ML17317B181
| ML17317B181 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 05/01/1979 |
| From: | Dolan J INDIANA MICHIGAN POWER CO. |
| To: | James Keppler NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| References | |
| AEP:NRC:00185, AEP:NRC:185, NUDOCS 7905150345 | |
| Download: ML17317B181 (26) | |
Text
INDIANA I MICHiGAN POWER COMPANY P. O. BOX 18 BOWLING GRE EN STATION NEW YORK, N. Y. 10004
= May 1, 1979 AEP: NRC: 00185 Donald C.
Cook Nuclear Plant Units 1 and 2
Docket Nos.
50-315 and 50-316 License Nos.
OPR-00 and DPR-74 Mr. J.
G. Keppler, Regional Director U.
S. Nuclear Regulatory Commission Office of Inspection and Enforcement Region III 799 Roosevelt Road Glen Ellyn, Illinois 60137
Dear Mr. Keppler:
The purpose of this letter is to provide responses to the Nuclear Regulatory Commission's IE Bulletin No.79-06A, Revision 1 which we received on April 23, 1979.
The responses to Items 1 through 12 of the Bulletin are contained in the attached enclosure.
We in the New York office as well as our Cook Plant management have reviewed the circumstances and chronology of the Three Mile Island Unit 2 loss of feedwater accident.
The NRC IE Bulletins and meetings with the NRC Staff have been very helpful in our review and understanding of the Three Mile Island Plant accident.
This event was indeed unfortunate, but we stand to benefit from the lessons learned from the incident.
We would like to discuss some of the major differences that exist between the Westinghouse (W) design employed at the Cook Plant and the Babcock 8 Wilcox (BSW) design of the Three Mile Island Plant.
First, the reactor would have tripped immediately upon the turbine trip.
This occurs as long as either the reactor thermal power or the turbine power is above 10/.
Operability requirements for these channels of the reactor protection system are part of our Technical Specifications.
There are a number of reactor trip circuits that are initiated by a departure from normal feedwater flow, water levels in the steam generators, or a trip of the turbine generator.
The turbine, the generator and the reactor are interlocked to trip each other.
A second difference is the Westinghouse steam generator designs Cook' four steam generators are of the recirculation, U-tube type, with steam being produced at saturated conditions.
A conservative estimate tells us that the amount of latent heat needed to dry up our steam generators is 7 905 150 8 f~
- t' 1979
Mr. J.
G. Keppler AEP:NRC:00185 approximately 4.5 times larger than the amount needed to do the same in the BLW design.
This difference is partly responsible for the longer time needed to uncover the reactor core in the Westinghouse design.
Finally when a Phase A containment isolation is initiated (caused by Safety Injection signal derived from the Reactor Protection System and/or Containment Pressure
- High at 1.2 psi ), the sump pumps become isolated.
After isolation, these pumps do not become operable automatically; that is, operator action is required after either Safety Injection or Containment Isolation is reset.
Cook's design would have made more difficult the primary coolant transfer without operator knowledge that took place in TMI-2 from inside the containment to the Auxiliary Building.
We believe our technical staff is competent and well-prepared.
We do,
- however, recognize the need to continuously seek further improvement.
I consider the Cook Plant personnel of very high quality and quite capable of operating a nuclear plant.
Your staff is fami liar with the Cook Plant's daily operations; your resident inspectors have been helpful to us in achieving our present level of performance.
In closing, we would add our belief that nuclear power represents an acceptable and needed source of electric energy for at least the next two decades.
Rather than discourage its growth or use because of the Three Mile Island incident, we would be better off to learn how to make nuclear power safer and of further service to our economic well-being.
Very truly yours, JED:em Attachment ohn E. Dolan ice President Sworn and subscribed to before me this
~'-'day of May, 1979 in New York County, New York Notary Public fASK II
Nr. J.
G. Keppler AEP:NRC:00185 cc:
R.
C. Callen G. Charnoff R.
W. Jurgensen D.
V. Shaller - Bridgman N.
C. Noseley -
NRC
DONALD C.
COOK NUCLEAR PLANT
RESPONSE
TO IE BULLE IH 79-06A, REV.
