A PROLOGUE TO FAULT CALCULATIONS (Part IV)

A PROLOGUE TO FAULT CALCULATIONS
(Last Part of a Series)

SELECTION OF EQUIPMENT

To recap, short circuits must therefore be quickly removed from the power system and this is the reason why protective devices such as circuit breakers and fuses are being placed there. To accomplish this, the protective devices must have the ability to interrupt the maximum short circuit current without injury; otherwise the injured breaker becomes the fault itself. The maximum value of short circuit current is frequently referred to as the “available short circuit current” or in some other terminology, the “available SC MVA”. The protective devices at any point of the system must be sized such that in any event of fault wherever they might be in the system, the associated upstream device closest to the fault must first interrupt the fault without disturbing others. The value of short circuit current is directly related to the size and capacity of the reference power source and is independent of the load current of the circuit being protected. The larger the capacity of the reference power source (e.g. larger transformer sizes), the greater the short circuit will be, while cable impedances along its path tend to lower them down.

Once the short-circuit levels are determined, the engineer can specify proper interrupting rating requirements, selectively coordinate the system and provide component protection. With personnel safety while minimizing equipment damage in mind, it is essential to use equipment with short circuit ratings greater than the available short circuit current that can occur at the equipment location. The 2005 National Electrical Code states that: “Art. 110.9 Interrupting Rating. Equipment intended to interrupt current at fault levels shall have an interrupting rating sufficient for the nominal circuit voltage and the current that is available at the line terminals of the equipment. Equipment intended to interrupt current at other than fault levels shall have an interrupting rating at nominal circuit voltage sufficient for the current that must be interrupted”.

When these requirements are applied to a circuit breaker, busway or to switchgear bracing, the maximum 3-phase fault current the breaker will be required to interrupt must be calculated. This current is applied as the short-circuit current available at the terminals of the protective device.

Distribution equipment, such as circuit breakers, fuses, busways, switchgears and MCCs have interrupting or withstand ratings defined by the maximum rms values of symmetrical current. In MV systems, as GE Publication GET-3550F say: “a circuit breaker can't interrupt a circuit at the instant of inception of a short circuit. Instead, due to the relay time delay and breaker contact parting time, it will interrupt the current after a period of five to eight cycles, by which time the DC component would have decayed to nearly zero and the fault will be virtually symmetrical.”

“Closing a breaker against an existing fault makes it possible to intercept the peak asymmetrical short-circuit current, which is greater than the rms value of the symmetrical current. Fault analysis must thus calculate and compare symmetrical and asymmetrical current values in order to select a protective device to adequately protect a piece of electrical distribution equipment. For this reason, equipment is also tested at a particular test X/R ratio value typical to a particular electrical apparatus, such as switchgear, switchboards, or circuit breakers, and is designed and rated to withstand and/or close and latch the peak asymmetrical current described above.” It is also for this reason that modern circuit breakers have built-in rms momentary rating equal to 1.6 times the symmetrical current rating for medium voltage circuit breakers and typically 1.25 times for low voltage circuit breakers.

Calculations seeking for maximum fault duties for purposes of establishing KAIC or MVA ratings of circuit breakers or switchgears must not be misinterpreted as applied to breaker trippings. As explained earlier, the KAIC or MVA rating of a protective device is intended to be over & above the actual fault currents flowing into it such that the same shall not disintegrate or injure itself in the course of interrupting such faults. That’s why in breaker KAIC sizing, it is important to know the maximum possible fault current at any condition because the interrupting ratings of the devices placed in the system must be capable of enduring the tremendous energy associated with faults.

‘Breaker Tripping’ in MV systems on the other hand is applied to ‘Protective Relaying’. Tripping points are settable and can be programmed, in fact, contrary to KAIC capabilities; minimum fault current values are sought in protective relaying. Arming up relays are programmed not at maximum fault currents ‘per se’, but on lesser fault values suited for its operation depending on the Time Current Performance Curve selected and the way the engineer wants them to perform. These settings also include varying degrees of overloads.

Therefore, a high interrupting capacity rated circuit breaker does not mean that it can not trip during low magnitude faults. Nor that it would only trip during high fault current condition. The relay trips the breaker according to how the relay is set. This is true to all power circuit breakers whether medium or low voltage.

For low voltage Molded Case Circuit Breaker applications, the principle of KAIC sizing remains in effect. The only difference is the absence of protective relays in MCCB’s. In MCCB’s, its built-in thermal element takes care of overload conditions as can be selected through its Continuous Current Rating while its magnetic trip element for faults.

DIMENSIONING THE CIRCUIT BREAKER

We have to establish and completely specify the KAIC or MVA ratings of circuit breakers. What then is KAIC all about?

To start with, each circuit breaker has three most important ratings – a continuous current rating, a voltage rating and an interrupting capacity (IC) rating. The IC rating is the maximum amount of current that the device will open safely to relieve a fault condition - without injuring itself. The ‘injury’ means the condition where after interrupting a fault, the breaker ceased to be operable - or worse, the breaker disintegrated because the fault current is too much for the breaker to handle. It must be remembered that breakers are placed in the system to protect the system itself. What if during a fault, it is the protective device that disintegrated? Isn’t it the design engineer’s lapses? Well and good, “the installation is operating for five years and no untoward incident like this happened, if it is my fault, why only now?”, says the engineer. Fine.., because in five years time there was no fault! It’s worthwhile to mention that breakers are not placed in the system for normal conditions; breakers are expected to perform its intended work during abnormal conditions. Abnormal conditions don’t just happen during the first energization event. They happen when the installations are going older where faults are lurking and loads are becoming more demanding.

New generation circuit breakers do not include anymore the “momentary rating” in its nameplates. The “momentary rating” (in answer to the asymmetrical current during the inception of the fault) as expressed in the old generation breakers refers to the greatest current that the device must withstand during the first half-cycle of the fault - where the transient contributions of the synchronous & induction motors in the system along with the DC component (which make the fault current asymmetrical) do occur.

It should not be understood that the momentary rating is already scrapped out. What was done was that the momentary rating is already built-in the KAIC symmetrical rating of the modern day protective device. In the interest of simplicity in the calculation and specification, the recent general procedure in breaker sizing is only to compute for the symmetrical fault current values and specify the KAIC ratings based on those values. New generation breakers do express in their nameplates the symmetrical KAIC or MVA but in reality, the momentary rating is already built-in (normally with the factor of 1.6 times the nameplate KAIC for high & medium voltage and 1.25 for low voltage circuit breakers).
.
Therefore, it is not enough to specify the Continuous Current Rating and Voltage Rating of the breaker but most importantly, the engineer must specify the KAIC ratings of these protective devices. This does not only cover the large breakers but must transcend to all breakers including the smallest branch circuits at the end points of the system.

THE VALUE OF FAULT CALCULATIONS

The output of a fault calculation exercise will bear in the engineer’s frame of mind, the following realities. During fault conditions, i.e., three-phase faults, phase-to-phase faults, single line-to-ground faults whether bolted or arcing faults, the system behaves tremendously different from normal conditions:

1) During fault conditions, the system current behavior is to skyrocket to magnitudes in the KA levels at fraction of a second time condition where sub-transient reactances (not steady state) in the system prevail,

2) That during these conditions the protective devices must work as intended to,

3) That the protective device must not disintegrate or injure itself during these abnormal conditions and it is the responsibility of the engineer in providing such technical expertise in the design of the system in the first place,

4) That too much over-sizing or under-sizing of breaker KAIC ratings because of oversight is not supposed to be acceptable. Too much over-sizing results to tremendously large costs than what is needed while KAIC undersizing might result to disintegration of the breaker,

5) That lengths & sizes cables, sizes & impedances of transformers, fault duties of utility companies influence determination of the KAIC specifications of the breakers,

6) That the design engineer must perform a “Power System Study/Analysis” on the industrial plant he is supposed to be designing, especially in breaker KAIC sizing, protective relay settings and coordination/ discrimination,


MEDIUM VOLTAGE POWER CIRCUIT BREAKERS

Power Circuit Breakers for medium voltage application in the Philippines industries are in the 2.4, 4.16, 6.9, 13.8, 34.5 & 69 KV levels. These circuit breakers are in the forms of: Air, Oil, SF6 Gas or Vacuum types. Air & Oil Circuit Breakers are now obsolete while Vacuum Circuit Breakers are in the trend today – soon to replace the SF6 types which are lately found as non-environmentally friendly.

Vacuum Circuit Breakers at the time of this writing have reached the confidence level at the 25 KV Class while a few manufacturers claimed to have produced vacuum breakers at 36 KV levels. Leading electrical manufacturing countries in the world have been developing vacuum circuit breakers for applications at higher voltage classes with the intention that new generation vacuum breakers will replace the existing SF6 breakers in the immediate future. In the meantime, breakers at 36 KV, 69 KV and above have yet to contend with SF6 types.

LOW VOLTAGE CIRCUIT BREAKERS

The larger low voltage circuit breakers with trip units are known in the USA as "LV Power Circuit Breaker” while in Europe this type is called “Air Circuit Breaker”. LV Power Circuit Breakers are usually used in Power Transformers with low voltage secondaries. Consequently, Molded Case Circuit Breakers downstream the distribution feeders are recommended. Note the KAIC ratings of these circuit breakers on the manufacturers’ standard tables.

The Industrial Plant Systems Designer (IPSD) must know the fault duties of circuit breakers at any point of the system including the low voltage side. These fault duties will be pegged as the minimum KAIC ratings of the circuit breakers which will then be matched with standard ratings of circuit breakers available in the market. The engineer then has to specify the KAIC ratings in terms of standard sizes. The process may look easy in words but because of so many frame sizes & types with corresponding KAIC ratings in a continuous current rating of the breaker, the exercise is confusing than it may suggest. Before performing any fault calculation exercise, it is imperative to look at the ratings of modern-day molded circuit breakers. Note however that other manufacturers especially European–based have different KAIC ratings. It is therefore recommended to consult product journals/catalogs so that specifications will be done accordingly.

