ML19305C080
| ML19305C080 | |
| Person / Time | |
|---|---|
| Site: | Grand Gulf  |
| Issue date: | 03/19/1980 |
| From: | Stampley N MISSISSIPPI POWER & LIGHT CO. |
| To: | Harold Denton Office of Nuclear Reactor Regulation |
| References | |
| IEB-79-08, IEB-79-8, NUDOCS 8003250562 | |
| Download: ML19305C080 (59) | |
Text
. _ _ _ _ _ _ _
MISSISSIPPI POWER & LIGHT COMPANY
]
Helping Build Mississippi
~
"L P. O. B OX 1640, J AC K S ON, MIS SIS SIP PI 3 9 2 05 "C"",',5 i s w March if, 1980 U. S. Nuclear Regulatory Coccission Office of Nuclear Reactor Regulation Washington, D. C.
20556 ATTENTION:
Mr. Harold R. Denton, Director
Dear Mr. Denton:
SUBJECT:
Grand Gulf Nuclear Station Units 1 and 2 Docket Nos. 50-416 and 50-417 File 0272/0270/L-860.0/16684/0755 Ref.: AECM-80/24 Follow-up Action Regarding the Three Mile Island Unit 2 Acci-dent AECM-80/26 The purpose of this letter is to transmit the Mississippi Power & Light Company responses to IE Bulletin 79-08 (Attachment 1) as well as plant unique data requested by the Bulletins and Ccders Task Force (Attachment 2).
Also included are our responses to Bulletins and Orders Task Force requests for additional information concerning NEDO-24708 (Attachmentr 1 and 4).
- incerely, If MRK/JDR/LFD:pa Attachments cc:
Mr. R. B. McGehee Mr. T. B. Conner
\\
t:-
b Mr. Victor Stello, Jr., Director g(
\\g Division of Inspection & Enforcement g
U. S. Nuclear Regulatory Commission gg e
Washington, D. C.
20555 Q
ek#
9 Mer-ber %ddie Sc; tn Utilities System h
8003250 1
(ATTACMNT I)
MISSISSIPPI POWER & LIGHT COMPANY GRAND GULF NUCLEAR STATION - UNITS 1 & 2 ITEMIZED RESPONSE TO IE BULLETIN 79-08 QUESTION 1 Review the description of circumstances described in Enclosure 1 of IE Bulletin 79-05 and the preliminary chronology of the TMI-2 3/2S/79 accident included in Enclosure 1 to IE Bulletin 79-05A.
a.
This review should be directed toward understanding:
(1) the extreme seriousness and consequences of the simultaneous block-ing of both trains of a safety system at the Three Mile Island Unit 2 plant and other actions taken during the early phases of the accident; (2) the apparent operational errors which led to the eventual core damage; and (3) the necessity to systematically analyze plant conditions and parameters and take appropriate corrective action.
b.
Operational personnel should be instructed to (1) not override automatic action of engineered safety features unless continued operation of engineered safety features will result in unsafe plant conditions (see Section 5a of this bulletin); and (2) not make operational decisions based solely on a single plant para-meter indication when one or more confirmatory indications are available.
All licensed operators and plant management. and supervisors with c.
operational responsibilities shall participate in this review and such participation shall be documented in plant records.
RESPONSE
A review of the information contained in Enclosure 1 to IE Bulletin 79-05 and 79-05A was completed. A training session was conducted covering the points specified in items 1.a and 1.b for all operators, licensed and non-licensed, as well as plant management and supervisors with operation's responsibilities.
Documentation of this review and training session is available at the site.
Training personnel have been instructed to stress the importance of the points made in Item 1 of this bulletin in the operator training program.
QUESTION 2 Review the containment isolation initiation design and procedures, and pre-pare and implement all changes necessary to initiate containment isolation, whether manual or automatic, of all lines whose isolation does not degrade needed safety features or cooling capability, upon automatic initiation of safety injection.
(2)
RESPONSE
A review of Grand Gulf's containment isolation initiation design was per-formed to ensure that systems not needed for an ECCS injection vould isolate if an injection signal were present.
During this review (which excluded emergency core cooling and make-up systeus because of their needed safety features), it was determined that Grand Gulf's design provides the necessary containment and reactor coolant pressure boundary isolation prior to or simultaneous with initiation of emergency core cooling and safety injection sysr. ems in all areas except, plant service water and component cooling water.
Presently, these two closed systems contain check valves and remote-manually j
operated valves for containment isolation. The adequacy of the design for these two systems is currently under evaluation. Upon completion of therc evaluations, appropriate modifications will be made if deter =ined necessary.
Each of these systems forms a closed loop in the containment and do not have an open path to the containment atmosphere. This does not preclude the possi-bility of line f ailure in the containment but in light of the incident being reviewed, the present configuration appears to be adequate. The remainder of containment penetrations which did not involve lines needed to perform a safety function were determined to have the necessary isolation via an automatic isolation or due to the fact that valves on these lines are normally closed during operation.
Grand Gulf will have specific Operating Instructions for Containment Isola-tion which will include isolation criteria, step by step directions for completing all manual actions, and for verifying completion of all automatic actions required for containment isolation.
Isolation valves will remain shut even if the initiating signal clears until reset by the operator. Procedures will also include stepwise directions and precautions for resetting containment isolation signals and reopening lines penetrating the containment following an isolation event.
Q'JESTION 3 Describe the action, both automatic and manual, necessary for proper function-ing of the auxiliary heat removal systems (e.g., RCIC) that are used when the main feedwater system is not operable. For any manual action necessary, des-cribe in summary form the procedure, by which this action is taken in a timely sense.
RESPONSE
This response describes both automatic and manual actions necessary for proper functioning of the auxiliary heat removal systems. These systems are used when the main feedwater system is not operable. The procedures are described i
in summary form assuming the reactor is scrammed and isolated from the main i
condenser.
I Automatic action provides abundant make-up water to the core for initial cooling.
Long term core and containment cooling can be provided with few manual actions.
Information is available to the operator in the control room to assist him in taking the required manual actions. Information in the control room permits the operator to verify that the objective of these actions is being achieved.
(3)
The auxiliary heat removal systems provided to remove decay heat from the reac-tor core and contain=ent following loss of the feedwater systems are:
High Pressure Core Spray (HPCS) System Reactor Core Isolation Cooling (RCIC) System Low Pressure Core Spray (LPCS) System Residual Heat Removal (RHR) System Automatic Depressurization System The description that follows details the operation of the systems needed to achieve initial core cooling followed by containment cooling and then followed by extended core cooling for long term plant shut down.
Initial Core Cooling Following a loss of feedwater and reactor scram, a low reactor water level signal (level 2) will automatically initiate the HPCS and RCIC Systems into the reactor coolant make-up injection mode. The HPCS and RCIC systems will continue to inject water into the vessel until a high water level signal (Level 8) automatically trips the RCIC system and closes the HPCS injection valve.
Following a high reactor water level 8 trip, the HPCS injection valve will automatically re-open when reactor water level decreases to the low water level signal (level 2).
The RCIC system must be manually reset by the operator in the control room before it will automatically re-initiate af ter a high water level trip.
The HPCS and RCIC Systems have redundaat supplies of water. Normally they take suction from the condensate storage tank (CST), which maintains 170,000 gallons of condensate in reserve for use by HPCS and RCIC. The RCIC and HPCS Systems suction will automatically transfer from the CST to the suppression pool if the CST water level is low or the suppression pool water level increases to a high level.
The operator can manually initiate the HPCS and RCIC Systems from the control room before the level 2 automatic initiation level is reached. The operator has the option of manual control after automatic initiation and can maintain reactor water level by throttling system flow rates. The Operator can verify
~
that these systems are delivering water to the eeactor vessel by:
a)
Verifying reactor water level increases when systems initiate (see water level discussion in response to Question 4).
b)
Verifying system flow using flow indicators in the control room.
c)
Verifying system flow to the reactor by checking control room position indication of motor-operated valves. This assures no diversion of systam flow from the reactor.
.Therefore, the HPCS and RCIC systems can maintain reactor water level at full reactor pressure or until pressure decreases to where low pressure systems such as the Low Pressure Core Spray (LPCS) or Low Pressure Coolant Injection (LPCI) can maintain water level. If necessary, the operator can use one or more
. safety relief valves to depressurize the reactor.
1 4
(4)
Containment Cooling After reactor scram and isolation and establishment of satisfactorv core cooling, the operator would start contain=ent cooling. This m>;..f opera-tion removes heat resulting from safety relief valve discharge or RCIC turbtne exhaust to the suppression pool. This would be accomplished by placing the Residual Heat Removal (RRR) System in the containment (suppression pool) cooling mode, i.e., RHR suction from and discharge to the supression pool.
The operator could verify proper operation of the RHR syster containment cooling function from the control room by:
a)
Veridying RHR and Standby Service Water (SSW) System flow using system control room flow indicators.
b)
Verifying correct RER and SSW system flow paths using control room position indication of motor-operated valves.
c)
On branch lines that could divert flow from the required flow paths, closing the motor-operated val res and noting the effect on RER and SSW flow rate.
Even though the RRR is in the containment cooling mode, core cooling is its primary function. Thus, if a low low reactor water level (Level 1) or a high drywell pressure signal is received at any time during the period when the RER is in the containment cooling mode, the RHR system will automatically revert to the LPCI injection mode. The Low Pressure Core Spray (LPCS) sys-tem would automatically initiate and both the LPCI and LPCS systems would in-ject water into the reactor vessel if reactor pressure is below system dis-charge pressure.