1 NRC ACTION 1.
Review the description of circumstances described in Enclosure 1 of IE Bulletin 79-05 and the preliminary chronology of the TYiI-2 3/28/79 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 blocking of both auxiliary feedwater trains at the Three !lile Island Unit 2 plant and other actions taken during the early phases o
the accident; (2) the apparent operational errors which led to the eventual core da -.age; (3) that the potertial
- exists, under certain accident or transient conditions, to have a water level in the pressurizer simultaneously with the reactor vessel not full of water; and (4) the necessity to systematically analyze plant conditions and parameters and take appropriate co. rective 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 7a.);
and (2) not make operational decisions based solely on a single plant parameter indication: hen one or more confirmatory indications are available.
c.
All licensed operators and plant management and supervisors with operational responsibilities shall participate in this review and such participation shall be documented in plant records.
AEP
RESPONSE
On April 5,
- 1979, two members of the AEPSC Nuclear Engineering Division and the Cook Plant Operations Superintendent participated in a meeting at Westinghouse Electric Corporation offices, along with other utilities operating Westinghouse PHR's, to review the events which transpired during the Three Nile Island incident and their impact on Westinghouse PWR's.
Review meetings with the four operating groups or shifts were held by the Operations Superintendent on April 10, ll, 12 and 14, 1979.
Even though these were conducted prior to the date of this IE Bulletin, the requested review material was used and it was reviewed in detail.
Also reviewed was a letter from Westinghouse to AEP dated April 2,
- 1979, This letter contained preliminary recommendations related to the TMI incident.
Attending these meetings were all Licensed Shift Operators with the exception of two who were on, vacation, Also attending were five Senior Licensed Personrel who are not assigned to the rotating shifts.
On April 18, 1979, l1essrs.
John Streeter and Robert Campbell of the NRC were at the Cook Plant and three meetings were held in which ter.
Streeter made a very detailed review of the sequence of events thai occurred at Tt/1-2 including the NRC observations of importance to operating personnel.
These meetings were attended by a total of 116 persons in the following categories:
Licensed Personnel Assigned to Rotating Shifts 29 Licensed Personnel Not Assigned to Potating Shifts 11 Non-Licensed Operating Personnel Assigned to Rotating Shirts 34 Non-Licensed Operating Personnel Assigned to Training 9
Balance of Plan'. Personnel 24 Corporate 0 fic
, Ft.
- Wayne, Indiana 2
Corporate
- Office,
.",ew York, New York 4
NRC On-Site Inspectors 2
Alloperations personnel, except two licensed and two non-licensed, assigned to rotating shifts attended the NRC review.
Since then, onsite inspector Robert hasse has reviewed the events that occurred at THI-2 with these four people's On April 11 and 26, AEPSC personnel attended meetings called by the NRC in their Bethesda, t1d. offices to discuss with Westinghouse and utilities opera ing Westinghouse NSSS plants, the impact of the Three Yiile Island accident on design and operation of the Westinghouse NSSS plants.
A task force of AEPSC and Cook Plant personnel was formed on April 9, 1979 to study the loss of feedwater flow transient at the Three tlile Island Plant and to evaluate the Cook Plant design, procedures and training against the Tt~iI. incident for potential impact.
The task force has had several meetings with AEP and Cook Plant management to discuss their findings to date.
1.a This entire paragraph was stressed in both sets of meetings at ~
the Cook Plant on April 10-14 and 18 as follows:
(1) During the chronological review when the Auxiliary Feed Pumps started without delivery of water it was explained what was thought to be the cause and why it took 8 minutes into the accident to establish flow.
(2) The largest apparent errors during the transient were the tripping of Reactor Coolant
An explanation of why the open relief valve was not isolated until 2.3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> into the accident could not be
established.
(3) It was explained that a void forming any-where in the Reactor Coolant System would have to displace water into the pressurizer and as such pressurizer level would not be a true indication of total system inventory.
(4) It was explained that it is necessary for the operator to look at many confirmatory parameters before making decisions.
The operator will use pressure and temperature readings to determine margin to the saturation point.
1.b Personnel were told (1) not to override automatic engineered safety features actions unless the cause is knoi n and corrected, and (2) was a restatement of l.a(4).
On April 7, 1979 a Standing Order w."s issued by the Cook Plant Operations Superintendent to the Shift Operatirg Engineers instructing them to manually initiate sa,ety injection with an uncontrolled reac.or coolant system pressure reduction when the pressurizer pressure reaches the low pressure setpoint for safety injection ac'uation regardless of pressurizer water level.
