ML20127N655

Responds to Concerns Raised During 850516 Meeting in Bethesda,Md Re Review of Emergency Electric Power Sys. Response Addresses Independence of Redundant Emergency Power Trains,Rapid Transfer Sys Testing & Switchgear Control Sys

ML20127N655
Person / Time
Site:	Fort Saint Vrain
Issue date:	06/14/1985
From:	Warembourg D PUBLIC SERVICE CO. OF COLORADO
To:	Johnson E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
References
P-85208, TAC-51055, TAC-51955, NUDOCS 8507020061
Download: ML20127N655 (8)

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2420 W. 26th Avenue, Suite 100D, Denvr. Colorado 80211 June 14, 1985 Fort St. Vrain Unit No. 1 P-85208 Regional Administrator Region IV

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U. S. Nuclear Regulatory Comission 611 Ryan Plaza Drive, Suite 1000 $ l $@

Arlington, Texas 76011 Attn: Mr. E. H. Johnson Docket No. 50-267

SUBJECT:

Questions on Electrical Review of Fort St. Vrain Emergency Electric Power System

REFERENCE:

Meeting of May 16, 1985 and Phone Conversation on June 6, 1985

Dear Mr. Johnson:

During our meeting in Bethesda on May 16, 1985, the staff raised several concerns which could not be answered without research. The following are those concerns and the PSC response:

NRC Concern 1:

The staff stated that they did not understand how the system would respond to a fault on 4 kV Bus 1 or 4 kV Bus 3 when the faulted bus was also tied to 4 kV Bus 2. The potential concern here is that the loss of 2 out of 3 4 kV buses would cause the emergency diesel generators (EDGs) to start and load, instead of automatically transferring to the reserve auxiliary transformer (RAT). Selection of -p the EDGs to supply emergency power is undesirable if an offsite ,

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PSC Response to Concern 1 When a fault occurs on 4 kV Bus 1 (or 4 kV Bus 3) and the tie breaker to 4 kV Bus 2 is closed, 4 kV Bus 1 (or 4 kV Bus 3) will be isolated and 4 kV Bus 2 will be transferred to the RAT. This process takes approximately 1-1/2 seconds. During this time period the EDGs will be given a start signal, however, load shedding and loading of the 480 V buses to the EDGs will not occur. The coordination between the 4 kV and 480 V undervoltage relays is such that it takes a loss of voltage on the 480 V bus of approximately 5 seconds duration before outside power is abandoned.

The following is a detailed description of the automatic actions that occur if 4 kV Bus 1 and 4 kV Bus 2 are tied together when the scenario starts. Similar actions would take place for the 4 kV Bus 3 scenario.

1) Overcurrent relays will sense the fault and lockout relay 186ATI will trip. Auxiliary contacts of 186ATI will trip and block j closing of breaker 152AT1 (4 kV Bus 1 main feed from unit auxiliary transformer) and, trip and block closing of breaker 152BT21 (4 kV Bus 2 to 4 kV Bus I tie breaker).

Breaker 152RT2 (4 kV Bus 2 feed from RAT) will close automatically when it senses low voltage on 4 kV Bus 2, and both 4 kV bus tie breakers are open. The 152BT21 and 152BT32 breaker will also be blocked open when 152RT2 (4 kV Bus 2 feed from i

reserve auxiliary transformer) is closed.

NRC Concern 2 The staff noted that in numerous cases, the Fort St. Vrain Electric Power System drawings indicated that the redundant emergency power trains were not independent. Specific examples that were discussed included:

1) Logic controlling the EDG breakers

2) Logic controlling the essential 480 V bus tie breakers.

The staff's initial conclusion was that logic permissives and interlocks from one train were required to close the EDG breaker from the second train. The existence of such logic permissives does not assure automatic operation of the redundant EDGs. However, the staff stated that they believed that the lack of independence in the logic circuits did not canpromise the independence of the system when 3

operated in the manual mode.

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PSC Response to Concern 2:

PSC is in agreement that automatic operation of the EDG breakers and the essential 480 V tie breakers is not assured with the present control logic.

