a) Voltage control (excitation control) now controls the reactive poweroutput of the generator. If the generator is over excited, instead ofthe voltage rising the excess excitation will result in generation and



delivery of excess kVARs to the bus. If it is under excited it will“absorb” kVAR’s from the bus. When the excitation level is exactlycorrect for the actual bus voltage the generator will share the kVAR’srequired by the load.

(b) Frequency control (governor speed control) now controls the realpower output of the generator set (kWe output). If the governorfrequency (speed) setting is higher than the actual bus frequency,the governor will sense an underspeed condition and attempt tocorrect the condition by increasing the fuel. This can only result inincreased power output. Likewise if the governor frequency setting isbelow the actual bus frequency, then the governor will senseoverspeed and react by reducing the fuel.

8) In the case of two or more engine generator sets operating in parallel, it isreadily apparent that the regulators and governors must function togetherto achieve system control.

9) In the case of an engine generator paralleled to an infinite bus, it is notpossible to control the infinite bus. Its regulators and governors are notaccessible, and even if they were, other considerations (such as otherconnected customer needs) would prevent adjusting the bus controls tosatisfy an insignificantly small paralleled generator.

For paralleling considerations a bus can start to be considered as infinitewhen the bus capacity is about 5 times the paralleled generator capacity.Thus if a 100 kW generator is paralleled to a bus powered by a 1000 kWegenerator, it is essentially being connected to an infinite bus. (There areexceptions to this condition but these are beyond the scope of this salesand marketing seminar)

10) This is a classic case of “two halves do not necessarily make a whole”.However, the control of paralleled generator(s) is in fact simple, reliableand extremely versatile.

Load Control:

1) Whenever engine/generators are paralleled, the loads should be dividedand controlled so that the system will not be overloaded. Overloading anemergency system will cause voltage and frequency deviations andpossibly cause the failure of the complete system. The loads can begrouped into blocks consistent with the prime mover size. See Figure 7-10. This means that load prioritization is necessary. The system can thencontrol the connection of load to the bus in a prioritized sequence asgenerators are placed on line. Similarly, the system must disconnect, orshed loads in reverse order of priority, to ensure maximum continuity of



power to the highest priority loads if bus capacity reduces due to loss ofgenerating units.

2) Having established the basis for load connection and shedding, it isnecessary to consider the means to achieve this switching. There areseveral ways to switch the loads. In an emergency power system, oneconvenient means is to utilize the automatic transfer switches for loadconnect and load dump operation. See Figure 7-11. Another methodinvolves the use of remote-control switches, or contactor to open andclose, adding and shedding the loads. Downstream circuit breakers canalso be tripped to shed load. However, if shunt-tripped molded-case circuitbreakers is the method used, consideration should be given to the fact thatthese breakers must be manually reset to reconnect the load. In short,there are many approaches to load switching. The preferred approach forany application is determined by the requirements of the application.

Load Share Basics:

1) Governor speed adjustment controls generator set load (kW) after thegenerator is paralleled to a bus.

If a diesel generator with droop governing is paralleled to the utility bus, thegenerator frequency will be exactly the same as the utility bus at themoment that paralleling occurs. If no change in set speed occurs, thegenerator will run in parallel with the utility, but will not produce any load.

2) A more normal parallel generator set condition is the parallel operation of 2or more engine generators onto a common bus. The considerations areidentical to the infinite bus except that speed (or voltage) set pointadjustments on one generator will in fact result in a speed or voltagechange on the bus along with the expected change in real or reactive load.Increasing the load on one generator will correspondingly decrease the loadon the other bus connected generators. To maintain the bus frequency andload share requires adjustments of both governors. Likewise, to maintainbus voltage and kVAR share requires adjustment of both regulators.

3) For paralleling with load-droop governors or reactive load droop regulators,the set speed (voltage) of both sets must be adjusted (one up, one down) ifa constant bus frequency (voltage) is required. Usually the small voltagevariations are of no concern, and voltage adjustments are not necessaryprovided both regulators have equal kVAR droop and both are set for equalvoltage at equal kVAR load. It is often desirable to maintain a relativelyconstant bus frequency at various loads. If droop governing is being used,the set speeds must be trimmed with each load change.



4) Electronic load sensing governors can be used for parallel operation withisochronous speed (frequency) control and electronically controlled loadlevels.

The electronic load signals from all the paralleled generators can beinterconnected and used to bias each governor so that it carries its share ofthe total load. The sets do not have to be equal size. Each will carry itsproper portion of the total load.

5) The generator voltage regulators can be equipped with a reactive loadshare system which will avoid regulator droop with varying kVAR loads. Thisis called cross current compensation.

9087A – 198th Street, Langley, BC Canada V1M 3B1 � Telephone (604) 888-0110Telefax (604) 888-3381 � E-Mail: [email protected] � www.thomsontechnology.com

ENCLOSED CONTACT

VERSUSOPEN CONTACT TYPETRANSFER SWITCHES

ENGINEERING BRIEF

EB019 Rev 0 00/12/07

ENCLOSED CONTACT VERSUS OPEN CONTACT TYPE TRANSFER SWITCHES


There are two distinct dominant, certified (UL #1008 and CSA #178) automatictransfer switch designs available in North America today. These two designs arecommonly referred to as “breaker type” and “contactor type”. The references to“breaker type” and “contactor type” are misleading terms when referring to certifiedautomatic transfer switches. A more correct description of the two types ofautomatic transfer switch designs would be “enclosed contact” (breaker) and “opencontact” (contactor).

