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