PSC is also in agreement that the identified logic permissives and interlocks do not compromise the system when operated in the manual mode.

PSC will evaluate this problem within 90 days and provide the evaluation to the staff. At that time, if design changes are required, a schedule for implementation will be provided. In the meantime, the following justification for continued operation is presented.

JUSTIFICATION FOR CONTINUED OPERATION In view of the importance of the NRC Concern 2, PSC immediately conducted a review of the accidents and events considered in the FSAR to determine what effect this sequence of events could have on the outcome of these accidents. The results of this evaluation, presented below, demonstrate that continued operation with the present design is justified.

In order to facilitate the presentation of the results of the evaluation the following conditions are defined:

Condition A: Coincident loss of Outside Electric Power and Main Turbine Trip with loss of one Diesel Generator, described in FSAR section 10.3.2.

Condition B: Cooldown with Safe Shutdown List Equipment Items Following Design Basis Earthquake or " Maximum Tornado", described in FSAR section 10.3.9.

Condition C: Coincident Loss of Outside Electric Power and Main Turbine Trip with the single failure which prevents the automatic closure of both of the diesel generator breakers. This situation is not presently described in the FSAR.

The only event which requires the automatic startup and sequencing of a diesel is Condition A.

Condition A is the same as Condition C except with the added loss of the second diesel generator due to the failure in the logic circuitry causing the diesel generator breaker to remain open.

The time for the operator to manually close the breaker and load the diesel generator with the required equipment was estimated as follows:

Consultation and decision time to manually close the breaker and align the swing Bus tie breakers 20 minutes Time taken to manually load the sequence shown in FSAR Table 8.2-4, assuming 1 min /

operation 24 minutes 44 minutes In Condition B, the diesel generators automatically startup and sequence. However, no credit is taken in the core temperature transient analysis for forced circulation core cooling for 1-1/2 hours. This delay is due to the manual alignment of valves that must be performed to provide cooling for the steam generators by the firewater pumps and motive force for the helium circulators by the firewater pumps and emergency water booster pumps.

Although Condition C is not explicitly described in the FSAR, the resulting plant conditions are well within those shown in the FSAR for Condition B. This can be readily seen by comparing the above 44 minute time frame that it takes the operator to initiate forced core cooling for Condition C with the 1-1/2 hours required to achieve forced circulation core cooling for Condition B.

The reason that the time frame for initiation of forced care cooling is so much less for Condition C than Condition B is that in Condition C the condensate pumps are used as the motive force for driving the helium circulators and for providing steam generator cooling rather than the firewater pumps used in Condition B. The condensate pumps can be aligned from the control room to provide motive force for forced core cooling in the emergency condensate line and the time frame to provide this function depends only on the time required to perform the operations shown above. The pathway for the firewater pumps has to be manually aligned which is more time consuming.

The much shorter time frame with no forced cooling in the core will ensure that the core temperatures experienced for Condition C will be substantially less than those for the previously analyzed Condition B.

~5-The temporary unavailability of both diesel generators due to l the single failure in the logic circuitry of one of the diesels results in conditions which are substantially less severe than that l previously analyzed and found to be acceptable. Therefore, continued operation without changes to the existing design is justified.

NRC Concern 3:

The staff inquired as to whether the 4 kV Rapid Transfer System was tested and if this requirement was part of the Technical Specifications.

PSC Response to Concern 3 PSC is planning to test the 4 kV rapid transfer system.

Information regarding this testing was sent to the NRC in proposed changes to the Technical Specification LC0 4.6.1.1 and SR 5.6.1 (P-85041), dated February 6,1985.

NRC Concern 4 The DC control power systems for the plant switchgear were discussed. PSC noted that all switchgear was provided DC power from both redundant battery supplies. The Staff inquired how the loss of DC voltage to the switchgear was indicated to the operators, both at the switchgear and in the Control Room.

PSC Response to Concern 4 PSC initially indicated to the Staff that the source of DC control power for the FSV switchgear is administrative controlled by manually inserting a fuse block in the desired power feed. Further research has revealed that this is only the case for the 4 kV switchgear.