(End of Article)

A PROLOGUE TO FAULT CALCULATIONS (Part III)

A PROLOGUE TO FAULT CALCULATIONS
(Third of a Series)

TRUE-TO-LIFE STORY

In an effort to highlight system fault protection, it is deemed worthwhile to share a true-to-life story - the lessons learned from which, are worthy to recall:

In one afternoon of July 1999, four explosions in succession were heard over the whole plant area, the last of which was the loudest. One of the four XLPE 500 MCM phase “X1” (Phase “A”) main secondary conductors of the 5 MVA, 69KV/4.16KV Substation “B” developed an single-line-to-ground fault with the steel structure supporting the cables & the AVR by-pass switch. All the four events of faults did not trip the 69 KV SF6 primary circuit breaker that could have isolated the fault. The fourth fault eventually melted & cut-off the faulted cable while cutting a portion of the 8” steel channel member of the structure. In other words, the fault cleared itself when the faulted cable was cut-off - likened to the operation of a 500 MCM ‘fuse link’. Power from the Utility remained on line until plant personnel shut off the primary breaker. Utility System did not trip off because to the eyes of the utility it was only a throughfault. The nearest Utility breaker is some 25 kilometers away.

Each substation system was provided with GEC Alsthom top-of-the-line KCGG 140 phase overcurrent with residual ground relay at the primary circuit. Likewise, the transformer was provided with GEC Alsthom MBCH differential relay coupled with a lockout relay. The lock-out relay also accommodates signals on transformer over-temperature and over-pressure parameters that will trigger trippings of both the primary and secondary breakers. There was also a back-up ground fault protective relay 51G at the transformer neutral circuit. The system therefore was provided with millions of peso worth of protection equipment & devices the books could offer.

After the smoke cleared, subsequent investigation revealed the following:

 "The GEC Alsthom KCGG 140 Relay (50-51/50N-51N) for the primary circuit was found not ‘armed’ or ‘set up’. Parameters found were factory default values and therefore not “enabled”. Likewise, the tripping contact circuit was erroneously wired such that even if the relay worked, no breaker tripping could be realized.

 "The GEC Alsthom MBCH differential relay (87T) for transformer protection was tested and found OK, but the lockout relay (86T) did not trigger tripping because the lock-out relay dc power supply was incompletely wired. When the lock-out relay was finally made activated and simulated, no trippings of the 69 KV primary breaker and the main 5 KV secondary breaker happened. Again, the wirings were found erroneous.

 "The back-up ground protection (51G) was not set up as it was not correctly wired. If correctly wired and set up, this relay could have tripped the primary breaker and could have isolated the transformer should all other relays failed.

The subject plant is located somewhere in the southern part of the country. Built in nice quality aesthetics with recognition as ISO 9002 & ISO 14000 certified, the plant was made operational in 1995. However, it took four (4) years to discover the uselessness of the installed protective devices because of a simple reason, i. e., failing to arm the protective system into putting it to work when the need comes. A check with the other 5 MVA Substation "A" revealed the same condition as the faulted Substation "B". The rest is now history…

By sheer luck, there was a good thing that did not happen in the above story: the transformer was not burned, at least for the moment. Otherwise the transformer could have joined the archives of electrical disasters.

According to IEEE publications, damage to transformers brought by faults is cumulative. It means that in this case, there were already four faults that the transformer had been subjected to! Thanks, it did not give way in the fourth fault! But luck will surely run out. The engineer must not rely on luck, because the possibility of a disaster is always there - like a Sword of Damocles hanging over his neck.

In such a ground fault, how much destructive current was involved? Among others, this is what this paper seeks to answer.

POWER SYSTEM STUDY FOR EXISTING PLANTS

For existing installations where there are no visible fault calculation records, a Power System Study is necessary to establish the integrity of the power system. The value of Power System Study confirming correct ratings of circuit breakers leading to effective protective relaying can not be appreciated until a major fault occurred, after all - the protection system only comes to work during these abnormal times. Beyond a nice looking system, any industrial plant must review and see to it that the protection scheme is properly commissioned, set to predetermined performance levels, tested, simulated and live up to predictable expectations. The new Distribution Code and the new Grid Code of the Philippines require these commissioning chores.

Moreover, it seems that budgets for power system studies & commissioning most of the time, are forgotten or even not considered as necessary when it is in fact, the most important phase of a power system project. The truth of the matter is that commissioning the power system of a plant is never easy. It requires expertise & confidence acquired over long years of experience & practice. It also requires a battery of tests and test equipments that are not cheap, and the activity itself is NOT CHEAP.

In fact it needs a Power System Study to correctly set or arm the system protection devices. What happens next is that systems are energized with protective equipment & devices not commissioned to respond to abnormalities. Again, as long as when the system is energized, that’s it. Why mess with success? With lots of luck, the system operates for a few years, until an explosion is heard. Then, the electrical engineer will be brought to the center stage – grilled! Electrical Engineering is perceived by many as an easy job! No! Electrical Engineering is never easy! And nobody can substitute electrical engineers in his playing field.

(to be continued...)

A PROLOGUE TO FAULT CALCULATION (Part II)

A PROLOGUE TO FAULT CALCULATIONS
(Second of a Series)

THE NEED FOR FAULT CALCULATIONS IN DESIGN

Fault Calculations must precede any effort to procure system protection devices. This activity is supposed to be one major part of the design process, but is oftentimes skipped or omitted. Several provisions of the National Electrical Code, the Philippine Electrical Code & ANSI/IEEE Publications relate to proper system protection. Safe and reliable operation of the industrial plant based on these provisions mandate that electrical systems must be protected adequately & effectively.

While over-current protective devices (OCPD’s) are provided for overload protection for system components such as switchgears, busses, wires & cables, motor controllers, etc; it is also necessary as discussed earlier to place protection for more damaging events such as faults. To obtain a reliable operation and to assure that system components are protected from damage during abnormal events, it is necessary to first calculate the fault duties at various points in the electrical system while still on the drawing boards and adequate protective devices must subsequently be in place to anticipate these faults.

For all possible conditions, it is the responsibility of the system designer to design electric power systems with adequate control of short circuits as one major consideration. It is also the plant engineer’s responsibility to see to it that the protective relaying devices are armed to pre-determined settings either by himself or by consultants. As can be recalled, uncontrolled short circuits can cause service outages with accompanying production downtime and associated inconvenience, interruption of essential facilities, extensive equipment damage, personnel injury or fatality and a possible full-blown fire.

It is therefore important to de-mystify the stigma of faults and its counter-measures. Again, the system designer is responsible for the selection of the right equipment; and would generally have the task of calculating system short circuits. But alas… - procedures & techniques for these calculations are not generally available in one dissertation but are scattered among many publications & technical papers.

Fault Calculations also result to at least three very significant outputs which will become the bases of the following:

1) First: Proper selection of protective equipment ratings as circuit breakers or fuses that suit to system requirements;

2) Second: Realistic arming up of protective relays to trigger operation of circuit breakers once faults do occur;

3) Thirdly, Proper coordination of operation of these protective devices to effect selective interruptions of the only required breakers to trip faulted circuits without the hassle of rendering the other portions of the system powerless.

TYPES OF POWER SYSTEM SHORT CIRCUITS

Contributing sources of Short Circuit Currents into an industrial plant in focus include: Utility Generation thru the Industry Substation, Local Generation, In-Plant Synchronous Motors and Induction Motors. Capacitor discharge currents are normally neglected due to their short time duration.

In several forms or ways, short circuits can occur on a three-phase system. Again, for any type of faults, the protective devices must interrupt the faulted circuits while at the same time be able to withstand these faults.

a) THREE-PHASE BOLTED SHORT CIRCUITS

Three-phase bolted short-circuit describes the condition where the three conductors are physically held as if they were bolted together. In this condition, the impedance between these conductors or terminals is zero. This establishes a “worst case” condition, which results in maximum thermal and mechanical stress in the system. While ‘bolted short circuit condition’ seldom occurs (only in cases of errors in connecting buses or cables), it generally results in maximum short-circuit values and for this reason that the “basic short circuit calculation” in power systems is employed.

Subsequently, it is from these maximum values that the selection of fault duty ratings of circuit breakers, other protective devices and switchgear withstand ratings shall be based, busways included.

b) LINE-TO-LINE BOLTED SHORT CIRCUIT

From the three-phase fault calculation, other types of fault conditions can be obtained. The levels of line-to-line bolted short circuit currents in most three-phase power systems are approximately 87% of three-phase bolted short circuit currents, but this calculation is seldom required because it is not the maximum value, especially for establishing circuit breaker ratings. But then these values are needed as basis in relay settings or other purposes.

c) LINE-TO-GROUND BOLTED SHORT CIRCUITS

In solidly grounded systems, single line-to-ground bolted short circuit current in general, can be almost equal to the three-phase bolted short circuit current. Most of the time, SLG fault currents are lower than the 3Φ short circuit current due to the impedance of the ground return circuit and due to the non-zero-sequence current contribution from the motors which are usually ungrounded. Line-to-ground fault calculations are seldom necessary in solidly grounded low voltage industrial or commercial systems, but are needed in medium voltage systems for relay setting purposes.

In resistance-grounded medium voltage systems (common in 4.16 to 23kV) the neutral grounding resistor is generally selected to limit ground fault current to a value ranging between a few hundreds & a few thousand amps. Magnitudes of Line-to-Ground fault currents on these systems are controlled primarily by the resistor itself and a line-to-ground fault calculation using symmetrical components is generally required to size up the resistor.

d) ARCING SHORT CIRCUITS

In the real world, faults in many power systems tend to be arcing in nature. Statistics say that Single-Line-to-Ground Arcing Faults are the most frequent faults experienced in any power system.

Arcing faults are much lower level short circuit currents than the bolted ones at the same fault point. These lower levels of currents are due to the impedance of the arc ‘inserted’ into the circuit. Normally, arcing fault currents fall in the range from 40% to 50% of the bolted values.

