MYSTIQUES IN SYSTEM PROTECTION - PART 3

MYSTIQUES IN SYSTEM PROTECTION
By Doods A. Amora, PEE

[PART 3 OF A SERIES OF 3]

PROTECTIVE RELAY SETTINGS & COORDINATION

The output of Fault Calculations is equally vital as inputs and/or reference range in setting-up protective relays. It also serves as “key-ins” in the simulation of relay responses to various modes and magnitudes of fault currents. After all, the relays must be armed ready to respond to the various modes of faults at any magnitudes of over-currents that could happen in any part of the system and at any possible operating conditions. These now form part of the so-called System Protection & Coordination Study.

RELAY SETTING & COORDINATION consists of the selection or the setting-up of all protective devices in series from the load side, then going upstream and finally to the power generators. In arming up these protective devices, a valuation is made on the operating times of all the devices in response to various levels of over-currents. Again, the objective, of course, is to design a selectively coordinated electrical power system.

With power analysis software such as ELECTRICAL POWER SYSTEM DESIGN & ANALYSIS (EDSA) or its equivalent, “Coordination Tables & Curves” can be established based on the relay setting schemes -- and simulations to predict relay responses can easily be accomplished. The procedure involved is to select or set up the various protective devices so that the resulting characteristic curves established on a composite time-current graph from left to right corresponding to relays from the downstream to the upstream with no overlapping of curves. Should there be any overlapping of these relay response curves in extremely remote but possible conditions, they are referred to as ‘compromise’.

In the case of the IPP described in this article; the Coordination Curves derived from the “As-Found” settings has to be established on paper. In the same manner that the “New” Coordination Curves derived from the recommended new setting parameters; simulations and/or predictions on relay responses can be finally done at any mode and magnitudes of faults. These outputs must be compared with each other. It is then expected that the new curves must be in better health than the previous coordination schemes that had caused the problems.

However, the attempts made to re-parameterize the relays of the IPP Power Plant in this article to respond and operate as ideally desired at all possible operating conditions, at all modes of faults and at all magnitudes or severity of faults; may not at all be possible because of the following factors as: limitations of existing relays, overlapping zones of protection and even the sizes and number of generators viz-a-viz the power transformers. Thus in this scenario, this is where the so-called “compromise” in protective relaying comes in.

It is in this light that the system protection engineer has to seek for the best relay settings possible to effect the paramount but not necessarily the perfect coordination given these limitations.


METHODOLOGY FOR THE STUDY

Since the coordination requirements differ for each power system, all programmable protective devices must be set in the field to achieve the desired coordination. In setting the relays, "there is no mystery involved; rather, it is a case of perseverance in trying various combinations of characteristic curves to insure correct operation on both maximum fault currents”.

Going back to the IPP problem described in this article; if a study has to be conducted, the following legs have to be undertaken in crafting the complete job, to wit:

1) Understanding the System: At the onset, the system as it was historically and what it is today have to be understood. As such, establishment of the system single line diagram with the latest interconnections with the grid becomes imperative. Existing protective devices and their functions in the system likewise have to be probed along with their corresponding sensors as PT’s & CT’s.


2) Physical Inventory of System Components: Physical inventory on all circuit breakers, power fuses, disconnects, overhead lines, transformers, generators, disconnecting switches, etc have to be performed to confirm what’s on paper are the ones in actuality. Establishment of nameplate capacities & ratings (whenever and wherever possible) and the capabilities of circuit breakers, transformers, generators & other major components have to be done.

3) Fault Calculations & Simulations: Fault Calculations have to be performed to confirm that the circuit components especially the protective devices are still within operating limits in events of faults. It is also from these calculations that simulation of faults for various conditions can be conducted and their magnitudes recognized. By using EDSA analysis software or its counterpart, fault duty simulations can be made straightforwardly, especially in establishing relay responses to various magnitudes and modes of fault currents.