Extended Core Cooling 6
When the reactor has been depressurized, the RHR system can be placed in the long term shutdown cooling mode. The operator manually terminates the con-rainment cooling mode of one of the RHR containment cooling loops.
In this operating mode, the RER system can cool the reactor to cold shutdown.
Proper operation and flow paths in this mode can be veriffad by methods sisi-lar to those described for the containment cooling mode.
QUESTION 4 Describe all uses and types of vessel level indication for both automatic and manual initiation of safety systems. Describe other redundant instrumentation which the operator might have to give the same information regarding plant status.
Instruct operators to utilize other available information to initiate safety systems.
(5)
RESPCNSE Reactor vessel water level is continuously monitored by 7 indicators or recorders for normal, transient and accident conditions. Those monitors used to provide automatic safety equipment initiation are arranged in a redundant array with two instruments in each of two or more independent electronic divisions. Thus, adequate information is provided to automati-cally initiate safety actions and provide the operator with assurance of the vessel water level at all times.
These water level measurement devices have operated in BWR Plants for 20 years.
Tests of BWR water level instrumentation under simulated steam and water line breaks have been conducted showing satisfactory performance.
The range of reactor vessel water level from below the top of the active fuel area up to to the top of the vessel is covered by a combination of narrow and wide-range instruments. Level is indicated and/or recorded in the control room.
A separate set of narrow-range level instrumentation on separate condensing chambers provides reactor level control via the reactor feedwater system. This set also indicates or records in the control room (three level indicators and one level recorder).
The safety-related systems or functions served by safety-related reactor water level instrumentation are:
Reactor Core Isolation Cooling System (RCIC)
High Pressure Core Spray System (HPCS)
Low Pressure Core Spray System (LPCS)
Residual Heat Removal / Low Pressure Injection (RHR/LPCI)
Automatic Depressurization System (ADS)0)
Nuclear Steam Supply Shutoff System (NS Standby Service Water System (SSW)
All systems automatically initate on low reactor water level. In addition, the RCIC and HPCS systems shutdown on high reactor water level. The HPCS sys-tem automatically restarts if low reactor level is reached again.
(See re-sponse to Question #3 for further discussion on this).
In the case of RCIC, manual resetting is required if the high reactor vessel water level trip is reached.
Additional instrumentation which the operator can use to determine changes in reactor coolant inventory or other abnormal conditions are:
Drywell High Pressure Containment High Radioactivity Levels Supression Pool High Temperature Safety Relief Valve (SRV) Discharge High Temperature High/ Low Feedwater Flow Rates High/ Low Main Steam Flow High Containment, Steam "annel, and Equipment Area Differential
. Temperatures High Differential Flow-Re. actor Water Cleanup System Abno mal Reactor Pressur-.
Rich Suppression Pool Wr.or Level High Dryvell and Contai: aent Sump Fill and Pumpeut Rate VJ;1ve Stem Leakoff Eigh femperatures
(6)
Low RCIC Stes= Supply Pressure High RCIC Steam Supply Flow Low Main Stes: Line Pressure An example of the use of this additional information by the operator is as follows: Drywell high pressure is an indirect indication of coolant loss.
. Coincident high suppression pool temperature further verifies a loss of reactor coolant. High SRV discharge temperature would pinpoint loss of coolant via an open valve.
Other instrumentation that can signal abnormal plant status but not necessari-ly indicative of loss of coolant are:
High Neucron Flux High Process Monitor Radiation Levels Main Turbine Status Instrumentation Abnormal Reactor Recirculation Flow High Electrical Current (Ampetes) to Recire Pump Motors Operators will be instructed in use of other available information to initiate safety systems as a continuing part of training.
Question 5 Review the action directed by the operating procedures and training instructions to ensure that:
a.
Operators do not override automatic actions of engineered safety features, unless continued operation of engineered safety features will result in unsafe p3'ut ca.dttions (e.g. vessel integrity).
b.
Operators are provided cdditional information and instructions to not rely upon vesse: level indication alone for manual actions, but to also examine other plant parereter indications in evaluating plaat conditions.
RESPONSE
All of this information will be specifically addressed in an Operations Section administrative procedure, which provides operators with guidelines for response to abnormal conditions. All Control Room Operat. ors will be required to demon-strate specific knowledge of this procedure.
(Additional information provided in response to Question 4 regartaing additional information provided to the operator.)
Additionally, all Operations Instructions " vill be written keeping the Three Mile Island events in mind. Peesonnel who are preparing operation and administrative procedures for the control of raintenance activities will be briefed on the TMI incident and methods to prncedurally avoid similar circumstances at Grend Gulf.
QUESTION 6 Review all safety-related valve positions, positioning requirements and positive controls to assure that valves remain positioned (open or closed) in a manner to ensure the proper operation of engineered safety features.
(7)
Also, review related procedures, such as those for maintenance, testing, plant and system startup, and supervisory periodic (e.g., daily / shift checks ) surveillance to ensure that such valves are returned to their correct positions following necessary manipulations and are maintained in their proper positions during all operational modes.
RESPOSSE A review of the emergency core cooling systems (ECCS) indicated that the system valves' positions are suitably controlled by the following means:
1.
Auto =atic actuation of power operated val-Jes within the system is provided to isolate the boundary / bypass paths and to align the system for proper operation. Main control room valve position indication is provided for these valves. The handswitches in the control room for these valves are spring return to the auto position to allow the valve to operate automatically if required.
2.
Manual valves within the main flow path are provided with locking pro-visions to ensure correct valve positions. Manual valves which are not accessible during power operation (i.e., located in drywell) are also provided with main control room position indicating lights.
3.
Manual valves on branch piping to the main flow path piping are provided with locking provisions if incorrect valve position could affect system safety function. Exceptions are the piping high point vents, low point drains, and test connection valves which are verified procedurally to be aligned properly for operation.
For the condensate storage tank piping to the suction of the HPCS and RCIC pumps, the manual isolation valve adjacent to the storage tank will be verified procedurally that it has been aligned properly.
For all other safety-related systems other than ECCS, the power operated valves have been equipped with handswitches having the spring return feature and have been equipped with position indication in the control room. The manual valves in these systems will be verified procedurally that they have been aligned properly. These manual valves are not equipped with position indication in the control room.
All system P&lDs havt been reviewed to verify that the valves are positioned correctly for proper operation of the safety-related system.
A revision to the Protective Tagging Procedure is being prepared to use minia-ture tsgs on control panels to avoid obscuring any active indicators on control I
panels.
The position of each manually operated valve will be identified in a valve line-up sheet. Valve line-up checks will be conducted as required by technical specifications to verify system flow paths. In addition, valve line-up checks will be conducted after each refueling outage and following any major work on a system. For safety reisted systems / components, this valve line-up will have independent verifications. Where appropriate, valves will be locked in the designated position to prevent inadvertent repositioning.
(8)
If valve positions are to be changed for surveillance purposes, the surveillance procedure will have steps requiring return to normal valve line-up prior to completion. Start and completion of surveillance proce-dures will be logged in the control room logbook.
When maintenance is performed on a safety related system which requires valves to be repositioned, administrative procedures governing conduct of maintenance will require:
1.
The approval.of the Shif t Supervisor prior to performing maintenance to allow the Shift Supervisor to verify redundant flow paths, etc.
prior to authorizing maintenance.
2.
The maintenance work documents to specify post-maintenance functiona) checks or operability tests to verify system return to normal follow-ing maintenance activities.
When possible, Operations will perform a. functional test or Surveillance Operability Test following maintenance on any safety related system. When such tests are not possible, a complete valve and electrical lineup will be performed within the tagged boundary and a partial functional test will be performed where possible to provide assurance that systems are in fact func-tional after maintenance.
System line-up changes, other than those covered by step-by-step procedures will be logged and abnormal line-ups will be covered during shif t turnover.
During periodic tours, Operators and Supervisory personnel will conduct spot checks of fluid system and electrical line-ups.
QUESTION 7 Review your operating modes and procedures for all systems designed to trans-fer potentially radioactive gases and liquids out of the primary containment to assure that undesired pumping, venting or other release of radioactive liquids and gases will not occur inadvertently.
In particular, ensure that such an occurrence would not be caused by the resetting of engineered safety features instrumentation. List all such sys-tems and indicate:
_e..
- e..
.,-.e.-
n..
.- =
(9) c.
Whether interlocks exist to prevent transfer when high radia-tion indication exists, and b.
Whether such systems are isolated by the centainment isolation
- signal, c.
The basis on which continued operability of the above features is assured.
RESPONSE
Th2 following systems are capable of pumping or venting potentially radio-activa fluids and gases from the containment:
1.
Clean-up systems 2.
Floor and equipment drains 3.
Fuel transfer tube 4.
Condensate and refueling water storage and transfer ed system 5.
Containment cooling system s
6.
Combustible gas control system (containment purge mode) 7.
Reactor sample lines a.
Of the systems listed above, only the combustible gas control system, and the containment cooling system isolate on a high radiation signal.
There are no direct high radiation interlocks on liquid transfer lines.
b.