(to be continued...)

A PROLOGUE TO FAULT CALCULATIONS

A PROLOGUE TO FAULT CALCULATIONS
(First of a Series)

GENERAL DISCUSSION

Experts say that, “continuity of operation in an industrial plant is as good as its electric power system. Its value speaks for itself the instant power is interrupted during production days or much more, during the visit of company officers. Even with the best design and top-of-the line materials available, the likelihood of a fault in power systems increases with age". According to experience, faults usually surface out after about five years operation of a brand-new plant. The industrial plant therefore must be designed to anticipate these faults, thus the need for fault calculations - the end objective of which is to design a plant sturdy enough to survive the disastrous effects of faults.

Electrical practitioners should be aware of the responsibility that an electrical system should not only be designed and constructed as a ‘safe system’ under normal service conditions but also during abnormal conditions. Its protection schemes designed & selectively coordinated as well, to insure continuity of service even during abnormal times. Abnormal conditions are always associated with electrical faults and a well-planned fault control system from the medium voltage level down to the last low voltage circuit is one where only the faulted circuit is isolated without disturbing any ‘unfaulted’ parts of the system. Although electrical systems are supposedly designed by responsible system designers to be free from short circuits as possible, but even with these precautions, the plant can not escape from faults because short circuits will surely do occur – perhaps not today but in the future.

It is worthwhile to mention that Fault Calculations may be easy to utility system engineers who may have been assigned in the ‘System Protection Department’ for years; but may be mystifying to operation or maintenance engineers in the industrial plant. Fault Calculations as a subject can not be understood nor mastered without constant practice & exposure to it over a long period of time. The task may seem overwhelming at least … at first, but constantly practicing a methodical step-by-step procedure can keep a novice engineer from getting tripped up…

IEEE says that power systems should be designed so that “protective relays operate to sense and to cause the quick isolation of faults in the end view of limiting the extent & duration of service interruptions. Because of their function, protective relays are the so-called "watchdogs or silent sentinels in a power system.” In medium voltage power systems, relays are considered as the “brains” while the breakers, the “muscles”. While smaller circuit breakers in the LV Systems are ‘electrical devices’, it should be noted that MV Power Circuit Breakers are not real electrical equipment. Being the muscles, they are in fact, ‘more of a mechanical device’ as the only electrical in them are the charging motor, tripping & closing circuits. Protective Relays guard the power system from the ever-present threat of damage caused by over-currents that can result to equipment loss, system failure and a much greater production loss.

But before attempting to set-up any system protection scheme, faults as complex phenomena must first be understood & their magnitudes calculated.

OVER-CURRENTS

An “over-current” as a widely-held phrase is either an overload or a short-circuit current. ‘Overload’ is defined as an excessive current in reference to normal operating current, but one which is confined to the normal conductive paths provided by the conductors & other components of the distribution system. On the other hand, as the name implies, a ‘short-circuit’ current is one which flows outside the normal conducting paths.

OVERLOADS

How ‘over’ are overloads? Overloads are usually between one and six times the normal current level. Generally, these are undisruptive fleeting surges that occur in events of motor or transformer starts-up. Such ‘transient overloads’ are normal events. Since they are of very brief duration; any temperature rise is trivial & has no harmful effect on the circuit components. In such cases, protective devices should not react to them.

Another form of overload is the ‘sustained overload’ that may have been caused by defective motors (such as worn motor bearings), overloaded equipment, or too many loads on a circuit. Such sustained overloads are destructive and must be disconnected by protective devices before they damage the distribution system or system loads. However, since they are relatively lower in extent compared to short-circuit currents, removal of the overload current within a few seconds is an acceptable practice. A sustained overload current if not cut-off results in overheating of conductors & circuit components and will cause deterioration of insulation, which may subsequently result in more severe damage such as short-circuits if not interrupted.

SHORT-CIRCUITS

While overloads do occur at somewhat modest levels, the ‘short-circuit’ or ‘fault current’ can be hundred times larger than the normal operating current. A high level fault may be 50,000 amperes and larger. If not interrupted within a matter of a few thousandths of a second, damage & destruction can become rampant. There can be severe insulation damage, melting of conductors, vaporization of metal, ionization of gases, arcing & fires. Moreover, high level short-circuit currents can develop huge magnetic-field stresses between switchgear buses that can reach destructive forces that even heavy bracing may not be able to keep them from being distorted beyond repair.

INTERRUPTING RATING

A protective device must be rated to withstand the destructive energy of short-circuits. If a fault current exceeds a level beyond the capability of the protective device, the device may rupture and disintegrate. The rating which defines the capacity of a protective device to maintain its integrity when reacting to fault currents is termed as “interrupting rating”. The interrupting rating of most branch-circuit molded case circuit breakers typically used in residential service entrance panels is 10,000 amperes. Larger circuit breakers used in industrial plants may have interrupting ratings of 18 kA or 60 kA or higher. In contrast, modern current-limiting fuses have an interrupting rating of 200 kA or 300kA and are commonly used as current-limiting devices.

SELECTIVE COORDINATION - PREVENTION OF BLACKOUTS

Note that proper coordination or discrimination of the operation of protective devices will prevent total system power outages or blackouts. When only the protective device nearest a faulted circuit opens and the larger upstream OCPD’s remain closed, the protective devices are “selectively coordinated” or in other words, “discriminated”. The word “selective” is to denote total coordination – meaning, isolation of a faulted circuit by the opening of only the affected circuit protective device. In other terminologies, this is also known as “fault control”.

(to be continued...)

POWER SYSTEMS

POWER SYSTEMS

It is being said that electrical power is somewhat like the air we all breathe. Power is just ‘there,’ meeting our every need, constantly. In an industrial plant for instance, it is only a matter of pushing a button and a 5,000 hp motor starts up - just like that! And nobody is thinking about it…

As one article in the internet puts it, “it is only during a power failure; when one walks into a dark room and instinctively hit the useless light switch, realizing how important power is in daily life. We use it for heating, cooling, cooking, refrigeration, light, sound, computers, entertainment… Without power, life can get somewhat cumbersome”. And production in manufacturing plants would come to a massive halt. Fact is that hitting the switch is actually invoking power from probably thousands of kilometers from a source passing through a maze of power distribution grids. Generally, the complete loop of an electric system may be composed of generation, transmission & distribution systems.

a) THE GENERATION SYSTEM

Generation of electric power is accomplished in a “power plant” where bulk power is produced through a system of prime movers coupled to generators turning out electricity. Generated voltages may vary from 4,000 to 24,000 volts (in most cases), or higher - depending on the size of the generating units. The prime movers may be in the form of internal combustion engines (ICE’s) or turbines (hydraulic, steam or gas). Generation in the Philippines is usually done by power producers such as the National Power Corporation (now known as Genco’s) and by Independent Power Producers known as IPP’s interconnected to common grids such as the Luzon, Visayas and Mindanao Grids.

For general discussion, generators can be classified as Turbo-Generators, Hydro-Generators, Industrial Generators or Induction Generators.

Turbo-Generators are driven by steam or gas turbines covering power outputs from a few MW up to the largest 1,300 MW steam turbine unit currently in existence. Information gathered by this author has it, that in two or three years time from now, the largest in the world will be the 1,600 MW 70-meter unit now being built by Siemens for a Finnish utility nuclear power plant. Operating at 3,600 rpm (2 poles) or 1,800 rpm (4 poles), these amazing machines are cooled by circulating air through shaft-mounted fans either drawn directly from external atmosphere or using an enclosed circuit having secondary air/air or air/water heat exchangers. For larger units typically in utility power plants of say 200 MW or larger, the rotor and stator cores may be cooled by circulating hydrogen and the stator windings by passing de-mineralized cooling water down the center of winding conductors.

Industrial plants however commonly use turbo-generators at sizes, 1,000 kW to 10,000 kW at 4,160v.

Hydro-Generators are driven by water turbines and are generally much slower than the steam or gas turbine counterparts. Depending on the available water head, these units are operating at 60 – 1,200 rpm. They have usually large diameters to accommodate a large number of salient pole pairs but with correspondingly short axial length. Generally such machines have vertical spindles with the generators mounted above the turbine. In the Philippines hydro-generators are usually found in utility power plants.

Industrial Generators are Diesel-Driven Generators widely used by industrial plants for standby power or for island generation. Standby power units at 1,750 rpm are typically the simple diesel fuel-fed units with ratings as large as 2,000 KW while island generation application engines are the more complicated bunker-oil fed units. Ratings of bunker-fed units may be up to 12 MW running at lower speeds of 300 – 700 rpm.

Operation with a Large System:

When the Industrial Plant decides to parallel their power plants with the grid, the following discussions are thus important:

When generators are connected to a large system as the grid, the action of the individual machine controls can not have significant effect on the system as a whole. Hence opening the throttle of the prime mover to increase power input to the machine can not affect system frequency but the power exported by the machine will be increased, while it continues to run at synchronous speed.

Similarly, increasing the machine excitation can not increase the voltage on the system but this simply increases the VARs exported by the machine to the system at the same time drifting the machine power factor further lagging. In the same way that reducing the machine excitation causes the power factor to move further leading however, reducing the excitation too far will cause the power factor to move more to the leading condition so that the machine could become unstable and pole-slip. Generally, to avoid any risk of pole-slipping leading power factor operation is limited to about 0.70 at zero load to 0.90 at full load. In the case of a generator connected to the system via a generator unit transformer, the change in reactive power and consequently the change in excitation are achieved by the operation of the on-load tap changer on the transformer.

b) THE TRANSMISSION SYSTEM

As learned from CESEEPS Power Books, power transformation may take place in several stages in sequence, starting at the generating plant where the voltage is raised to approximately 1,000 volts for every mile of transmission. Voltages are then progressively reduced to the voltage required for household, commercial or industrial use. A substation that has a step-up transformer increases the voltage whilst decreasing the current, while a step-down transformer decreases the voltage for domestic, commercial and industrial distribution.