True (NEMA) contactors are electrical devices designed to make or break current.They are most often designed for motor starting and lighting control, are electricallyor mechanically held and have mechanical endurance ratings that can number in themillions of operations. “Contactor” type transfer switches do not use contactors thatare designed for lighting or motor control and do not provide the same certifiedendurance ratings.

“Contactor” type transfer switches often use an “Open Contact” circuit breakerdesign that incorporates breaker contacts, arcing horns and arc chutes. Some ofthese types of switches were developed with circuit breaker manufactures at thetime of their original design. This “Open Contact” design is then tested and certifiedin accordance with the applicable automatic transfer switch standards, UL #1008,CSA #178 in North America.

Automatic transfer switch certification requires that all automatic transfer switchespass the endurance ratings as per UL standard UL #1008 table 30.2. and CSAstandard CSA #178 table 10 as a minimum. The endurance tests listed in the UL#1008 and CSA #178 standards are the only endurance tests that are certified byUnderwriters Laboratories and the Canadian Standards Association for automatictransfer switches. No other claims related to endurance should be givenconsideration unless recognized by the appropriate certifying bodies.

Enclosed Contact transfer switch designs take advantage of the technology inswitching, contact, arc chute and arcing horn designs that continue to be developedin molded case circuit breakers. Just as the original designers of “Open Contact”transfer switches saw the advantages in circuit breaker switching and contacttechnology available at the time, “Enclosed Contact” manufactures take advantageof the technical advances of today.

Enclosed Contact designs utilize devices that are specifically tested and certified(UL #1008 and CSA #178) for automatic transfer switch applications. In addition tobeing certified to the applicable automatic transfer switch standards, devices usedin enclosed contact designs have often been certified to other more demandingcertification tests such as, UL 489, UL 1087, CSA 5.1, CSA 5.2. These certifiedtests results are recognized by the appropriate certifying bodies and should beconsidered when comparing automatic transfer switch designs.



In addition to taking advantage of state of the art switching and contact technology,Enclosed Contact designs also take advantage of the inherent stored energyfeature of the “spring over center” mechanism in molded case circuit breakers. The“spring over center” mechanism guarantees consistent, reliable opening and closingof the transfer switch contacts when switching in the manual mode. Enclosedcontact transfer switches are rated to switch manually while under load because ofthe inherent stored energy design of molded case circuit breakers.

Open Contact transfer switches clearly state that all sources of load must bedisconnected before operating manually. Manually switching a transfer switch thatis connected to an electrical source without a stored energy mechanism may causepremature contact wear and could potentially be a safety risk to operators.

Enclosed Contact designs utilize two separate, enclosed switching components in acommon mechanism. By separating the switching components and enclosing thecontacts, enclosed contact automatic transfer switch manufactures are able toprovide a higher degree of reliability and redundancy. Logically, separate switchingcomponents and enclosed contacts also provide superior operator safety.

Enclosed Contact transfer switch designs can also be provided with circuit breakerswith an inherent self-protecting overcurrent trip unit, providing an additional level ofprotection. With a correctly coordinated electrical system protection scheme, theintegral overcurrent trip unit in the automatic transfer switch will not adversely affectsystem operation or performance.

Utilizing an Enclosed Contact type transfer switch provides the economic benefits ofallowing integral overcurrent protection for applications such as service entranceequipment without the need for external circuit breakers, as is typically the case withopen contact design transfer switches.

Endurance Test Cycles UL table # 30.2

Number of Cycles of OperationSwitch Rating Rate of

Operation a, bWith

Current cWithoutCurrent Total

0 – 300 1 per minute 6000 – 6000 301 – 400 1 per minute 4000 – 4000 401 – 800 1 per minute 2000 1000 3000

801 – 1600 1 per 2 minutes 1500 1500 30001601 and above 1 per 4 minutes 1000 2000 3000

a May be conducted at a faster rate if agreeable to those concerned however, not fasterthan one operation per minute for tungsten ratings unless synthetic load is employed.



b The indicated number of cycles of operation applies only to that part of the test withcurrent. When no current is used, the switch may be operated at any convenient speedrepresentative of intended operation.

c For transfer switches rated for total system transfer, motor loads, or electric-dischargelamp loads, the test shall be conducted for one half of the specified number of operationsat 200 percent of rated current and for one half of the specified number of operations at100 percent of rated current.

CSA table # 10

Number of Cycles of OperationSwitchRating

Rate ofOperation * †

WithCurrent

WithoutCurrent Total

0 – 300 1 per minute 6000 – 6000 301 – 400 1 per minute 4000 – 4000 401 – 800 1 per minute 2000 1000 3000 801 – 1600 1 per 2 minutes 1500 1500 30001601 – 4000 1 per 4 minutes 1000 2000 3000

* May be conducted at a faster rate if agreeable to those concerned; however, not fasterthan one operation per minute for tungsten ratings unless synthetic load is employed.

† The indicated number of cycles of operation per minute applies only to that part of thetest made with current. When no current is used, the switch may be operated at anyconvenient speed representative of normal operation.

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