All of the systems above are isolated by the Containment Isolation Control System except the fuel transfer tube, which is only used during refueling operations.
tent.
c.
Continued operability of the Containment Isolation Control is assured during all modes of plant operation. Power to the isola-tion and control logic is provided by emergency power supplies.
tam,
All isolation logic is de-energized to actuate, assuring isolation
- ally in the unlikely event of loss of power. In addition, each of these protective features is routinely calibrated and/or tested.
In cddition, the Operations Instructions f or Containment Isolation will doccribe how to reset isolation signals and establish specific flow paths during isolation to prevent inadvertent releases.
lu-
- h-QUESTION 8
!DC
- he Revisv and modify as necessary your maintenance and test procedures to ensure 3
that they require:
c.
Verification, by test or inspection, of the operability of n-redundant safety-related systems prior to the removal of int.
any safety-related system from service.
a sm-b.
Verification of the operability of all safety-related systems 8-when they are returned to service following maintenance or testing.
c.
Explicit notification of involved reactor operational personnel whenever a safety-related system is removed from and returned to service.
l
--...--.-..----..--~~n.
- ~
(11).
' Operating' instructions will be vritten'to adequately address all of the above modes' of operation.
OUESTION 11 Propose changes, as required, to those technical specifications which must
- be modified as a result of your implementing the items above.
RESPONSE
1 Grand Gulf has not yet submitted technical specifications,.however a draf t is'being prepared for submittal in 1980 keeping in mind the lessons learned from the Three Mile Island accident. Modifications to the draft will be
.made as necessary to implement the recommendations presented as a result of TMI.
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Mississippi Power & Light Company Grand Gulf Nuclear Station Units 1 and 2 (Docket Nos. 50-416 and 50-417)
Response to Bulletins and Orders Task Force Requests UNIOUE PLANT DATA I.
BYPASS CAPACITY Plant Steam Bypass capacity is 35% of rated steam flow.
II.
SYSTEMS AND COMPONENTS SHARED BETWEEN UNITS Shared Between Syste:n or Components Units Number SSW Basin A 1 and 2 SSW Basin B 1 and 2
- SSW "A" recirculation line 1 and 2
- SSW "B" recirculation line 1 and 2
- SSW "A" transfer line to Basin B 1 and 2
- SSW "B" transfer line to Basin A 1 and 2
- SSW Basin A and B blowdown line 1 and 2
- SSW Basin A and B chlorination line 1 and 2
- SSW Basin A and B chemical treatment line 1 and 2 A
- Each line interconnecting the two SSW pump discharge lines has redundant automatic isolation valves.
- Failure of the nonessential chlorination, chemical treatment, or blowdown subsystems will not prevent the SSW System from performing its safety function.
i I
~
-- s--
.t III. PLANT-SPECIFIC SYSTEM INFORMATION
~t INSTRUMENTATION SYSTEM CENERAL WATER SOURCES AND CONTHOL Safety Seismic Safety Seismic Safety Seismic Frequency of Sys-Class.
Category Class.
Category Class.
Category tem and Component Tests I.
RCIC 2
1 Note 2 I
2 I
Note 1 2
2.
Isolation Note 3 Condenser 3.
IIPCS 2
I Note 2 I
2 I
2 t'
4.
HPCI Note 3 5.
LPCS 2
I 2
I 2
I 6.
RilR-LPCI 2
I 2
I 2
I i
'7.
ADS 1
I Note 4 Note 4 2
I l
8.
SRV 1
I Note 4 Note 4 2
I l
9a. RilR Steam 2
I 2
I Note 6 Note 5 Condensing Other
~l 9b. RHR S D Cooling, 2
I 2
I 2
I Supp. Pool Cooling, and CtMT Spray Modes)
- 10. SSW 3
I Note 10 1
3 I
3
- 11. CCW Note 6 Note 5 Note 6 Note 5 Note 6 Note 5 l
Other Other Other
- 12. CRDS Note 8 I
Note 9 1
2 I
- j 2
2
- 13. CST Note 6 Note 5 Note 6 Note 5 Note 6 Note 5 other other other
- 14. Feedwater Note 7 I
Note 6 Note 5 Note 6 Note 5 l
Other other
.I
- 15. Recirculation Pump /MTR Cooling Note 3
't
III. PLANT-SPECIFIC SYSTEM INFORMATION l
1.
Grand Gulf Technical Specifications have not yet been approved.
2.
Alternate supply of water is from the suppression pool. The preferred source is from the non-j seismic, non-safety class CST.
RCIC and lipCS suction piping. f rom CST is Safety Class 2 and Seismic Category I.
3.
Not applicable to Grand Culf.
4.
Not applicable to this system.
5.
The seismic requirements for the safe shutdown earthquake are not applicable to the equipment.
6.
Safety Classification "other" d signates structures, systems, and components in the power conver-sfon or other portions of the facility which have no direct safety function but which may be connected to or influenced by the equipment within safety classes 1, 2, or 3.
- 7., the classification of the feedwater lines from the reactor vessel to and including the thitd l
isolation valve is Safe:v Class 1, beyond the third valve, the lines are safety class other j
(See Noce 6).
8.
HCU's, insert / withdraw piping, scram discharge volume. Remainder of CRDH system is other (Note 6) l and seismic category NA (Note 5) 9.
Scram accumulators and associated piping.
10.
SSW Cooling Towers and Storage basins.
'l i
f
IV.
CONTAINMENT ISOLATION VAINE INF0P.".ATION All of the requested information is found in the Grand Gulf FSAR (See GG-FSAR Table 6.2-44 and Figures 6.2-76 through 79) with the exception of the following:
A.
All of the valves listed in Table 6.2-44 are Seismic Class I.
B.
All valves listed in Table 6.2-44 have control room indication except for the following:
1.
F11E015 is N/A (Transfer Tube) 2.
321F010A 18.
E12F104B 3.
B21F010B 19.
G41F053 4.
E51F065 20.
G41F201 5.
E12F019 21.
P11F004 6.
E12F046A 22.
G41F040 7.
E12F046C 23.
E12F046B 8.
E51F040 24.
P11F041 9.
C11F122 25.
P53F006 10.
P44F043 26.
E12F025C 11.
P71F151 27.
E12F018 12.
PS2F122 28.
E12F036 13.
P53F002 29.
E12F005 14.
P42F035 30.
E12F055A 15.
E51F021 31.
E12F104A 16.
E12F055B 32.
E12F103A 17.
E12F103B 33.
P41F169A 34.
P41F169B C.
All valves listed in Table 6.2-44 are Quality Group B except for the following which are Quality Group A:
1.
B21F028A
~2.
B21F022A 3.
B21F067A 21.
E51F076-B 4.
-B21F028B 22.
E51F066 5.
B21F022B 23.
E51F065 6.
B21F067B 24.
E51F013-A 7.
B21F028C 25.
E12F023-A 8.
B21F022C 26.
E12F019 9.
B21F067C 27.
B21F019-A 10.
B21F028D
- 28. B21F016-B
- 11. B21F022D
- 29. E12F042A-A
- 12. 321F067D 30.
E12F041A
- 13. B21F032A
- 31. E12F042B-B
- 14. B21F010A 32.
E12F041B 15, B21F032B 33.
E12F042C-B 15.
B21F0105 34.
- 17. E12F008-A 35.
- 18. E12F009-B 36.
E22F005 19.
E51F063-B 37.
E21FC05-A 20.
- 38. E21F006
- 39. G33F001-B 40.
V.
DESIGN REQUIREMENTS FOR CONTAINMENT ISOLATION BARRIERS QUESTION Discuss the extent to which the quality standards and seismic design classi-fication of the containment isolation provisions follow the recommendations of Regulatory Guides 1.26, " Quality Group Classifications and Standards for Water, Steam, and Radioactive-Water-Containing Components of Nuclear Power Plants", and 1.29, " Seismic Design Classification".
RESPONSE
The design of the Containment Isolation system follows the recommendations of Regulatory Guide 1.26 and 1.29 as addressed in the Grand Cul: FSAR Appendix 3A.
VI.
PROVISIONS FOR TESTING QUESTION Discuss the design provisions for testing the operability of the isolation valves.
RESPONSE
Every automatic containment isolation valve is provided with a handswitch in the control room for remote manual operation. Every automatic containment iso-lation valve is provided with position indication in the control room. The majority of the containment penetration isolation valves can be operability tested f rom the control room during normal plant operation. Certain systems or valves cannot be (or should not be) tested during normal plant operation.
Examples of such valves are: 1) low pressure coolant injection valves cannot be opened when the reactor is at high pressure because a pressure permissive must be satisfied before the valve can be opened, 2) the outboard feedwater check valve cannot be closed during power operation because the exercising cylin-der does not provide enough force to close the valve when feedwater is in
. operation.
VII. CODES, STANDARDS, AND GUIDES QUESTION Identify the codes, standards, and guides applied in the design of the con-tainment isolation system and system components.
RESP 0NSE A.
The Containment Isolation system is designed in accordance with Seismic Category I requirements.
B.
Containment isolation valves and associated piping and penetrations meet the requirements of ASMI Code,Section III, Classes 1 or 2, as applicable.
C.
Containment isolation for system lines which can provide an open path from the containment to the environs during normal operation is in accordance with NRC Branch Technical Position CSB 6-4 " Containment Purg-ing During Normal Plant Operations".
D.