Long distance transmission of energy over the feeders may take place at voltages as high as 500,000 volts. With sufficiently large load justifying the transmission, the farther the distance, the higher is the line voltage employed. Extra-High Voltages (EHV) reaching up to 1,200,000 volts are no longer uncommon in the United States, Sweden and Russia. In economic terms, this reduces conductor sizes while at the same time bringing down the line losses in transmission. However, more elaborate towers and higher insulation requirements are needed to accomplish this type of power conveyance.

The transmission line can therefore be considered as that part of the power system connecting one remote area with another remote area along with delivering bulk power over long distances. This is made possible by a system of towers carrying currents at high voltages. The towers usually of steel construction are now usually found crisscrossing the countryside. In Luzon Grid for instance, transmission voltages are accomplished at 500 KV, 350 KV, 230 KV and 115 KV. The Visayas Grid has 350 KV, 230 KV, 138KV, 115KV and occasionally 69 KV as sub-transmission lines while the Mindanao Grid at 138 KV and 69 KV. High Voltage DC transmission systems are now gaining popularity because of the tremendous economic advantage. The Philippines is no longer an exception, today the country has already this type of transmission at 350 KVDC.

Self power-generating industries normally omit the “transmission” component of the system because of the close proximity of the load centers from the power plant. In most cases, the distribution systems of the industrial plant also carry the function of transmission system.

c) THE DISTRIBUTION SYSTEM

The transmission lines end up at the proximate area of distribution. Electricity then is once more fed into substation transformers that reverse the process by lowering the voltage to some degree, normally in the Philippines at 69KV. Downstream of the system, another voltage transformation may still be necessary and be routed to various places for local distribution and utilization.

From the point of view of the power company, the distribution system is intended to cover a specific area such as towns, cities or directly to industrial plants usually through 60 footer wooden or concrete poles at 69 KV. These voltages may feed directly to large industrial plants while for towns or cities, another voltage transformation may be necessary to produce 13.8 or 23 or 34.5 KV. These feeders are usually called laterals.

In industrial plants, scenarios like self-generating power at 2.4 KV, 4.16 KV, 6.9 KV or 13.8 KV and distribute it directly to power centers which in turn transform the voltage to 480 V or 240 V are common installations in the country. Underground distribution or through over-head cable trays are likewise employed as common feeder management methods in industries.

d) THE SUBSTATIONS

The term ‘substation’ comes from the days before the distribution system became a grid. The first substations were connected to only one power station where the generators were housed, and were just ‘subsidiaries’ of that power station. Today, Substations carry several functions. They generally contain one or more transformers, and have switching, protection and control systems. In medium and large size substations, circuit breakers are used to interrupt any short circuit or overload currents that may occur on the network. Substations do not (usually) have generators, although a power plant may have a substation nearby. A typical substation will contain line termination structures, high-voltage switchgear, one or more power transformers, secondary switchgear, surge protection, controls & metering. Other devices such as power factor correction capacitors and voltage regulators may also be located at a substation.

Substations may be on the surface in fenced enclosures, or underground, or located in special-purpose buildings. Substations located within the buildings they serve are particularly a feature of high-rise buildings. Indoor substations are usually found in urban areas to reduce the noise from the transformers, and for reasons of appearance. Where a substation has a fence, it must be properly grounded (‘earthed’ in European terms) to protect people from high voltages that may occur during a fault in the transmission system.

Transmission Substations

A transmission substation is one whose main purpose is to connect together various transmission lines. The simplest case is where all transmission lines have the same voltage. In such cases, the substation contains high-voltage switchers that allow lines to be connected together or isolated for maintenance.

Transmission substations can range from simple to complex. A small "switching station" may be little more than a bus plus some circuit breakers. The largest substations can cover a large area with multiple voltage levels and a large amount of protection and control equipment.

Large transmission substations usually have complex configuration. Aside from the function of switching several incoming & outgoing circuits, redundancy as well as by-pass schemes are common in these types of substations. Set-up of circuit breakers and their related relaying, as well as arrays of HV switchers, surge arresters and disconnect switches make the system more complicated.

Bulk Distribution Substations

A distribution substation is one whose main purpose is to transfer power from the transmission system to the distribution system of some area. Note that it is uneconomical or impractical to directly connect electricity consumers to the main transmission network (unless they use huge amounts of energy, see Chapter 3 of this book). So the distribution station reduces voltage to a value suitable for connection to local loads.

The input for a distribution substation is typically at least two transmission or sub-transmission lines. Input voltage may be, for example, 115 kV or 138 kV, or whatever is common in the area. The output is a number of feeders. Distribution voltages are typically medium voltage, between 13.8, 24, 34.5 and 69 kV depending on the size of the area served and the practices of the local utility. The feeders will then run overhead, along streets (or under streets, in a city) and eventually power the distribution transformers at or near the customer premises.

Besides transforming the voltage, the job of the distribution substation is to isolate faults in either the transmission or distribution systems. Distribution substations may also be the points of voltage regulation, although on long distribution circuits (several kilometers), voltage regulation equipment may also be installed along the line.

Complicated distribution substations can be found in the downtown areas of large cities, with high-voltage switching, and switching and backup systems on the medium-voltage side. More typical small distribution substations have a disconnect switches, one transformer, and minimal facilities on the secondary voltage side.

SIZING TRANSFORMERS WITH LARGE MOTOR LOADS (PART II)

LESSONS WE NEED TO LEARN

SIZING TRANSFORMERS

WITH LARGE MOTOR LOADS

(PART II)

By Doods A. Amora, PEE
(December, 2006)

(Last of Two Parts)

6.0: VOLTAGE SAGS IN LARGE MOTOR STARTING

The voltage dip at the transformer terminals is proportional to the motor load required in start-up. As discussed earlier, the voltage drop can be expressed as a percentage of the inrush motor load compared to the maximum capability of the transformer.

% Voltage Drop = (Motor Starting kVA) x 100 /(Motor Starting kVA + Short Circuit kVA)

EXAMPLE:

Now, supposing a lone 2,000 hp, 4.16 kV, Code Letter J motor (Starting kVA = 7.6 times its rated hp) is connected to the 7,500 kVA transformer described above, would it not be that the transformer is too large for the motor load? Probably yes, probably not! Let us see why.

A) IF THE MOTOR CONTROLLER IS ACROSS-THE-LINE (FULL-VOLTAGE CONTROLLER):

Starting kVA of 2,000 hp Motor (SkVA = 7.6):
Starting kVA of 2,000 hp motor = 2,000 kVA x 7.6 or 15,200 kVA

Three-Phase Short Circuit Capacity of the Transformer:
3Φ SC kVA of 7,500 kVA Trafo = 7,500 kVA/0.08 or 93,750 kVA

Note: In this case, the 7.5 MVA transformer has a maximum of 93.75 MVA
short circuit capability.

The voltage drop on motor inrush will be:

VD at Trafo Terminals = 15,200/(15,200 + 93,750) = 0.1395 or, 13.95%
VD at Trafo Terminals = 580 v
Trafo Terminal Volts During Motor Start-Up = 3,580 v

The transformer output voltage will drop from 4,160v to 3,580v (4,160 x 0.8605 = 3,580 v) as against a minimum requirement of 3,600v for a 4,000v motor. Thus, we can see that the transformer even at 7.5 MVA is small for a 2,000 hp motor!

Therefore, the transformer must be sized to a short circuit capability equal to or greater than 15,200 kVA times 10, or, 152,000 SC kVA in order to have a voltage drop of 10% or less.

The next higher standard size transformer at 10,000 kVA 8.0% impedance would have a short circuit output capability of 125,000 kVA which is still not sufficient. Or a 12.5 MVA transformer could be the choice!

In this particular application, the ratio of the selected standard size transformer kVA to motor kVA is 12,500 kVA/2,000 kVA = 6.25. Thus the transformer rating is 625% larger than the rating of the motor! Fantastic!

Note that the voltage sag in reality will even be bigger (actual voltage smaller) because the source can never be infinite in fault duty plus in addition, the voltage drop at the distribution cables from the transformer to the motor end. The total voltage sag is the sum of the sag in the secondary unit substation transformer and the secondary circuit. In the case of very large motors of several hundred to a few thousand horsepower, the impedance of the supply system (or the ‘available fault duty’) should be considered.


B) IF THE MOTOR CONTROLLER IS AN AUTOTRANSFORMER REDUCED VOLTAGE STARTER:

Now therefore, here comes the wisdom in using reduced voltage starting scheme and the choice of Code Letter specification of a motor. Normally in practice, large motors need to be equipped with Auto-Transformer RVS controllers while the motor Code Letter specification can be chosen.

Let us now see the effect with a 2,000 hp Code Letter E motor (Starting kVA = 4.8 times rating) is controlled by an Auto-transformer RVS. Establish further that the Auto-transformer RVS shall be at 65% tap.

From the table below, the line current at 65% tap draws 46% of the full voltage starting current.


Table 2: MOTOR STARTING METHODS FOR SQUIRREL CAGE INDUCTION MOTORS:
(Table re-configured for easy reference) in this blog:

 Full Voltage : 100%: Line Starting Current or kVA

 Reduced Voltage (RVS Autotransformer Type):

80% Tap: 68% of Line Starting Current or kVA of 100% of Full Voltage Starting
65% Tap: 46% of Line Starting Current or kVA of 100% of Full Voltage Starting

 Reduced In-Rush:

Wye-Delta: 33% of Line Starting Current or kVA of 100% of Full Voltage Starting

NOTE: In addition to methods listed above, users should consider solid-state soft-start motor controllers and/or adjustable speed drives.


In this example:
Motor Starting kVA = 46% of 2,000 kVA x 4.8 or 4,416 kVA
Motor Starting kVA can therefore be placed at 4,416 kVA.