On April 26, 1979 the pressurizer low water level histables were placed in the tripped position, after a complete study of the effects of doing so were made.
Safety injection actuation will occur automatically on pressurizer l.ow pressure regardless of the pressurizer water level signals. 'his matter is discussed further in the response to Item 3.
1.c Detailed review of the meetings with four operating shifts is documented and the attendance lists of the NRC review meetings are in the Plant files.
Yir. Streeter also reviewed Bulletin 79-06A at the April 18, 1979 meetings.
NRC ACTION 2.
Review the actions requi red by your operating procedures for coping with transients and accidents, with particular attention to:
a.
Recognition of the possibility of forming voids in the primary coolant system large enough to compromise the core cooling capability, especially natural circulation capability.
b.
Operation action required to prevent the formation of such voids.
c.
Operator action required to enhance core cooling in the event such voids are formed. (e.g.,
remote venting)
AEP RESPOND'USE 2.a The primary indication of void formation in the primary coolant system is when the pressurizer pressure falls below the hot leg saturation pressure.
However, during a loss of coolant event, void formation in the primary coolant system would be expected with two exceptions:
( I) the loss of coolant is being caused by a stuck open pressurizer relief valve which closes or is isolated before the system depressurizes to hot leg saturation, or, (2) the reactor coolant system reaches an equilibrium pressure above hot leg saturation, when the safety injection flow equals the break flow.
Thus, in these two specific cases, confirmation of no voids in the system will be apparent by the pressure in the pressurizer.
In the remaining cases the engineered safeguards system has been designed to cope with voiding.
Thus, it is not necessary to be able to recognize void formation in those cases.
2.b These will be discussed as appropriate under Emergency Operating Procedures.
Immediate actions, prior to diagnosis of the specific accident classification, which tend to prevent formation of voids, include:
2.
3.
4.
Verify that reactor trip and 'safety injection have occurred Verify that residual heat is being dissipated; that is, reactor coolant temperature is not increasing.
Verify that feedwater is being supplied to the steam generators.
Operator action should be taken to maintain a water level in the pressurizer by charging and emergency makeup control, dissipate residual heat through the steam generators and maintain an indicated water level in all steam generators not directly affected by the accident.
ITEM 2
<<2 For some LOCA cases, no operator action will prevent the formation of voids in the primary coolant system.
The emergency safeguards system was designed to recover and cool the core following various degrees of primary coolant system voiding, depending on the break size and location.
2.c From the review of the TMI-2 events, all operators have been instructed as to the importance of keeping Reactor Coolant System pressure greater than the saturation temperature of the hottest spot to prevent void formation.
This can eitner be accomplished by increasing pressure or decreasing temperature.
This review also included the necessity of adequate feedwater level in Steam Generators for heat removal purposes.
All applicable operating procedures are under review to see that these instructions are contained and/or adequately stress d.
The procedure review a: d any subsequent revisions will be followed with training sessions for all operators for explanation of the procedures in light of'he events that occurred at TMI-2.
Further information on this matter is contained in response to Item 7.b.
Procedure revision and training sessions will be accomplished before July I, 1979.
NRC ACT IG."
3.
For your facilities that use pressurizer water level coincident with pressurizer pressure for auto-:.:atic initiation of safety injec;ion into the reac:o:
coola. i system, trip the low pressurizer level:e--
point bistables such t,.".at, when the p~essur> "er ol essure reac.".~s
-..".=-
low se point, safe.y in'ect on..c;ld be initi;-.tcd rerar"..'iess of pressurizer le.'e The pressuri "er ]e".e] b,s.bi s;..ay be re:"
to theil ror;:al o."era'.i
" posi;ions
='- ri..".
-."= ~ressu"'=" "re-.-.re channel unctio."1 s rveil iance;esses.
Ir. =-"='".'.-icn. ins-.i".c operators o:-an;a.l, in ti:-;e s=.=ty ii'.'==tion wnen;!:e:ress'.:
i===.
pl essul e lndlcation l eac.",es The actuation setpc'.n
'e.'ne:i:el o'.
not the level in"ication ras drc~-ed to
-.he ac.-.ation se:poin;.
AEP RESPO.'lS=
Both D.
C.
Cook Unit's safeguards logic uiilize pressurizer vater level coincident with pressurizer pressure for a.tc..'.atic initiation of safety injection.
