ML17053B681
| ML17053B681 | |
| Person / Time | |
|---|---|
| Site: | Nine Mile Point  |
| Issue date: | 05/21/1980 |
| From: | Ippolito T Office of Nuclear Reactor Regulation |
| To: | Dise D NIAGARA MOHAWK POWER CORP. |
| References | |
| IEB-79-08, IEB-79-8, NUDOCS 8006020046 | |
| Download: ML17053B681 (46) | |
Text
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'ocket No.
50-220 We have concluded that you have taken the appropriate actions to meet the requirements'of each of the eleven, action items identified in IE Bulletin 79-08.
A copy,of our evaluation is ehclosed.
As you know, NRC staff review of the Three Mile Island, Unit 2 (TMI-2) accident is continuing and other corrective actions may be required at a later date.. Specific requirements for your facility that result from this review and other TMI-2 investigations will be addressed to you in separate correspondence.
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DRoss EJordan NRR Reading Atty, OELD PBoehnert Local PDR ISE (3)
RFrahm NRC PDR JRBuchanan JGuttman DEi senhut TERA EThrom RTedesco ACRS (16)
B 5 0 File WGammill HDenton WHodges JMiller ECase
.PMatthews DVassallo GMazeti s Vice President - Engineering RVollmer CHeltemes PNorian Niagara Nohawk Power Corporation 300 Erie Boulevard liest TIPPol lto Dzlemann KMahan
- Syracuse, New York 13202 SSheppard ZRosztoczy PPol k OParr
Dear Hr. Disc:
JLee JSto.l z WKane Israel
SUBJECT:
NRC STAFF EVALUATION OF NIAGARA MOHAWK POWER CORPORATION RESPONSES TO IE BULLETIN 79-08 FOR (INE MILE POINT NUCLEAR STATION, UNIT 1 We have completed our review of the information that you provided in your letters responding to IE Bulletin 79-08 for the Nine Mile Point Nuclear Station, Unit l.
Enclosure:
NRC Staff Evaluation
cc w/enclosure:
See next page Thomas A. Ippolito, Chief Operating Reactors Branch 82 Division of Licensing Oo609o%&
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Disc Niagara Mohawk Power Corporation May 21, 1980 CC:
Eugene B. Thomas, Jr.,
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MacRae 1757 N Street, N.
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20036 Anthony Z.
Roisman Natural Resources Defense Council 917 15th Street, N.
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20005 State University College at Oswego Penfield Library - Documents
- Oswego, New York 13126
0
EVALUATION OF LICENSEE'S RESPONSES TO IE BULLETIN 79-08 NIAGARA'OHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION, UNIT 1 DOCKET NO. 50-220
Introduction By letter dated April 14, 1979, we transmitted Office of Inspection and Enforcement (IE)Bulletin 79-08 to Niagara Mohawk Power Corporation (Niagara Mohawk or the licensee).
IE Bulletin 79-08 specified actions to be taken by the licensee to avoid occurrence of an event similar to that which occurred at Three Mile Island, Unit 2 (TMI-2) on March 28, 1979.
By letter dated April 24,
- 1979, the licensee provided responses to Action Items 1 through 10 of IE Bulletin 79-08 for the Nine Mile Point Nuclear Station, Unit 1 (Nine Mile Point 1).
By letter dated May 14,
- 1979, the licensee responded to Action Item ll of IE Bulletin 79-08.
The NRC staff review of the licensee's responses led to the issuance of
-requests for additional information regarding the licensee's responses to certain action items of IE Bulletin 79-08.
These requests were contained in a letter dated July 20, 1979.
By letter dated August 3,
- 1979, the licensee responded to the staff's request for additional information.
The licensee's responses to IE Bulletin 79-08 provided the bases for our evaluation presented below.
In addition, the actions taken by the licensee in response to the bulletin and subsequent NRC requests were verified by onsite inspections by IE inspectors.
Evaluation Each of the ll action items requested by IE Bulletin 79-08 is repeated below followed by our criteria for evaluating the response, a summary of the licensee's response and our evaluation of the response.
1.