The voltage drop at transformer terminals on motor inrush will be:

VD at Trafo Terminals = 4,416/(4,416 + 93,750) = 0.045 or, 4.5%
VD at Trafo Terminals = 187.2 v
Trafo Terminal Volts During Motor Start-Up = 3,972.8 v

The transformer output voltage will drop from 4,160v to 3,972.8 (4,160 x 0.955 = 3,972 v) against a minimum requirement of 3,600v for a 4,000v motor.

Thus, we can see that the 7.5 MVA transformer now becomes sufficient for a 2,000 hp motor with a different code letter and with the use of an RVS. Note also that if the auto-transformer RVS is at 80% tap, the voltage drop as seen by the motor would still satisfy the 10% VD requirements.


7.0: MULTIPLE MOTORS IN A TRANSFORMER

What if there are smaller motors plus other loads among a few large ones in a single transformer source?

EXAMPLE:

Assume that in the 7.5 MVA Substation transformer described above, there are 2,150 kVA smaller 460 v motors in the system through a number of transformers downstream the 4,160 v bus of the substation. Other load, load growth included is 750 kVA. Assume also that there are 800 hp 4.16 kV Code Letter E motors directly connected at the 4.16 kv bus. How many 800 hp motors can be energized into the system complying with the 10% voltage sag requirements? Assume that RVS’s for the 800 hp motors are at 65% tap and the motors shall not be started at one time.

If there are several motors on one transformer:

TRAFO KVA = (Maximum Demand kVA of Small Group Motors) + (Maximum Demand kVA of Other Loads Including Load Growth) + (kVA Ratings of all Large Motors) + (Additional Trafo kVA capacity necessary to accommodate the inrush current of the largest motor)

Thus:

TRAFO KVA = 7,500 kVA
Max Demand of Small Group Motors = 2,150 kVA

Other Loads Including Load Growth = 750 kVA

kVA of Large Motors = KVA of LM (Unknown)
Additional Trafo kVA for 800 hp Start-Up = Unknown

Solving for the Starting kVA for 800 hp Code Letter E motor
with RVS at 65% tap:

800 hp Starting kVA = (0.46 x 800 x 4.8)
800 hp Starting kVA = 1766 kVA

Solving for the Additional Trafo kVA Needed for 800 hp Start-Up:

Trafo SC kVA Needed for one 800 hp Start-Up to maintain a 10% VD = 1,766 x10
Trafo SC kVA for one 800 hp Start-Up to maintain a 10% VD = 17,660 kVA

Additional Trafo kVA Needed for one 800 hp Start-Up = SC kVA x %IZ of Trafo
Additional Trafo kVA for one 800 hp Start-Up = 17,660 x 0.08 = 1,413 kVA

Solving for the Number of 800 hp Motors
that can be placed into the system:

Recalling: TRAFO KVA = (Max Demand kVA of Small Group Motors) + (Max Demand kVA of Other Loads Including Load Growth) + (kVA Ratings of all Large Motors) + (Additional Trafo kVA capacity necessary to accommodate the inrush current of the largest motor)

7,500 kVA = 2,150 kVA + 750 kVA + KVALM + 1,413 kVA

KVA Large Motors = 7,500 – 2,150 – 750 - 1,413
KVA Large Motors = 3,187 kVA

Number of 800 hp motors = 3,187/800
Number of 800 hp motors = 3.984, say 4

The transformer selected will be capable of running and starting all motors
provided that only one large motor is started at any one time. Additional capacity will be required for motors starting simultaneously.


8.0: BACK TO THE BOARD PROBLEM

A 250 hp motor driving a pump is served by 3 x 100 kVA 13.8kV- 480v transformer bank. Other data are as follows:

 Transformer Impedance: 3.7% IZ
 Short Circuit Capacity of Source: 200 MVA
 Motor Starting Current: 8 times of FLC
 Length of Cable from Transformer to Motor Controller: 50 ft

Solve for:

a) Size of Cable & Conduit
b) Branch Circuit Breaker & Controller Size if Auto-Transformer type RVS
c) Determine the voltage dip during motor start-up using full voltage starter
d) Determine the voltage dip during motor start-up using Auto-Transformer Reduced Voltage Starter tapped at 65%.

Solution:

a) Solving for the Cable Size & Conduit
Motor Full Load Current = 302 A (From NEC Table)
Size of Cable = 1.25 x 302 or 377 A
USE: 500 MCM THW in 4”Φ Conduit

b) Solving for the Branch Circuit Breaker & RVS Controller Size
Branch Circuit Breaker = 2.0 x 302 A or 604 A
USE: 600AT/600AF, 3P, 600V MCCB
USE: Auto-Transformer RVS NEMA Size 5

c) Solving for the Voltage Dip Using Full Voltage Starter:

SC kVA at Transformer Terminal

Let: kVA Base = 300 kVA
V Base = 480 v
I Base = 361 A

X @ 13.8 kV = kVA Base / SC KVA@ 13.8 kV Source
X @ 13.8 kV = 300 / 200,000
X @ 13.8 kV = 0.00150 pu

X T = %IZ/100 x kVA Base /Trafo kVA
X T = 3.7/100 x 300/300
X T = 0.037 pu

X EQ = 0.00150 + 0.037
X EQ = 0.0385 pu

I SC = IBASE / X EQ
I SC = 361 A / 0.0385
I SC = 9,377 A

Three-Phase Short Circuit Capacity of the Transformer:
KVA SC = √3 x 0.48 x 9,377
KVA SC = 7,796 kVA

Motor Starting kVA:

Motor Starting kVA = 250 hp x 8
Motor Starting kVA = 2,000 kVA

The voltage drop on motor inrush at the transformer terminals will be:

VD at Trafo Terminals = 2,000/(2,000 + 7,796) = 0.2042 or, 20.42%
VD at Trafo Terminals = 98 v
Trafo Terminal Volts During Motor Start-Up = 382 v

Voltage Drop at the Cables:

Impedance ZC of 500 MCM THW Cable in Metallic Conduit= 0.00575 Ω per 100 ft (From IEEE Table)

Impedance of C1: 50 ft, from transformer to Motor Controller:
ZC = 0.00575 Ω/100 ft x 50 ft
ZC = 0.002875 Ω

Voltage Drop along the Cable C:
VDC = √3 x (IMOTOR LINE START) x ZC1
VDC = √3 x (302 x 8) x 0.002875
VDC = 12.0 v

Total Voltage Drop at Motor Controller:
98.0 + 12.0 = 110 v

Voltage at Motor Controller Line Side Terminals during Start-Up = 370 v
Voltage Requirements during Start Up = 414 v for 460 v motors

The set-up can not satisfy voltage dip requirements. Not even 3 x 250 kVA (750 kVA). In fact a 3 x 333 kVA (1,000 kVA) set-up at 5.2%IZ can barely satisfy the requirement!

There could be two remedies for the situation. One is to change the motor controller from full voltage to auto-transformer RVS type. The other alternative is to change the Transformer from 300 kVA (3 x 100 kVA) to 1,000 kVA (3 x 333 kVA).

d) Solving for the Voltage Dip Using Auto-Transformer RVS:

If RVS Auto-Transformer Tap to 65%:
Motor Starting kVA = 0.46 x 250 hp x 8
Motor Starting kVA = 920 kVA

The voltage drop on motor inrush at the transformer terminals will be:

VD at Trafo Terminals = 920/(920 + 7,796) = 0.1055 or, 10.55%
VD at Trafo Terminals = 50.64 v
Trafo Terminal Volts During Motor Start-Up = 429.36 v

Voltage Drop along the Cable C1:
VDC1 = √3 x (IMOTOR LINE START) x ZC1
VDC1 = √3 x (302 x 8 x 0.46) x 0.002875
VDC1 = 5.534 v

Total Voltage Drop at Motor Controller:
50.64 + 5.534 = 56.174 v

Voltage at Motor Controller Line Side Terminals during Start-Up = 423.826 v
Voltage Requirements during Start Up = 414 v for 460 v motors

Therefore, the 3 x 100 kVA transformer need not be replaced if its Auto-Transformer RVS is tapped at 65%. Note that if the RVS is tapped at 80%, the transformer needed must be 750 kVA (3 x 250 kVA)!

9.0: THE REAL ENGINEERING ECONOMICS

While first costs are very important to clients & plant owners; correct engineering practice should not be sidestepped in selecting best systems. More often than not, too much cheap engineering is in fact, costly. By making the first cost not objectionable, it does not mean that the engineer shall use cheap, undersized and substandard materials or equipment. Applying correct Value Engineering, the design must fundamentally conform to good engineering practice, codes and standards. This fundamental or minimum requisite must not be compromised under the cloak of costs.

It is important for the Industrial Power Systems Designer to understand that First Cost is not enough in determining the economics of the project. Total Life Cycle Cost of the power system depends on equipment purchase price & quality, construction & installation costs, operating costs including losses, outage costs, repair costs, useful lifetime of the equipment and administrative costs.

In the USA & other advance countries, the insurance companies play lead roles in the safety and soundness in any installations. That’s why they are strongly behind the National Electrical Code and the National Fire Protection Code. In the Philippines, if it’s “faulty electrical wirings”, the insurance companies pay without much fuss, and nobody seems to ask how standards were complied.

But alas, more often than not, what design engineers consider as “best solutions” may not correspond to what owners perceive. In the name of cost, the ‘economical solutions’ that clients want usually end up into sickly systems that are vulnerable to failure or worse, violations to the Code and Correct Engineering Practice for which we engineers are supposed to profess. Note that there is a common misguided thought in electrical engineering design economics. For instance, why use an expensive RVS when Across-the-Line Starter will do? Or why a 1,000 kVA transformer for a 250 hp motor? In this case, we say that firstly, the engineer must know his codes & standards. The standards must first be satisfied before any value engineering can be focused. Sensitive to safety & system operability in the ultimate analysis, it is the engineer's responsibility to find solutions that satisfy both parties.