All Operations personnel were instructed to manually initiate safety injection during normal operation when th
.pressurizer pressure indication reaches the actuation setpoint, regardless of pressurizer
- level, on April 7, 1979.
Following a review of the system o ensure that no other functions were associated with the low pressurizer level setpoint bistables, these bistables were placed in the trip position on April 26,
- 1979, on Unit 2.
This was not done on Unit
'. as it is presently in refueling; however, all procedures for both units were revised to reflect this change and Unit 1 bistables will be placed in the trip'osition prior to entering the appropriate operating mode.
Procedural revisions include returning all the bistables to normal operating positions during channel functional surveillance testing of thc pressurizer pressure channels.
In addition, Technical Specifications on Unit 2 require that the low pressurizer pressure setpoint for safety injection be set at '900 psig and the P-11 permissive be set at '915 psig.
With a 1'.; lockup on the P-11 bistables, the reset point for this bistable during unit cooldown is 1907 psig.
This allows only a 7 psig increment, with no allowance for bistable drift, for manually blocking safety injection during cooldown.
As we consider this situation unaccept-able for Unit 2, the pressurizer level bistables will be returned to their normal operating position at a pressurizer pressure of < 2000 psig during unit cooldown, until a change in the P-. 11 setpoint Technical Specification=
can be obtained.
These immediate changes are considered only a short term solution as the resulting condition would enable a single pressurizer pressure trans-mitter failure to initiate safety injection.
Studies are presently under-way to evaluate long term solutions to the problem, including logic revisions to initiate safety injection with a 2/3 pressurizer pressure signal rather than the existing 1/3 logic caused by tripping the low pressurizer level bistables.
NRC ACTION 4.
Review the containment isolation initiation design and procedures, and prepare and implement all changes necessary to permit 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.
AEP
RESPONSE
Phase A containment isolation is automatically initiated by a safety injection signal derived from the Reactor Protection System and/or Containment Pressure
- High at 1.2 psi.
Phase A isolation can be manually initiated at any time.
Isolation valves cannot be reopened by manipulation of control switches while the isolation actuation is tripped.
The Phase containment isolation ac.uation may be reset by the Operator by operation of the "Reset" pushbutton on the control panel.
Resetting the containment isolation will no:,
by itself, reopen valves closed by the containment isolation actuation.
After the containment isolation actuation has been reset, a valve may only be reopened by first operating its control switch to the "closed" posi tion and then to the "open" position.
Containment Isolation Phase A may be initiated by the operator at any time whether it had been previously reset or not.
Containment Isolation Phase B is initiated by containment pressure greater than 3
psi All lines enteri ng or leaving the containment are isolated except those required for reactor core cooling.
Valves closed by Phase B isolation operate in the same manner as
.hose closed for Pnase A
isolation.
Further information is contained in our responses to items 7.a and 9.
Further review of containment isolation is underway since, in light of certain events at THI-2, it may be desirable to operate additional equipment.
This operation may not be possible now because either the equipment itself or a supporting system for that piece of equipment is isolated on Phase A or B.
NRC ACTION 5.
For facilities for which the auxiliary feedwater system is not automatically initiated, prepare and implement immediately procedures which require the stationing of an individual (with no other assigned concurrent duties and in direct and continuous communication with the control room) to promptly initiate adequate auxiliary feed. rater to the steam generator(s) for those transients or accidents the consequences of which can be limited by such action.
AEP
RESPONSE
The auxiliary feedwater system at the Donald C.
Cook Nuclear Plant is automatically initiated upon receipt of an :ctuation signal that requires it to function.
Therefore, action item 5 is not applicable.
NRC ACT IOH 6.
For your facilities, prepare and implement irrmediately procedures which:
a
~
b.
Identify those plant indications (such as valve discharge piping temperature, valve position indication, or valve discharge relief tank temperature or pressure indication) which plant operators may utilize to determine that pressurizer power operated relief valve(s) are open, and Direct the plant operators to manually close the power operated relief block val ve(s) when reactor coolant system pressure is reduced to below the set point for normal automatic closure of the power opera.ed relief valve(s) and the val ve(s) remain stuck open.
AEP RESPONSE 6.a.
6.b.
Each Cook unit has three pressurizer power operated relief valves (PORV).
Each of these three-inch valves can be isolated with a normally open three-inch motor operated block valve in series with it.