Review the description of circumstances described in Enclosure 1 of IE Bulletin 79-05 and the preliminary chronology of the TMI-2 March 28, 1979 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 trains of a safety system at the Three Mile Island Unit 2 plant
and other actions taken during the early phases of the accident; (2) the apparent operational errors which led to the eventual core damage; and (3) the necessity to systematically analyze plant conditions and parameters and take appropriate corrective action.
b.
Operational personnel should be instructed to (1) not override automatic action of engineered safety features unless continued operation of engineered safety features will result in unsafe plant conditions (see Section Ba of this bulletin); and (2) not make operational decisions based solely on a single plant parameter indication when 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.
The licensee's response was evaluated to determine that (1) the scope of review was adequate, (2) operational personnel were properly instructed and (3) personnel participation in the review was documented in plant records.
The licensee's response dated April 24, 1979 described the dissemination of the TMI-2 information to the licensed and non-licensed operators and to the staff of Nine Mile Point l.
In addition, the licensee committed to a formal review of the TMI-2 events as part of its operator requalification program.
By its letter dated August 3, 1979, the licensee indicated the completion of this review and the documentation of same in the station's training records.
By its letter dated April 24,
- 1979, the licensee confirmed the revision of the operating orders (night orders) to require operators to neither override automatic engineered safety features functions nor to rely solely on a single plant parameter indication.
These orders were likewise formally reviewed=and documented in the plant's training records.
We conclude that the licensee's scope of review, instructions to operating personnel and documented participation satisfy the intent of IE Bulletin 79-08, Item l.
2.
Review the containment isolation initiation design and procedures, and prepare and implement all changes necessary to initiate containment
isolation, whether manual or automatic, of all lines whose isolation does not degrade needed safety features or cooling capability, upon automatic initiation of safety injection.
The licensee's response was evaluated to verify that containment isolation initiation design and procedures had been reviewed to assure that (1) manual or automatic initiation of containment isolation occurs on automatic initia-tion of safety injection and (2) all lines (including those designed to transfer radioactive gases or liquids) whose isolation does not degrade cooling capability or needed safety features were addressed.
By its letter dated April 24,
- 1979, the licensee indicated that its review of the design of containment and primary coolant isolation initiation had been completed and no changes were considered necessary.
The Nine Mile Point 1
design provides for automatic safety injection (core spray initiation) on either high drywell pressure or low-low reactor vessel water level.
These signals also initiate the following:
Containment isolation Primary coolant system isolation (main steam,
- cleanup, shutdown cooling)
By its letter dated August 3,
- 1979, the licensee indicated that its review included all lines which penetrate the primary containment.
However, in certain instances, such as the recirculation sample line to the reactor building, isolation would not occur.
By a telephone conversation on November 26,
- 1979, the licensee indicated that the review had been completed.
Subsequent to the licensee's August 3, 1979 submittal, verbal communication with the licensee revealed the need to modify its Technical Specifications to reflect the isolation function of recirculation system sampling lines as well as containment isolation system instrument sensing lines.
The licensee verbally committed to submitting the necessary Technical Specification amendment request.
In the interim, the licensee stated that sampling procedure Nl-SP-ll, "Reactor Water Sampling with Reactor Cleanup System
Isolated,"
ensures that if a reactor coolant isolation signal is obtained, the valve will be immediately closed by the member of the operating staff taking the sample.
The other valve in the line will close automatically on high f1 ow.
We conclude that the licensee's review of containment isolation initiation design and procedures satisfy the intent of IE Bulletin 79-08, Item 2.
3.
Describe the actions, both automatic and manual, necessary for proper functioning of the auxiliary heat removal systems (e. g.,
RCIC) that are used when the main feedwater system is not operable.
For any manual action necessary, describe in summary form the procedure by which this action is taken in a timely sense.
The licensee's response was reviewed to assure that (1) it described the automatic and manual actions necessary for the proper functioning of the auxiliary heat removal systems when the main feedwater system is not operable and (2) the procedures for any necessary manual actions were described in summary form.
