IR 05000245/1980018
| ML19345F388 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 12/15/1980 |
| From: | Keimig R, Shedlosky J, John Thomas, Zimmerman R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML19345F386 | List: |
| References | |
| 50-245-80-18, 50-336-80-20, NUDOCS 8102170377 | |
| Download: ML19345F388 (17) | |
Text
.
.
O U.S. NUCLEAR REGULATORY COMMISSION OFFICE OF INSPECTION AND ENFORCEMENT 50-245/80-18 Report No. 50-336/80-20 50-245 Docket th. 50-336 DPR-21 License No. DPR-65 Priority Category C
--
Licensee:
Northeast Nuclear Energy Company P.O. Box 270 Hartford, Connecticut 06101 Facility Name:
Millstone Nuclear Power Station, Units 1 & 2 Inspection at:
Waterford, Connecticut 06385 i
Inspection conducted: October 5 thru November 8, 1980
-
Inspectors:
M[
f 7 /9/;Po
[ T. Shedlosky Sr. Resident Inspector date signed b
A,
/7 /q/Ao R/P.'ZimmennaM 4tesident Inspector
'date signed
/
Y A%
/t/9/Fo
~
A. Thomas
' dent Inspector, Oyster Creek date signed Approved by:
e f
Station (Oct. 14 - 24,r198
/>- /
SectionNo.)ThieMReactorProjects R.Keimif,
' date signed
, ROUNS Branch Inspection Summary:
i
i Inspection on October 5 thru November 8, 1980 (Combined Report Nos. 50-245/80-18 and 50-336/80-20 Areas Inspected:
Routine, onsite, regular and backshift inspection by three resident inspectors (74 hours8.564815e-4 days <br />0.0206 hours <br />1.223545e-4 weeks <br />2.8157e-5 months <br />, Unit 1; 45 hours5.208333e-4 days <br />0.0125 hours <br />7.440476e-5 weeks <br />1.71225e-5 months <br />, Unit 2). Areas inspected included the control rooms and the accessible portions of the Unit I reactor, turbine, radio-active waste, gas turbine generator, and intake buildings; the Unit 2 primary contain-ment, enclosure, auxiliary, turbine and intake buildings; and the condensate polishing facility; radiation protection; physical security; fire protection; plant operating records; surveillance testing; calibration; maintenance; core power distribution limits; and reporting to the NRC.
Results:
No items of noncompliance were identified during this inspection.
l l
Region I Form 12 (Rev. April 77)
8JO2170 N
'
.
.
DETAILS 1.
Persons Contacted The below listed technical and supervisory level personnel were among those contacted:
J. Bangasser, Station Security Supervisor J. M. Black, Unit 3 Superintendent P. Callaghan, Unit 1 Maintenance Supervisor A. Cheatham, Radiological Services Supervisor J. Crockett, Unit 2 Engineering Supervisor F. Dacimo, Quality Services Supervisor E. C. Farrell, Station Services Superintendent H. Haynes, Unit 2 Instrumentation and Control Supervisor R. J. Herbert, Unit 1 Superintendent J. Kangley, Chemistry Supervisor J. J. Kelley, Unit 2 Superintendent E. J. Mroczka, Station Superintendent V. Papadopoli, Quality Assurance Supervisor R. Place, Unit 2 Maintenance Supervisor R. Palmieri, Unit 1 Engineering Supervisor W. Romberg, Unit 1 Operations Supervisor S. Scace, Unit 2 Operations Supervisor E. Spruill, Health Physics Supervisor F. Teeple, Unit 1 Instrumentation and Control Supervisor 2.
Review of Plant Operation - Plant Inspections (Units 1 and 2)
The inspectors reviewed plant operations through direct inspection and observation of Units 1 and 2 throughout the reporting period. Activities in progress at Units 1 and 2 included refuel outage work and return to power operation of Unit 2.
a.
Instrumentation
'
Control room process instruments were observed for correlation between channels and for conformance with Technical Specification requirements.
No unacceptable conditions were identified.
b.
Annunciator Alarms
The inspector observed various alarm conditions which had been received l
and acknowledged. These conditions were discussed with shift personnel who were knowledgeable of the alams and actions required. During pk. t inspections, the inspector observed the condition of equipment assoc'
-d with various alarms. No unacceptable conditions were identified.
l t
!
.
1.
.
.
.
..
.
.
.
.
c.
Shift Manning The operating shifts were observed to be staffed to meet the operating requirements of Technical Specifications, Section 6, both to the number and type of licenses.
Control room and shift manning were observed to be in conformance with Technical Specifications and site administrative procedures, d.
Radiation Protection Controls Radiation protection control areas were inspected.
Radiation Work Permits in use were reviewed, and compliance with those documents,
!
as to protective clothing and required monitoring instruments, was inspected. Proper posting of radiation and high radiation areas was reviewed in addition to verifying requirements for wearing of appropriate personal monitoring devices. There were no unacceptable conditions identified.
e.
Plant Housekeeping Controls Storage of material and components was observed with respect to prevention of fire and safety hazards.
Plant housekeeping was evaluated with respect to controlling the spread of surface and airborne con-tamination. There were no unacceptable conditions identified.
f.
Fire Protection / Prevention The inspector examined the condition of selected pieces of fire fighting
~
equipment. Combustible materials were being controlled and were not found near vital areas. Selected cable penetrations were examined and fire barriers were found intact.