DC power to the essential 480 V switchgear buses is supplied from both DC Bus 1 and DC Bus 2. In the switchgear compartment of each of the three essential 480 V switchgear, there are two circuit breakers and two DC contactors. One contactor and circuit breaker fed from DC Bus 1 and one contactor and circuit breaker fed from DC Bus 2. The contactors provide automatic throwover in the event of loss of one of the DC buses. The circuit breakers in the DC buses are alarmed to the Control Room; However, no loss of DC alarm exists in the 480 V switchgear.

A schematic diagram of the contactor arrangement has been sent by separate letter to Iqbal Ahmed. This control power transfer method will be included in our evaluation of concern number 2.

NRC Concern 5 Will synchronizing switching relays prevent manual breaker closure, if you are trying to manually energize a dead bus?

PSC Response to Concern 5 Synchronizing relays do not exist in the control circuitry of the 4 kV and 480 V buses, therefore, no inhibit is present. All synchronizing is done with the aid of a syncscope. The generators can easily be connected to a dead bus.

NRC Concern 6 Assuming that the diesel generator breaker automatic closure feature fails, how long does it take to perform a manual closure and energize the dead bus?

PSC Response to Concern 6 All circuitry is in place to allow this action, i.e. no electrical jumpers are required. Features of the automatic circuitry cannot inhibit the manual operation of the 480 V EDG breakers.

Therefore, the only time associated with this action would be investigatory in nature to determine if we have experienced any equipment failures. It has been determined this situation can be investigated in approximately 20 minutes.

i OTHER TOPICS DISCUSSED NRC Concern r On a loss of all outside power with the main turbine generator running, will emergency diesel generators be loaded in parallel with the main turbine generator?

PSC Response 1

In the event of loss of all outside power the governor of the main turbine generator would reduce generation to the level required to support the house power loads, lockout relay 86RT would operate l and 152RT2 would be prevented from closing, isolating the plant from the outside system.

The emergency diesel generators would automatically start but no loading would occur unless all voltage is lost or degraded on the 480 V buses, at that time load shedding and auto sequencing would occur.

The only time the emergency diesel generators are operated in parallel with the main turbine generator is during the technical specification required exercise of the diesels.

NRC Concern Which helium purification compressor is on the automatic sequencer? Compressor 18 is on the list of sequenced loads but compressor IA is not?

PSC Response Helium purification compressor IB is fed from 480 V essential Bus 3 and is an automatically sequenced load. Helium purification compressor 1A is fed from 480 V essential Bus 2, and since loads on Bus 2 are not automatically sequenced, helium purification compressor 1A does not show on a sequenced list.

NRC Concern Are trip alarm contacts installed in the 480 V essential switchgear breakers?

PSC Response The contacts labeled as Bell Alarm (B.A.) are more correctly called automatic trip alarm contacts and operate only on an overcurrent trip. The contacts are installed in the 480 V essential switchgear.

NRC Concern Does the inverter transfer to the back-up power source on a loss of AC or on a loss of DC?

PSC Response The inverters supplying power to the noninterruptible buses transfer to back-up power on loss of AC. DC input or logic failure would also show as a lo:s of AC output and the inverter would transfer to the back-up power source.

NRC Concern What are the power requirements for the closing circuitry on the 4 kV and 480 V circuit breakers?

PSC Response Breaker closing and charging n10 tor currents 4 kV breaker Charging Motor = 10 AMPS Closing Circuit = 6.7 AMPS 480 V Breaker (3000 and 4000 AMP)

Charging Motor = 10 AMPS Closing Circuit = 2.06 AMPS 480 V Breaker (225 and 600 AMP)

Charging Motor = 10 AMPS Closing Circuit = .76 AMPS Should you have any further questions regarding the above, please contact Mr. M. H. Holmes at (303) 571-8409.

Very truly yours, j b O.(U%~h /

D. W. Warembourg, Man er Nuclear Engineering Division DWW/WK:pa

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