By its letter dated April 24,
- 1979, the licensee indicated that the auxiliary heat removal system that would be utilized at Nine Mile Point 1 if the main feedwater system is not operable is the emergency condenser system.
This system has double capacity at times greater than 100 seconds after a reactor trip.
Either half of the emergency condenser system may be independently initiated and isolated.
Isolation of the system is automatically initiated on either high reactor pressure at 1080 psig or low-low reactor water level signals at five inches indicator scale (ten-second time delay).
Upon automatic initiation, the condensate return valves to the reactor (direct current solenoid-operated air valves) open allowing a return path to the reactor.
The system can be manually initiated at any time by opening the condensate return valve from the control room.
Cooldown and pressure control is available by cycling either the condensate return isolation valve or the steam supply isolation valves.
'I
Me conclude that the licensee's procedural summary of automatic/manual actions necessary.for the proper functioning of auxiliary heat removal systems used when the main feedwater system is inoperable satisfies the intent of IE Bulletin 79-08, Item 3.
4.
Describe all uses and types of vessel level indication for both automatic and manual initiation of safety systems.
Describe other redundant instrumentation which the operator might have to give the same informa-tion regarding plant status.
Instruct operators to utilize other available information to initiate safety systems.
The licensee's response was evaluated to determine that (1) all uses and types of vessel level indication for both automatic and manual initiation of safety systems were addressed, (2) it addressed other instrumentation available to the operator to determine changes in reactor coolant inventory and (3) opera-tors were instructed to utilize other available information to initiate safety systems.
By its letter dated April 24,
- 1979, the licensee provided a description of the level instrumentation at Nine Nile Point 1.
Table 1 describes the uses and types of vessel level instrumentation for both manual and automatic initiation of safety systems.
Included is a description of redundant instrumentation which the operator has available to aid in determining plant status.
In addition to the foregoing, the licensee stated in its letter dated August 3, 1979 that the control room operators have many other sources of information that would assist them in determining changes in reactor coolant inventory including the following:
Drywell Temperature Torus Water Temperature Torus Pressure Torus Mater Level Drywell Pressure Drywell-Torus Differential Pressure
TASLE 1 VESSEL LEVEL INSTRUMENTATION (A)
GEMAC LEVEL INSTRUMENTATION (1)
General Descri tion (a)
Uses high pressure leg and low pressure leg.
(b)
High pressure leg is reference leg.
Connected to unlagged condensing pot.
Maintains constant water level in leg.
(c)
Low pressure leg is variable leg.
Connected to source of water level being monitored.
(d)
Level detector monitors the differential pressure between the two legs and converts differential pressure to usable electronic signal.
(e)
Compensated for density by reactor pressure signal.
(f)
Indicates on meters or charts and also used by feedwater control.
(2)
Ran es of GEMAC Instrumentation (a)
Narrow-range GEMAC (1)
Two systems:
Channels 11 and 12.
(2)
Instrument zero is 302 feet, 9 inches.
(3)
Range of narrow-range GEMAC's +3.0 feet to -5.0 feet.
(4)
Normal level control band is 0.0 feet to 1.0 feet (302 feet, 9 inches to 303 feet, 9 inches).
(5)
Narrow-range GEMAC's located:
(a)
Vertical section "F" panel, two meters.
(b)
Cleanup section "K" panel through selector switch.
(c)
Console section "E" panel through selector switch.
(6)
"F" panel vertical section has chart recorder.
Signal through selector switch on console.
(7)
Narrow-range GEMAC used by feedwater control system.
(8)
Level alarms actuated by switches on chart recorder (a)
High level:
+2.0 feet (304 feet, 9 inches)
(b)
Low level:
-0.5 feet (302 feet, 3 inches)
(b)
Hide-range GEMAC (1)
Uses same variable leg tap as narrow-range GEMAC.
Condensing pot taps off top of vessel, giving different reference leg than narrow-range instrumentation.
(2)
Mide-range GEMAC has meter on the vertical section of "F" panel by the two narrow-range meters.
(3)
Range of wide-range GEMAC is +23.0 feet to -7.0 feet (325 feet, 9 inches to 295 feet, 9 inches).