The power operated relief valves and the motor operated block valves have individual control switches on the control panels in the Control Room which provide manual operation and also indication of open and close by limit switches.
The lines with each pair of valves come together into a common six-inch header where discharge temperature is measured.
Temperature is displayed on the control panel in the Control Room and an alarm sounds on high temperature.
This six-inch line is headered together with lines from the three safety valves which also have similar indications and alarm on discharge temperature.
The power operated relief valves and safety valves discharge through a
common 12-inch header to the Pressurizer Relief Tank.
This tank is monitored on the control panels in the Control Room for liquid temperature, pressure and level.
Alarms are provided for excessive temperature, excessive pressure and high and low level.
In addition, if a pressurizer power operated relief valve opens, the condition is alarmed.
All of these multiple indications of a PORV in an open position are currently in our procedures and Operators are directed to close the three-inch motor operated block valves.
NRC ACTION 7.
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 plant conditions.
For example, if continued operation of engineered safety features would threaten reactor vessel integrity then the HPI should be secured (as noted in b(2) below).
b.
Operating procedures currently, or are revised to, specify that if the high pressure injection (HPI) system has been automatically actuated because of low pressure condition, it must remain in operation until either:
(I) Both low pressure injection (LPI) pumps are in operation and flowing for 20 minutes or longer; at a rate which would assure stable plant behavior; or (2) The HPI system has been in operation for 20 minutes, and all hot and cold leg temperatures are at least 50 degrees below the saturation temperature for the existing RCS pressure.
If 50 degrees subcooling cannot be maintained after HPI cutoff, the HPI shall be reactivated.
The degree of subcooling beyond 50 degrees F and the length of time HPI is in operation shall be limited by the pressure/temperatJre considerations for the vessel integrity.
c.
Operating procedures currently, or are revised to, specify that in the event of HPI initiation with reactor coolant pumps (RCP) operating, at least one RCP shall remain operating for two loop plants and at least two RCPs shall remain operating for 3 or 4 loop plants as long as the pump(s) is providing forced flow.
d.
Operators are provided additional inforrrlation and instructions to not rely upon pressurizer level indication along, but to also examine pressurizer pressure and other plant parameter indications in evaluating plant conditions, e.g., water, inventory in the reactor primary system.
AEP
RESPONSE
7.a. Operators have always had instructions not to override automatic actions of engineered safety features until the cause has been determined, evaluated and plant conditions have stabilized.
ITEM 7 Further, on January 4,
1979 in response to the NRC letter of November 28,
- 1978, we provided the results of our review of all safety actuation signal circuits which incorporate an override feature and provided additional steps taken to prevent inadvertent overriding of safety actuation circuits.
Our response of January 4,
1979 (AEP:NRC:00114) describes these action: in more detail and subsequent conversations with members of the NRC Staff have adequately addressed the concerns expressed in the
<november 28, 1978 letter which also apply here.
The response to Item 2 of Bulletin 79-06A reiterated the specifics of reset feature for Containment Phase A and Phase B isolation.
Our January 4,
1979 letter describes the reset feature for all those ESF systems which incorporate it.
It is noted that when swi tchover from the injection mode to the recirculation mode is required, folio;ing a design basis LOCA, the SI signal must be reset before this can be accomplished.
Emergency Operating procedures provide adequate instruction to take these actions.
7.b.
From the review of the Tf1I-2 events, all operators have been instructed not to terminate SI without reviewing multiple parameters.
All applicable procedures are under review and revisions will provide specific instructions for terminating SI, such as Reactor Coolant System pressure, 50o sub-cooling of liquid below saturation temperature, adequate steam generator level and adequate pressurizer level.
Procedure revision wi 11 be followed by a training session for all operators for explanation of the revised procedures.
These procedure reviews and training sessions will be accomplished before July 1, 1979.
7.c.
From the review of the TYiI-2 events, operators have been instructed that it is desirable to keep one or two RCP's operating if possible.
All applicable operating procedures are under review and revisions included in these procedures will provide specific instructions as to pressure temperature relationship, system pressure, cooling water availability and pump vibration.
This will be covered in greater detail in training, sessions prior to July 1, 1979.
7.d.
From the review of the Tt<I-2 events, all operators were instructed that depending on system conditions, a steam bubble could be formed elsewhere in the system which would displace water into the pressurizer.
