ML20213A589
| ML20213A589 | |
| Person / Time | |
|---|---|
| Site: | Fermi  |
| Issue date: | 01/28/1987 |
| From: | Agosti F DETROIT EDISON CO. |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| VP-NO-87-0014, VP-NO-87-14, NUDOCS 8702030371 | |
| Download: ML20213A589 (22) | |
Text
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Cat 0,t!!',"
Nuclear Operattoris
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January 28, 1987 VP-NO-87-0014 U. S. Nuclear Regulatory Commission Document Control Desk washington, D. C.
20555
References:
1)
Fermi 2 NRC Docket No. 50-341 NRC License No. NPF-43 2)
NRC Generic Letter 83-33, "NRC Positions on Certain Requirements of Appendix R to 10CFR50", dated October 19, 1983.
3)
IE Information Notice No 84-09, " Lessons Learned from NRC Inspections of Fire i
Protection Safe Shutdown Systems (10CFR50, Appendix R)", dated February 13, 1984.
4)
Detroit Edison Letter to NRC,
" Transmittal of Fire Protection Information", EF2-69218, dated August 4, 1984.
5)
Detroit Edison Letter to NRC, " Submittal of Deviations from Staff Interpretations of Fire Protection Features in 10CFR50 i
Appendix R and Justification",
EF2-72717, dated August 3, 1984.
6)
Detroit Edison Letter to NRC,
" Alternative Shutdown In the Control Center Complex," EF2-72718, dated August 16, 1984.
7)
Detroit Edison Letter to NRC Region III,
" Detroit Edison Response to Inspection Report 50-341/84-16," EF2-70022, dated i
October 8, 1984.
l 8)
Detroit Edison Letter to NRC,
" Implementation of Alternative Shutdown at Fermi 2," EF2-71994, dated October 22, 1984.
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USNRC January,28, 1987 VP-NO-87-0014 Page 2 9)
Detroit Edison Letter to NRC, " Design of Alternative Shutdown Approach,"
EF2-72001, dated October 22, 1984.
10)
Detroit Edison Letter to NRC,
" Additional Information Concerning Fire Protection", EF2-72025, dated December 7, 1984.
11)
Detroit Edison Letter to NRC, " Request For Amendment For the Alternative Shutdown Program," RC-LG-85-0051, dated September 27, 1985.
12)
Detroit Edison Letter to NRC,
" Alternative Shutdown System Procedures", VP-NO-85-0206, dated November 6, 1985.
13)
Detroit Edison Letter to NRC,
" Alternative Shutdown System Procedures," VP-NO-85-0220, dated November 27, 1985.
J 14)
Region III Letter to Detroit Edison "IE Inspection Report 50-341/85050 (DRS),"
dated January 3, 1986.
15)
Detroit Edison Letter to NRC,
" Alternative Shutdown System,"
2 VP-NO-86-0005, dated January 30, 1986.
16)
Detroit Edison Letter to NRC,
" Alternative Shutdown Proposed Technical Specification," VP-NO-86-0091, dated July 15, 1986.
17)
Detroit Edison Letter to NRC, " Editorial Changes to Proposed Technical Specification," VP-NO-86-Oll7, dated August 15, 1986.
18)
NRC Letter to Detroit Edison, " Draft SER on Alternative Shutdown System Technical Specifications," dated August 19, 1986.
19)
Detroit Edison Letter to NRC, " Response to Draft SER," VP-80-0136, dated October 14, 1986.
, - - - - - - - - -., - - - - - - - - - - - - - - - - - - - ~ - ~ - ~
USNRC January 28, 1987 VP-NO-87-0014 l
Page 3 20)
NRC Letter to Detroit Edison,
" Alternative and Dedicated Shutdown Capability," dated November 21, 1986.
J
Subject:
Alternative Shutdown System References (2) and (3) provided information to the licensees concerning the NRC staff interpretations and positions relative to 10CFR50 Appendix R.
Upon reviewing and evaluating References (2) and (3), Detroit Edison submitted the known deviations and justifications for Fermi 2 by References (4) and (5).
During the time Detroit Edison was discussing with NRR on how we were meeting the Appendix R requirements, the Region came out to Fermi to audit our Fire Protection commitment implementation (IE. Inspection Report 84-16).
