ML19274G030
| ML19274G030 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 08/24/1979 |
| From: | Proffitt W VIRGINIA POWER (VIRGINIA ELECTRIC & POWER CO.) |
| To: | Harold Denton, Vassallo D Office of Nuclear Reactor Regulation |
| References | |
| LQA-EAB:PWC, NUDOCS 7908270462 | |
| Download: ML19274G030 (45) | |
Text
,
VinorxxA ErzcTarc arn Powza COMPANY Rictimonn, Vxrionna 2020t August 24, 1979 w.
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Mr. HaroldiR. Denton, Director Serial No. 681 Office ~of Nuclear Reactor Regulation LQA/EAB:pwc Attn: Mr. iD. :B. Vassallo, Acting Director Division of Project Management Docket Nos. 50-338
- U..S. Nuclear Regulatory Commission 50-339 Washington,
- D.C. ' 20555
Dear Mr. Denton:
Attached is the company's response to the Nuclear Regulatory. Commission TMI-2 Lessons Learned Task Force Short Term Recommendations as applicable to the North Anna Power Station. This response focuses primarily on North Anna 2 and is submitted to assist ~ the staff in its review of that units operating license. This unit is now complete and ready for fuel loading.
We have been actively engaged in reviewing and evaluating all of the infor-mation that has been generated and made available describing the circumstances surrounding the TMI-2 incident. An inter-departmental Company Task Force was formed shortly after the incident to review and disseminate information to appropriate personnel within the company. Our representatives are continuing to participate on an industry wide basis as members of the Westinghouse Owners Group and Study Committees of the Atomic Industrial Forum. We are also follow-ing and will be participating in the activities of the recently organized Nuclear Saft v Analysis Center (NSAC) under the auspices of the Electric Power Research Insuitute. In addition, we have attended and participated in numerous meetings with the staff to address questions raised concerning applicability of findings from TMI-2 to other pressurized water reactor facilities.
It is important to note that many of the short term recommendations already exist at North Anna and we have implemented others. Substantial upgrading of nuclear operations has already taken place through revisions to operating procedures and operator trainir!g. Our training simulator has proven to be invaluable as all licensed operators have undergone and successfully completed simulated training exercises including the TMI2 incident.
We feel that the attached information is responsive to the recommended short term actions for North Anna 2 and that it is sufficient to support issuance of the operating license. These inquiries have the approval of the company's senior management and have been reviewed by the Vepco TMI2 Task Force, the Station Nuclear Safety and Operating Committee, and the System Nuclear Safety and Operating Committee.
790827 cme _
vinonn t.ucraic aso rowru coeur '
fir. }larold.R. Denton 2
ilo short term recommended actions will be foreclosed by proceeding with issuance of the operating license for fiorth Anna 2.
Our staff is prepared to meet with you to discuss these responses in more detail should you deem i t necessary.
Very truly yours,
^!a?^
W.L.
Proffitt
Attachment:
Vepco Responses To Tf1I-2 Lessons Learned Task Force Short-Term Recommendations (30) cc:
Dr. R. J. Mattson
s 8
VEPCO !!ESPONSES TO TML-2 LESSONS LEARNED TASl; F0ltCE Sil0RT-TElbl RECOMMENDATIONS (NUllEG-0578)
AuEust 24, 1979
8 TABLE OF CONTENTS VEPCO RESPONSES TO NRC LESSONS LEARNED TASK FORCE S!! ORT-TERM RECOMMENDATIONS Page 2.1.1 Emergency Power Supply Requirements for the Pressurizer IIcaters, Power-Operated Relief Valves and Block Valves and Pressurizer Level Indicators in PWRs.
1 2.1.2 Performance Testing for BWR and PWR Relief and Safety Valves.
4 2.1.3.a Direct Indication of Power-operated Relief Valve and Safety Valve Position for PWRs and IMts.
5 2.l.3.b Instrumentation for Detection of Inadequate Core Cooling in PWRs and BWRs.
6 2.l.4 Diverse and More Selective Containment Isolation Provisions for PWRs and BWRs.
8 2.1.5.a Dedicated Penetrations for External Recombiners or Post-Accident Purge Systems.
14 2.1.5.b Inerting LWR Containments.
15 2.1.5.c Capability to Install Hydrogen Recombiner at Each Light Water Nuclear Power Plant.
16 2.1.6.a Integrity of Systems outside Containment Likely to Contain Radioactive Materials (Engineered Safety Systems and Auxiliary Systems) For PWRs and DWRa 17 2.1.6.b Design Review of Plant Shielding of Spaces for Post-Accident Operations 18 2.1. 7.a Automatic Initiation of the Auxiliary Feedwater System for PWRs.
20 2.1.7.b Auxiliary Feedwater Flow Indication to Steam Generators for PWRs 22 2.1.8.a Inproved Post-Accident Sampling Capability.
23 2.1.8.b Increased Range of Radiation Monitors.
24 2.1.8.c Improved In-Plant Iodine Instrumentation.
25 2.1.9 Analysis of Design and Off-Normal Transients and Accidents.
26 2.2.1.a Shift Supervisor's Responsibilities.
2B 2.2.1.b Shift Technical Advisor.
30 2.2.1.c Shift and Relief Turnover Procedures.
31 2.2.2.a Control Room Access.
33 2.2.2.b Onsite Technical Support Center.
34 2.2.2.c Onsite Operational Support Center.
35 2.2.3 Revised Limiting Conditions for Operation of Nuclear Power Plants Based Upon Safety System Availability.
36
e TITLE:
Pressurizer IIcater Power Supp1v (Sect ion ?. l.1. 3.1)
NRC POSITION 1.
The pressurizer heater power supply design shall provide the capability to supply, fron either the offsite power source or the energency power source (when of fsite power is not availabic), a predeternined nunber of pressurizer heaters and associated controls necessary to establish and maintain natural circulation at hot standby conditions.
The required heaters and their controls shall be connected to the energency buses in a nanner that vill provide redundant power supply capability.
2.
Procedures and training shall be established to nake the operator aware of uhen and how the required pressurizer heaters shall be connected to the energency buses.
If required, the procedures shall identify under uhat con-ditions selected energency loads can be shed f ron the energency power source to provide sufficient capacity for the connection of the pressurizer heaters.
3.
The tine required to acconplish the connection of the preselected pressurizer heater to the emergency buses shall be consistent with the tinely initiation and naintenance of natural circulation conditions.
4.
Pressurizer heater native and control power interfaces uith the energency buses shall be accomplished through devices that have been qualified in accordance with spFety-grade requirenents.
RESPOS3:
Position 1 Two of the five pressurizer heater banks are fed fron separate redundant safety related 430 v load centers.
Preliminary infornation from the NSSS indicates that 215 kW is needed to provide natural circulation. These two backup heater banks are rated at 270 and 215 kW.
Position 2 The pressurizer heaters may be connected to the energency buses within the linitation of the diesel generator at any time follouing a loss of offsite power accident.
If all loads that could be automatically connected to the energency bus are connected, the heaters cannot be connected to the energency bus after a loss of offsite power accident until a reduction in load has been acconplished.
During natural circulation operation nany of the energency loads will not be connected.
There is a kW neter on each of the emergency diesel generator control panels in the main control roon, so that the operator can observe the diesel load and keep it uithin limits.
Station operating procedures will be developed for the load shedding sequences.
Position 3 The timing of the reconnection of the pressurizer heaters is being formulated by Westinghouse and will be made available as soon as it is received and incorporated into operating procedures.
1
Position 4 Motive and control power interface equipment meets safety grade requirements except the supports for the tray sections that enter t' e bottom of the pressurizer. Although the cabling between the pressurizer heater distribution panels and the heaters themselves are not color-coded, the cabling is in separate raceways and meets the intent of the color-c.oded separation requirements in t.he FSAR. The tray section to the heaters virt be upgraded to withstand seismic loads.
Upgrading the tray sections to withstand selsnic loadings will be accomplished on Unit 2 by fuel loading.