(4)
Instrument zero is 302 feet, 9 inches.
TABLE 1 (CONTINUEO)
(c)
Flange-level GEMAC (1)
Instrument zero is 315 feet, 9 inches; corresponds to 13 feet (315 feet, 9 inches) on wide-range GEMAC.
(2)
Uses same detector as wide-range GEMAC.
(3)
Meter indication has suppressed range so it will only indicate +3.0 feet to -3.0 feet (318 feet, 9 inches to 312 inches, 9 inches).
(B)
ROSEMOUNT LEVEL INSTRUMENTATION (1)
General Oescri tion (a)
(b)
(c)
(d)
Rosemount level instrumentation utilizes existing Yarway temperature compensated self-venting reference column.
A high and low pressure leg from the column are connected to a
differential pressure transmitter.
The low pressure leg is the variable tap of the column.
In the reference column, both the reference and variable legs are kept at the same temperature.
The variable leg has a
standpipe that extends into the condensing pot.
The overflow of excess water will continuously replace the colder water with hot water which causes the colder water to flow back to the vessel.
This flow keeps the variable leg temperature high.
Using metal clamps to aid in heat transfer; plus the fact that the two legs are in close proximity, cause the reference leg to be maintained at some higher temperature.
A cold reservoir serves as a surge volume for the Rosemount column.
The "auxiliary head chamber assembly" makes up for level surges in the condensing chamber.
On a level increase, the excess water will surge into the cold reservoir; on a level
- decrease, the cold reservoir will supply cooler water to the condensing chamber as well as keep some level in the condensing chamber.
The Rosemount level detector has a capacitor diaphragm networ k-to separate the high and low pressure legs.
As the level changes in the variable leg, the pr'essure on the diaphragm also changes.
This change in pressure will cause the capacitance of the diaphragm to change.
The changing capacitance is elec-tronically sensed and amplified by the transm'itter which feeds the trip unit level indicators.
Small pressure differences in, the reference to variable leg indicate high levels; large differences indicate low levels.
(2)
Hi h
Low and Low-Low Level (a)
Two channels of Rosemount level indication:
Channels 11 and 12.
TABLE 1 CONTINUED)
(b)
There are two level transmitter/trip units in each channel that give protective actions when level setpoints are exceeded.
(c)
Each channel has a remote readout in the control
- room, on the vertical section of the "F" panel.
(d)
Local Rosemount level indicators (A,B,C,D), one per cabinet which are located in each corner of the reactor building on Elevation 281.
(e)
The range of the Rosemount instrument is zero inches to 100 inches.
(f)
Instrument zero is 297 feet, 4 inches.
(g)
The normal control band is 65 inches to 83 inches.
(1) 95 inches (2) 53 inches (3) 5 inches 5
inches'urbine trip and stop valve closure 36-03 A,B,C,D (high level)
Reactor scram and after five seconds time delay.
(low level) 36-03 A,B,C,D Reactor vessel isolation - includes 36-04 A,B,C,D (low-low level)
Main steam isolation valve closure Cleanup system isolation Shutdown cooling isolation Emergency cooling vent and drain isolation Containment isolation - includes:
Nitrogen inerting valves Drywell equipment drain line valves Floor drain valves Oxygen sampling line valves Core spray test discharge valves Drywell continuous air monitor isolates Traversing incore probes automatically retract and block valve closes 5 inches 5 inches Recirculation pumps trip With decreasing reactor pressure signal of less than 365 psi, core spray system will initiate 5 inches 5 inches With a time delay of ten seconds, emergency cooling will initiate.
With a high drywell pressure signal plus a
time delay, containment spray will initiate.
0
TABLE 1 (CONTINUED)
(3)
Low-Low-Low Level (a)
Two channels of Rosemount level indication:
Channels ll and 12 (b)
There are two level transmitters in each channel that give protective actions when level setpoints are exceeded.
(c)
Variable leg tap off core spray sparger; reference leg is narrow-range GEMAC condensing pot.
(d)
Spargers located inside shroud.
(e)
Indication is -124. 1 inches to -265.4 inches; local indication in each of the four new cabinets.