As a result o'f that inspection, a Deviation, (Item 84-16-02) was identified.
This deviation concerned the Control Center Complex.
References (6) and (7) revised our commitments as negotiated with the NRC staff in a July 11, 1984 meeting resolving the subject deviation.
NRC staff review of Detroit Edison's' application for an operating license for Fermi 2 identified that certain modifications to the design would be required.
By Reference-(8), we agreed to enhance our design as described in Reference (9).
On November 2, 1984, representatives from Detroit Edison met with the NRC staff concerning the design of the Alternative Shutdown System and the schedule for implementation of that system.
As a result of that meeting, the NRC conditioned the Fermi 2 Operating License to install the Alternative Shutdown System, as outages permit, in the time frame not to exceed startup after the first refueling outage.
The License also required that the Plant Technical Specifications be amended accordingly (Reference 10).
In accordance with Reference (10), Detroit Edison informed the NRC as to the completion of the installation of the Alternative Shutdown System, Draft Procedures, and provided proposed Technical Specifications by References (11), (12), (13), (15),
{
(16), and (17).
i On December 2-6, 1985 (Reference 14) an inspection was performed by the Region concerning Detroit Edisons l
commitments on the Fermi 2 Fire Protection Program as referenced above.
The results identified that the proposed design of the Alternative Shutdown System as reviewed and accepted by the NRC as discussed in f
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USNRC January,28, 1987 VP-NO-87-0014 Page 4 Supplements No. 5 and 6 of the Fermi 2 Safety Evaluation Report (SER) would accomplish all the postfire safe shutdown performance goals necessary to minimize the release of radioactivity to the environment.
Reference (18) provided Detroit Edison a Draft SER related to the Staff's review of our proposed Technical Specifications.
Based on the information presented in Reference (18), Detroit Edison requested to meet with the NRC to supply some additional information pertaining to the testing of the Alternative Shutdown System.
As a result of that meeting, Detroit Edison supplied additional information to the NRC by Reference (19).
The Staff's review of Reference (19) generated additional questions that were transmitted to us by Reference (20).
Our response to these questions is provided as an enclosure to this letter.
If you have any questions, please contact Mr. S. R. Frost at (313) 586-4210.
Sincerely,
[
Enclosure cc:
Mr. E. Greenman Mr. W. G. Rogers Mr. J. J. Stefano USNRC Region III
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Enclosuro to VP-NO-87-0014 Page 1 NRC Ouestion A The enclosure to the October 14, 1986 Detroit Edison letter, bottom of page 3, references an October 22, 1984 letter, which stated that an analysis performed by Detroit Edison showed that over 20 minutes is available before operator action is required to mitigate the transient for reactor isolation events with no feedwater or ECCS initiation.
The draft FSAR Figure 9B-25 provided in the October 22, 1984 letter, shows that the reactor water level is at the top of the active fuel 20 minutes into the event.
Appendix R, Paragraph 3L.1 (10CFR50) states that, "During the postfire shutdown, the reactor coolant system process variables shall be maintained within those predicted for a loss of normal,...."
Paragraph 3L.2.b states that, "The reactor coolant makeup function shall be capable of maintaining the reactor coolant level above the top of the core...."
The information provided with the October 22, 1984 letter does not clearly describe how the top of the active core will not be uncovered when makeup water is not initiated for the first 20 minutes.
It is, accordingly, requested that Detroit Edison provide a supplemental analysis which demonstrates compatibility with the above cited paragraphs of Appendix R, without the initiation of makeup for 20 minutes, in order for the Staff to understand the degree of margin which exists in the Fermi 2 design.
Detroit Edison Response to Question A A supplemental analysis has been performed using the RETRAN Computer code for a conditi,on with no makeup water to the Reactor Pressure Vess'el (RPV).
The purpose of the analysis was to determine the length of time available before the reactor core becomes uncovered.
The analysis assumes a loss of off-site power occurs at the beginning of the event.
This event creates a RPV isolation almost immediately.
The ECCS and feedwater systems are assumed to be inoperable.
The RPV pressure is relieved by the Safety Relief Valves (SRV) in the overpressure mode and are assumed to close at their respective set points.
The short term sequence of events is given in Table 1 attached.
The RETRAN model was run for a 45 minute long transient.