2
i TITLE: Power Supply for Pressurizer Relief and Block Valves and Pressurizer Level Indicators (Section 2.1.1.3.2)
NRC POS_ITION 1.
Motive and control components of the power-operated relief valves (P0PVs) shall be capable of being supplied from either the offsite poser source or the emergency power source when the offsite power is not availabic.
2.
Motiva and control components associated with the PORV block valves shall be capable of being supplied from either the offsite power source or the emergency power source when the offsite power is not available.
3.
Motive and control power connections to the emergency buses for the PORVs and their associated block valves shall be through devices that have been qualified in accordance with safety grade requirements.
4.
The pressurizer level indication instrument channels shall be powered from the vital instrument buses. These buses shall have the capability of being supplied from either the offsite power source or the emergency power source when offsite power is not available.
RESPONSE
Positica 1 Control and indication circuits for the PORVs are powered frem redundant safety grade emergency buses. Motive power for the power operated relief valves (?0RVs) 2455C and 2456 is currently provided only by containment instrument air.
Nitrogen supply tanks are provided as a redundant source of moti /2 pauer for the PORVs as a part of the overpressurization system employed during solid water operation. Motive power for the PORVs will be upgraded by the addition of a line and three (3) spring loaded check valves to the nitrogen supply system.
This will provide another source of notive power.
The nitrogen supply system, as shown on 12050-FM-45A, is composed of seismically supported, stainless steel components, and is sized for 120 valve operations.
This modification will be accomplished on Unit 2 prior to fuel loading.
Position 2 Motive power and control for the block valves is from redundant safety grade emergency buses.
Position 3 Electrical notive and control power to the PORVs and associated block valves is qualified safety grade.
Position 4 The pressurizer level indication instrument channels are powered from vital buses that are powered from redundant safety grade emergency buses.
3 C1707/4
TITLE:
llelief and Safety Valve Testing (Section 2.1.2)
N11C POSITION Pressurized water reactor and belling water reactor licensees and applicants shall conduct testing to qualify the reactor coolant system relief and safety valves under expected operating conditions for design basis transient:s and accidents. The licensees and applicants shall deternine the expected v 1ve operating conditions through the use of analyses of accidents and anticipated single failures applied to these analyses shall be chosen so that the dynanic forces on the safety and relief valves are maxinized. Test pressures shall be the highest predicted by conventional safety analysis procedures. Reactor coolant systen relief and safety valve qualification shall include qualification of associated control circuitry piping and supports as well as the valves thenselves.
RESPONSE
The Power Operated Relief Valves (PORV) installed at North Anna Unit 2 are of a significantly different design than those caployed at TM1-2 and other BSW reactors. The North Anna Unit 2 PORV's are standard design air operated globe pattern control vnives, (20,000 series) as manufactured by Masonellan International, Inc.
Vepco is currently investigating the aspects of qualifying the pressurizer relief and safety valves by full scale prototypical testing with two phase and liquJd phase flow.
We have canvassed valve manufacturers and independent test facilities to determine the extent of preparation in progress to meet the requircaents for testing PUR safety and relief valves. There are no facilities in the U.S. capable of testing PWR safety and relief valves. Wyle Labs has a facility about 75 percent completed and we are discussing the capabilities of this facility with Wyle. This facility is expected to be cperational in January 1980.
EPRI has initiated a program to test PWR safety and relief valves.
EPRI is also examining the capabilities of the Wyle facility. We are in contact with EPRI and we will support the EPRI program.
The NSSS vendor has been requested to supply transient design conditions for the safety and relief valves. This information will be used in evaluating the adequacy of the test program.
Vepco will actively pursue and participate in the developaent of an industry sponsored test program to determine safety and relief valve qualification for PWR transient conditions, and to conduct appropriate prototypical testing of these valves.
4
e TITLE:
Direct Indication of Valve Position (Section 2.1.3.a)
NRC POSITION Reactor s sten relief and safety valves shall be provided with a positive indication in the control roon derived from a reliable valve position detection device or a reliable Indication of flou in the discharge pipe.
RESPONSE
Pressurizer power operated relief valves 2455C and 2456 have direct indication derived f rom limit switches on each valve that indicate open-close position and are displayed in that control roon.
The indication is powered from a vital source.
In addition, an indirect indication is available by tenperature indication of the P.O.R.V. discharge header. Motor operated block valves 2535 and 2536 in series with the P.O.R.V.'s have direct indication derived f rom limit switches on each valve that indicate open-close position and are displayed in the control roon.
The indication is powered f rom a vital source.
No direct indication of safety valve poaltion exists.
Indication of va're position through indirect neans is available by temperature indication of the discharge pipe devastrean of each valve, located in the control room.
Uc have evaluated two possible methods of monitoring the position of the safety valves. These nethods are 1) direct indication of the safety valve rosition by nounting a limit s.dtch on the safety valve, and 2) nonitoring the flow in the discharge pipe with acoustic devices. We believe the acoustical nethod is superior to the use of linit switches. We have identified and have had discussions with several vendors of acoustical equipment and are presently actively pursuing inglenentation of ca acoustical systen with Rockwell, Internationel. We have requested proposals f ron Rockwell and should place an order for the necessary equi; rant prior to Septenber 14, 1979. We have started the preliminary design for the insto'Iction of the tranducers, cabling, and nonitoring cabinet.
Due to the delivery schedules for this equipment, installation of acoustic monitoring of the safety valves may require several nonths. Justification for plant op2 ration is based on the following.
1.
Tenperature indication is provided on the discharge piping of each safety valve.
2.
Both tenperature and level in the pressurizer relief tank are monitored.
3.
Decreasing pressurizer pressure with indication that the PORV is closed, the operator wcald take action with abnormal procedure " Decreasing Reac-tor Coolant System Pressure."
5
TITLE:
Instrumentation for Detection of Inadequate Core Cooling in PWR's and BWR's (Sec tion 2.1. 3.h. )
NRC POSITION 1.
Licensees shall develop procedures to be used by the operator to recognize inadequate core cooling with currently availabic instrunentation. The licensee shall provide a description of the existing instrumentation for the operators to use to recognize these conditions.
A detailed descrip-tion of the analyses needed to form the basis for operator training and procedure development shall be provided pursuant to another short-term requirement, " Analysis of Of f-Normal Conditions, Including Natural Circulation" (see Section 2.1.9 of this appendix).
In addition, each PWR shall install a primary coolant saturation meter to provide on-line indication of coolant saturation condition.
Operator instruction as to use of this meter shall include consideration that is not to be used exclusive of other related plant parameters.
2.
Licensees snall provide a description of any additional instrumentation or control s (primary or backup) proposed for the plant to supplement those de'cices cited in the preceding section giving an unambiguous, easy-to-internrat indication of inadequate core cooling.
A description of the functional design requirements for the system shall also be included.
A description of the procedures to be used with the proposed equipment, the analysis used in developing these procedures, and a schedule for instaU ing the equipment shall be prosided.
RESPONSE _
l.
Change s to emergency procedures have been made to emphasize the need to insure cdecua te coolant flow and to insure that reactor coolant tempera ture and pressure are maintained or immediately restored to achieve a nargin to saturation of at least 50*F.
All licensed reactor operators and current trainees have received special instruction in the TMI type incident with particular emphasis on the use of existing instrumenation to determine core conditions.
Ve are participating in a Westinghouse Operating Plant Owners Group to more ef fectively deal with the generic issues resulting from the TMI inc id e n t.
Included in the scope of work currently authorized by the group is a complete review and rewriting of the Westinghouse Generic Daegency Operating Instructions to incorporate lessons learned from the TMI incident.
Specific concerns to be addressed in this review include the use of existing instrumentation to determine core conditions and the adequacy of core cooling.