Under these conditions
ITEh 7
pressurizer level indication would not be a true indication of total system inventory.
Instructions are provided to compare all hot leg and cold leg temperatures to standard steam tables.
A curve has been developed from the steam tables with a line 50o below the saturated pressure curve.
This curve has beer issued to the operators as a guide to determine system conditions.
This will be covered in greater detail in training sessions prior to July 1, 1979.
NRC ACTION 8.
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.
Also review related proce'ures, such as those for maintenance, testing, plant and system star'.up, 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.
AEP
RESPONSE
The valve position requirements for the safety-related systems at the Cook Plant were reviewed in light of the THI-2 incident as follows:
EHERGENCY DIESE!
GENERATORS The Emergency Diesel Generators and all supporting systems are run frequently for required surveillance.
Successful Emergency Diesel Generator operation is a clear indication that valves in the flow paths of all the supporting systems are properly aligned.
Each Emergency Diesel Generator is checked for automatic starting and acceptance of blackout and ECCS loads during each refueling.
The Technical Specification requirements provide further assurance that the Emergency Diesel Generators are operable.
We consider this to be a properly aligned and proven system.
AUXILIARY FEEDWATER SYSTEH This system has been thoroughly reviewed in all aspects such as automatic actuation requirements, flow requirements, power supplies, steam supply, valve positions and operable flow paths.
All manual valves in the flow path are either locked or sealed in proper positions.
The positions of all power operated valves are indicated to the Operator in the Control Room.
The auxiliary feedwater system is used frequently and Operators are completely familiar with its operation.
This system is used during normal unit startup until main feedwater becomes available with steam being supplied from the Steam Generators to the Hain Feedwater Pump Turbines.
The auxiliary feedwater system is then placed in its Automatic Emergency Standby Hode.
Upon a trip the auxiliary feedwater system is automatically actuated and its flow is required to bring the unit to the shutdown condition.
Technical Specification requirements further assure that the auxiliary feedwater system is operable.
We consider this to be a properly aligned and proven system.
ITEfi 8 ESSENTIAL SERVICE MATER AND COMPONENT COOLING WATER SYSTEl>S These are constant in-service operating systems.
All possible flow paths are periodically used.
The positions of all power operated valves are indicated to the Operator in the Control Room.
We consider these to be properly aligned and proven systems.
HIGH HEAD SAFETY INJECTION This system serves a dual function.
For normal operation this system provides the normal Charging and Reactor Coolant Pump seal injection flow.
Under an emergency condition this system provides the High Head Safety Injection flow vith boron injection to the Reactor Coolant System.
There are four manual flow distribution valves in this syste; that are pre-s t an" mechanically locked in position wi th valve
'operators re:-.oved.
The positions of all power operated valves are indicated to the Operator in the Control Room.
Technical Specifica:io requi re.; ents further assure that this system is operable.
We consider this to be a properly aligned and proven system.
INTERllEDIATE HEAD SAFETY INJECTION, LOM HEAD SAFETY INJECTION (RHR)
AND CONTAIil:i HT SPRAY SYSTitl These systems have been totally reviewed and verified that the valve alignment as required by procedure is correct.
The actual valve alignment was then checked against the procedure and no errors were found.
All manual flow path valves are-either locked or sealed in the requi red position.
This alignment check was only made on Unit 2 wnich is operating at power.
On Unit I, these systems will be aligned according to procedure prior to returning the Unit to service following refueling.
Technical Specification requirements further assure that these systems are operable.
We consider these to be fully checked and operable systems.
All surveillance test procedures for safety related systems require verification when a valve is taken out of normal position for test purposes and verification that it is returned to normal position at the completion of the procedure.
When a piece of safety related equipment is returned from maintenance, it is functionally tested and documented.
All power operated valves in the safety related systems are equipped with status lights and these lights are arranged in groups on the control panels.
All normally lit lights are identified so that by a quick survey of the status light groups any mispositioned valve is immediately identified.
This is a required check at the start of each shift with a test that all unlit lights have the ability to light.
NRC ACTION 9.
Review your operating modes and procedures for all systems designed to transfer 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 systems and indicate:
a.
Whether interlocks exist to prevent transfer when high radiation indication exists, and b.
Whether such syste."s are isolated by the containment
'.so'.ation signal.
c.
The basis on >>hich continued operability of the above features is assured.