Application of Regulatory Guides are described in the Grand Gulf FSAR in Appendix 3A, and more specific applications of selected guides to the Containment Isolation System are discussed in FSAR Section 7.3.2.2.2.1.1.
E.
Containment Isolation Control System conformance to 10CFR50 Appendix A is discussed in FSAR Section 7.3.2.2.2.2.
F.
Containment Isolation Control System conformance to industry codes and standards is discussed in Section 7.3.2.2.2.3.
VIII. NORMAL OPERATING MODES AND ISCLATION MCDES QUESTION Discuss the nor=al operating modes and containment isolation provision and procedures for lines that transfer potentially radioactive fluids out of the containment.
RESPCNSE The response to the question is formated such that the following data is provided for each system line designation.
a.
Fluid being transferred b.
Normal operating mode (s) c.
Containment isolation provision (s)
The isolation signal codes for the alphabetic isolation signal symbols shown are provided at the end.
Any one of the isolation signal (s) shown for a line or group of lines will initiate closure of the isolation valves. Handswitches in the control room are provided for remote-manual control of every isolation valve; however, an isolation cannot be reopened remote-manually until all of the isolation signals have cleared.
1.
Nuclear Boiler - Main Steam Lines a.
Fluid being transferred Primary Coolant in the form of steam b.
Normal operating mode (s)
During normal plant operation, the main steam lines transt'er steam from the reactor vessel to the main turbine and auxiliaries.
c.
Containment Isolation Provision (s)
Redundant pneumatically operating y-pattern globe valves pro-vide containment isolation. There is a motor operated globe valve located in the drain line that is on the outboard valve.
These valves will close automatically upon receipt of isola-tion signals C, D, E, F. N and P 2.
Residual Heat Removal - Pump Suction Lines a.
Fluid being transferred Suppression Pool Water is transferred out of the containment during system operation (post-accident) or during system test and is then transferred back into the containment through a closed loop.
(VIII~Continu:d) b.
Normal operating mode (s)
During normal plant operation, these lines are inactive but with the isolation valves open c.
Containment Isolation Provision (s)
Motor-operated valves outside the containment (combined with a closed loop outside the containment) provide the necessary isolation. A handswitch in the control room controls the operation of the isolation valves.
3.
Residual Heat Removal (RHR) - Shutdown Cooling Suction a.
Fluid being transferred Reactor Coolant is transferred out of the containment to the RHR heat exchangers and then is returned by way of a closed loop outside containment to the reactor vessel.
b.
Normal operation mode (s)
During normal plant operations, the suction line is isolated.
During reactor shutdown this line is used to cooldown the reactor once the reactor vessel pressure is low.
c.
Containment Isolation Provision (s)
Motor Operated valves are provided inside and outside the containment. These valves will automatically close upon receipt of isolation signals A, U, and M.
4.
Reactor Core Isolation Cooling (RCIC) - Steam Supply to RER System and to RCIC Turbine a.
Fluid being transferred Reactor Coolant in the form of steam b.
Normal operating mode (s)
During normal plant operation, this line is pressurized with steam to maintain the line (and the RCIC system) in standby (quick start capability).
i c.
Containment Isolation Provision (s)
Motor operated gate and globe valves inside and outside the con-tainment provide the necessary isolat.on. These valves will j
automatically close when isolation signals J, K, and T are present.
l i.
(VIII Continu:d) 5.
Nuclear Boiler - Main Steam Line Drains a.
Fluid Being transferred Reactor coolant in the form of steam and/or water b.
Normal operating mode (s)
During normal plant operation, the isolation valves are normally open transferring steam and/or water as required to the main condenser.
c.
Containment Isolation Provision (s)
Motor operated gate valves inside and outside the contain-ment provide the necessary containment isolation. These valves will automatically close upon receipt of isolation signals C, D, E, F, N and P.
6.
High Pressure Core Spray (HPCS) - Pump Suction Line a.
Fluid being transferred Suppression pool water b.
Normal Operating Mode (s)
During normal plant operation, the system is inactive. During system operation (during a transient or accident), this valve will open when the condensate storage tank is lov.
c.
Containment Isolation Provision (s)
The suction line isolation valve (together with the closed loop of the system outside containment) provides the necessary containment isolation.
A handswitch is provided in the control room for operating this valve.
7.
Reactor Core Isolation Cooling (RCIC) - Pump Suction a.
Fluid being transferred Suppression Pool Water
'b.
Normal operating mode (s)
During normal plant operation, the pump suction line is inactive E
+
l
(V112 Continued) with the valve closed. When the RCIC is operating, the valve is also closed except when the condensate storage tank level is low, then this valve will open automatically c.
Containment Isolation Provision (s)
A motor operated gate valve (together with the system closed loop) outside containment provides the necessary containment isolation. A handswitch is provided in the control room to actuate the valve.
8.
Low Pressure Core Spray (LPCS) - Pump Suction a.
Fluid being transferred Suppression pool water is transferred out of the containment during system operation (post-accident) or during system testing and is then transferred back in to the containment through a closed loop.
b.
Normal operating mode (s)
During normal plant operation, the LPCS suction is inactive with the isolation valve open.
c.
Containment Isolation Provision (s)
A motor-operated valve outside the containment (combined with a closed loop outside the containment) provides the necessary isolation. A handswitch in the control room controls the operation of the isolation valve.
9.
Containment Cooling - Containment purge and ventilation air supply and exhaust a.
Fluid being transferred Air is moved into the containment, is mixed with the con-tainment atmosphere and is the discharged out of the containment.
b.
Normal operationg mode (s)
Usually during normal plant operations, these large lines (20" Dia.) are isolated. Less than 1% of the time, these valves will be open.
c.
Containment Isolation Provision (s)
The ventilation lines are equipped with air-to-open, spring-to-close butterfly valves that are located both inside and outside the containment. These valves vil close automatically when isolation signals B, G and 2 are present.
(VIII Continusd) 10.
Reactor Water Cleanup (RWCU) - Drain to Main Condenser a.
Fluid being transferred Reactor Water b.
Normal operating mode (s)
During normal plant operation, the containment isolation valves will be closed.
During plant startup, reactor level swell can be transferred out of the containment to the main condenser.
c.
Containment Isolation Provision (s)
Motor-operated gate valves located inside and outside the con-tainment provide the necessary containment isolation.
Isola-tion signals B, D, H, L, W, Y will initiate closure of the outboard isolation valve and isolation signals B, D H, L, Y vill initiate closure of the inboard isolation valve 11.
Reactor Water Cleanup (RWCU) - Backwash transfer pump discharge to spent resin tank i
a.
Fluid being transferred Water with 0.8" suspended solids by weight b.
Normal operating mode (s)
The isolation valves are normally closed. The valves are opened when transferring the spent resins to the tank which is outside the containment c.
Containment Isolation Provision (s)
Pneumatically operated (air-to-open, spring-to-close) gate valves are provided for containment isolation. These valves will auto-matically close when isolation signals B and G are present.
12.
Floor and Equipment Drains - Drywell and Containment Equipment and Floor Drains, and Chemical Waste Sump Pump Discharges.
a.
Fluid being transferred Water from equipment and floor drains and the chemical waste b.
Normal operating mode (s)
The valves are normally open but water is being transferred periodically (that is, to pump out the sumps)
~.
(Vill Continutd) i c.
Containment Isolation Provision (s)
Pneumatically operated (air-to-open, spring-to-close) gate valves provide the necessary containment isolation. The valves will close automatically when isolation signals B and G are present.
- 13. Reactor Water Cleanup (RWCU) - System Return to Feedwater a.
Fluid being transferred Reactor water b.
Normal operating mode (s)
These containment isolation valves are normally open to provide the system flow path out of the containmenc to the feedwater line which directs the fluid to the reactor vessel.
Containment Isolation Provision (s) c.
Motor operated gate valves provide the necessary containment isolation. These valves will close automatically when isola-tion signals B, D, H, L and Y are present.
14.
Condensate and Refueling Water Storage and Transfer Lines To and Fron Upper Containment Pool a.
Fluid being transferred Pool Water b.
Normal operating mode (s)
During normal plant operation, the isolation valves are locked closed.
During shutdown for refueling, these valves are opened to transfer pool water.
Containment Isolation Provision (s) c.
Locked closed manual gate valves provide containment isolation 15.
Fuel Pool Cooling and Cleanup - Upper Containment Pool to Fuel Pool Drain Tank a.
Fluid being transferred Pool Water b.
Normal Operating Mode (s)
The containment isolation valves are opened or closed as re-quired to permit the transfer of the pool water during cleanup of the upper containment pool.
~ ~ ~
~ ~~
(VIII Continu:d) c.
Containment Isolation Provision (s)
Motor operated gate valves provide the necessary containment isolation. These valves will close automatically when isola-tion signals B and G are present.
16.
Containment Cooling - Purge air to containment exhaust charcoal filter train and from outside air supply a.
Fluid being transferred air b.
Normal operating mode (s)
The valves are normally open during plant operation to provide a flow path for the low volume (500 SCFM) purge c.
Containment Isolation Provision (s)
Pneumatically operated (air-to-open, spring-to-close) butterfly valves provide the necessary containment isolation. These valves will automatically close when isolation signals B, G and Z are present
- 17. Condensate and Refueling Water Storage and Transfer - Refueling Water Transfer Pump Suction a.