Improvements developed as part of the generic procedures review will be incorporated into the North Anna emergency procedures. While the specific procedural applications of this owners' group effort are incomplete, Westinghouse has developed an identification and categorization of those instruments which are essential for diagnosis of of f normal conditions. The minimum set of instrumentation that is required for operator infornation in order to diagnose the type of plant event, take the necessary manual actions, and to monitor critical parameters is as fc110ws.
6
2.1.3.b page 2 Uide Range Reactor Coolant System Pressure Wide Range RTD - hot legs Wide Range RTD - cold legu Pressurizer Level Incore Thermocouples RWST Level Containment Sump Level High Head Safety Injection Flow Auxiliary Feedwater Flow Condensate Storage Tank Level Containment Pressure Containment Radiation Steamline Pressure Steam Generator Narraw Range Level Steam Generator Wide Range Level Air Ejector Radiation Steam Cenerator Blowdown Radiation Boric Acid Tank Level Control Room and Auxiliary Building Area Radiation "onitors North Anna Unit 2 currently has all of this instrumentation.
Two mechanisms have been provided to allow the operator to immediately asseso the primary coolants margin to saturation conditions. The unit process ccmpu+.er will be programmed to alarm when nargin to saturation is reduced bel ew a prese t value.
Specifically, when one of the following temperature readings rises to within a preset limit to the saturation temperature for the existing RCS pressure, a computer alarm will sound.
1.
Highest core exLt thermocouple 2.
Any one of three wide range cold leg temperatures 3.
Any one of three wide range hot leg temperatures Additionally, an operator can initiate a trend of system s *uration tempera-ture and one or more of these temperatures.
This computet ased alarm will be implemented prior to unit startup.
In the longer term, the computer based alarm will be fed to a main control board annunciator. A saturation curve has been posted on the control board.
This curve, combined with nearby indications of reactor coolant system tenperatures and pressures, enables the operator to quickly determine the systems margin to saturation.
2.
The identification of the need for any additional instrumentation will be made in conjunction with the ongoing analyses and procedural reviews. At this time no definite additions or modifications have been determined to be necessary.
7
TITLE:
Diverse Containment Isolation (Section 2.1.4)
NRC POSITION 1.
All containment isolation system designs shall comply with the recommenda-tions of SRP 6.2.4; i.e.,
that there he diversity in the parameters sensed for the initiation of containment isolation.
2.
All plants shall give careful reconsideration to the definition of casential and non-essential, shall identify each system determined to be non-essential, shall describe the basis for selection of each essential system, shall modify their containment isolation designs accordingly, and shall report the results of the reevaluation to the NRC.
3.
All non-essential systems shall be automatically isolated by the containment isolation signal.
4.
The design of control systems for automatic containment isolation valves shall be such that resetting the isolation signal will not result in the automatic reopening of containment isolation valves. Reopening of contain-cent isolation valves shall require deliberate operator action.
RESPONSE
1.
The North Anna Unit 2 containment Phase A isolation system complies with the signal diversity requirements of SRP-6.2.4.
All non-essential systems having automatic containment isolation valves and not required for an orderly.
reactor shutacun or to maintain cantainment atmospheric conditions are closed on c safety injection actuation signal.
This is defined as Containment phase A isolation and has the following " diverse" input parameters:
(1) high steam line flow with either low steam line pressure or low low T average, (2) high containment pressure, (3) high steam line differential pressure, or (4) low pressurizer pressure.
These four sources provide for the required diversity of parameters sensed which is in conformance with Section 6.2.4 of the Standard Review Plan.
2.
Tables I through III list the essential and non-essential containment penetra-ticas.
The essential systems are divided inte, two categories (levels) which are based on their ability to mitigate the severity of various types of accidents. Level 1 of the essential systems are defined as Engineered Safety Features (ESP) and Containment Depressurization systems required to operate after a LOCA. These systems are listed in Table I.
The essential Level 2 systems are defined as those required to maintain the operation of critical systems and functions such as the containment heat removal and, therefore, remain unisolated from the containment until a design basis LOCA is indicated (Phase B isolation) or when these systems are no longer required. These Level 7 systems are listed in Table II.
8
e 3.
The non-essential systema listed in Table III are either isolated on Phase A actuation signal (SIS) er are closed during nomal plant operation.
Some non-essential systens listed in Table III may be utilized following a LOCA if conditions warrant.
4.
Once Containment Phasa A isolation has been initiated by a safety i nj ec tion actuation signal, the automatic isolation valves can be opened only tqon manual reset of the actuating signal and deliberate remote manual operation of the individual valve (refer to Section 6.2.4.3 of the FSAR).
9
?!/1707/3
TABLE I ESSENTIAL SYSTEMS - LEVEL 1 Valve Position
System Description
Alter SIS
- liigh llend Safety Injection to the Cold Leg open liigh IIcad Safety Injection to the llot Leg closed Low ifcad Safety Injection to the Cold Leg open Low Ilead Safety Injection to the llot Leg closed Low llead Safety Injection Suction From closed the Sump Containment Atmospheric Cleanup closed Seal Water Injection to RC Pump open lQuenchSprayPumpDischarge**
closed ***
F.ecirculatica Spray Suction / Casing Cooling Discharge *n open ilEcc.rculation Spray Discharge open l
. ice Iater into the Recirculation Spray licat Exchanger closed ***
Service 1:ater Return From the Recirculation Spray Heat Exchanger closed ***
Notes
- Isolation valves designated as closed receive a signal to close immediately af ter safety injection actuation and are opened by the operator or automatic controls at some period of time following a LOCA.
- Quench spray pumps 2nd casing cooling pumps are selectively isolated after it is established that the use of this system is no longer required.
10
e TABLE II ESSENTIAL SYSTEMS - LEVEL 2 Systems Description Mode of Containment Isolation Component Cooling from RC Pump Thermal Barriers Phase B Component Cooling from Contai.nment Air Recirculation Cooling Coils Phase B C om.p o ne nt Cooling to RC Pump Motor Phase B Component Cooling from RC Pump Motor Phase B Main Steam Relief Set Point Pressure Auxiliary Feedwater Componeat Cooling Water Return f rom RIIR lient Exchanger Phase B Cles:_d syster. side and check valve outside represent containment isolation.
11 M/1707/2
e TABLE Ill NON-ESSINTIAL SYSTEMS Mode of System Descrip_ tion Containment Isolation Charging-CVCS Phase A Charging System Letdown Phase A RC Pumps Seal k'ater Return Phase A Containment Air 1:adiation Monitor Phase A Sample Pressurizer Relief Tank Gas and Licluid Phase A Space Samples Prit:nry Coolant Hot Leg Sample Phase A Primary Coolant Cold Leg Sample Phase A
. Pressurizer Vapor Space Sanple Phase A Residual Heat Removal Sample Phase A IContainman: Instrument Air Return Phase A I
I Sa f e ty Injection Accumulator Makeup Adi..
Controlled
- Normally Closed RH:1 Retura to Ri?ST Adm. Controlled
- Normally Closed i
Stem Cen. Wet Layup Adm. Centrolled
- Normally Closed Primary Drain Transfer Discharge Phase A Containment Sump Pump Discharge Phase A Steam Gen lilowdown Phase A Service Air Adm. Controlled
- Normally Closed Primary Grade Water Phase A RC Loop Fill Adm. Controlled
- Normally Closed Primary Vent lleader Phase A Nitrogen to Waste Gas Charcoal Phase A Filters 12
e TAliLE III (cont'd)
!! ode of Systen Lescription Con t a i rrae r t Isolation Nitrogei to Pressurlzer Relief Tank Phase A Primary Vent Pot Vent Ada. Controlled
- Norna11y Closed Containment Leakage Monitoring Phase A Steam Cen. Illowdown Sample Phase A Condenser Air Ejector Vent Phase A Containment Purge Air Ducts Locked-Closed Containment Air I:Jeetor Suction Locked-Closed Pressurizer Dead WL. Calibrator Adm. Controlled
- Normally Closed Refueling Purifier Inlet and Adm. Controlled Outlet
- Normally Closed
- cumulator Tanks Test Line Phase A
, Containment Instrument Air Suction Phase A Jecdwater Cl.rical Addition
'!ain Stea- (iRIP) - Shares Pen. with
- -!.S. Relief Lines l
lFeedwater-Shares Pen, with Auxiliary I'eedwater Lines Phase A NOTES:
- Closed system inside and check valve outside represent containment isolatloa.