4) Establishment of Relay Setting History: It is important to understand the frames of minds behind the previous relay settings. From the original set parameters, there could have already been several events of relay resetting in its history. Taking off from these previous parameters, the engineer will understand the “why’s” and “how’s” the old frameworks of set-parameters were laid down.

5) “As Found” Relay Settings: History’s latest “as-left” settings should be what the engineer finds out in actual inspection in establishing the “as-found” settings. This activity will confirm that the actual relay settings jibe with what’s on paper.

From this information, the engineer can make “As-Found Coordination Charts” where faults can be simulated and responses of the relays established based on the existing settings. An analysis on the “As-Found Coordination Charts” will explain inconsistencies of relay performances and why the unwanted trippings happened. This activity must not be limited to paper works alone but includes circuit tracings on actual wirings and connections made on the relays so with the confirmation of CT ratios actually used.

6) Formulate New Schemes of Relay Settings: With all the above information and the ensuing analyses especially on the “as-found” data, a new scheme of relay settings could be formulated to address present problems. Again with EDSA software, “Coordination Tables & Curves” can be established based on the new scheme and simulations to predict relay responses can be accomplished.


EPILOGUE

The action of the 86T’s (Lock-Out Relays) of the twin transformers in the scenario of the IPP in this article is triggered by the stroke of the 51G’s (Transformer Back-Up Ground Protection). Note that the 51G’s in this case are wired to interface with the Lock-Out Relays. Once activated, the Lock-Out relays in turn trip both the Primary and the Secondary Circuit Breakers of the Transformers. The simultaneous triggering of the 51G’s are due to the fact that the two 40 MVA 13.8–69 kV step-up, delta-wye transformers are paralleled at 69 kV (secondary) side through a tie bus. Hence, any ground fault current sensed at the neutrals of the two transformers can be seen simultaneously by the 51G’s.

As being said earlier, a single line-to-ground fault scenario away from the Power plant occurred at the 69 kV feeder for one of its customer – the Industrial Economic Zone. But then, the Feeder Circuit Breaker through the 67N (Directional Ground Fault Relay) protecting this line must have tripped ahead of the 51G’s of the two transformers.

But alas! It didn’t live up to expectations. It thus meant a faulty coordination. Among other causes, there could be three most probable reasons (or a combination of these probable causes) why the scenario:

1) Faulty settings on the cascading relays with respect to each other,

2) Wrong choice of threshold pick-up currents, relay operating characteristic curves & Time Multiple Settings (TMS),

3) Or it could be: wrong CT tap used, especially in multi-tap multi-ratio CT’s.

But then, as being said earlier, an attempt to re-set some relays in the system to address specific problems may upset like domino effect the discrimination of the operation of other relays with respect to each other. To ensure total coordination of protective devices in the system, all other relays in the system (from the load ends to the generating end) must likewise be probed and re-set whenever found necessary. So the story on the IPP’s predicament in this article could be a tip of the iceberg. For instance, out of 50 relays being considered, it could be that 20 of them may need some re-programming.

Finally, adequate control of short circuits & faults through proper settings are one major consideration, because 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 & fire damage – even explosions.

For all possible conditions (normal & abnormal), it is the responsibility of the system designer to build electric systems in a safe and reliable manner. It is also the plant management’s responsibility to see to it that protective devices are armed to pre-determined performance either by his engineers or by consultants.

Ultimately therefore, it is service continuity that is the rationale of good system protection.

End of Article ...
DAA 3/12/2009

MYSTIQUES IN SYSTEM PROTECTION - PART 2

MYSTIQUES IN POWER SYSTEM PROTECTION

By Doods A. Amora, PEE

[PART 2 OF A SERIES OF 3]

OVERVIEW OF FAULTS

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

As the name implies, a ‘fault current’ is one which flows outside the normal conducting paths. Fault modes refer to: Three-Phase Faults, Single Phase (Line-to-Line) Faults, Double Line-to-Ground Faults and Single Line-to-Ground Faults. And these currents always come in large magnitude!