The level and pressure responses are shown in Figures 5 and 6.
After 20 minutes, the reactor water level is about 90 inches (7 1/2 feet) above the Top of Active Fuel (TAF), after 45 minutes the water level is approximately more than 30 inches above the TAF.
Enclosure to VP-NO-87-0014 Page 2 The RETRAN model was tested for validity by comparing the model against the FSAR Chapter 15 transient analysis.
The FSAR transient selected for comparison was the " loss of all grid connections" as shown in Figure 15B.2.6-1 of the Fermi 2 FSAR.
Comparison plots (for 50 seconds) between RETRAN and the FSAR for reactor water level, pressure, core flow, and heat flux are shown in Figure 1 through 4 of this response.
These plots compare very well, the difference in the water level response can be attributed to the faster core flow reduction as predicted by RETRAN (see Figure 3).
The slight difference in the reactor pressure response is due to the higher Safety Relief Valve (SRV) set point pressures (nominal plus 1%) used in the FSAR analysis.
The RETRAN model used for the Fermi 2 analysis compares with a ORNL study for Browns Ferry, NUREG-CR-2182, titled Station Blackout at Browns Ferry Unit 1, Accident Sequence Analysis (Table 9.5).
This report for station blackout assumes loss of all makeup water to the RPV.
The size of the reactor, type, power and containment design (Mark I) are similar to that of Fermi 2.
The computer code used was the BWR-LACP (BWR-loss of AC Power).
This study indicates a 33 minute time period to reach TAF.
Therefore, the RETRAN analysis supports our previous submittals that there is a greater than 20 minute time period before the TAF is reached.
NRC Ouestion B l
i The second paragraph on page 2 of the enclosure to the October 14, 1986, letter states in part that, "This testing (of the 3L panel) included actual verification of transferring control, of the affected components, from the control room to the 3L Panel and various local shutdown panels.
Each component was operated from its respective shutdown panel and verified that the control l
of the panel could not be overridden by the control l
room."
The question is: "What protection is provided to l
prevent the 3L panel from overriding control room signals?"
l Detroit Edison Response to Question B The checkout and initial testing of the Alternative l
Shutdown System control components verified that with the transfer switch moved to the " local" position that the components operated properly from the local panel.
The procedure then required verification that operation i
)
Enclosure to VP-NO-8.7-0014 Page 3 of the controls in the control room would not override or affect any control function from the Dedicated Shutdown Panel.
The transfer switch was then placed back to the " Control Room" position and the procedure was reversed.
The controls in the control room were verified to control the component, and the controls at the Alternative Shutdown System were verified that they did not control or affect these components.
This procedure is repeated during the 18 month surveillances of the Alternative Shutdown System.
NRC Ouestion C In conjunction with item A above, Detroit Edison calculated that 20 minutes will be available to power the 3L panel to provide makeup water to the reactor vessel in the event of a fire; and that tests conducted by Detroit Edison have determined that the 3L panel can be successfully powered for this purpose within 13 minutes.
As stated in the last paragraph on page 2 of the enclosure to the October 14, 1986 letter, the operator will scram the reactor, isolate the CTG #1 power supply " designated" as the power source for the 3L panel and isolate the Standby Feedwater System (SBFWS) before leaving the control room.
These multiple actions appear to presuppose the location and growth of the fire, an assumption for which credit has not been previously given by the staff in evaluating a plant's compliance with fire protection requirements.
The 13 minute time period was determined by having CTG #1 on line, by opening the output breaker, and by restarting CTG #1 to verify its ability to reject load and to restart and supply power to the 3L panel.
In order to ascertain that there will be sufficient margin to ensure makeup water to the reactor vessel within the 20 minutes calculated by Detroit Edison, it is requested that Detroit Edison consider the effects of the time required to initiate makeup water to the reactor vessel by not isolating CTG #1 and the SBFWS until after the operator leaves the control room, with the fire initiating in the CTG #1 and SBFWS control room panels, and considering the resultant spurious operation and shorting of those panel circuits due to the fire.
Also verify that no damage will result to the 3L panel and shutdown components, that adequate water will be provided to safely shutdown the reactor and that makeup water to the reactor vessel can still be initiated well within the 20 minutes calculated from fire onset.