- Isolated either by intermediate high-high containment pressure, high steam line flow with low steam line pressure, or low low T average.
13
a TITI,E -
Dedicated 119 Control Penetration (Section 2.1.5.a)
NRC POSITION Plants using extcrnal recombiners or purge systems for post-accident combustible nas control of the containment atmosphere should provide containment isolation systems for external recombiner or purge systems that are dedicated to that ser-vice only, that meet the redundancy and single failure requirements of General Design Criteria 54 and 56 of Appendix A to 10 CFR Part 50, and that are sized to satisfy the flow requirements of the recombiner or purge system.
RESPO';SE The post-accident hydrogen recombiners take a suction on the containment through the same containment penetration which is used for the suction of the containment vacuum pumps. The recombiner discharges back to the containment through its own dedicated penetration.
The suction penetrations are considered to be dedicated to the hydrogen recombiner during accident conditions since the containment vacuum system is not required for containment depressurization during accident conditions.
The recambiner system is in no way connected to the purge system.
The containment isolatica for these penetrctiens nect the redundancy and singic failure criteria.
Deviatienn f ron Genral Dengn Criteria 54 and 56 are necessary to provide access to the nutomatic trip valves in order to ensure operability of the hydrogen re M irar and are O cumented in Section 6 of the FSAR. The two inch hydrogen recomb'.v r lines t!e inte the two inch containment vacuum lines downstream of the centa!r~ nt isolation valves. To establish operation of the recombiner system, a m n'l valve (r at teject to single active failure by spurious motor-operator v t), which n accescible on the 274' elevation of the Auxiliary Building tro vc near to; contaicm :0 cacuum pumps,i,ust be closed to isolate the containment atmosphcre from the containment vacuum system. This can be accomplished without excessh ' exposure to plant operating personnel. The existing arrangement, there-fore, satisfies the intent of NUREC 0578.
14
TITLE:
Inerting INR Contalinaents (Section 2.1.5.b)
NRC POSLTION It shall be required that the Vermont Yankee and llatch 2 Mark I llWR containments he inerted in a raanner similar to other operating BWR plants Inerting shall also be required for near term OL licensing of Mark I and Mark II BWRs.
RESPONSE
This item is not applicable to North Anna.
15
T IT!,E :
Capability to Install llyd rogen Recombinr r at Fach I,lght k'a ter 1:aclear Power Plant (2.1.5.c)
_NRC POSITION 1.
All licenses of light water reactor plant e, shall have the capability to obtain and install recombiners in their plants within a few days followin:; an accident if containment access is imp:tird and if r.uch a system is needed for long-term post-accident combustible gas control.
2.
The procedures and bases upon which the recombiners would be used on all plants should be the subject of a review by the licensees in considering sheilding rerptirenents and personnel exposure limitations as demonstrate.1 to be necessary in the case of TMI-2.
RESPONSE
North Anna has two (2) Post Accident flydrogen Recombiners rated at 50 ccfn each that are shared between units 1 and 2.
The recombiners are separate and independent.
Technical Specification 3.6.4.2 and 4.6.4.2 governs the operability c" 3 surveillance requirenents.
Each unit is capable of Leing ranua11y val, ed to either containment. The procedures and bases upon wcich the recerbiners would be used will be reviewed in considering shieldin ; rec,uirements and personnel exposure limitations.
This effort will be ccepicted in conjunction with the plant shielding review.
16
TITIZ:
Integrit y of Sys tens Outside Containment Likely to Contain Radioact ive f'a te r ial s (Engineered Safe ty Systens and Auxiliary Systens) for PWR's and MWR
2.1.6.a NRC POSITIO" Applicants and licensees shall innediately implement a progran to reduce lea kage f rom systens outside containment that would or could contain highly rad ioac t ive fluids during a serious transient or accident to as-low-as-practical levels.
This progran shall include the following:
1.
Inmediate Leak Reduction a.
Inplement all practical Icak reduction neasures for all systens that could carry radioactive fluid outside of containment.
h.
Measure actual leakage rates with systen in operation and report then to the NRC.
2.
Continuing leak Reduction Establish and implement a pro', ram of preventive naintenance to reduce leakage to as-low-as-practical levels.
This progran shall include pariodic integrated leak tests at a frequency not to exceed refuelim; cycle intervals.
F L5 ?MS E The s y s t ens that may have to operate during an accident that are located outeide of the containment are now under study to insure that all sections are included.
The Residual lleat Removal Systen (RllR) is located entirely eithin the containrent.
The RHR does not perform any ESF functions.
The Che,1 cal Voltm and Control Systen (CVCS) is leak tested as a portion of the Reactor Coolant Systen (RCS) and is isolated by a safety injection actuation.
This leakage testing is governed by Technical Specification
- 4. l. 6. 2. a t least once every 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
Portions of other systens such as the Safety Injection Systen (SI), and the Recirculation Spray Systen (RS) are located outside the contai nment.
The RS systen is located within the Safeguards Building and the containment where the need for personnel access would be ninim1.
The Low IIend Safety Injection (LIISI) pumps are also located within the Safeguards Building where LIISI lines, when in the recirculation phase, are returned directly to the containnent without transversing another building.
The LIISI lines to the charging pumps (or liigh !! cad Injection Pumps) suction are directed through portions of the Auxiliary Building where the charging pumps are located.
Further study will be required to identify those systems or portions of systen which will carry primary coolant inmediately following an accident.
These systens will also be the bases for the plant shiciding review.
An inmediate leak reduction progran will be formulated and inplemented by January 1, 1980.
A continuing leak reduction progran to reduce and naintain as-low-as practice.1 levels will be formulated by.Tanuary 1, 1980.
17
TITII:
Plant Shielding Review (Section 2.1.6.b)
Nf:C POSITION Uith the an uuption of a post accident release of radioactivity equivalent to that described in Regulatory Guides 1.3 and 1.4, each licensee shall perform a radiation and shielding design review of the spaces around systems that nay, as a result of an accident, contain highly radioactive naterials. The design review should identify the location of vital areas and equipment, such as the control room, radvaste control stations, enargency power supplies, motor control centers, and instrument areas, in which personnel occupancy may be unduly limited or safety equipment nay be unduly degraded by the radiation fields during post accident operations of these systems.
Each licensee shall provide for adequate access to vital areas and protection of safety equipmant by design changes, increased permanent or temporary shielding, or post-accident procedural controls.
RESPONSE
A plant shielding review will be performed to evaluate the ability to operate essential systems required af ter a LOCA with significant core damage.
Th i. s review will evaluate activity levels in vital areas of the plant which nuut he accessible to pernit operation of essantial systema and to ensure that nafety gradr equipment car perform its intended function in the resulting radiation fi el d.
Design changes, increased perranent or temporary shielding and/or post accidant procedural controls vill be impicmented, where required to assure the proper Speration of cital systems.
Tc est:31ish the basis of this review, ne have identified those systems and porti ms of system, operating outside the containment boundary, which could contain highly radioactive fluid or gas and may be required to mitigate the effects of a LOCA, A radioactive release equivalent to that described in the Regul atory Guides 1.3 and 1.4 will be assumed to be contained in those systems.
Systens to be evaluated have been divided into those required for mitigation of the accident (i.e. place the plant in a safe condition) and those required for clean up and recovery.
The distinction is nade based on the TMI-2 experience w?.ich indicates that the recovery phase will be a controlled process which will be carried out a significant time after the accident is nitigated. Additionally, a very significant lesson learned from the TML-2 accident is that to limit the radioactivity exposure to both site and of f-site personnel, no reactor coolant should be routed outside containment unless absolutely necessary for operation such as the Safety Injection System, the Recirculation Spray Systen or tne Sampling System.