AEP RESPOND>SE Our current procedures and operating modes, for systems which handle potentially radioactive gases and liquids between the containment and auxiliary building are under review.
In the Cook Plant there are several types of Containment Isolation
- systems, each with different operating features as described below:
a)
Containment Isolation - Phase A
1.
Phase A isolates non-critical lines entering or leaving the Containment.
2.
Automatic initiation of Phase A isolation is caused by a Safety Injection signal derived from the Reactor Protection System and/or Containment Pressure-High at 1.2 psi.
3.
Phase A isolation can be manually initiated from the main control room at any time.
b)
Containment Isolation Phase B
1.
Phase B isolates Non-Essential Service Water to the containment coolers and Component Cooling Water to the Reactor Coolant Pump motor oil coolers.
2.
Phase 8 is automatica'Ily initiated from a containment Pressure-High-High signal which is caused by containment pressure greater than 3 psi.
3.
Phase B isolation can be manually initiated from the main control room at any time.
c)
Containm rt Ventilation Isolation 1.
This isolates all containment ventilation openings which includes purge supply and exhaust and containment pressure relief lines.
2.
Containment Ventilation Isolation is initiated automatica',ly by:
a.
Safety Injection Signal derived from the Reactor Protection System and/or Containment Pressure-High at 1.2 psi.
b.'igh Containment Radiation derived from any of the following monitors:
i)
Containment Air Particulate Yonitor ii)
Containment Radiogas t1onitor iii)
Containment Area tIonitor 3.
Containment Ventilation Isolation can be manually initiated at any time froi: the main control room.
Valves closed by actuation of the above isolation circuits will remain closed if the isolation circuit is blocked or reset by the Operator.
The valves may be reopened by manual operation of the valve control switch aft r isolation actuation is reset.
During standing isolation actuation, the closed valve cannot be reopened by manipulation of the control switch.
All isolation valves operate in this manner except those specifically identified in the systems listed below.
The specific response to 9.a and 9.b is contained in the following list of systems which could transfer potentially radioactive gases or liquids out of the containment.
1.
Steam Generator Blowdown S stem 9.a This system is not interlocked to automatically isolate on a high radiation indication inside containment.
9.b This system is isolated on Phase A containment isolation and/or high radiation in the blowdown itself.
ITEM 9 2.
Containment Sum Pum s
9.a The containment sump pump header is not interlocked to automatically isolate on a high radiation indication inside containment.
9.b The containment sump pump header is isolated on Phase A
Isolation.
In addition, the containment su.".,p pumps are tripped and locked out on closure of the isolation valves.
The sump pumps will not automatically restart after the sump header discharge valves have been reopened by operator action without additional action required to reset the pump lockout and restart the pump.
3.
Pressurizer Relief Tank Dischar e
9.a The pressurizer relief tank discharge line is not interlocked to automatically isolate on a high radiation indication inside containment.
9.b The discharge line is isolated on Phase A containment isolation, 4.
Letdown g.a The letdown line from the Reactor Coolant System is not interlocked to automatically isolate on a high radiation indication inside containment.
9.b The letdown line is isolated on Phase A containment isolation.
5.
Reactor Coolant Pum Seal Water g.a The RCP seal water discharge line is not interlocked to automatically isolate on a highradiation indication inside containment.
9.b The discharge line is isolated on Phase A containment isolation.
6.
Reactor Coolant Drain Tank RCDT Vents g.a The Reactor Coolant Drain Tank vent lines are not interlocked to automatically isolate on a high radiation indication inside containment.
9.b The Reactor Coolant Drain Tank vent lines are isolated on a Phase A containment isolation.
ITEM 9 7.
Reactor Coolant Drain Tank Dischar e
9.a The Reactor, Coolant Drain Tank discharge line is not interlocked to automatically isolate on a high radiation indication inside containment.
9.b The Reactor Coolant Drain Tank discharge line is isolated on a
Phase A containment isolation.
The Peactor Coolant drain pumps are stopped by closure of either of the isolation valves.
8.
Ice Condenser Fan Cooler Drains and the Containment Ventilation Unit Drains 9
9.b These drains are not interlocked to automatically isolate on a high radiation indication inside containment.
These drains isolate on a
Phase A containment isolation.
9.