Doods A. Amora
December, 2006

SIZING TRANSFORMERS WITH LARGE MOTOR LOADS (Part 1)

LESSONS WE NEED TO LEARN

SIZING TRANSFORMERS

WITH LARGE MOTOR LOADS

By Doods A. Amora, PEE
December 1, 2006)

(First of Two Parts)

1.0: INTRODUCTION

The purpose of this article is to help expand the engineer’s basic understanding on ‘short circuit capacity’ – how it affects voltage sags during starts-up of motors of significant sizes.

But why are Short Circuit & Motor Starting Calculations involved in transformer sizing?

One clue is:

"Starting up one thousand-1.0 hp motors is world apart from starting up one-1,000 hp motor"

SIDEBAR 1:

When I took my PEE board exams 22 years ago, there was one problem under the subject “ELECTRICAL DESIGN & CONSTRUCTION” which ran similar as follows:

A 250 hp motor driving a pump is served by 3 x 100 kVA 13.8kV- 480v transformer bank. Other data are as follows:

 Transformer Impedance: 3.7% IZ
 Short Circuit Capacity of Source Utility: 200 MVA
 Motor Starting Current: 8 times of FLC
 Length of Cable from Transformer to Motor Controller: 50 ft

Solve for:

a) Size of Cable & Conduit
b) Branch Circuit Breaker & Controller Size if Auto-Transformer type RVS
c) The voltage dip during motor start-up using full voltage starter
d) The voltage dip during motor start-up using Auto-Transformer Reduced Voltage Starter tapped at 65%.

To be honest, I wasn’t ready to solve the (c) and (d) parts of the problem. To my defense mechanism, I told myself, “the problem was irrelevant. Nandiyan na ‘yan, naka-install na kunyari; bakit kwentahin pa ang voltage dip?“

To make the story short, lumipas ang mahabang panahon… Then here comes now a real situation. What if one is asked to design a set-up for a 500 hp motor driving a pump somewhere? Would a 750 kVA transformer be sufficient? Maybe yes, maybe not! Try solving the problem and one will discover things that are assumed easy but are actually not quite simple!

SIDEBAR 2:

In one brewery I happened to work with, we had two – 450 hp 4 kV motors driving ammonia compressors controlled by Auto-Transformer RVS. Later, three – 700 hp motors were added but interestingly this time with across-the-line starters. The system was directly connected to the Power Plant’s 4,160 v bus through feeders. No problem was imagined because the Power Plant as a standard operating procedure, used to operate with significant spinning reserve capacity at any given time – and there were nine (9) generating units to support the loads.

However, when we started-up for the first time one of the three 700 hp compressors, a huge voltage dip occurred and the neighboring Glass Plant tripped off all its operating air compressors thus shutting down the entire plant. Pandemonium followed as the Power Plant struggled to recover the voltage by shedding off other major loads. Power Plant finally recovered but with all major manufacturing plants served by it at shutdown, including the brewery.

The event’s aftermath saw signs posted on all compressor control panels that reads: “NOTIFY POWER PLANT BEFORE STARTING”. Why? Because Power Plant had to add more generators on stream before any starting can be done. This was to provide the on-line generating capacity large enough to support the starting kVA needed, thus averting objectionable voltage dips. Interestingly, after the start-up the additional generators had to be shutdown. In the end, the full voltage starters were replaced with RVS units. In the succeeding breweries being built thereafter, MV Soft Starters were employed.

Again, there’s more to it than meets the eye. Recalling back my own PEE board exams, now I understand that after all, the problem on voltage dip was not irrelevant but a test of engineering competence why I should be given a license as PEE.


2.0: SUBSTATION TRANSFORMERS VS. LOADS

Generators and transformers react to large motor starting as manifested in voltage dips. Let us first discuss transformers.

In general terms, transformers in an electrical system are usually larger than the maximum demands they serve, in some instances even larger than the connected loads. In the industrial plant scenario, the obvious reason at first glance for this apparent oversizing is the anticipation for future load growth. Fine…

But more often than not, sizing the transformer with extra kVA capacity unwittingly addresses voltage sag problems, not for load growth for which it is intended originally. That’s why for newly constructed plants where load growth is not yet there, the problem of starting significantly large motors may not surface out. Why? Because the extra kVA capacity intended for load growth is taking care of it.

3.0: SYSTEM BEHAVIOR IN EVENTS OF FAULTS

Short circuit capacity calculation is used in many applications, some of which are the following:

a) selecting the interrupting capacity ratings of circuit breakers and fuses,
b) specifying the short-time withstand of switchgears,
c) determining if a line reactor is required,
d) and a host of many others.

But unknown to many, Short Circuit Calculations together with
Motor Starting Calculations are also used in Sizing Transformers.

Short Circuit condition brings down the voltage very dramatically. The amount of voltage during a full three phase fault at the terminals of the transformer is determined by the %IZ of the transformer, i.e., if the transformer is connected to an infinite source of short circuit currents.

Take for instance a 7,500 kVA, 8.0% IZ, 69-4.16 kV transformer. The 8.0% impedance rating would mean that full load currents of 1,041 amps will flow in the secondary if the secondary is short circuited and the primary voltage is raised from zero volts to a point at which 8.0% of 4,160 volts, or 332.8 volts, appears at the secondary terminals. Therefore, the impedance (Z) of the transformer secondary may now be calculated:

Z = V / I = 332.8 volts/1,041 amps = 0.3197 ohms

The exercise described above is what is known in textbooks as the “Short Circuit Test” which is actually performed in laboratories or electrical shops (drying up transformers). What if the short circuit at the secondary is real – meaning, the short circuit happened at full 4160v at the inception of the fault? If the transformer is connected directly to a source capable of supplying the transformer with an unlimited short circuit kVA capacity, the short circuit amperage capacity which the transformer can deliver from its secondary is:

4,160 volts /0.3197 = 13,012.5 amps

Another method of calculating short circuit capacity for the above transformer is:

SC Capacity = Trafo FLC/%IZ
= 1,041 A / 0.08
= 13,012.5 amps,

or terms of kVA:

SC Capacity = 7,500 kVA/0.08 = 93,750 kVA

Such three-phase fault will bring down the voltage at the secondary terminals from 4,160v to approaching zero, while at the same time delivering 93.75 MVA of short circuit power to the point of fault. This condition however must of course be short-lived because some sort of protection upstream must operate to interrupt the circuit quickly, otherwise the transformer will fail. Transformer damage (known as the transformer short-time withstand) is dependent on the amount of fault current and the impedance of the transformer. Usually this transformer short-time withstand could only last for a few seconds.

4.0: SYSTEM BEHAVIOR DURING LARGE MOTOR START-UP

Why is motor starting related to short circuit condition? Partly similar to short circuit condition, motors have a high initial inrush current when energized and draw heavy load at a low power factor (0.30 lagging for 100 hp & about 0.16 for 1,000 hp motor) for a very short time. This sudden increase in the current flowing to the load causes a momentary increase in the voltage drop at the supply transformer terminals, the voltage drop along the distribution system, and a corresponding reduction in the voltage at the utilization equipment.

The magnitude of transient current involved in motor starting is however very much lower than the short circuit condition. But in effect, switching “on” to energize a large motor can be likened to a “soft short circuit”. Like short circuits, the effect of starting large motors results to voltage dips. The voltage drop at the transformer secondary terminals is proportional to motor starting kVA over the short-circuit capacity of the transformer. When motor starting kVA is drawn from a system, the voltage drop in percent of the initial voltage is approximately equal to the Motor Starting kVA divided by the Sum of this kVA and the Short Circuit kVA.

% Voltage Drop = (Motor Starting kVA) x 100 /(Motor Starting kVA + Short Circuit kVA)

5.0: MOTOR STARTING KVA

Thus, we need to know the starting kVA of the subject motor. In general, IEEE Red Book says, “the starting current or starting kVA of a standard motor draws several times its full-load running ratings. Without any specific information on a subject motor, a motor is always assumed to require about 1 kVA for each motor horsepower in normal operation, so the starting current of the average motor will be about 5 kVA for each motor horsepower. When the motor rating in horsepower approaches 5% of the secondary unit substation transformer capacity in kilovolt-amperes, the motor starting apparent power approaches 25% of the transformer capacity which, with a transformer impedance voltage of 6.07%, will result in a noticeable voltage sag on the order of 1%. This sudden increase in the current drawn from the power system may result in excessive drop in voltage unless it is considered in the design of the system. The motor-starting load in kilovolt-amperes, imposed on the power supply system, and the available motor torque are greatly affected by the method of starting used”.

The specific starting values for ac motors over hp are indicated in terms of Code Letters on the nameplates of North American-made motors. NEMA Code Letters indicate the motor starting characteristics as presented in the following table.

TABLE 1: NEMA CODE LETTER DESIGNATIONS (STARTING KVA’s)

CODE LETTER KVA per HP

A: 3.15
B: 3.16 – 3.55
C: 3.56 – 4.0
D: 4.1 – 4.5
E: 4.6 – 5.0
F: 5.1 – 5.6
G: 5.7 – 6.3
H: 6.4 – 7.1
J: 7.2 – 8.0
K: 8.1 – 9.0
L: 9.1 - 10.0
M: 10.1 - 11.2
N: 11.3 - 12.5
P: 12.6 - 14.0
R: 14.1 - 16.0
S: 16.1 - 18.0
T: 18.1 - 20.0
U: 20.1 - 22.4
V: 22.5 - and up

The above table means that a 200 hp motor with a NEMA Code Letter ‘G’ requires a starting kVA of 1,140 to 1,260 kVA (1,200 kVA on the average) when using Full Voltage (Across-the-Line) motor controller. This starting kVA is also known as “Locked Rotor kVA” or sometimes “Locked Rotor Amperes”.

With the starting kVA of the motor such as described above, we must then determine the voltage dip caused by the motor inrush on start-up. The ensuing voltage during start-up must stay within the allowable operating voltage of the system. If such condition happens, then no oversizing of the transformer is required. But when the voltage dip exceeds the operating requirement of the system, then the transformer must provide extra kVA.