Based on the above the following systems have been designated as mitigating systems: The Safety Injection Systen (including the low head and high head recirculation path), and the Recirculatton Spray System.
The let down and normal charging portions of the Chemical and Volume Control system have not been designated as a nitigating system since it in automatically isolated 18
by the pha se A Cont ai n aent I solation signal and its use is not required to rai t i gat e a LOC \\.
In fact, TML-2 experience indicate, that using the letdown nyst"m could severly increane the possibility of radiation release, with no significant n: tigating ef fect to the accident.
Plant. operating procedures will be rodified to instruct the operator not to re-initiate letlowa unless he has decerninnd through his indications (e.g.
radiation nanitors, initial sampling, etc.) that core damage has not occurred, then letdown could be used.
For these reasons letdown will he considered an a recovery aaae system only. Other recovery phase systens include Boron Recovery, Vent and Drain, Liquid, Caneous, and Solid Waste, Containment Atnosphere Clean Up, and the Sanpling Systca.
The chielding review and determination of required chielding and/or procedural changes for the nitigation phase of the accident will be co:npleted by fuct loading. The remaining review for the recovery phase will be completed by 1 P,0.
19
TITI.E : Auto InitIntion of Auxiliary reed (Section 2.1.7.a)
N!!C POSITION Cens1 stent with satisfying the requirements of General Design Criterion 20 of Appendi> A to 10 Crn Part 50 vith respect to the timely initiation of tha auxili ary feedwater sys t en, the following requirenents shall be impleruented in the short te rn:
1.
The design shall provide for the autonatic initiation of the auxiliary feedwater systen.
2.
The automatic initiation signnis and circuits shall be designed so that a single failurc will not result in the loss of auxiliary feed-water systen function.
3.
Testability of the initiating signals and circuits shall be a feature of the design.
4.
The initiating signals and circuits shall be powered from the energency btues.
5.
- anual capabili t'.
to initiate the auxiliary feedwater system fron the centrol rx..
hall be retained and shall be inplemented so that a singic failure Jn tim :a ul circuits vill not result in the loss of systen function.
6.
The a-c re tc. r-J riw n pumps and valves in the auxiliary feedwater systen shall be included in the auto:,atic actuation (simultaneous and/or sequential) of the l o n.s.
to the emergency buses.
7.
The automatic initiating signals and circuits shall be designed so that their f ailure will not result in the loss of manual capability to initiate the AI'.S from the contrel roon.
In the lens term, the automatic initiation sig;nals and circuits shall be upgraded in accord rce with safety-grade requirenents.
The current desi;;n of the Auxiliary Feedwater System provides for automatic initiation.
2.
All initiation signals and circuits are designed to prevent a single failure from causing a loss of the Auxiliary I'ecdwater System.
3.
The Auxiliary Feedwater System is initiated automatically by safety injection signal, loss of of fsite power, and on low lou stean generator 1cvel. These actuation signals are testable and these signals are the system actuations on which the FSAR Chapter 15 accident analysis is based. The Auxiliary Feed-water System is also automatically initiated on loss of the main feedwater pumps in anticipation of low stean generator Icvel. This,nticipatory actuation is not testable during normal operation.
20
4.
All initiating circuits which autonatically start the Auxiliary Feedwater System, are powered from vital buses and are backed-up by the emergency power system.
5.
The capability presently exists te nanually initiate the Auxiliary Feedwater System from the control room.
A single failure in the manual circuits will not result in the loss af system function.
6.
The AC cotor feed pumps in the Auxiliary Feedwater Systen are automatically initiated.
The motor operated valves and air operated hand control valves required to establish a flow path from the discharge of these pumps to the steam generators are left in the open position and do not receive automatic signals. These valves are under strict administrative control and can be operated from the control room. Therefore, an automatic signal is not required. To further alert the operator if one of these valves is shut, an alarm will be added in the control room which will alarm if any of these normally open valves are not full open. The motor operated valves are powered from the emergency bus.
The air operated hand control valves are powered by the vital bus.
The valve controls will be powered from a vital bus.
The AC motor driven pumps are protected by automatic pressure control valves in the pump discharge lines. These valves prevent destructive pump runout in the avent of a break in the pump discharge line. These valves are normally clored and autonatically open on pump start up to maintain the pump discharge absce 900 psis.
To alert the operator that the pressure control valves nay not be functioning properly af ter pump ctart up, an alarm will be added in the control room ;hich will alarn if these valves have not opened.
All attempts will be made to install the modifications prior to fuel loading of Jait 2 pendin;; hardware availability, but no later than January 1, 1980.
7.
The automatic signals are designed in such a manner that their failure will not result in loss of ranual capability to start the Auxiliary Feedwater System.
8.
The automatic initiation circuits are presently safety-grade equipment and meet the 3cng-term requirements.
21
TITLE: Auxiliarr Feed Flow Indication (Section 2.1.7.b)
NRC POSITION Consistent with satisfying the requirements set forth in GDC 13 to provide the capability in the control room to ascertain the actual performance of the AFWS when it is called to perform its intended function, the following requirements shall be implemented:
1.
Safety-grade indication of auxiliary feedwater flow to each steam generator shall be provided in the control room.
2.
The auxiliary feedwater flow instrument channels shall be powered from the emergency buses consistent with satisfying the emergency power diversity requirements of the auxiliary feedwater system set forth in Auxiliary Systems Branch Technical Position 10-1 of the Standard Keview Plan, Section 10.4.9.
RESPONSE
1.
Auxiliary Feedwater flow indication to each steam ge-;ador is safety grade equipment and is displayed in the control room with the exception of power supply diversity.
2.
Aux 111,ry Feedwater flow indication is powered from the emergency bus via the seal vital bus, which does not meet the diversity requirements of ASTB 10-1 of the standard review plan Section 10.4.9.
To meet the diversity re:icirements of ASI3 10-! the Auxiliary Feedwater flow indication power supplies will be moved tn an existing cabinet which meets the diversity requirements.
This change will meet the position and can be implemented by fuel loading on Unit 2.
3.
This change will result in safety-grade indication in the control room of auxiliary fecduater flow to each steam generator and thus satisfies all the requirements, including implementation category B, in NUREG-0578.
22
TITLE:
Improved Post Accident Sampling Capability (Section 2.1.8.a)
NRC POSTION A design and operational review of the reactor coolant and containmenc atmos-phere sampling systems shall be performed to determine the capability of personnel to promptly obtain (less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />) a sample under accident conditions without incurring a radiation exposure to any individual in excess of 3 and 18 3/4 Rems to the whole body or extremities, respectively. Accident conditions should assume a Regulatory Guide 1.3 or 1.4 release of fission products.
If the review indicates that personnel could not promptly and safely obtain the sampics, additional design changes features or shielding should be provided to meet the criteria.
A design and operational review of the radiological spectrum analysis faci-lities shall be performed to determine the capability to promptly quantify (less than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />) quantify certain radioisotopes that are indicators of the degree of core damage.
Such radionuclides are nobic gases (which indicate cladding failure), iodines and cesiums (which indicate high fuel temperatures),
and non-volatile isotopes (which indicate fuel melting).
The initial reactor coolant spectrum should correspond to a Regulatory Guide 1.3 or 1.4 release.
The review should also consider the ef fects of direct radiation from piping and components in the auxiliary building and possible contanination and direct radiation from airborne effluents.
If the review indicates that the analyses recuired cannot be perf ormed in a prompt manner with existing equip-rent, then design modifications or equipment procurement shall be undertaken to meet the criteria.
In addition to the radiological analyses, certain chemical analyses are necessary for monitoring reactor conditions.
Procedures shall be provided to perform boron and chloride chemical analyses assuming a highly radioactive initial sample (Regulatory Guide 1.3 or 1.4 source term).
Both analyses shall be capable of being completed promptly; i.e.,
the boron sample analysis within an hour and the chloride sample analysis within a shif t.