Fluid being transferred Suppression Pool Water b.
Normal operating mode (s)
During normal plant operation, the line is opened to provide the flowpath for suppression pool cleanup system operation c.
Containment Isolation Provision (s)
Pneumatically operated (air-to-open, spring-to-close) butterfly valves provide the necessary containment isolation. These valves will automatically cicae when isolation signals B and C are pre-sent.
- 18. Reactor Water Cleanup (RWCU) - Pump Suction a.
Fluid being transferred Reactor Water b.
Normal Operating Mode (s)
During normal plant operation, the pump suction is open to provide
~
' ~
(VIII Continu d)'
a flow path for this system out of the containment to the RWCU pumps c.
Containment Isolation Provision (s)
Motor operated gate valves provide the necessary containment isolation. The inboard isolation valve will close automati-cally when signals B, D, H, L and Y are present; the outboard isolation valve will close automatically when signals B, D, H, L, W and Y ere present.
1 I
i i
1 4
L F
t:.
G..
- - ~ + -
~+-~+- -* - - - -
-, -.i.....
ISOLATION SIGNAL CODES Signal Description A*
Reactor vessel low water level - level 3.
(A scram occurs at this level alse. This is the highest of the three isolation low water level signals.)
B*
Reactor vessel low water level - level 2.
(This is the second of the three low water level signals.
(The RCIC and HPCS systems are initiated at this level.)
C*
Reactor vessel low water level - level 1.
(This is the lowest of the three water level signals, and main steam line isolation occurs at this level. THe LPCS and LPCI systems are also initiated at this level.)
D*
High radiation - main steam line E*
Line break - main steam line (steam line high steam flow)
F*
Line break - main steam line (steam line high space or high differential temperature)
G*
High dryvell pressure i
H*
Line break in reactor water cleanup system -
(high space temperature)
J*
Line break in RCIC system steam line to turbine (low steam line pressure)
K*
Line break in RCIC system steam line to turbine (high steam line space temperature, or high steam flow)
L*
High differential flow in the reactor water clean-up system M*
Line break in RER shutdown and head cooling (high space temperature)
N*
Low main condenser vacuum
ISOLATION SIGNAL CODES (Cont.)
P*
Lov main steam line pressure at inlet to turbine (RUN mode only)
T High pressure RCIC turbine exhaust diaphragm U
High reactor vessel pressure - Close RER -
shut down cooling valves and head cooling valves W
High temperature at outlet of cleanup system non-regenerative heat exchanger Y
Standby liquid control system actuated Z*
High radiation, containment and drywell ventila-tion exhaust RM*
Remote manual switch from control room (All automatic initiated isolation valves are capable of remote manual operations from the control room)
- These are the isolation functions of the containment, and reactor vessel isolation control system; other functions are given for information only.
~
(ATTACE{CC 3)
Mississippi Power & Light Company Grand Gulf Nuclear Station Units 1 and 2 (Docket Nos. 50-416 and 50-417)
Response to Bulletins and Orders Task Force Requests For Additional Information Concerning NEDO-24708 Question Set D QUESTION 1 With regard to Tables 2.1.4a thru 4.1.4n which provide a description, in matrix form, of system initiation, permi-sives, manual valve lineups, etc.
it is noted that additional valves installed by AE are not included. These Tables should be complete. Furthermore are they administratively controlled?
RESPONSE
The statement that additional valves installed by AE are not included is not applicable for Grand Gulf. All valves were included in the analysis for Grand Gulf. Furthermore, all valves are administratively controlled.
QUESTION 2 Discrepancy between Table 2.1-1 and 2.1-2b regarding existence of FWCI for Dresden 1.
RESPONSE
Not applicable for Grand Gulf.
QUESTION 3 In Figures 2.1.2 & 2.1.5, why are turbine stop valves and control valves shown open for RCIC and closed for EPCI System?
RESPONSE
These figures are not applicable for Grand Gulf.
QUEFTION 4 Table 2.1-2a under items 1-4, 4-4, and 14-4, it is noted that some plants require on-site AC power for small break protection. Prolonged operation of RCIC & HPCI can require AC powered space coolers. The following infor-nation is required:
(a) How long can these systems operate without space coolers?
(b) What is operating temperature Ibnit w/o coolers?
(c) Power source for coolers (d) What specific components in each system require cooling and temperature limitation on component?
_ _ _-. 7 _.__
.__u--
=. _
(Attechment 3 Continuid)
RESPONSE
a)
Minimum 29 minutes, Not applicable Indefinite possibly longer' for Grand Gulf b) 148 F @ 100% Relative humidity for RCIC; unknown for Main F.W. Sys.
c)
RCIC: Class IE AC Power (Division I)
HPCI: Not applicable Main F.W. Sys. :
(Cooled by turbine building general area fan coil Units): Onsite - AC Power d)
RCIC: The temperature limiting component in the RCIC room is not known.
All equipment in the room is designed to meet the above temperature specification given in b.
Main F.W. pumps - unknown QUESTION 5 Table 2.la Item 14-3, Why doesn't CST require power for level indication?
RESPONSE
CST Level indications are powered from on site AC and on site DC.
QUESTION 6 Table 2.1-2a Items 1-8, 2-8, 3-8, 4-8, 5-8, 6-8, 9-8 identify auxiliary systems that may require cooling for long-term operation. Answer questions 4a-d with regard to auxiliary systems.
RESPONSE
ITEM SYSTEM COOLING EOUTPMENT 1-8
.RCIC RCIC Room Cooler 2-8 Isolation Con-Not Applicable denser 3-8 HPCS HPCS Room Cooler 4-8 HPCI Not Applicable 5-8 LPCS LPCS Room Cooler 6-8 LPCI*
RHR A, B, or C Room Cooler as applicable RHR A Room Cooler 9-8 RHR A RHR B Room Cooler RER B RER C RHR C Room Cooler SSW Pumps - SSW Pump House Cooling Fans
- Available as a mode of RER A 3, or C
(Attcchment 3 Continu:d) a)
RCIC - min. 29 minutes, possibly longer Isolation Condenser - N/A RPCS - min. 4.1 minutes, possible longer HPCI - N/A LPCS - min 9 minutes, possibly longer LPCI* - RERA - min.10.3 minutes, possibly longer RHR3 - min. 10.3 minutes, possibly longer RHRC - min.15.6 minutes, possibly longer RHRA - min. 7.7 minutes, possibly longer RHR3 - min. 7.7 minutes, possibly longer RHRC - min.15.6 minutes, possibly longer SSW - min. 1.2 minutes, possibly longer
- Availaba as a Mode of RHR A, B, or C b)
RCIC, HPCS, LPCS, LPCI*, RHRA, RER3, RHRC - 148 F @ 100*
Relative Humidity SSW - 1040 F, possibly higher
- Available as a mode of RER A, B, or C.
c)
RCIC - Class IE AC Power (Division I)
Isolation Condenser - N/A HPCS - Class IE AC Power (Division III)
HPCI - N/A LPCS - Class IE AC Power (Division I)
HPCI* - RHRA - Class IE AC Power (Division I)
RERS - Class IE AC Power (Division II)
RHRC - Class IE AC Power (Division II)
SSW Pumphouse: Basin A - Class IE AC Power (Division I)
Basin B - Class IE AC Power (Division II) d)
RCIC, HPCS, LPCS, LPCI*, RHRA, RHRB, RHRC - the temperature limiting com-ponent in these rooms is not known. All components in each room is design-
- ed to meet the above temperature specification given in b.
SSW Pumphouse - Rated temp. rise of SSW pump motors QUESTICN 7 Table 2.1-2a Item 14-8.
What are requirements for feed pump ventilation system? Answer questions 4A-d with regard to this system.
RESPONSE
Feed Pump Ventilation System is not applicable to Grand Gulf.
1
(Attcchment III Cantinu;d)
QUESTION 8 Table 2.1-2a column 9b power source list is incomplete. Should identify AC requirements and if on-site or off-site, i.e., power source for auxiliary systems not identified.
RESPONSE
See the attached modified page from Table 2.1-2a which has been changed to reflect Grand Gulf System Design Information in response to this question.
Column 8b shows the power source for auxiliary systems; and column 9b shows the power source for automatic startup logic. Power sources for pump room coolers is provided with the response to Question 6.
QUESTION 9 Table 2.1-2a and 2.1-2b Column 11, manual actions required and how long they take is a short-term item that was not addressed.
RESPONSE
Column 11 should be headed '>bnual Initiation of the System Done in the Control Room. If not, what actions are required and how long do they take*?
In a meeting with the BWR Owners Group (7/12/79 in San Jose, California) NRC indicated that what was desired was the manual actions outside the control room. Actions performed in the control room are accomplished in a very short period of time (=-1 min.).
1
Tablo 2.1-2s (Nodified)
SYSTEM DESIGN INFORMATION - CRAND CULF 8a 8b 9a 9b Auxiliary Systems Required System for Operation Power Source Automatic Startup lo g hver Source X-8 Note X-9a
- 1. RCIC None (Note 1-8)
N/A la Level 11 0, lx2x2 On Site DC 2
'2.