North American motors are rated for 230, 460, 2,300, 4,000, 6,600 or 13,200 volts for use with distribution sub-systems that are rated at 240, 480, 2400, 4,160, 6,900 or 13,800 volts respectively. Note the difference in motor nameplate voltages viz-a-viz the transformer terminal voltages. The apparent lower motor voltages than distribution nominal voltages are deliberately established by manufacturers to deal with the inherent voltage drops in the system such as: internal voltage drop of the transformer as dictated by its voltage regulation capability, voltage drop along the distribution cables and the impedance of the system. This could mean that the 4,160 v at the transformer at no-load condition may only be 3,800 v at the motor terminals when the system is already heavily loaded. In this condition, when a large motor is started-up somewhere in the system, the lower will the voltage be as felt by other loads in the system.

That’s why NEMA standard motors are designed to be capable of operating at plus or minus 10% of nameplate voltage. Therefore, the voltage drop on inrush should not be allowed to drop more than -10% of the rated voltage. This means 208v for 230v or 414v for 460 volt motors. Likewise, 2.07 kV or 3.6 kV for 2.3 or 4.0 kV motors, respectively. It means that a 4 kV motor can still operate satisfactorily at 3,600 v but any disturbance in the system that brings the system voltage lower, the affected motors may trip off as provided for by its protection – or if not, the motor burns.

(To be continued…)

Doods A. Amora
December, 2006

PLANT EFFICIENCY

DOOD’S KEYNOTE ADDRESS:

SCHNEIDER ELECTRIC ROAD SHOW

PRESENTATION 2006

Parklane Hotel, Cebu City
November 9 & 10, 2006

INTRODUCTION

Invoking ‘PLANT EFFICIENCY’ as Schneider Electric’s theme in this Road Show is very much timely in these times of resurging uncertainties in energy costs as variable inputs to production economy. As we speak today, manufacturing plants in the Philippines are unsure of what tomorrow will bring to the state of oil prices even as business itself has again been sailing into another uncharted economic limbo. After all, [COST + PROFIT] = [SELLING PRICE]; that’s business all about.

In physics; Efficiency means, Output/Input. In engineering, Efficiency = Output/(Output + Losses). We had been taught that efficiency is always less than 100%. And that Output is always less than the Input. In order to gain Maximum Efficiency, Output must be at its possible maximum while losses at its possible minimum. Simple, yet how do we interpret that in the Shop Floor? The center-stage therefore in analyzing efficiency is: losses! To the layman on the shop floor, the better word is “waste”.

Interpreting wastages or losses in real-life plant environment could be cumbersome. It takes not only technical & managerial expertise but also business sense in integrating a labyrinthine maze of nitty-gritties into an orchestrated energy management program. It is not switching off lights or air-conditioning systems during lunch breaks that counts but Energy Management extends beyond mediocre imagination.

TODAY’S COMPETITIVENESS

In general terms, Management experts say that the ingredients of today’s competitiveness are: quality, efficiency and productivity. To help attain this goal, several old inefficient plants in the 90's were replaced with high technology lines giving way to modern techniques and processes in manufacturing. On top of this, organizations were restructured to meet new synergistic requirements. Several companies in the country sought for ISO certification - showing to the world that these companies are at par with world class standards. The mood in the 1990’s therefore was modernization to meet global competition. But modernization is in fact going back to basics, again to: quality, efficiency and productivity. That is still valid even up to today…

The phrase ‘energy management’ means different things to different people.

Quality Buffs say, “AIM QUALITY” … and Efficiency as well as Productivity follows…

Productivity Enthusiasts say, “FOCUS ON PRODUCTIVITY” … and Efficiency as well as Quality follows…

Efficiency Practitioners declare, “EFFICIENCY IS EVERYTHING” … Productivity & Quality are built-in.

Whatever it is, it is the same banana. Simply because there must be a “War On Waste”. In our lingo, we say, WOW! And WOW has always been beautiful. Let us therefore dwell in WOW!

THE NEED FOR ENERGY MANAGEMENT

To me, there are three reasons why we need Energy Management.

1) Manufacturing Economics: The company, (meaning, your company and everyone else’s) has to survive. Energy Costs have now been an expensive raw material and closing shops would mean unemployment debacle of large proportions.

2) National Good: Energy management is good for the national economy as the balance of payments becomes more favorable and the peso stronger. Energy management makes us less vulnerable to leaps in energy prices, or curtailments due to political unrest or natural disasters elsewhere.

Although the Philippines has oil, forget about it. We need to realize that until the country strikes a new liquid black gold mine, Philippine indigenous oil is forgettable. The Philippines is consuming an average of 338,000 bbl/day, with net oil imports of 312,000 bbl/day (92.3%). This dependence on imported oil makes the Philippine economy vulnerable to sudden spikes in world oil prices. Although exploration underneath the Malampaya gas field revealed an estimated 85 million barrels of oil, this could probably supply the country for a period of nine (9) years at present production level of 25,000 bbl/day (7.7% of the country’s needs). If Malampaya field supplies the country 100% of its oil requirements of 338,000 bbl/day, Philippine oil deposits would only last for (hold your breath) 8 months.

In comparison, the USA consumes 24.5 million barrels of oil per day in 2004. The Malampaya oil deposit of 85 million barrels will last for only for THREE DAYS in the USA.

3) Energy management is kind to our environment as it eases some of the strain on our natural resources and may leave a better world for future generations.


WHAT IS ENERGY MANAGEMENT?

To the energy managers, energy management is: “the judicious and effective use of energy to maximize profits (minimize costs) and enhance competitive positions”.

According to Mr. Barney L. Capehart, PhD, CEM, in his book “Guide to Energy Management”, the primary objective of energy management is to maximize profits or minimize costs. Some desirable sub-objectives of energy management programs include:

1. Improving energy efficiency and reducing energy use, thereby reducing costs,

2. Developing and maintaining effective monitoring, reporting, and management strategies for wise energy usage,

3. Finding new and better ways to increase returns from energy investments through available controls system & automation,

4. Developing interest in and dedication to the energy management program from all employees. Cultivating good communications on energy matters,

5. Reducing the impacts of curtailments, brownouts, or any interruption in energy supplies.

-------------------------------------------------------------------

What therefore is the relevance of Energy Management to this Roadshow? Let me talk first about “Plant Efficiency”…

PLANT EFFICIENCY

Plant Efficiency is related to production throughput. To a Plant Manager, the cue would always be: ‘Cost Vs. Production’. Low Production Cost is good. Similarly, High Production Output is good. Which is which?

The best is when you have the highest production at the lowest cost, because the two measurements must be integrated into a ratio. The lowest ratio of Cost per unit Product is always seen as the penultimate measure. That is one element of the so-called “throughput”!

Production of course is dependent on the capacity of the plant. But even if production wanted to achieve the same output as the capacity, seldom is it possible because of loss factors such as quality rejects, idling, speed adjustments, line adjustments, technical troubles, waiting times, etc., are influencing production throughputs.

In any industrial plant or commercial complex, energy must be seen as a raw material to production. Nevertheless, Energy Management must not be understood as doing without energy but is in fact, making the most out of it. Often misunderstood, energy management is actually a ‘War on Waste’ (WOW). Its basic strategy is to eliminate unnecessary losses while paying for wastages are mortal sins. Energy Management means that monthly power bills are as normal as eating three square meals per day but paying for unnecessary extras is a waste that every business abhors. Yet in most plants, energy management as a discipline is often “said than done”; because it is always not seriously taken into action.

Energy Management therefore must focus on the following:

a) Managing the Load, because mismanaged load could mean millions of pesos,

b) Managing Power Losses, because unmanaged extra losses mean big bucks.

If your plant doesn’t manage the load or is not concerned on losses, then that plant has never understood energy management. All energy conservation pronouncements by management are just plain rhetoric. Many Plant Managers are usually non-cognizant to the fact on how to tap the seemingly non-existent gold mine in his plant’s backyard!

---------------------------------------------------

The objective of today’s Road Show is to reinforce the managers and engineers in the modern tools to achieve the highest efficiency in plant facilities. Surprisingly, the subjects in today’s Road Show jibe with Mr. Capehart’s goals in energy management. Non-scripted, the following areas are featured as today’s highlights, namely:

a) Power Monitoring,
b) Selective Automation,
c) Energy Efficient Devices & Controls.

But let me add two more things,

d) Effective Maintenance, and
e) Efficiency-Driven Workforce.

All of these are part of WOW. Allow me discuss each …

1) POWER MONITORING

Remember the dictum: “You can’t control if you don’t measure”. We need meters to measure. And there are six good reasons why we should meter a plant. A management, who wants to manage energy but doesn’t want to install measuring means, is an oratorical management who is not serious in energy management. Unless energy usage is measured, it is next to impossible to know where to direct efficiency efforts.

A metering system provides that vital ingredient to a successful energy management program. There are six (6) reasons why we should meter the plant.

• CHARGE OUT ENERGY TO INDIVIDUAL DEPARTMENTS

This is the most basic reason to meter. Experience in this country has shown that a 5–10% reduction in consumption can be achieved after meters are installed just by letting the users know that they are monitored. Up to 10% more reduction can occur when the users start to manage the use of their energy. Ultimately, up to a 25% to 30% reduction will be achieved when metering is tied directly to the process through a Programmable Logic Controller (PLC) or Distributed Control System (DCS), in a closed loop automated process control arrangement.

 ACCOUNTABILITY FOR ENERGY USED

Once metered, establish energy budgets for the various departments. Each month the total energy bill is proportioned to each department. This data is used to compare costs against the department's budget and thus develop a variance-peso value.

Trending of energy consumption per unit of production or per service performed is the basis for initial analysis and resulting corrective actions. Accountable for every kw-h consumed, each department shall be made to explain the variances of the use of energy.

Management and creative personnel are always critical components of an energy management program. Tough, specific, and measurable goals need to be developed. Once the goals are established, management should carefully monitor the results, but the energy management staff should be allowed to perform its functions.

Staff and management need to realize that:

1) energy costs, not consumption, are to be controlled

2) energy should be a direct cost—not an overhead item, and

3) all energy consumers need be metered and monitored closely.