RESPONSE
A design and operational review of the reactor coolant and containment samp-ling systems will be performed to determine the capability of promptly ob-taining samples under accident conditions without incurring a radiation exposuce to any individual in excess of the limits specified in 10 CFR 20.
If this review indicates the need for any design changes or shielding we will provide a description of the proposed modification by January 1, 1980. In-plementation would be completed during the first refueling or extended outage f ollowing January 1,1981.
The associated procedures would be completed prior to completica of the modification.
23
TITLE:
Increased Range of Radiation Monitors (Section 2.1.8.b)
NRC POSITION The requiremeats associated with this recommendation should be considered as advanced implementation of certain requirements to be included in a revision to Regulatory Guide 1.97, " Instrumentation to Follow the Course of an Accident," which has already been instiated, and in other Regulatory Guides, which will be promulgated in the near-term.
1.
Noble gas ef fluent monitors shall be installed with an extended range designed to function during accident conditions as well as during normal operating conditions; multiple monitors are considered to be necessary to cover the ranges of interest.
Noglegaseffluentmonitorswithanupperrangecapacityof a.
10 uC1/cc (Xe-133) are considered to be practical and should be installed in all operating plants, b.
Noble gas effluent monitoring shall be provided for t rangeofconcentrationextegdingfromaminimumof10petotal uCi/cc (Xe-133) to a maximum of 10 uCi/cc (Xe-133). Multiple monitors are considered to be necessary to cover the ranges of interest.
The range capacity of individual monitors shall overlap by a factor of ten.
2.
Since iodine gaseous effluent monitors for the accident condition are not considered to be practical at this time, capability for ef fluent nonitoring of radiciodines for the accident condition shall be provided with sampling conducted by adsorption on charcoal or other media, followed by onsite laboratory analysis.
3.
Ingcontainment radiation level monitors with a maximum range of 10 rad /hr shall be installed. A minimum of two such monitors that are physically separated shall be provided.
Monitors shall be designed and qualified to function in an accident environment.
RESPONSE
Nobic gas ef fluent and radiation level monitors capabic of providing the extended ranges recommended in Section 2.1.8.b do not appear to be commercially available at this time.
Studies are being performed,
however, to determine appropriate, conservative monitoring ranges based on plant specific parameters.
These studies may show that commercially available equipment which approaches but does not reach the recommended range extremes can provide the necessary monitoring capability with an adequate nargin of conservatism.
Additional studies will be performed to determine how best to utilize existing station equipment for monitor-ing of radioiodines in gaseous ef fluents under accident conditions.
The findings of the above studies will be impicmented to provide appro-priate monitoring capability for Marth Anna Unit No. 2 during the first refueling or extended outage following January 1, 1981.
2/
TITLE:
Improved In-Plant Iodine Instrumentation (Section 2.1.8.c.)
NRC POSITION Each licensee shall provide equipment and associated training and procedures for accurately determining the airborne iodine concentration throughout the plant under accident conditions.
RESPONSE
Improved capability for the assessment of in-plant airborne radioiodine cen-centrations under accident conditions will be provided by the following measures:
1.
An adequate stock of " silver zeolite" sampling cartridges will be purchased and maintained at the station for emergency use.
Existing station equipment will be used to perform gamma spectral analysis on collected samples to accurately assess iodine concentrations.
2.
Procedures will be revised to instruct appropriate personnel in the proper precautions to be taken when sampling with charcoal cartridges. The pro-cedure will address acceptable methods for removal of noble gases from charcoal cartridges, prior to performing gamma spectral analysis.
These measures will be implemented prior to the " Category A" implementation date of January 1, 1980.
NRL:M13 25
TITLE:
Analysis of Design and Of f-Normal Transients and Accident (Section 2.1.9)
NRC POSITION Analyses, procedures, and training addressing the following are required:
1.
Small break loss-of-coolant accidents; 2.
Inadequate core cooling; and 3.
Transients and accidents.
Some analysis requirements for small breaks have already been specified by the Bulletins and Orders Task Force.
These should be completed.
In addition, pretest calculations of some of the Loss of Fluid Test (LOFT) small break tests (scheduled to start in September 1979) shall be performed as means to verify the analyses performed in support of the small break emergency procedures and in support of an eventual long term verification of compliance with Appendix K of 10 CFR Part 50.
In the analyses of inadequate core cooling, the following conditions shall be analyzed using realistic (best-estimate) methods:
1.
Low reactor coolant system inventory (two examples will be required -
LOCA with forced flow, LOCA without forced flow).
2.
Loss of natural circulation (due to loss of heat sink).
These calculations shall include the period of time during which inadequate core cooling is approached as well as the period of time during which in-adequate core cooling exists.
The calculations shall be carried out in real time far enough that all important phenomena and instrument indications are included.
Each case should then be repeated taking credit for correct opera-tor action.
These additional cases will provide the basis for developing copropriate emergency procedures.
These calculations should also provide the analytical basin for the design of any additional instrumentation needed to provide operators with an unambiguous indication of vessel water level and core cooling adequacy (see Section 2.1.3.b in this appendix).
The analyses of transients and accidents shall include the design basis events specifits in Section 15 of each FSAR.
The analyses shall include a single active failure for each system called upon to function for a particular event.
Consequential failures shall also be considered.
Failures of the operators to perform required control manipulations shall be given consideration for permutaticns of the analyses.
Operator actions that could cause the complete loss of function of a safety system shall also be considered.
At present, these analyses need not address passive failures or multiple system failures in the short term.
In the recent analysis of small break LOCAs, complete loss of auxiliary feedwater was considered.
The complete loss of auxiliary feedwater may be added to the failures being considered in the analysis of transients and accidents if it is concluded that more is needed in operator training beyond the short-term actions to upgrade auxiliary feedwater system reliability.
Similarly, in the long term, multiple failures and passive failures may be considered depending in part on staf f review of the results of the short-term analyses.
26
2.1.9. page 2 The transient and accident analyses shall include event tree analyses, which are supplemented by computec calculations for these cases in which the system response to operator actions is unclear or these calculations could be used to provide important quantitative information not available from an event tree.
For example, failure to initiate high-pressure injection could lead to core uncovery for some transients, and a computer calculation could provide information on the amount of time available for corrective action.
Reactor simulators may provide some information in defining the event trees and would be useful in studying the information available to the operators. The transient and accident analysis are to be performed for the purpose of identifying appropriate and inappropriate operator actions relating to important safety considerations such as natural circulation, prevention of core uncovery, and prevention of more serious accidents.
The information derived from the preceding analyses shall be included in the plant emergency procedures and operator training.
It is expected that analyses performed by the NSSS vendors shall be put in the form of emergency procedure guidelines and that the changes in the procedures will be implemented by each licensee or applicant.
In addition to the analyses performed by the reactor vendors, analyses of seleated transients should be performed by the NRC Office of Research, using the best available computer codes, to provide the basis for comparisons with the annlytical methods being used by the reactor vendors.
These comparisons together with comparisons to data, including LOFT small break test doua, will constitute the short-term verification ef fort to assure the adequacy of the analytical methods being used to generate emergency procedures.
RESPONSE
Included in the scope of work authorized by the Westinghouse owners group are a variety of transient and accident analyses which are being pe:. formed in response to NRC requests.
Small break loss-of-coolant accident analyses results entitled " Report on Small Break Accident for Westinghouse NSSS System" were forwarded to the NRC on June 29, 19 79.
We have received your comments regarding the June 29, 19 79 submittal and will provide the additional information requested as soon as possibic.
Additional analyses are now in progress to assess certain transient and accident conditions and the impact of various operator actions.
Operating and emergency procedures are being reviewed and revised based on analyses results to improve operator diagnosis and perfornance under accident conditions.
Information derived from these analyses and procedure reviews will be included in operator training and retraining programs.
We will continue to support the users' group and to authorize those analyses required to address your concerns.
However, additional discussions between representatives of the users' group and the NRC will be necessary to establish a more clearly defined scope of analyses.