(f)
Level transmitter trip units have inputs to reactor protection system for automatic depressurization of reactor vessel.
(Automatic depressurization system also needs high drywell pressure signal plus a time delay to function).
(g)
Low-low-low level setpoint is -127. 1 inches meter scale.
(1)
Elevation 294 feet, 10 inches (7 feet, 11 inches below
.GEMAC instrument zero).
(2) 4 feet, 8 inches above top of active fuel (290 feet, 2 inches).
(C)
YARWAY LEVEL INSTRUMENTATION (1)
Two Yarway level indicators are provided, one ineach of the east and west instrument rooms in the reactor building, elevation 281 feet.
These are connected to the same reference described in B(1)(a) through (B)(1)(c).
(2)
These instruments provide redundant local reactor vessel level indication and would be operable in the event of total loss of electrical power.
(3)
The Yarway level detector has a diaphragm that keeps the high pressure and low pressure legs apart.
As the pressure
- changes, due to level change, the diaphragm will move.
The movement of the diaphragm causes a magnet to move.
A pointer will follow the movement of the magnet to indicate the level.
Smaller differential pressure readings mean the actual level is approaching the level in the reference leg so there will be a high.level indicated.
Large differential pressure will give low level indications.
10 Drywel 1 Continuous Airborne Honitor Drywell Equipment Drain Tank Drywell Floor Drain Tank We conclude that the licensee's description of the uses and.types of reactor vessel level/inventory instrumentation and instructions to operators regarding the use of this information satisfies the intent of IE Bulletin 79-08, Etem 4.
5.
Review the actions 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 (e.g.,
vessel integrity).
b.
Operators are provided additional information and instructions to not rely upon vessel level indication alone for manual actions, but to also examine other plant parameter indications in evalating plant conditions.
The licensee's response was evaluated to determine that (1) it addressed the matter of operators improperly overriding: the automatic actions of engineered safety features, (2) it addressed providing operators with additional informa-tion and instructions to not rely upon vessel level indication alone for manual actions and (3) that the review included operating procedures and training instructions.
By its letter dated April 24, 1979, the licensee indicated that Site Administrative Procedure APN-2A, "Conduct of Operations and Composition and Responsibilities of Station Organization," delineates the responsibilities and actions of on-shift operators.
This procedure
- has, since its-inception in 1969, stressed conservative use of instrumentation; he has the responsibility to believe and respond conservatively to instrument indications unless they may be otherwise proven to be incorrect.
He shall at all times operate in accordance with approved procedures unless immediate and unforeseen action is required to ensure the safety of the reactor, the plant, plant personnel or the general public."
- Further, the licensee committed to expanding this section to include clarifications on overriding automatic actions of engineered safety features and reemphasis on use of redundant parameter indications.
In addition, the licensee committed to stress these points in its operator requalification program lectures.
By its letter dated August 3,
- 1979, the licensee indicated that all station operating and special procedures had been reviewed for these areas of concern and that amplification and clarification wi 11 be made to specific procedures identified in its review.
Any -changes to these procedures would be included as information and instructions, in the operator requalification program.
By a telephone conversation on November 26,
- 1979, the licensee indicated that the aforementioned changes to the procedures had been completed.
Site Administrative Procedure APN-2A has been expanded and clarified to ensure that the conduct of shift operation is in accordance with the. above philoso-phies.
Specifically, Section 1.6. 1 reads "The Operations Supervisor, Station Shift Supervisor and station operators shall be trained and qualified in accordance with 10 CFR 55 and as outlined in APN-10..All operations shall be conducted in accordance with approved procedures.
Under all circumstances operators shall be guided by redundant or corroborating instrumentation when available and in the absence of other definite operational
- evidence, they shall always believe instrument indications.
No automatic engineered safety feature shall be manually overridden unless there is sufficient operational or instrumented evidence to show that the system is not performing its intended function and is operating so that continued operation will prolong or produce an unsafe condition.
Restoration of systems,to normal shall be at the direction of the Station Shift Supervisor only after it is established that the station is in an acceptable condition for normal operation."