Contributing sources of fault currents into a system in focus include: Grid Generation, Local Generation, In-Plant Synchronous Motors and Induction Motors. Therefore, Fault Calculation is needed to establish new levels of fault duties brought about by any changes in the grid or in the industrial plant system itself.

Three-Phase Bolted Short Circuits: This 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 and the short circuit current flowing into the fault point at the time is influenced by the sub-transient impedance of the system at the inception (1/2 cycle) of the fault. This establishes a “worst case” condition, which results in maximum thermal and mechanical stress in the system. While ‘bolted short circuit condition’ seldom occurs, 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 ½ cycle maximum values that the selection of fault duty ratings of circuit breakers, power fuses, other protective devices and switchgear withstand ratings shall be based, busway bracings included.

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 (single phase) bolted short circuit currents in most three-phase 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 bases in relay settings or other purposes.

Line-to-Ground Bolted Fault Circuits: In solidly grounded systems, single line-to-ground bolted short circuit current in general terms, can be almost equal to the three-phase bolted short circuit current. Most of the time, actual 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.

In resistance-grounded medium voltage systems common in generators, the Neutral Grounding Resistor (NGR) is generally selected to limit ground fault current to a value ranging between say, a few tens or hundreds of amperes allowed to pierce into the neutral of the generator. Magnitudes of Line-to-Ground fault currents on these systems are limited primarily by the grounding resistor itself and a line-to-ground fault calculation using symmetrical components is generally required to size up the resistor.

Arcing Faulted Circuits: In actuality, 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 and the impedance of the ground return path. Normally, arcing fault currents fall in the range from 40% to 50% of the bolted values or could be much lower especially in limestone earthing environments.

In the real world, statistics showed the frequency of occurrence of these faults are as follows:

Single Line-to-Ground Faults: 70% – 80%
Double Line-to-Ground Faults: 10% - 17%
Phase-to-Phase Faults: 8% - 10%
Three-Phase Faults: 2% - 3%


FAULT DUTIES

For new installations, Fault Calculations must precede any effort to procure system protection devices purposively to arrive at the appropriate ratings & capabilities that fits various system conditions to include future considerations.

For existing plants where Power System Study is conducted, this activity is likewise imperative to establish that the protective devices such as circuit breakers in switchgears are still within operating limits. Updating the awareness in system fault duties is always true to situations where the Grid has changed significantly where fault duties have also changed.

While overloads do occur at somewhat modest levels, the ‘short-circuit’ or ‘fault current’ can be hundred times (or more) larger than the normal operating current. A high level fault in the medium voltage systems may be 40,000 amperes (or even larger). If not interrupted within a matter of a few thousandths of a second (depending on the magnitude of fault current), damage & destruction can become very serious. There can be severe insulation damage, melting of conductors, vaporization of metals, ionization of gases, explosion, arcing & eventually fires. Moreover, high level short-circuit currents can develop huge magnetic-field stresses between switchgear buses that can reach destructive forces beyond their short-time ratings that even heavy bracings may not be able to keep them from being distorted beyond repair.


Protective devices such as circuit breakers in switchgears must be rated to withstand the destructive energies of fault currents. If a fault current exceeds a level beyond the capability of the protective device, the device may rupture and disintegrate in its attempt to interrupt a fault. This is the first step.

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.


PROTECTIVE RELAYS

Today, Fault Control by protective relays is just one part of a protective umbrella covering such conditions as equipment & component deterioration, natural hazards, reliability requirements and similar considerations. As one article on the web puts it: "But if system protection is the “heart” then, electronic devices now being integrated into electrical systems have become the “nerves” of today’s systems. In just one generation, the introduction of new, “smarter” devices has significantly changed equipment and design practices."

Protective relays have been described as the watchdogs or silent sentinels in the power system. They come in anticipation for faults. Again, to minimize the effects of faults on the system, these devices should be selective in operation so that the one nearest the fault downstream will operate first and, if any device should fail to function, the next closest device on the upstream side should open the circuit. This is what is globally referred to as “failing well”.