27
TITLE: Shif t Supervisors Responsibilities (Section 2.2.1.a)
NRC POSITION 1.
The highest level of corporate management of each licensee shall issue and periodically reissue a management directive that emphasizes the primary management responsibility of the shif t supervisor for safe operation of the plant under all conditions on his shift and that clearly establishes his command duties.
2.
Plant procedures shall be reviewed to assure that the duties, responsi-bilities, and authority of the shif t supervisor and control room operators are properly defined to effect the establishment of a definite line of command and clear delineation of the command decision authority of the shif t supervisor in the control room relative to other plant management personnel.
Particular emphasis shall be placed on the following:
a.
The responsibility and authority of the shif t supervisor shall be to maintain the broadest perspective of operational conditions affecting the safety of the plant as a matter of highest priority at all times when on duty in the control room.
The idea shall be reinforced that the shif t supervisor should not become totally involved in any single operation in times of emergency when multiple operations are required in the control room.
b.
The shif t supervisor, until properly relieved, shall remain in the control room at all times during accident situations to direct the activities of control room operators.
Persons authorized to relieve the shift supervisor shall be specified.
c.
If the shif t supervisor is temporarily absent from the control room during routine operations, a lead control room operator shall be designated to assume the control room command function.
These temporary duties, responsibilities, and authority shall be clearly specified.
3.
Training programs for shif t supervisors shall emphasize and reinforce the responsibility for safe operation and the management function the shift supervisor is to provide for assuring safety.
4.
The administrative duties of the shif t supervisor shall be reviewed by the senior officer of each utility responsible for plant operations.
Administrative functions that detract from or are subordinate to the management responsibility for assuring the safe operation of the plant shall be delegated to other operations personnel not on duty in the control room.
RESPONSE
1.)
A directive will be issued by the company president which emphasizes the primary management responsibility of the shift supervisor for safe operation of the plant under all conditions and clearly establishes his command duties.
28
2.2.1.a page 2 2a,b,6c.)
Existing administrative procedures delineate the responsibilities of station supervisory and operations personnel, including the authority of the shift supervisor.
These procedures will be reviewed and revised to include or emphasize the points cited in your position.
In addition, we will increase shift staffing by adding a SR0 to allow the shift supervisor to maintain a broader oversight of plant safety and operating conditions.
Shift staffing will then include two SRO's for one unit operation and three SRO's for two unit operation.
At least one of these senior reactor operators will be in the control room at all times.
The shif t supervisor will maintain an overview of plant conditions, make decisions regarding plant operations, and direct the actions of the control room operators.
3.
Training programs for shif t supervisors and SRO's will be improved to provide greater emphasis on and reinforcement of the responsibility for safe operation and the management function the shif t supervisor is to provide for assuring safety.
Additional details on this training are included in our response to your position on Shif t Technical Advisors.
4 The administrative duties of the shif t supervisor will be reviewed by our Director of Nuclear Operations.
Additional control room canning, as discussed above, will allow the delegation of routine administrative duties to other control room personnel.
29
TITLE:
Shif t Technical Advisor (Section 2.2.1.b)
NRC POSITION Each licenset shall provide an on-shif t technical advisor to the shif t super-visor.
The shif t technical advisor may serve more than one unit at a multi-unit site if qualified to perform the advisor function for the various units.
The shift technical advisor shall have a bachelor's degree or equivalent in a scientific or engineering discipline and have received specific training in the response and analysis of the plant for transients and accidents.
The shif t technical advisor shall also receive training in plant design and la yout, including the capabilities of instrumentation and controls in the control room. The licensee shall assign normal duties to the shift technical advisors that pertain to the engineering aspects of assuring safe operations of the plant, including the review and evaluation of operating experience.
RESPONSE
We do not believe that the proposed Shif t Technical Advisor represents the most effective means to provide the requisite expertise in the diagnosis of off normal conditions.
We believe that this expertise can best be provided by upgrading senior reactor operator training and by augmenting the shif t complemen with one additional senior reactor operator.
Accordingly we intend to institute an advanced training program for senior reactor operators.
This advanced training will include both classroom and simulator instruction in plant design, thermal hydraulics, accident analyses and diagnosis of off normal conditions.
The specific details of this program are under development.
The program will be finalized within 90 days with instruction of current senior reactor operators beginning on or about January 1,1980. As explained in our response to the previous recommendation we intend to increase our shif t staf fing by one SRO to allow the shif t supervisor more time to maintain a comprehensive oversight of plant safety and operating conditions. At 1cass one of the two or three SR0's or shif t will have completed this advanced training.
Generally, this will be the shif t supervisor. We believe that these two tions address the concerns expressed in your discussion with the clear advantage of combining the diagnostic expertise and command authority in one individual.
30
TITLE: Shif t and Relief Turnover Procedures (Section 2.2.1.c.)
NRC POSITION The licensees shall review and revise as necessary the plant procedure for shif t and relief turnover to assure the following:
1.
A checklist shall be provided for the oncoming and offgoing control room operators and the oncoming shif t supervisor to complete and '
sign.
The following items, as a minimum, shall be included in the checklist:
Assurance that critical plant parameters are within s lowable a.
limits (parameters and allowable limito shall be listed on the checklist).
b.
Assurance of availability and proper alignment of all systems essential to the prevention and mitigation of operational transients and accidents by a check of the control console (what to check and criteria for acceptable status shall be included on the checklist);
Identification of systems and components that are in a degraded c.
mode of operation permitted by the Technical Specifications.
For such systems and components, the length of time in the degraded mode shall be compared with the Technical Specifications action statement (this shall be recorded as a separate entry on the checklist).
2.
Checklists or logs shall be provided for completion by the of fgoing and oncoming auxiliary operators and technicians.
Such checklists or logs shall include any equipment under maintenance of test that by themselves could degrade a system critical to the prevention and mitigation of operational transients and accidents or initiate an operational transients (what to check and criteria for acceptable status shall be included on the checklist); and 3.
A system shall be established to evaluate the effectiveness of the shif t and relief turnover procedure (for example, pericdic indepen-dent verification of system alignments).
RESPONSE
Presently Administrative Procedures outline the requi.:crants for shif t turnover.
This procedure shall be revised to incorporata signed off check-lists to verify that systems important to safety are not in a degraded mode.
The checklist will verify that primary plant parameters are in a normal band, and system alignment (ie. breaker controls and valve switches) is in accordance with the requirements of the mode of operation which the Unit is in.
The checklist will require that the action Statement status log be reviewed with a verification of the time remaining until the Limiting Condition of Operation must be satisfied or the mode of operation changed.
31
2.2.1.c page 2 Checklists will be implemented for the auxiliary operating stations which will require that they list maintenance activities in their area on safety related systems which could effect plant operation.
The checklists will require the signature of the oncoming and of fgoing operator in each area and the oncoming shift supervisor.
These checklists will be implemented on or about October 15, 1979.
The company quality assurance department conducts periodic audits and inspections to verify compliance with administrative controls including shift ture ier procedures.
32
TITLE: Control Room Access (Section 2.2.2.a.)
NRC POSITION The licensee shall make provisions for limiting access to the control room to those individuals responsible for the direct operation of the nuclear power plant (e.g., operations supervisor, shif t supervisor, and control room operators), to technical advisors who may be requested or required to support the operation, and to predesignated NRC personnel.
Provisions shall include the following:
1.
Develop and implement an administrative procedure that establishes the authority and responsibility of the person in checge of the control room to limit access.
2.
Develop and implement procedures that establish a cicar line of authority and responsibility in the control room in the event of an emergency. The line of succession for the person in charge of the control room shall be established and linited to persons possessing a current senior reactor operator's license.
The plan shall clearly define the lines of communi-cation and authority for plant management personnel not in direct command of operations, including those who report to stations outside of the control room.