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Enclosure to VP-NO-87-0014 Pagc 4 i
Detroit Edison Response to Ques _ tion C The October letter described the process of shutting Fermi 2 down using the Dedicated Shutdown Panel procedure due to a fire in the control room.
The Dedicated Shutdown Panel procedure describes various steps to be taken during a fire, such as starting the CTG and transferring control to the Dedicated Shutdown Panel.
These procedures were written to cover conditions where a fire develops in a progressive manner.
However, the procedures and the Alternative Shutdown System are designed to cover a worst case situation where the control room must be immediately abandoned.
The only action assumed is tripping the plant before. evacuating the control room.
This procedure has been accepted in SSER #5, Section App.
E.VII.C.
The Alternative Shutdown System Controls are designed to be independent of the fire area after transfer.
- Also, once transferred, the systems are capable of recovery from any fire damage or spurious actions that could g
occur before the transfer takes place.
The scenario of achieving reactor shutdown is affected very little whether the CTG Unit is started or restarted from the main control room or the Dedicated Shutdown Panel.
The affect is small because the Dedicated Shutdown Panel is located in the Radwaste Building switchgear room.
This room is adjacent to the east wall of the control center, one floor level below the control
{
room.
Normally, the control room door on the east wall would be used for the operators to travel to the Dedicated Shutdown Panel.
If the door on the South wall were used, an additional 100 feet would have to be j
travelled to reach the stairwell.
Access to this panel by either door from the control room can be achieved within 1 minute.
Once at the Dedicated shutdown Panel, the transfer switch is thrown to the " local" control.
Local control of the CTG Unit 1 is provided via a multiplexer transmitter to the CTG.
CTG startup can be initiated from the Dedicated Shutdown Panel.
Local control is also provided for the breakers, valve controls, pump controls and instrumentation to align the electrical power train up to the SBFW pumps and then start and control SBFW pump injection into the RPV.
Indication is provided via back-lighted push buttons, bus monitor lights, etc., which are battery powered.
Local battery pack lights are also provided to illuminate the area and I
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Enclosure to VP-NO-8.7-0014 Page 5 access paths.
Cases 1 and 2 below, designate an approximate time breakdown of the actions from the time of the fire until injection of water begins with SBFW.
One SBFW pump equals RCIC flow (600 gpm) which, at these times, is greater than the boil off rate.
Thus, once SBFW flow is established, the water level will recover.
Case 1 assumes the CTG is not running when the fire occurs.
In Case 1 a Loss of Off-Site Power (LOP) is assumed to occur when the control room is evacuated and reactor scramed.
(If a LOP does not occur, then off-site AC power is available or can be lined up to power SBFW.
Therefore, a LOP assumption is the worse case).
The CTG has been tested to demonstrate that it can be warmed up in as little as 6 minutes.
Once the CTG is initially started, a conservative warm up period of 10 minutes is assumed until the CTG can accept load.
Once the CTG is ready, one minute is assumed to operate breakers and initiate the SBFW pump (s).
The SBFW system valves are DC powered and are aligned for i
pump start while the CTG is starting.
An additional 1.5 minutes is required to open the DC powered pump globe valves.
A two minute delay is assumed for valve alignment before SBFW is injected into the RPV.
Case 1
. Time Actions i
o Fire occurs in control room, warranting rapid abandonment.
o Reactor scrammed and control room abandoned.
LOP occurs at this time, creating loss of all AC power as the EDG's are assumed to be inoperable due to the fire.
1 min.
Operator reaches Dedicated Shutdown Panel in the Radwaste Building switchgear room.
Operator initiates procedure placing the transfer switches " local" position.
2 min.
Initiate CTG Unit 1 start from Dedicated Shutdown Panel.
Operations personnel initiate the DC stripping procedure.
At the Dedicated Shutdown Panel, breaker positions verified in proper alignment and placed in proper alignment if not.
SBFW system valves aligned for startup.
1
Enclosure to VP-NO-8,7-0014 Page 6 12 min.
CTG Unit 1 started, ready for load - breaker closed and voltage restored to bus.
13 min.
A SBFW pump, started, begin opening globe valve.
15 min.
SBFW valves in proper position - injection of water begins to vessel.
Case 2 assumes the CTG is running as a peaker, synchronized to the Edison grid when the fire occurs.