Isolation System is N/A for Crand 1
Condenser Gulf a
- 3. HPCS None (Note 1-8)
N/A Lo level 11 0, Ix2x2 On Site DC 2
Hi Drywell, lx2x2 9
- 4. HPCI System is N/A for Crand Gulf
- 5. LPCS None (Note 1-8)
N/A Lo Level 11 0, Ix2x2 (hi Sit e DC 2
111 Drywell Pres., Ix2x2
- 6. LPCI None (Note 1-8)
N/A lo Imvel 11 0, Ix2x2 on Site DC 2
111 Drywell Press., Ix2x2 lo Level 1I 0, 2x2 or 2x2 On Site DC
- 7. ADS None N/A 2
111 Drywell Press., 2x2 or 2x2 (Note 7-9a)
- 8. SRV None N/A N/A N/A t
- 9. RHR - incl.
Standby service water On Site AC N/A (Note 9-9a)
N/A
- shutdown, (Note 1-8) l cooling, sta.
I, cond., supp.
pool cooling, cont. spray modes b
- 10. SSW None (Note 1-8)
N/A Lo Level 11 0, lx2x2 On Site DC 2
111 Drywell Press lx2x2 R!IR Pump Start LPCS Pump Start Diesel Cen. Start l
RCIC Turbine Start i
Tcbis 2.1-2s (Modified)
SYSTEM DESIGN INFORMATION - CRAND CULF 8a 8b 9a 9h Auxiliary Systems Required System for Operation Power Source Automatic Startup Ingic Power Source X-8 Note X-9a i
- 11. CCW Plant Service Water Off Site AC N/A N/A j
(Note 1-6)
- 13. CST None N/A N/A N/A i
- 14. Main Fd.
Condensate. TBCCW, Plant Off Site AC N/A N/A Wtr. Sys.
- 15. Recircu.
System is N/A for Grand j
Pump / Motor Gulf Cooling Sys.
I 4
I i
i t
1
(Attachment 3 Continued).
QUESTION 10 Table 2.1-2a Column 12, there appears to be an inconsistency between note I-12 which states that logic system functional tests and surveillance testing of systems may impede systems for auto initiating and response as given in Column 12.
RESPONSE
For RCIC, HPCS, LPCS, LPCI and other modes of RHR, the system may be made temporarily inoperable during logic system testing. The logic system test may prevent auto-initiation of the system. Howevor, automatic features indi-cate this loss of system availability to the operator, and administrative pro-cedures do not allow simultaneous testing of more than one ECCS logic systen.
Once the ECCS auto-initiation signal has been received, the ECCS mode will over-ride any other mode of the system in ef fect at time of initiation.
QUESTION 11 Table 2.1-2a Column 13, inconsistency between response and notes. Plants for which cperation is performed should be identified. Also for ADS doesn't operator eventually have to close ADS valves?
RESPONSE
Attached is a modification of Column 13 from Table 2.1-2a showing system design information applicable to Grand Gulf.
No operator action is required to close the ADS valves.
-.----- i+
,,..; J e---.
s...
^' '
+
Table 2.1-2a (Modiff.ed)
SYSTEM DESIGN INFORMATION - GRAND GULF Actions Pe ormed by the Operator for System Operation and Control after Initiation of the-System System Within Two Hours 1.
RCIC None (Note 1-13) 2.
Isolation Condenser System N/A for Grand Gulf 3.
HPCS None (Note 3-13) 4.
HPCI System N/A for Grand Gulf 5.
LPCS None (Note 5-13) 6.
LPCI None (Note 6~-13) 7.
ADS None 8.
SRV None 9.
RHR-incl. shutdown
'N/A (Note 9-9a)
Cooling, Stm.
(Note 9-13)
Cond., supp. Pool Cooling, Cont. Spray modes.
10.
SSW None (Note 10-13)
- 11. CCW N/A 12.
CRDS (Note 12-13)
- 13. CST N/A
~
- 14. Main Feedvater Systern N/A
- 15. Recire. Pump / Motor System N/A for Grand Gulf Cooling System i
Table 2.1-2a (Modified)
SYSTDi DESIGN INFORMATION - GRAND CLIF COLL'MN 13 - NOTES 13 RCIC flow is manually controlled ~once level recovers. If RCIC trips, turbine must be reset locally.
3-13 Injection valve closes on hi Reactor Water Level if hi Drywell pressure is cleared. Reopening requires Reactor Lo Water Level or valve switch to open.
5-13 LPCS Flow is manually controlled once level recovers.
6-13 LPCI flow is annually controlled once level recovers. LPCI Heat Exchange Bypass Valve can be closed after 10 min time delay.
9-9a BWR 6 has automatic initiation of containment spray on high contain-ment pressure.
9-13 Containment spray requires manual shutdown. Suppression Pool Cooling may be needed about ils hours later.
10-13 Manipulations required to prevent crosstie to other systems on re-gaining offsite power.
12-13 Verify control rods full in.
t-I m s w a-ass
.w-
.e.<m.e...mne e
e
-~.,77
(Attcchment 3 Continuid)
QUESTION 12 Table 2.1-2a & 2.1-2b Column 17c. Identify size debris strainer will allow to pass instead of just starting strainer size is coarse.
RESPONSE
Attached is a modification of column 17 a, b, and c from Table 2.1-2a showing System Design Information applicable to Grand Gulf.
- QUESTION 13
. Table 2.1-2a, for note X-24 clarify what is meant by indirect indication on manual valves. Also identify which plants comments applicable to.
RESPONSE
This note is not applicable to Grand Gulf.
QUESTION 14 Table 2.1-2a, there appears to be an inconsistency between "no" responses in Column 25 and Note X-25.
RESPONSE
This note is not applicable to Grand Gulf.
QUESTION 15 Table 2.1-2a, Column 26, identify other means of detecting leaking SRV.
RESPONSE
A leaking SRV may also be detected by an increasing suppression pool temperature.
W' N MMW 9W*
Whe
_-.W#69efe #
d9 N e pwe = w eg m a wew. e g o g g g gg.g,
y,,
.w
~
Table 2.1-2a (Modified)
SYSTEM DESIGN INFORMATION - GRAND GULF 17a 1,7_b, 17c b
Strainers Strainer Strainer Systen in System Location Size 1.
RCIC Yes Suppression Pool 0.1" opening Suction 2.
Isolation Condenser (System N/A to Grand Gulf) 3.
HPCS Yes Suppression Pool 0.1" opening Suction 4.
HPCI-(System N/A to Grand Gulf) 5.
.LPCS Yes Suppression Pool 0.1" opening Suction 6.
LPCI Yes Suppression Pool 0.1" opening Suction 7.
ADS N/A N/A N/A 8.
SRV N/A N/A
%l.'
9.
RHR - incl. shut-Yes Suppression Pool 0.1" opening down cooling, stm.
Suction supp. pool cooling, cont. spray modes 10.
SSW No N/A N/A
- 11. CCW No N/A N/A
- 12.. CRDS No N/A N/A
- 13. CST No N/A N/A
- 14. Main Feedwater Yes Turbine Bldg. Coarse /60 mesh
. System (Note 14-17a)
(Note 14-17b)
- 15. Recire pump /
(System N/A to Grand Gulf) motor cooling system
......~; -----
a:
Table 2.1-2a (Modified)'
SYSTEM DESIGN'INFORMATION - GRAND GULF -
! Column 17 - Notes 9
Coarse screens are located in condenser 14 - 17a i
on condensate pumps suction lines.. Also j
14 - 17bJl-strainers located in condensate cleanup
. system.
9 6
s 3
h
+
.L
-g l
l 1
e 9.. C.
- 4... - U4
-O
-.--.J
, _ _.. e4..
(Attcchment 3 Continusd)
QUESTION 16 Table 2.1-2a, and 2.1-2b, response incomplete. Would like to know plants that perform independent procedure verification and which do physical verifica-tion and if there is any significant dif ferences in performance.
- RESPONSE Note X-28b would read as follows to apply to Grand Gulf:
X-28b - Operations personnel are required to perform an independent verification by physically checking all test line ups and restoration to normal for all safety systems.
_UESTION 17 Q
Table 2.1-1 shows Dresden I does not have ADS or FWCI. Table 2.1-2b indicates it does. Also Table 2.1-1 shows HB does not have LPCI, Table 2.1-2b indicates it does.
RESPONSE
Not applicable to Grand Gulf QUESTION 18 Table 2.1-2b, note 2-8, how long can isolat n condenser remove heat without makeup?
RESPONSE
Not applicable to Grand Gulf QUESTION 19 Table 2.1-2b, Column 9a, why does core spray have to be operating to use ADS for Humboldg Bay?
RESPONSE
Not applicable for Grand Gulf QUESTION 20 Table 2.1-2b, Column 13 and 15b: What is meant by N/A for operator action under FWCI? Also not 4-15b -missing.
RESPONSE
Not applicable for Grand Gulf
+%e,+
e-
... - +
(? ' ~
_ Attcchment 3 Continu2d)
(
QUESTION 21 Table 2.1-2b column 15c, why is there no dedicated capacity specified~for HPCI?
RESPONSE
Not applicable for Grand Gulf ~
QUESTION 22-Table 2.1-2b, Column 13, isn't _ operator action required to close ADS valves?
Also, why is operator action under FWCI for D-1 not' applicable?
RESPONSE
Operator action is not required to close ADS valves. FWCI is N/A for Grand Gulf.
QUESTION 23 Tables 2.1-4 for systems such as LPCI, LPCS and HPCS. Are there no trips on component malfunctions,' i.e., high pump bearing temperatures or loss of coolant to pump bearing.