• EFFICIENCY OF UTILITY EQUIPMENT & SYSTEMS

The objective of an energy reporting system is to measure energy consumption and compare it either to company goals or to some standard of energy consumption. Ideally, this should be done for each operation or production cost center in the plant, but most facilities simply do not have the required metering devices. Many plants only meter energy usage at one place—where the various sources enter the plant. Most plants are attempting to remedy this, however, by installing additional metering devices when the opportunity arises. Systems that should be metered include steam, compressed air, and chilled & hot water.

There are established world standards in machine or system performance. For instance, how is your refrigeration system performance compared with world standards? In a Bottling Plant for instance, how much kw-hour does your plant consume per case or per liter of product as compared to established world standards? Is your air-conditioning kw-hours per unit area more than industry standards? It is prudent for plant management to benchmark its performance to the established best practices. This way, management will know if you are performing well or not.

• PROVIDE INFORMATION FOR AUDITS OF ENERGY PROJECTS

With funding becoming increasingly difficult to obtain, audits of cost reduction energy management projects have been required more frequently. But energy audits will be blind without meters.

• IDENTIFY PERFORMANCE PROBLEM AREAS & PROVIDE FEEDBACK TO MANAGERS

The collection of energy-consumption data in support of energy management is seen as a viable tool, greatly aiding in the identification of equipment performance problems. As a side issue, performance problems associated with the people operating the equipment are also identified, allowing managers to take any necessary corrective action.

Cost center orientation is important, as are comparison to some standard or base and calculations of variances.

• IDENTIFY POTENTIAL ADDITIONAL ENERGY SAVINGS

According to IEEE publications, “… with the long-term goal of management being one of continual improvement, metering and trending systems provide data on which to base resource allocation decisions. With regard to audits of the electrical power system, metering results can be used to compile an energy profile that will reveal areas where conservation projects are most beneficial. Monitoring and reporting energy consumption allows for close control while minimizing expenses. It also provides historical energy consumption data to aid in projecting future loads and developing standards for the next year. Such data are essential to financial forecasts and operating budgets. Through proper monitoring, recording, and analysis, the use of meters can lead to corrective actions that produce the desired result of reducing energy per unit of production or per service performed”.

2) SELECTIVE AUTOMATION

Technology advancements could have been kind to the electrical engineering profession. The electrical engineering we knew of 20 or 30 years ago is no longer the same engineering today. With the entry of power & control electronics highlighted with industrial automation, electrical engineering has raised its dignity significantly. With the new wonders in electrical engineering unfolding, in a high-tech brewery scenario for example, the electrical cost component of a project is now elevated from a forgettable 9% of the past to some 15% today. For a P 2.0 billion brewery, it is not surprising to have an electrical budget of some P 300 million.

The acceptance of new technologies in industries today made the increase of the value of electrical engineering. To keep pace with global pursuit to manufacturing quality and efficiency, more plants in the country are upgrading or modernizing their facilities. Small candy factories for instance are now equipped with variable frequency drives. Tableware factories have now graduated from ancient manufacturing techniques to PLC orchestrated automation. The departure from the traditional TW or THW wires in conduits to industrial multi-core cables (not ‘Cord’, please) in cable trays, the shift to soft starters in lieu of the traditional magnetic contactors and the employment of DIN rail mounting molded case circuit breakers from age-old fuses; are just few examples but significant changes in the industrial plant landscape. Common electrical equipment as transformers, generators, power circuit breakers, protection and control devices had undergone series of evolution compared to counterparts in other engineering disciplines.

For the manufacturing plants, there’s no other way to increase production quality & efficiency throughput but to employ instrumentation that makes automation possible. The trend now is to manage production through a centralized control centre where all operational variables can be supervised through computer screens or mimic boards. There is no escape to new technology and electrical engineering is supposed to be the beneficiary.

The name of the game in manufacturing today is therefore automation & robotization. Why? Simply because in the global business arena, it is a must! John H. Zenger, a known American management expert in his book "Leading Teams" wrote, "In the 1960's, North America stood at the summit of world economic power. In those days, the order of the day for every manufacturing manager can be summarized by a sign that hung over his desk and that is:

GOOD. FAST. CHEAP.
PICK ANY TWO..!
It means that:

 "If you want quality and you want it fast, it'll cost you big bucks"

 "If you want it fast and cheap, no problem, but it won't be good enough to last through the winter"

 "If you want good quality at a good cheap price, that's fine too, but don't hold your breath for delivery. It'll probably take forever."

Then, comes the customer’s cue to nod in wide-eyed agreement:

"You always have to trade off one to get the other two."

Today in the third millennium, a manufacturing company has to give out all the THREE, in order to survive fierce competition. In a customer-driven business environment, automation therefore becomes the answer to the need of efficiency & speed. Robotization where applicable, is the key to achieve large volume and uniform quality throughput especially in industries where human factor is too hazardous. That in a nutshell, is why so many companies are putting themselves through so many agonizing internal changes, including the parting away of old traditional management styles. For until a manufacturing plant becomes "good, fast and cheap", it's an easy prey for any competitor that figures out how to deliver on all three.

3) ENERGY EFFICIENT DEVICES & CONTROLS

INSTRUMENTATION & CONTROLS..? Bulk of power consumption in a plant comes from conveyors running without materials conveyed, machines running even if there are no materials being fed, circulating pumps running even if not needed, air-conditioning in full-blast even if no people around, lights on with no one is using the light, and a host of others. Make an audit and you might discover that 25% to 30% of your power bills are consumed unproductively.

In modern plants, instrumentation & electronics control systems employing sensors are now common scenarios to watch over these problems. They came in the form of automated and intelligent buildings or plants. Machines & comfort equipment are shutdown automatically if sensors can not detect any reason why these machines should run. Pumps are slowing down when volume demand dwindles. Conveyors slowing down when full or gain speed when not loaded or shut down at all. Compressors loading and unloading automatically depending on demand and the list is endless.

4) EFFECTIVE MAINTENANCE

In the past, responsibilities of maintenance are to concentrate only in making machines and equipment run in service to the production department. Today, maintenance is already included in the ownership of the quality and quantity of the products produced, because after all, it is maintenance’s job to make the process capability of the plant fit to produce such products.

Maintenance is a critical part of a facility’s operation. Effectively maintained equipment and processes are necessary to keep the facility functioning at its optimum capability. Unfortunately, maintenance programs are often the first victims of any cost-cutting effort. Generally, proactively preventive or scheduled maintenance is cut back or eliminated. Then the maintenance effort is directed more toward “repair and replacement” than toward keeping the equipment running most efficiently. When this “run-to-failure mode" of maintenance happens, you are in the state of poor maintenance.

Maintenance should now be an integral part of any energy management program. Maintenance keeps equipment from failing, helps keep energy costs within reason, helps prevent excess capital expenditures, responsible to the quality and quantity of the products produced, and is frequently necessary for safety.

Again, automation & robotization bring the equipment or machines to the center-stage. When we say equipment or process machines, it means maintenance because maintenance now plays a much bigger role in production. Along with the shift in philosophies in maintenance, new concepts in modern management had been developed in Europe and anywhere else in the globe, among them are as follows:

 In the past, quality and quantity of production were to a large extent decided by the skills of men and their capacity to work fast. All through a long period of time, from generation to generation, maintenance had been thought of as a service department - not a condition to production.

 Times had changed. The quality and quantity of production now do not depend on man but on machines. With the increasing degree of automation and robotization in most manufacturing plants today, it is now appropriate to recall Mr. John Moubray a British expert on Reliability Centered Maintenance (RCM) when he said, "that product quality & quantity now depends on equipment". At the other side of the globe, Mr. Seiichi Nakajima, a Japanese guru on Total Productive Maintenance (TPM) preached: "that productivity, cost, inventory, safety, health and production output - as well as quality - now all depend on equipment”.

 In the scene of plant maintenance, the concept that maintenance is nothing but a service unit has now been changed to the concept that “maintenance is a function of production, and conversely, production is a function of maintenance”.


5) EMPLOYEE PARTICIPATION

Investing capital for “self-intelligence” & automation will pay off handsomely by eliminating big time losses. However, no amount of automation shall relieve the responsibilities of the attendant. There is still that so-called “human interface”. An energy management program can be successful only if it arouses and maintains the participative interest of the employees. Employees who participate and who feel themselves partners in the planning and implementation of the program will be more inclined to share pride in the results.

The use of company newsletters, bulletin boards, or posters for pictorializing energy conservation objectives and accomplishments will help impress employees with the importance of such matters. Employee participation can be increased by communicating examples of energy conservation ideas being implemented, photographs of persons who submitted the ideas and information on the savings realized.

Five critical factors in organizing an effective energy management program are as follows:

a) Top Management Commitment: This is a formally communicated, financially supported dedication to reducing energy consumption while maintaining or improving the functioning of a facility. This commitment shall be active and visibly communicated to all levels of the organization in terms of words and actions by top management.

b) People Commitment: People at all levels of the organization should be involved in the program. Ideas should be encouraged with rewards for significant contributions to the energy management program. People should be shown why their help is needed, and a team approach should evolve. Note that a most successfully planned program can be devastated by a single person trying to subvert the program.

c) Communication Channel: The purpose of this channel is to report to the organization the results of your efforts, to recognize high achievers, and to identify reward recipients. Use the channel to advertise the program and to encourage cooperation.

d) Organizational Changes: This is to give ample authority and commensurate responsibility for the conservation effort and develop an energy management program.

e) Monitor & Control the Program: An organizational plan, using the above criteria, should then be developed for both implementing and monitoring specific energy management programs.

6) CONCLUSION

In the next hours of the day, Schneider Electric will give you details on how to help achieve the objectives of Plant Efficiency.

In the modern times, we electrical engineers must remember that:

In the past,

[COST + PROFIT] = SELLING PRICE

Today,

[SELLING PRICE] – [COST] = PROFIT




DOODS A. AMORA, PEE
November, 2006