RESPONSE
Existing administrative procedures establish the line of authority from the Station bbnager through the Superintendent Operations, Operating Supervisor and the Shif t Supervisor. The procedure is explicit in that it states that "the shift supervisor has the responsibility of directing the actions of the station operators, to ensure safe and prudent operation of the facility".
The Superintendent Operations, Operating Supervisor, Shif t Supervisors and the Assistant Shif t Supervisors are SRO's as morAated by Technical Specifi-cation 6.2.2.
The administrative procaduraa vill be changed to establish that the Shift Supervisor or Assistant Shif t Supervisor has the authority and the responsi-bility to limit access to the control room during normal as well as emergency situations.
The administrative procedure will establish clear lines of authority and responsibility during emergency situations. Those persons in charge of the control room and with the authority to direct control room operations, shall be limited to Senior Reactor Operator licensed persons. The administrative procedure will clearly define the lines of communication and authority for plant management personnel not in direct cormand of operations, including these who report to stations outside of the control room.
The administrative procedure will clearly limit access to those individuals responsible for direct operation of the station plus other technical advisors as needed by operations.
Technical advisors, including NRC personnel, will be limited in number during any emergency or normal conditions.
NRC:b!15 33
TITLE:
Onsite Technical Support Center (Section 2.2.2.t._)_
NRC POSITION Each operating nuclear power plant shall maintain an onsite technical support center separate from and in close proximity to the control room that has the capability to display and transmit plant status to those individuals who are knowledgeable of and responsible for engineering and management support of reactor operations in the event of an accident. The center shall be habitable to the same degree as the control room for postulated accident conditions.
The licensee shall revise his emergency plans as necessary to incorporate the role and location of the technical support center.
A complete set of as-built drawings and other records, as described in ANSI N45. 2.9 -19 74, shall be properly stored and filed at tne site and accessible to the technical support center under emergency conditions.
These documents shall include, but not be limited to, general arrangement drawings, P& ids, piping system isometrics, electrical schematics, and photographs of components installed without layout specifications (e.g., ficid-run piping and instrument tubing).
RESPONSE
The Onsite Technical Support Center will be established in the Records Building.
The Records Building is adjacent to the power station inside the protected security area.
The Records Building has a complete controlled set of drawings, technical manuals and other records which are properly stored and accessible.
Cccounications will be upgraded by establishing both NRC phone systems in the building as well as placing adequate commercial phones in the Center.
The station PA system will also be available in the Center.
The Emergency Plan and Emergency Plan Impicmenting Procedures (EPIP's) will be revised to incorporate the role of the Technical Support Center. The Onsite Technical Support Center will be established as soon as possible, but no later than January 1, 1980.
The Emergercy Plan and EPIP's will be updated to reflect these changes by January 1,1980.
Engineering studies will be cade to determine the location of the Onsite Technical Support Center on a long term basis since habitability requirements to the same degree as that of the control room are not available in the Records Building.
4 34 NRC:M12
TITLE:
Onsite Operational Support Center (Section 2.2.2.c.)
NRC POSITION An area to be designated as the onsite operational support center shall be established.
It shall be separate from the control room and shall be the place to which the operations support personnel will report in an emergency situation.
Communications with the control room shall be provided. The emergency plan shall be revised to reflect the existence of the center and to establish the methods and lines of communication and management.
RESPONSE
Places of assembly at the onset of an emergency are designated by the Emergency Plan Implementing Procedures (EPIP's).
The Emergency Director will announce that all persons are to report to their normal place of assembly for account-ability.
This plan of action immediately establishes a situation whereby the shif t supervisor or the Emergency Director can locate the needed assistance; i.e. H. P. Techs in the H. P. of fice, instrument techs in the instrument shop, etc.
The procedures will be changed whereby operaters not required for control room operations will gather in the plant asr,embly room unless performing an operations function outside of the control room or otherwise instructed by the Shif t Supervisor.
Existing procedures now instruct other emergency teams such as the fire brigade and the first aid teams to assemble in the plant assembly room so as to be readily accessible to the Emergency Director.
Other support groups such as Health Physics, Instrument Technicians, Chemistry Technicians, Engineers, and the maintenance personnel will assemble in their respective work areas.
Explicit instructions will be included in the revised EPIP's that prohibits their entry into the control room unless requested by the shif t supervisor.
All of the above areas are served by adequate communications including commercial intraplant telephone and the station PA system. An intraplant telephone will be installed in the cafeteria to allow better communications from the Control Room to the Operations Support Center. A station FA system is already available.
Procedures will be revised to reflect the above changes by January 1,1980.
35 NRC:M14
TITLE:
Revised Limiting Conditions for Operation of Nuclear Power Plants Based Upon Safety System Availability (Section 2.2.3)
NRC POSTION All NRC nuclear plant licensees shall provide information to define a limiting operational condition based on a threshold of complete loss of safety function.
Identification of a human or operational error that prevents or could prevent the accomplishment of a safety function required by NRC regulations and analyzed in the license application shall re. quire placemant of the plant in a hot shutdown condition within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> and in a cold shutdown condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
The loss of operability of a safety function shall include consideration of the necessary instrumentation, controls, emergency electrical power sources, cooling or seal water, lubrication, operating procedures, maintenance procedures, test procedures and operator interface with the system, which must also be capable of performing their auxiliary or supporting functions.
The limiting conditions for operation shall define the minimum safety functions for modes 1, 2, 3, 4, and 5 of operation.
The limiting conditions of operation shall require the following:
1.
If the plant is critical, restore the safety function (if possible) and place the plant in a hot shutdown condition within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.
2.
Within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, bring the plant to cold shutdown.
3.
Determine the cause of the loss of operability of the safety function.
Organizational accountability for the loss of operability of the safety system shall be established.
4.
Determine corrective actions and measures to prevent recurrence of the specific loss of operability for the particular safety function and generally for any safety function.
5.
Report the event within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> by telephone and confirm by telegraph, mailgram, or facsimile transmission to the Director of the Regional Office, or his designee.
6.
Prepare and deliver a Special Report to the NRC's Director of Nuclear Reactor Regulation and to the Director of the appropriate regional of fice of the Of fice of Inspection and Enforcement. The report shall contain the results of steps 3 and 4, above, along with a basis for allowing the plant to return to power operation.
The senior corporate executive of the licensee responsible and accountable for safe plant operation shall deliver and discuss the contents of the report in a public meeting with the Office of Nuclear Reactor Regulation and the Office of Inspection and Enforcement at a location to be chosen by the Director of Nuclear Reactor Regulation.
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,e a
2.2.3 page 2 7.
A finding of adequacy of the licensee's Special Report by the Director of Nuclear Reactor Regulation will be required before the licensee returns the plant to power.
RESPONSE
We share your concerns and your objective of reducing the frequency of human or operational errors resulting in loss of safety system functions.
- However, we do not believe that the license condition proposed is the best or only way to improve operational reliability.
We propose the following limiting condition for operations.
A total loss of a safety function would involve the complete loss of one of more of the following:
High Head Safety Injection Low Head Safety Injection Quench Spray Containment Recirculation Spray Auxiliary Feed Water Containment Isolation Actuation Whenever there is the absolute loss of one or more of these safety functions in operational Modes 1 or 2, due to human or operational error, we will act proeptly to restore that function, and if that is not possible, the unit will be placed in at least HOT STANDBY within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, HOT SHUTDOWN in 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Any such event will be reported to the Director of the NRC Region II Of fice of Inspection and Enforcement, or his designee within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The Senior Vice President-Power end Vice President-Power Supply and Production Operations will arrange to meet promptly with the Director of Nuclear Reactor Regulation, and the Director of Region II Inspection and Enforcement Office to discuss the event and corrective actions to prevent recurrence.
A follow-up report of any such event will be prepared and forwarded within 14 days to the Director of Nuclear Reactor Regulation and to the Director of the Region II Office of Inspection and Enforcement. The report will contain a complete description of the cause of the loss of the safety function, the corrective action (s) required, and the measures to prevent recurrence of the loss of function along with a basis for allowing the plant to continue to operate.
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