RESPONSE
See attached modification of Tables 2.1-4c, 2.1-4f, and 2.1-4G showing informa-tion applicable to Grand Gulf.
1 I
....., _... ~....,
Tcblo 2.1-4c (Modified)
HICH PRESSURE CORE SPRAY SYSTEM (IIPCS)
(APPLIES TO CRAND CULF)
Degraded Conditions 1_siit t iation Permissive Trip Conditions Reduced Capacity Inoperable Comments
. Reactor Vessel
. None System Trips
. Return line to
. logic power
. This is a single channel Level Trip
. Reactor Vessel suppression failure system.
. High Drywell water level pool open
. Pump mtr.
Pressure
. Manual Trip Return line to power failure
.. Manual Diesel Trips condensate (off-site + diesel)
Initiation (Any operating storage tank
. Complete pipe Condition) open blockage
. Overspeed at 105%. Relief valve *
. Condensate storage Manual switch suppression,
tank empty and trans-l (Brkr control) return open fer to suppression Three phase fault pool blocked (differential relay)
Motor Trips Overcurrent l
Overfrequency i
i h
t 1
s 9
3
~
Tablo 2.1-4f (Modified)
LOW PRESSURE CORE SPuY SYSTEM
. l' (APPLIES TO GRAND GULF)
Degraded Conditions j
_ Initiation Permissive Trip Conditions Reduced Capacity Inoperable Comments
. Iow Vossal '
. Reactor System Triy Bypass test line loss of off This is a single Water Imvel Pressure
. Manual switches to suppression site power division system
. High Drywell low Motor Trip pool open
+ diesel gen-Pressure
. Overcurrent Safety valve erator failure
'. Manual
. Ground open to Complete flow blockage Initiation ESF bus load suppression shedding pool Logic power failure i
?
a i
i e
O
~
j Tablo 2.1-4g (Modified) i LOW PRESSURL COOI. ANT INJECTION SYSTEM (MODE OF RilR)
}
(APPLIES TO CRAND CULF)
Degraded Conditions
- Initiation Permissive Trip Conditions Reduced Capacity, Inoperable Comments
. liigh Drywell
. Reactor low System Trip
. Single Pump trip. Motive power
. This is Pressure pressure
. Manual' switches
. Injection valves failure in both a two divisional redundant
. Peactor Water Motor Trip not opening divisions (off-system. Either system is Low Level Trip
. Containment /
site + diesei) capable of providing f
. Manual Switches
. Ground spray cooling-
. Complete flow sufficient core cooling i
. ESF bus load valves not closing blockage requirements, i
shedding
. Min. flow bypass. Loop selection valve not closing failure, if
. Divisional motive applicable l
power failure (offsite + diesel) i
. Divisional logic power bus failure
. Test return line i
to suppression j
pool open I
i
~
.I 1
i t
t i
i
(Attachm:nt 3 Continu2d)
QUESTION 24 Table 2.1-4d,- what is source of auto isolation signal identified under trip conditions?
, RESPONSE Not applicable for Grand Gulf QUESTION 25 Table 2.1-4m&n identify turbine and pump protection trips. Table 2.1-4m
- under degraded conditions, reduced capacity, what.is significance of term "Open"?
RESPONSE
See attached modification of Table 2.1-4N-1 showing information applicable to Grand Gulf.
The term "open" is not applicable to Grand Gulf QUESTION 26 Table 2.1-Se, since Dresden I will not become operational without HPCI, shouldn't table reflect this? Also, FWCI should be included.
RESPONSE
Not applicable to Grand Gulf QUESTION 27 Table 2.1-5g & 2.1-51.
One diesel generator out of service missing from matrix.
RESPONSE
Not applicable to Grand Gulf f
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- - - - - ~ ~
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~-
1 i
Tabla 2.1-4N-1 (Modifitd) l FEEDWATER CONTROL SYSTEM (TUBRINE DRIVEN PUMP)
.j (APPLIES TO CRAND CULF)
Degraded Conditions
{-
Initiation Pe rmissive Trip Conditions Reduced Capacity Inoperable Comments
, Continuously
. Main
. Reactor vessel
. One of two
. Power Failure
. This is a non '
operates condenser
- level trip injection lines a) logic essential system I
~
acuum
. Turbine and becomes blocked b) loss of off-pump protection. Restricted site power trips steam line. flow. Condensate pumps or
. Manual to turbine condensate booster i
. Lack of manual pumps not operating'
. Low bearing oil reset inhibits
. Complete flow blockage pressure (pump automatic func-or turbine) tion i
. Low condenser I
vacuum
-j
. Thrust bearing j
wear l
. Pump suction
(
pressure low i
. Pump discharge pressure high e
I
. Pump flow low (less than minimum recirc).
1 i
1 1
4 I
t i,
E i
1
(Attrchment 3 Continutd)
QUESTION 28 Table 2.1-Sj. For Humboldt Bay does one or both ADS valves have to be out of service for plant to be shutdown
RESPONSE
Not applicable to Grand Gulf
' QUESTION 29 Table 2.1-4b.
Under inoperable status failure to manually reset to start on-low water level not included.
RESPONSE
Not applicable to Grand Gulf QUESTION 30 Table 2.1-2a, Column 8.
Isn't service air required as an auxiliary system to operate the main feedwater system?
RESPONSE
Instrument air is used to close the minimum flow recire valves and to operate the Startup Bypass Valve and Cleanup recirculation valve.
QUESTION 31 Table 2.1-2b, Column 9.
Does AC refer to on-site?
RESPONSE
Not applicable to Grand Gulf QUESTION 32 Table 2.1-2a, Column 16d. For small break is AWS required for manual opera-tion of backup water source sufficient to prevent core uncovery if HPCI or HPCS not available?
RESPONSE
This question is currently being reviewed by General Electric and the owners group as a part of emergency procedure guidelines.
Operator guidelines will be prepared regarding ADS initiatinn to ensure adequate core cooling.
QUESTION 33 Rad monitor for isolation condenser.
RESPONSE
Not applicable for Grand Gulf
.--.....-~,-.....n-----..n--.
(Attachm nt 4)
Mississippi Power & Light Company Grand Gulf Nuclear Station Units 1 and 2 (Docket Nos. 50-416 and 50-417)
Response to Bulletins and Orders Task Force Requests For Additional Information Concerning NEDO-24708 Question Set E QUESTION 1 According to section 3.1.1.1.2.1.6 of NEDO-24708, LPCS or LPCI must be throttled by the operator, for some plants, to insure adequate NPSE.
Can these lines be orificed to achieve the same goal without compromising the adequacy of the -system (s)? What are the consequences of not throttling?
RESPONSE
Not applicable for Grand Gulf.
QUESTION 2 Notes 5-8, 6-8 and 9-8 for Table 2.1-2a state that some plants require lube oil and seal cooling. Which plants does this refer to?
RESPONSE
Not applicable for Grand Gulf.
QUESTION 3 With regard to Table 2.1.4a thru 2.1.4n which provide a description, in matrix form, of system initiation, permissives, manual valve lineups, etc.,
it is noted that additional valves installed by AE are not included. These Tables should be complete.
Furthermore are they administratively controlled?
RESPONSE
The statement that additional valves installed by AE are not included is not applicable for Grand Gulf. All valves were included in the analysis for Grand Gulf. Furthermore, all valves are administratively controlled.
QUESTION 4 Table 2.1-2a under Items 1-4, 4-4, and 14-4, it is noted that some plants require on-site AC power for small break protection. Prolonged operatior.
of RCIC & RPCI can require AC powered space coolers. The following infermation is required:
(a) Hov long can these systems operate without space coolers?
(b) What is operating temperature limit w/o coolers?
(c) Power ' source for coolers j
(d) What specific components in each system require cooling and temperature limitation on component?
.. ~.. -..
.n-.
(Attechment 4 Continutd)
RESPCNSE a)
RCIC HPCI Main F. W. System Minimum 29 minutes, Not applicable Indefinite possibly longer for Grand Gulf b) 14Ts F @ 100% Relative humidity for RCIC. Unknown for Main F. W. System.
0 c)
RCIC: Class IE AC Power (Division I)
HPCI: Not Applicable Main F. W. Sys.:
(Cooled by Turbine Building General Area Fan Coil Units):
On Site - AC Power d)
RCIC: The temperature limiting component in the RCIC room is not known.
All equipment in the room is designed to meet the abova te=perature speci-fications given in b.
Main F. W. pumps: unknown QUESTION 5 Table 2.1-2a Items 1-8, 2-8, 3-8, 4-8, 5-8, 6-8, 9-8 identify auxiliary systems that may require cooling for long-term operation. Answer questions 4a-d with regard to auxiliary systems.