We conclude that the licensee's review of operating procedures and training instructions satisfies the intent of IE Bulletin 79-08, Item 5.
12 6.
Review all safety-related valve positions, positioning requirements and positive controls to assure that valves remain positioned (open or closed) in a manner to ensure the proper operation of engineered safety features.
Also review related procedures, such as those for maintenance,
- testing, plant and system start-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.
The licensee's response was evaluated to assure that (1) safety-related valve positioning requirements were reviewed for correctness, (2) safety-related valves were verified to be in the correct position and (3) positive controls were in existence to maintain proper valve position during normal operation. as well as during surveillance testing and maintenance.
By its letter dated April 24,
- 1979, the licensee indicated that all safety-related system procedures contain valve lineups for the required positions of valves.
According to the licensee's practices, job specifica-
- tions, and procedures, only qualified operations personnel may position valves under the direction of the shift control operator (licensed reactor operator) or the station shift supervisor (senior reactor operator).
Valve positions may be altered for maintenance or testing, but only in conformance with Procedures APN-7, "Procedure for the Control of Equipment Mark-ups,"
and APN-13, "Procedure for Control of Station Corrective Repair or Maintenance,"
and utilizing a company-wide procedure for mark-up.
Under Procedure APN-13, the person completing the maintenance or his supervision shall indicate on the work request form whether or not an operability test is required by Technical Specifications or the Maintenance Procedure."
Safety-related maintenance procedures contain requirements for post-operability test performance to demonstrate operable status in conformance with the Technical Specifications.
Additionally, if the Technical Specifica-tion requirements cannot be met because of a system or component failure, the station shift supervisor shall take the corrective actions in accordance with Procedure APN-S, "Test and Inspection Program," which provides that ".
he
13 initiate tests or operations provided by Technical Specifications which may demonstrate that the station continues to meet the limiting condition for operation."
The station surveillance program contains inoperable component tests and periodic frequency tests to meet these objectives.
A review of these tests has been accomplished and each has a "return to normal" section to ensure proper system lineup following any necessary manipulations.
By letter dated August 3, 1979, the licensee supplemented its,initial response with the following information:
The valve checkoff lists (valve lineups) for safety-related valves include not only the required positions but further define whether the valves are required to be locked open or closed for system operability. 'hen performing a system valve lineup, the operator must check that the valve is in its proper position as well as locked,- if required, and document this on the checkoff list.
All safety-related systems were lined up in accordance with their valve checkoff list prior to startup after refueling in June 1979.
Additionally, system operability surveillance tests, were also performed.
We conclude that the licensee's review of safety-related valve positioning requirements, valve positions and positive controls to maintain proper valve positions satisfies the intent of IE Bulletin 79-08, Item 6.
7.
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 systems are isolated by the containment isolation signal.
14 c.
The basis on which continued operability of the above features is assured.
The licensee's response was evaluated to determine that (1) it addressed all systems designed to transfer potentially radioactive gases and liquids out of primary containment, (2) inadvertent releases do not occur on resetting engineered safety features instrumentation, (3) it addressed the existence of interlocks, (4) the systems are isolated on the containment isolation signal, (5) the basis for continued operability of the features was addressed and (6) a review of the procedures was performed.
By its letter dated April 24,
- 1979, as revised by letter dated May 14,
- 1979, the licensee indicated that there are four potential pathways for radioactive gases or liquids to be transferred out of the primary containment:
(1)
Nitrogen vent and purge
- system, (2)
Containment atmosphere delution system, (3)
Drywell floor and equipment drains, and (4)
Recirculation sample line to reactor building sample sink.
All of the above systems would isolate on a containment isolation signal.
Overrides are provided for Items (1) and (2) such that they can be manually reopened for controlled venting and monitoring purposes.
Venting would take place through the reactor building emergency ventilation system.
This system would not isolate on high radiation.
By procedure, venting is allowed only after the containment atmosphere has been sampled and analyzed.
The drywell floor and equipment drains transfer liquid under normal operation.
These lines isolate on high drywell pressure and low-low level.