It may be convenient to think of the circuit breaker as the muscle providing brute force that does the work of isolating the component, while the relay is the brain which decides that isolation is required and the command for the circuit breaker to trip.

Most switchgear-type relays are enclosed in a semi-flush-mounting draw-out case. Relays usually are installed on the door of the switchgear cubicle. Again, protective relays are arguably the least understood component of medium voltage circuit protection. And, coordination doesn't need to be complicated too, that is, if we know some basic relay and sensor information. Let's then try to unravel the mystery.

Protective Relays come on the form of electro-mechanical, solid state and more recently the digital relays.

Electro-mechanical Relays: These relays are now extinct and therefore need no further discussion as far as this article is concerned.

Solid State Relays: These relays can perform all the functions that can be performed by electro-mechanical relays and, since the precision of solid state electronic relays is greater than that of electro-mechanical relays, they allow closer system coordination. In addition, because there is no mechanical motion and the electronic circuitry is very stable, they retain their target accuracy for a long time. Incidentally however, Solid State Relays had a short-lived popularity. Sooner than expected, these types of relays are now out of manufacture.

Digital Relays: Solid State relays were replaced by the development of more modern & superior Digital Relays that are now used in newer installations. Compared to its predecessors, digital relays carry superior functions than the electro-mechanical and solid state units. Because of the versatility of digital circuitry and micro-processors, these relays provide many functions not previously available in electro-mechanical & solid state counterparts.

Today’s Digital Relays are built immune to severe electrical environment of industrial or utility applications. They are built to withstand failure, especially from high transient voltages caused by lightning, on-site switching and other rugged application conditions. Digital Relays have gained a strong and rapidly growing position in power systems in terms of accuracy, dependability, versatility, and reliability, and most of all; they come in, much cheaper.

To be continued...
DAA 3/8/2009

MYSTIQUES IN SYSTEM PROTECTION - PART 1

MYSTIQUES IN SYSTEM PROTECTION
By Doods A. Amora, PEE

[PART 1 OF A SERIES OF 3]

PROLOGUE

One sunny morning in what could have been a promising smooth routine; the Diesel Power Plant of an Independent Power Producer (IPP) suddenly lost its 50 MW power flow to an Industrial Economic Zone. The audible thuds at the switchyard somehow announced that the circuit breakers at the primary and secondary sides of the twin - 40 MVA Power Transformers T1 and T2 tripped off simultaneously! From the looks of it, the Transformer Lock-Out Relays (86T’s) must have done it! But, why...?


It didn’t occur just once - it already happened a number of times. And it would certainly happen again.

In each of such eventualities, the IPP was brought into total power interruption –isolating entirely its valued customers.

The management of the Power Plant didn’t desire it. And the hundreds of companies in the Industrial Zone didn’t like it, either. So much productivity had been lost. Something’s needed to be done - necessitating that the power plant’s operating limits, protection system and its vulnerabilities re-revisited.

Subsequent investigation revealed that a Single Line-to-Ground Fault occurred at a 69 kV Feeder far and kilometres away from the Power Plant. But why the triggering of the Lock-Out Relays when there are circuit breakers in series closer to the fault? They must have failed doing their function when they shouldn’t...!



THE NEED FOR PROTECTION

“System Protection is the very heart of power generation & distribution systems. Faulty or inadequate protection can bring about the loss of the entire facility— or, worse, it can cause needless deaths or injuries to personnel.” Quoted from an e-book, those words are still true today as every application of power system results in the need for protection.

As one GE Publication said, “The designer of the system must face the reality that no matter how much redundancy he builds into the system, and no matter how much he pays for premium quality components, he simply cannot build a system which will never fail. This is where system protection becomes important. If component failure is inevitable, then it is necessary to provide a means of detecting these failures. Better and faster protection affords a number of desirable attributes, all of which ultimately result in saving the owner of the system money through cost avoidance.”