RESPON3E ITEM SYSTEM COOLING EQUIPMENT 1-8 RCIC RCIC Room Cooler 2-8 Isolation Condenser Not Applicable 3-8 HPCS HPCS Room Cooler 4-8 HPCI Not Applicable 5-8 LPCS LPCS Room Cooler 6-8 LPCI*
RER A, B or C Room Cooler, As Applicable RHR B RER B Room Cooler RER C RHR C Room Cooler SSW Pumps SSW Pumphouse Cooling Fans
- Available as a Mode of RHR A, B, or C.
a)
RCIC - min. 29 minutes, possibly longer ISO. Condenser - N/A HPCS - min. 4.1 minutes, possibly longer HPCI - N/A LPCS - min. 9 minutes, possibly longer '
LPCI* - RER A - min. 10.3 minutes, possibly longer l
(Attcchment 4 Continu;d)
RHRB - min. 10.3 minutes, possibly longer RRRC - min. 15.6 minutes, possibly lorger RHRA - min. 7.7 minutes, possibly longer RHRB - min 7.7 minutes, possibly longer RHRC - min. 15.6 minutes, possibly longer SS'4. min.1.2 minutes, possibly longer
- Available as a Mode of RHR A, B, or C b)
RCIC, HPCS, LPCS, LPCI*, RHRA, RHR3, RHRC - 1480 F @ 100%
Relative humidity SS'4 - 1040 F, possibly higher
- Available as a mode of RER A, B, or C.
c)
RCIC - Class IE AC Power (Division I)
Isolation Condenser - N/A HPCS - Class IE AC Power (Division III)
HPCI - N/A LPCS - Class IE AC Power (Division I)
HPCI* - RHRA - Class IE AC Power (Division I)
RERB - Class IE AC Power (Division II)
RERC - Class IE AC Power (Division II)
SSW Pumphouse: Basin A - Class IE AC Power (Division I)
Basin B - Class IE AC Power (Division II) d)
RCIC, HPCS, LPCS, LPCI*, RHRA, RHRB, RERC - the temperature limiting com-ponent in these rooms is not known. All components in each room is design-ed to meet the above temperature specification given in b.
SS'4 Pumphouse - Rated temp rise of SS'4 pump motors.
l i
l l
m --,--.,
. w.
(Attechment 4 Continurd)
QUESTION 6 Table 2.1-2a column 9b power source list is incomplete. Should identify AC requirements and if on-site or of f-site, i.e., power source for auxiliary systems not identified.
RESPONSE
See the r.tached modified page from Table 2.1-2a which has been changed to re-flect Grand Gulf System Design Information in response to this question. Column 8b shows the power source for auxiliary systems; and column 9b shows the power source for automatic startup logic. Power sources for pump room coolers is provided with the response to above question.
QUESTION 7 Table 2.1-2a and 2.1-2b column 11, manual actions required and how long they take is a short term item that was not addressed.
RESPONSE
Column 11 should be headed " Manual Initiation of the system Done la the Control Room. If not, what actions are required and how long do they take".
In a meeting with the BWR owners group (7/12/79 in San Jose, Cal.) NRC indica-ted that what was desired was the manual actions outside the control room.
Actions performed in the control room are accomplished in a very short period of time 0 /1 min.).
QUESTION 8 Table 2.1-2b. note 2-8, how long can insolation condenser remove heat without make up?
RESPONSE
Not applicable to Grand Gulf QUESTION 9 Tables 2.1-4 for systems such as LPCI, LPCS, and HPCS. Are there not trips on component malfunctions, i.e., high pump bearing temperatures or loss of coolant to pump bearing.
f r
- - ~,-,..-., - -. n... w.,.
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t I
Tcbla 2.1-2m (Modiffid)
SYSTEM DESIGN INFORMATION - CRAND CULF i.
8a 8b 9a 9h Auxiliary Systems Required System for Operation Power Source Automatic Startup Ingic Power Source X-8 Note X-9a
- 1. RCIC None (Note 1-8)
N/A Is Imvel II 0, Ix2x2 On Site DC 2
- 2. Isolation System is N/A for Crand Condenser Culf l
- 3. HPCS None (Note 1-8)
N/A lo Level 11 0, lx2x2 On Site DC 2
.i Ili Drywell, Ix2x2
- 4. HPCI System is N/A for Crand Gulf 4
i
- 5. LPCS None (Note 1-8)
N/A Lo Level 11 0, Ix2x2 On Site DC 2
j 111 Drywell Pres., 1x2x2 I
- 6. LPCI None (Note 1-8)
N/A Lo Level 11 0, lx2x2 On Site DC 2
111 Drywell Press., lx2x2 4
111 Drywell Press., 2x2 or 2x2 s
]
(Note 7-9a)
- 8. SRV None N/A N/A N/A
- 9. RilR - incl.
Standby service water On Site AC N/A (Note 9-9a)
N/A
- shutdown, (Note 1-8) cooling, stm.
i cond., supp, pool cooling, i
cont. spray modes
- 10. SSW None (Note 1-8)
N/A la Level 11 0, Ix2x2 On Site DC 2
]
111 Drywell Press lx2x2 i
RllR Pump Start l
LPCS Pump Start Diesel Cen. Start l
RCIC Turbine Start
l Tsble 2.1-2a (Modifitd)
SYSTEM DESIGN INFORMATION - CRAND GULF 1
I Ba 8b 9a 9b.
Auxiliary Systems Required System for Operation Power Source Automatic Startup legic Power Source
?
X-8 Note X-9a
- 11. CCW Plant. Service Water Off Site AC N/A N/A (Note 1-8)
- 13. CST None N/A N/A N/A
- 14. Main Fd.
Condensata, TBCCW, Plant off Site AC N/A N/A Wtr. Sye.
. i
- 15. Recircu.
System is N/A for Crand Pump / Motor Culf Cooling Sys.
d i
i.
d
(Attcchment 4 Continu:d)
RESPONSE
See setached modification of Tables 2.1-4c, 2.1-4f, and 2.1-4g showing infor-mation applicable to Grand Gulf.
- --ew-
==w me w =. ame
.mee.-.
p
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Tabis 2.1-4c ~ (Modified) 1 HICll PRESSURE CORE SPRAY SYSTEM (HPCS)
~
(APPLIES TO CRAND GULF)
Degraded Conditions Initiation Permissive Trip Conditions Reduced Capacity Inoperable,_
Comments
. Reactor Vessel
. None System Trips
. Return line to
. Iogic power
. This is a single channel l
Imvel Trip
. Reactor Vessel suppression failure sys: e'..
g
-. High Drywell water level pool open
. Pump mtr.
Pressure
. Return line to power failure
. Manual Diesel Trips condensate (off-site + diesel)
Initiation (Any operating storage tank Complete pipe i
Condition) open blockage
. Overspeed at 105%. Relief valve to. Condensate storage
. Manual switch suppression pool tank empty and trane-(Brkr control) return open fer to suppression-
. Three phase fault pool blocked (differential relay)
Motor Trips Overcurrent Overfrequency 1
?
t Z
l I
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h I
s 4
].
I I
Tabla 2.1-4f (Modified) j LOW PRESSURE CORE SPRAY SYSTEM (APPLIES TO CRAND GULF)
I Degraded Conditions I'
Initiation Permissive Trip Conditions Reduced Capacity Inoperable Commen_cs 1
. Low Vessel Reactor System Trip.
. Bypass test line. Ioss of off This is a single
.I Water Level Pressure
. Manual switches to suppression site power' division system l
. High Drywell Low Motor Trip pool open
+ diesel gen-
'j Pressure
. Safety valve erator failure i
. Manual
. Ground open to
. Complete flow Initiation
. ESF bus load suppression blockage shedding pool
. Logic power 1
failure n
9 I
i 8
4 1
1
s-t Tcbis 2.1-4g (Modified)
IlW PRESSURE C00lANT INJECTION SYSTEM (MODE OF RilR)
(APPLIES TO CRAND CULF)
[-
Degraded Conditions r
Initiation Permissive Trip Conditions Reduced Capacity Inoperable Comments
. High Drywelt
. Reactor low System Trip Single Pump trip, Motive power
. This is Pressure pressure
. Manual switches Injection valves failure in both a two divisional redundant Reactor Wdter Motor Trip not opening divisions (off-system. Elt.her system is j
Low Level Trip
. Overcurrent Containment /
site + diesel) capable of providing Manual Switches
. Ground
' spray cooling
. Complete flow suf ficient core cooling i-
. ESF bus load valves not closing blockage requirements.
shedding
. Min. flow bypass
. Loop selection valve not closing failure, if d
. Divisional motive applicable I
power failure l
(offsite + diesel)
I
. Divisional logic power bus failure
. Test return line
.to suppression pool open i
l i
i l
. i.
B
(Attecheznt 4 Continuid)
,UESTION 10 Q
One of the systems requests for information that has not been adequately addressed in NEDO-24708 is the loss of feedwater transient coupled with a stuck open SRV and loss of offsite power and diesels. From the information provided it is not possible to deter =ine what the end result of this scenario would be.
Since all the plants have various combinations of HPCI, RCIC and IC systems, SRV with varying relieving capacities, and varying stored energies, the results are plant specific. Therefore, for all the plants or plant types identified in NEDO-24708, provide the folicwing time dependent plots for the above scenario:
a) steam and coolant inventory lost b)'
coolant temperature and pressure c) coolant mtkeup (where applicable) d)
reactor vessel water level relative to top of active fuel e) fuel and cladding temperatures The initial plant conditions assumed in the analyses, the time assumed for startup of the available systems and the time the RCIC and HPCI can operate before the system depressurizes below their operating conditions should be prcrided. In addition, idantify when equilibrium conditions are achieved (core covered and water level maintained in normal operating range); if core uncovery occurs identify when, time duration, and extent of core damage (in-clude basis).
RESPONSE
To be submitted by General Electric on behalf of the BWR Owners Group.
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