Since level below top of fuel is required to produce significant fuel failures, highly radioactive liquid would not be automatically transferred to the waste building.
Activity in these lines is not normally monitored.
However, positive valve position indication is provided in the control room.
15 The drywell high pressure signal which initiates containment isolation has a
seal-in feature so that both reactor protection system channels must be cleared and manually reset before any isolation valves not provided with overrides can be reopened.
Thus, for the pumping of drywell drains to occur, these overt actions would be required.
Procedures are being modified to ensure that these positive controls remain in effect during events which produce significant radioactive liquids in the containment.
By a telephone conversation of November 26,
- 1979, the licensee indicated that procedure changes had been completed.
Three one-inch manual valves connect a sample line to a reactor recirculation line.
These valves are normally closed except during a sampling procedure.
The discharge of these one-inch valves reduces to 1/4 inch tubing which extends approximately 50 feet to a sample sink.
A flow fuse is installed outside of primary containment to limit flow through the line.
The licensee plans to install two automatic isolation valves during the refueling outage scheduled for early 1981.
These valves will close on high drywell pressure or low-low reactor water level.
The isolation valves will be provided with manual overrides to permit sampling during an isolated condition.
In the interim, operating procedures have been modified to ensure that positive administrative control assures the sample line is not inadvertently left open after use.
During sampling, a member of the operating staff continuously monitors sampling activities and verifies that at least two valves are closed when sampling is complete.
By its letter dated August 3, 1979, the licensee supplemented the foregoing information with the following.
When containment isolation is initiated by low-low reactor vessel water, there is no seal-in feature.
- However, a manual reset must be accomplished before any isolation valves can be manually reopened from the control room.
Procedures are presently in place which would preclude the inadvertent transfer of highly radioactive gases following an isolation event.
- However, procedures to preclude the inadvertent transfer of highly radioactive liquids after an isolation event have been implemented.
16 We conclude that the licensee's review of systems designed to transfer radio-active gases and liquids out of primary containment to assure that undesired pumping, venting, or other release of radioactive liquids and gases will not occur satisfies the intent of IE Bulletin 79-08, Item 7.
8.
Review and modify as necessary your maintenance and test procedures to ensure'hat 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 safety-related systems when they are returned to service following maintenance or testing.
c.
Explicit notification of involved reactor operational personnel whenever a safety-related system is removed from and returned to service.
The licensee's response was evaluated to determine that operability of redundant safety-related systems is verified prior to the removal of any safety-related system from service.
Where operability verification appeared only to rely on previous surveillance testing within Technical Specification intervals, we asked that operability be further verified by at least a visual check of the system status to the extent practicable, prior to removing the redundant equipment from service.
The response was also evaluated to assure provisions were adequate to verify operability of safety-related systems when they are returned to service following maintenance or testing.
We also checked to see that all involved reactor operational personnel in the oncoming shift are explicitly notified during shift turnover about the status of systems removed from or returned to service since their previous shift.
By letter dated April 24,
- 1979, the licensee indicated that the station safety-related operating procedures require that the operability of redundant safety systems be proven prior to the removal of any safety-related system from service, as well,.as when returned to service after maintenance.
These tests are performed using inoperable component surveillance tests as specified in the Technical Specifications.
0 J
17 Station Administrative Procedure APN-8 requires that the station shift supervisor be notified immediately if a system or component cannot meet the Technical Specification requirements.
Also, Station Administrative Proce-dures APN-7 and APN-13 require notification and concurrence of the station shift supervisor for the removal of and return to service of safety-related systems.
By its letter, dated August 3, 1979, the licensee supplemented its initial response with the following information.
The licensee's practice has always been to run an immediate operability test on safety system redundant com-ponents prior to removing a component for maintenance.
Reliance is not placed on prior operability tests within the Technical Specification surveillance schedule for verification of system performance, and therefore, a revision to maintenance and test schedule is not required.
Site Administrative Procedure APN-2A, "Conduct of Operations and Composition and Responsibilities of Station or Unit Organization,"
requires ".
a verbal exchange of information between shifts which must include the status of safety-related equipment and conditions, 'as set forth in the Technical Specifications."