When the loss of off-site power occurs, under-frequency protection trips the CTG Unit and the coastdown period begins.
Case 2 therefore assumes the LOP occurs at 1 minute into the accident, just before the CTG is transferred to " local" control at the Dedicated Shutdown Panel.
The coastdown time of 13 minutes has been used as the result of an actual test.
Since, the CTG was operating, no additional warm-up time is required.
As in Case 1, a 1 minute breaker alignment time is assumed and a 2 minute globe valve opening time is assumed before SBFW flow enters the vessel.
Case 2 Time Actions Fire occurs in control room, warranting o
control room evacuation.
CTG Unit operating as peaker, in parallel with Edison grid.
o Reactor scrammed (one action) and control room evacuated.
1 min.
LOP occurs and causes trip of CTG Unit 1 countdown time (13 min.) begins.
Operator reaches Dedicated Shutdown Panel in the Radwaste Building switchgear room.
Operator initiates procedure to place transfer switch into " local" position.
2 min.
At the Dedicated Shutdown Panel breaker positions are verified in proper alignment and re-positioned if necessary.
SBFW system valves aligned for startup.
Operations personnel are initiating the DC stripping procedure.
_. =.
Encionure to VP-NO-87-0014 Page 7 14 min.
CTG coastdown sufficient to restart.
CTG Unit I re-started and voltage restored to bus.
15 min.
SBFW pump started and begin opening globe valve.
17 min.
SBFW valves in proper position-injection of water begins to vessel.
3 The water levels corresponding to the 15 and 17 minutes specified in Cases 1 and 2 are the RETRAN runs from Response A above.
For Case 1 with a LOP and Scram at time 0, the water level at 15 minutes is 8.3 feet TAF.
Case 2 assumes scram at t=0 and LOP at t=1 minute i
resulting in a water level of 7.9 ft. TAF at 17 minutes.
For Case 2, the RETRAN program was not re-run for the one-minute delayed LOP.
Re-running the program for that reason is not justified considering the margins of water predicted.
These cases also show that the above procedures must be accomplished within 45 minutes, before the TAF is reached.
The next part of the question concerns the effects of spurious operations on the Alternative Shutdown System.
The control and components used for the Alternative
' Shutdown System are designed to recover from the affects of fire damage to the control circuits if such damage occurs before transfer takes place.
The " power" feeds to the valves, pumps, etc., are routed outside of the 4
i fire zones using the Alternative Shutdown System.
Only the control circuits are routed in these areas.
The transfer switches (located in NON-Alternative Shutdown fire zones) open the " fire damaged" control circuits, both hot and neutral sides, and close into the independent local control wiring.
Separate fuses are provided in the local scheme in case fire induced faults blow the original fuses.
The fuses in the circuit in the normal (or control room) position are coordinated s ith the control transformer rating to assure the w
' transformers would not be damaged by a high impedance fault in the fire zone.
The electrical design of the Alternative Shutdown System components considered the affects of fire damage that could potentially occur before the Alternative Shutdown System transfer takes place.
4 Although unlikely, valves, pumps and breaker controls provided on the Alternative Shutdown System Panels could spuriously operate before the transfer switches clear these controls from the fire zone.
Spurious affects due
Enclosure to VP-NO-87-0014 Page 8 to valve or pump mis-operation on SBFW or the CTG would require re-positioning the valves or CMC switches to the proper position or re-starting the CTG.
Note that the Alternative Shutdown System Panels provide position and status indication on the panel through the use of back-lighted push-buttons, bus monitors, etc.
Thus, the panel operator can verify proper positions at the panel.
The time to position or re-position the DC powered SBFW valves is accounted for in the case 1 and 2 studies.
A trip signal to the CTG could cause a trip before the panel is transferred.
However, the CTG can be re-started from the Dedicated Shutdown Panel and the Case 2 is replicated.
Any spurious breaker operation that happens before transfer can be re-aligned during the startup period of the CTG.
(Breaker Controls are DC).
The electrical line up is therefore ready except for closure of the CTG Breaker and SBFW pump breakers when the CTG is ready.
A spurious analysis was performed as part of the Alternative Shutdown System Design.
The analysis looked for various spurious events that could affect the ability to achieve shutdown.