Miscellaneous Sam le Lines (Gas and Li uid)
The the following is a list of gas or liquid sample lines leaving containment:
i)ii) iii) iv) v)vi) 9.a 9.b Pressurizer liquid space sample Pressurizer steam space sample Two RCS hot leg samples Four Accumulator samples Reactor Coolant Drain Tank gas sample Pressurizer Relief Tank gas sample These sample lines are not interlock to automatically isolate on a high radiation indication inside containment.
These sample lines are isolated on a
Phase A containment isolation.
10.
Containment Atmos here Sam lin S stem 9.a 9.b This system is not interlocked to automatically isolate on a
high radiation indication inside containment.
The containment gas sampling system is isolated by Phase A
Containment Isolation.
The gas sample valves may be reopened after Phase A Isolation without resetting the Phase A
isolation actuation by placing the gas sampling selector switch in the "Bypass" position and then opening the valve by operation of the valve control switch for the purpose of obtaining a containment atmosphere sample.
ITEM 9 ll.
Containment Pur e
S stem 9.a The containment purge supply, purge exhaust and pressure relief valves are interlocked to isolate on a high radiation indication inside containment.
Containment Ventilation Isolation actuation, whose signals are derived from the containment radiation monitors, isolates these lines.
9.b These lines are also automatically isolated by a Safety Injection signal derived from the Reactor Protection System and/or Containment Pressure-High at 1.2 psi.
9.c Continued operability of the above mentioned features is assured througn our procedures and operating modes.
Compliance with our Technical Specifications urther assures continued operability.
NRC ACTION 10.
Review and modify as necessary your maintenance and test procedures to ensure that they require:
a.
Verification, by test or inspection, of the operability of redundant safety-related systems prior to 'the removal of any safety-related system from service.
b.
Verification of the operability of all safety-related systems when they are returned to service following maintenance or testing.
c.
Explicit notification of involved reactor operational personnel whenever a
sa ety-related system is removed from and returned to service.
AEP
RESPONSE
10.a.
No additional testing beyond the established periodic surveillance and testing program is necessary.
Periodic surveillance and testing provides a sufficient level of confidence that redundant systems will function as designed when necessary.
Testing intervals are selected in recognition of the fact that certain equipment may be unavailable on a temporary basis due to maintenance, and restrictions are imposed on the leng+h of time such equipment can be removed from service.
Redundant safety related systems must be in an operable condition for compliance with Technical Specifications.
- Thus, when removing a safety related sys+em from service, the operability of the redundant system is assured.
10.b.
10.c.
The operability of safety related systems when returned to service after maintenance or testing is verified.
See the response to Item 8.
Reactor Operations Personnel are adequately notified when any safety related system equipment is removed from service or returned to service by either the Clearance Permit System or appropriate t1aintenance procedures.
NRC ACTION 11.
Review your prompt reporting procedures for NRC notification to assure that NRC is notified within one hour of the time the reactor is not in a controlled or expected condition of operation.
Further, at that time an open continuous communication channel shall be established and maintained with NRC.
AEP
RESPONSE
An administrative procedure has been issued requiring notification of the NRC Region III within one hour of any operating anomaly when the reactor is not in a controlled or expected condition of operation.
A telephone line dedicated for the purpose of providing a continuous comnunication channel between the plant and the NRC will be installed by June 1, 1979.
NRC ACTION 12.
Review operating modes and procedures to deal with significant amounts of hydrogen oas that
- may, be generated during a transient or other accident that would either remain inside the primary system or be released to the containment.
AEP
RESPONSE
Adequate Plant operating procedures for controlling the hydrogen that is produced in the containment following an accident will be provided.
The design of the hydrogen recombiner system is based on Regulatory Guide 1.7, for the hydrogen produced by corrosion of the aluminum portions of the
- NSSS, by radiolytic decomposi tion of the core cooling and sump solutions, by the reaction of the zirconium fuel cladding with water and by the release of the hydrogen dissolved in the reactor coolant and contained in the pressurizer vapor space.
The hyrdrogen recombiner system consists of two redundant accident qualified electric recombiner units p rmanently installed within the reactor containment which are controlled from the Control Room.
Plant operating instructions are under review to assure adequate post-accident containment sampling circulation, and means of hydrogen removal including venting and operation of recombiners.
Technical Specifications also provide assurance that the hydrogen recombiner system is operable.
Further in ormation is contained in the response to Item 2.
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