We conclude that the licensee's review and modification of maintenance, test and administrative procedures to assure the availability of safety-related systems and operational personnel knowledge of system status satisfies the intent of IE Bulletin 79-08, Item 8.
9.
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.
The actions specified in Item 9 of IE Bulletin 79-08 have been incorporated in the requirements of Section 50.72 of 10 CFR Part 50.
Since all licensees, including Niagara Mohawk, are subject to these requirements, we conclude that the licensee will meet the intent of IE Bulletin 79-08, Item 9.
18 We conclude that the.licensee's response satisfies the intent of IE Bulletin 79-08, Item 9.
10.
Review operating modes and procedures to deal with significant amounts of hydrogen gas that may be generated during a transient or other accident that would either remain inside the primary system or be released to the
. containment.
The licensee's response was evaluated to determine if it described the means or systems available to remove hydrogen from the primary system as well as the treatment and control of hydrogen in the containment.
By its letter dated April 24, 1979, the licensee indicated that should hydrogen be generated by either radiolysis or metal-water reaction, the following methods are available to vent the hydrogen from the reactor vessel:
(A)
The reactor head vent, located on top of the reactor vessel, relieves to the drywell equipment drain tank by remote manual control from the control room.
If low water level has occurred, which may result in fuel damage, the drain tank would be isolated and overflow would be to the drywell atmosphere.
(B)
The relief valves, located on the main steam lines, relieve to the torus.
At Nine Mile Point 1, there is a significant distance between the top of the core and the main steam line (approximately 20 feet).
This allows significant amounts of noncondensibles to be accommodated.
(C)
A Loss of coolant accident or safety valve actuation would result in direct release path to the primary containment.
Once the hydrogen has been vented from the reactor vessel, its concentration in the primary containment can be monitored and diluted with nitrogen from the containment atmosphere dilution system.
However, venting of the primary containment would be necessary should repressurization by the containment
19 atmosphere dilution system to 20 psig occur.
Vent initiation would not be required for approximately 38 days after a loss-of-coolant accident.
By a telephone conversation on April ll, 1980, the licensee indicated that its
. procedure changes for venting significant amounting of hydrogen gas have been completed.
Me conclude that the licensee's response satisfies the intent of IE Bulletin 79-08, Item 10.
ll.
Propose
- changes, as required, to those technical specifications which must be modified as a result of your implementing the items above.
The licensee's response was evaluated to determine that a review of the Technical Specifications had been made to determine if any changes were required as a result of implementing Items 1 though 10 of IE Bulletin 79-08.
By its letter dated May 14,
- 1979, the licensee indicated that n'o Technical Specification changes were required as a result of implementation of Action Items 1 through 10 of IE Bulletin 79-08.
- However, in a subsequent telephone conversation, the licensee agreed to forward a license amendment request to modify its Technical Specifications to reflect the modification to the recirculation system sampling lines.
Me conclude that the licensee's response satisfies the intent of IE Bulletin 79-08, Item 11.
Conclusion Based on our review of the information provided by the licensee to date, we conclude that the licensee has correctly interpreted IE Bulletin 79-08.
The actions taken demonstrate the licensee's understanding of the concerns arising from the TMI-2 accident in reviewing their implementation on Nine Mile Point 1
operations, and provide added assurance for the protection of the public health and safety during the operation of Nine Mile Point, Unit 1.
'll
20 References 1.
IE Bulletin 79-05, dated April 1, 1979.
2.
IE Bulletin 79-05A, dated April 5, 1979.
3.
IE Bulletin 79-08, dated April 14, 1979.
4.
Niagara Mohawk letter, R. Schneider to B. Grier, dated April 24, 1979.
5.
Niagara Mohawk letter, R. Schneider to BE H. Grier, dated May 14, 1979.
6.
NRC staff letter, T. Ippolito to D. Disc, dated July 20, 1979.
7.
Niagara Mohawk letter, J. Bartlett to H. Oenton, dated August 3, 1979.
8.
Niagara Mohawk letter, D. Disc to H. Oenton, dated August 31, 1979.
f