The analysis reviewed systems that could affect reactor coolant inventory, torus inventory and temperature, condercate storage tank inventory, SBFW flow and drywell temperature.
The results of the analysis are as follows:
- 1. Check valves contain the RPV pressure if various injection valves spuriously open.
- 2. The DC stripping procedure terminates a spurious open relief valve, RCIC or HPCI turbine operation in the first several minutes of the event.
- 3. The outboard RHR Shutdown Cooling valve is maintained de-energized at the Motor Control Center (MCC) so that it cannot spuriously open.
- 4. The AC stripping procedure terminates the Torus Water Management System pumps and condensate pumps which could direct torus water or condensate storage tank water away from the Alternative Shutdown System.
- 5. SBFW flow cannot be diverted from RPV through HPCI test line because the valve E41-F001 is maintained de-energized at the MCC.
Enclosure to VP-NO-87-0014 Page 9
- There are no additional spurious events that require operator action to recover beyond the re-positioning or re-starting events at the Alternative Shutdown System Panels and local operation of circuit breakers.
The DC and AC stripping procedures are in the Dedicated Shutdown procedure and do not involve the operator at t
the Dedicated Shutdown Panel.
1 Local operation of circuit breakers is utilized for the i
purpose of esta1>l1shing torus and drywell cooling and cold shutdown.
There is more time available to achieve these goals.
Control of breakers to recover RPV water is provided on the Dedicated Shutdown Panel.
As indicated, the two valves that could conceivably create a problem are maintained de-energized at the power distribution cabinet so that they cannot mis-operate.
Detroit Edison does not foresee any other time constraints on achieving RPV water recovery beyond those identified in this response.
NRC_ Question D Detroit Edison intends to use CTG #1 as the " designated" power supply source for the 3L panel.
The Staff's draft SER, submitted by letter dated August 19, 1986, specifies that a " dedicated" power supply be provided for the 3L panel.
The Staff is not certain whether the
" designated" power supply adequately meets the guidelines of Regulatory Guide 1.68 as committed to by Detroit Edison in the PSAR.
In the third paragraph on i
page 3 of the enclosure to the October 14, 1986 letter, it is stated that tests have demonstrated that the CTG #1 power supply, " designated" to provide power to the 3L panel, can be tripped (assuming it is being operated to provide peak power at time of the fire), and that power can be provided to the 3L panel to initiate makeup water to the reactor vessel within 13 minutes.
In addition to the information requested under Item C above, Detroit Edison is requested to provide a breakdown of the time required from onset of the fire until makeup water is supplied to the reactor vessel, assuming that CTG #1 is not tripped until the operator l
gets to the 3L panel.
If CTG #1 trips off-line when it is trying to pick up 3L panel loads, indicate the time required to restart CTG #1, to power the 3L panel and to
Enclosure to VP-NO-87-0014 Page 10 I
begin supplying makeup water.
In so doing, address what i
alternative power supply source (s), equipment operations, procedures, etc., have been considered to get water to the reactor vessel within the 20 minutes calculated to avoid core uncovery.
Detroit Edison Response to Question D Detroit Edison is using CTG Unit 1 as the backup power supply for Alternative Shutdown System as indicated in 1
SER Supplement 5, App. E.VII.B.
The Alternative Shutdown System, with CTG Unit 1 as the backup power supply, was designed to the requirements of 10CFR50 Appendix R, Section III.L.
There are no requirements to meet the Regulatory Guide 1.68 for this panel.
Detroit Edison does have a Remote Shutdown Panel, located in the Div. I Switchgear Room, that satisfies the requirements of GDC 19 and Reg. Guide 1.68 (see FSAR App. A).
The scenario of a control room fire requiring control room abandonment while the CTG Unit 1 is operating in synchronization to the Edison grid is covered in Case 2 of Detroit Edison's response to Question C of this letter.
Additional failures such as a CTG trip while picking up load, or failure of the CTG completely bconstitute additional single failures beyond the design crit'eria of App. R.Section III.L.6.
l t
I
TABLE 1 SHORT TERESEQUENCE & EVENTS (NOTE: Feedwater Flow Forced to Match FSAR Fig.15B.2.6-1)
Time (Seconds)
Event 1
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8.4 1 Turbine bypass valves start to close 99 I Group 1 SRVs close m
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