And faults are for real! Even with the best design possible; materials and equipment deteriorate, and the likelihood of faults increases with age.


Indeed, a serious uncleared fault can put at risk utility operation and can result in area outages that would affect numerous customers, notwithstanding the damage on pieces of equipment which are in some cases, irreparable. Every system then is subject to short circuits and ground faults that should be removed quickly - and the awareness of the magnitudes and effects of faults is necessary to arm suitable system protection.

Failures or breakdowns of various components of a power system are either man-made, accidental or by natural causes such as those brought about by lightning, hurricane or from mere deterioration. Thus, protection in an electric system is a form of insurance. It pays nothing as long as there is no fault or other emergency, but when a fault occurs, it can be credited with reducing the extent and duration of interruption, the hazards of property damage and personnel injury. A certain number of faults can be tolerated during the life of the system provided they are immediately isolated before they cause damage or cause the loss of system stability. As reliability experts say, “should the system fail, it must fail well”.


Losses associated with a service interruption vary widely in different types of industries. For example, a service interruption in a machining operation may mean only a delay in production, while a similar interruption in a chemical production plant can cause loss of material and production, costly clean-up operations and possible damage to production equipment. Other industries such as semi-conductor plants, refineries, paper mills, textile mills, breweries, cement plants, steel mills and food processing plants are affected similarly, but in varying degrees. For some type of loads involving complex automation, a momentary voltage dip can be as serious as a complete interruption. Others can tolerate a momentary interruption, but not a sustained one. Thus, the character of industrial operation has a major influence on the type of fault protection applied to the electric system.


THE ART OF SYSTEM PROTECTION

While it is being said that it would neither be practical nor economical to build a fault-proof power system, the application of protective relays is often referred to as more of an “art” than a “science”. Relaying is an art because there is judgment involved in the selection of protective devices and its subsequent parameterization. The selection of protective relays requires compromises between conflicting objectives, such as: maximum protection vs. minimum protection, reliable protection vs. high-speed operation, high sensitivity to faults but insensitive to fleeting overloads, selectivity in isolating only a small faulty part in the system but capable of operating properly for several system operating conditions.


System Protection of a plant must thus be armed to respond to the various modes of faults at any magnitudes of over-currents at any parts of the system. At the same time, faster and more sensitive detection of problems means that the cause of the problem can be corrected while it is still a minor problem, and before it escalates into a major catastrophe.

So then, 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 designed by responsible system designers to be free from short circuits as possible, even with these precautions, the plant cannot escape from faults because short circuits will surely occur – perhaps not today but in the near future.


THE SYSTEM PROTECTION & COORDINATION STUDY

Proper coordination of circuit interrupting devices is an essential but frequently overlooked phase of industrial power system design. To many, this is a mystery. For those in the utility companies assigned in system protection for years, protective relaying is a special competency.

SYSTEM PROTECTION & COORDINATION STUDY is sought to address the problems and to virtually arrive at a desirable tripping sequences within the identified problematic zones of protection of an electric system. The study covers two major areas, as follows:

a) FAULT CALCULATIONS & SIMULATIONS
b) PROTECTIVE RELAY SETTINGS & COORDINATION

The end state of this Study is to have armed or set-up the installed protective devices ready to operate and respond to various modes of faults at any magnitudes of over-currents at any parts of the system in a predetermined sequence to satisfy Selective Coordination requirements.

So then, a system protection & coordination study aimed to re-arm the protective relays became obligatory as in the case of the IPP’s predicament referred to above. If other relays appeared to have displayed no problems, an attempt to re-set some relays to address specific problems would lead to a domino effect the discrimination of the operation of other relays with respect to each other. To ensure total coordination of protective devices in the system, all other relays in the system (from the load ends to the generating end) must likewise be probed and re-set whenever found necessary.

But, as system protection deals on faults, the Study must include Fault Calculations & Simulations to establish the levels of fault duties brought about by the configuration of the system, among others.

To be continued...
DAA 3/4/2009