Cable trays were clear of debris.
g.
Control of Equipment During plant inspections, selected equipment under safety tag control was examined.
Equipment conditions were consistent with information in plant control logs.
I h.
Instrument Channels Instrument c5nnel checks recorded on routine logs were reviewed.
An independent comparison was made of selected instruments. No unacceptable conditians were identified.
i. Equipment Lineups The inspector examined the breaker position en switchgear and motor control centers in accessible portiors of the plant. Equipment I
conditions, including valve lineups, were reviewed for confonnance
'
with Technical Specifications and operating requirements.
In addition,
the inspector observed the location of load centers inside containment l
and determined that power for valve manipulation required for various modes of operation would not require a containment entry to be performed.
.
-,,
- - - - -
,m-
,
-,e--,
,,e,
-y
, -
m,
-e-
--4a
_
.
.
3.
Review of Plant Operations - Logs and' Records - (Units 1 and 2)
During the inspection period, the inspector reviewed operating logs and records covering the inspection time period against Technical Specifications and Administrative Procedure Requirements.
Included in the review were:
Shift Supervisor's Log daily during control room
-
surveillance Plant Incident Reports 10/5 through 11/8
-
Jumper and Lifted Leads Log all active entries
-
Maintenance Requests and Job Orders all active entries
-
Construction Work Permits all active entries
-
.
Safety Tag Log all active entries
-
Plant Recorder Traces daily during control room
-
surveillance Plant Process Computer Printed daily during control room
-
Output surveillance Night Orders daily during control room
-
surveillance The logs and records were reviewed to verify that entries are properly made; entries involving abnormal conditions provide sufficient detail to communicate equipment status, deficiencies, corrective action restora-tion and testing; records are being reviewed by management; operating orders do not conflict with the Technical Specifications; logs and incident reports detail no violations of Technical Specification or reporting requi ements; logs and records ar:a maintained in accordance
/
with Technical Specification and Administrative Control Procedure requirements.
No items of noncompliance were identified.
4.
Plant Maintenance and Modifications During the inspection period, the inspector frequently observed various maintenance and problem investigation activities. The inspector reviewed these activities to verify:
compliance with regulatory requirements, including those stated in the Technical Specifications; compliance with the administrative and maintenance procedures; compliance with applicable codes and standards; required QA/QC involvement; proper use of safety tags; proper equipment alignment and use of jumpers; personnel qualifica-tions; radiological controls for worker protection; fire protection; retest requirements and ascertain reportability as required by Technical Specifications.
In a similar manner the implementation of design changes and modifications were reviewed.
In addition to those items addressed above, the licensee's safety evaluation was reviewed.
Compliance with requirements to update procedures and drawings were verified and post modification acceptance testing was evaluated. The following activities were included during this review:
.
%
,ww
- --
,, -,-,
-,
, - - - -
-
a wL
~,
-
--
-m
.
.
Unit 1 Torus Modification - install vent header deflectors
---
Torus Modification - install sadiles
---
Torus Modification - cut downcu,.ers
-
---
Torus Modification - install new LPCI piping
---
Torus Modification - install new instrumentation
---
Replacement of Feedwater spargers
---
Removal of CRD return water piping and removal of reactor vessel
---
nozzle thermal sleeve Replacement of Core Spray Piping
---
Replacement of Feedwater Check Valves
---
Install ATWS Recirculation Pump Trip
---
Replacement of Service Water Piping
---
Unit 2 Repair of Reactor Head Cable Connectors
---
No items of noncompliance were identified.
5.
Licensee Event Reports (LER's)
The inspector reviewed the following LER's to verify that the details of the event were clearly reported, including the accuracy of the description of cause and adequacy of corrective action.
The inspector determined whether further information was required, and whether generic implications were involved. The inspector also verified that l
the reporting requirements of Technical Specifications and Station Administrative and Operating Procedures had been met, that appropriate corrective action had been taken, that the event was reviewed by the Plant Operations Review Committee, and that the continued operation of the facility was conducted within the Technical Specification limits.
l Unit i l
i 80-11:
Both air ejector off-gas radiation monitors inoperable; manual stop valve shut preventing the transfer of monitor sample point when shifting from the recombiner system to the off-gas delay pipe.
80-14:
Failure of two Main Steam Isolation Valves to meet containment local leak rate test acceptance.
80-15:
Setpoint drift reactor water level RPS Trip - one of four instruments.
80-16:
Discovery of cracking in five jet pump beams, ETS 80-2:
Failure to perform required surveillance testing of off-gas i
hydrogen monitors within the required time period.
.
--
y or
-.-
- - - +
--s y
y --
e..v,.
y.9-s-.
y---
.
Unit 2
-
J l
80-32: Failure of a closed cooling water containment isolation valve in the intermediate position due to a failed air actuator shear pin. The pin caused binding of the actuator.
This was found during local leak rate testing.
80-33:
Failure of one of two operating wide range neutron flux instruments due to improper maintenance.
78-33:
Updated Report - Completed modifications comprising final corrective actions to prevent clogging emergency diesel generator service water heat exchangers.
6.
Review of Periodic and Soecial Reports
~
Upon receipt, periodic and special reports submitted by the licensee pursuant to Technical Specification 6.9.1 and 6.9.2 and Environmental Technical Specification 5.6.1 were reviewed by the inspector. This review included the following considerations:
the report includes the information required to be reported by NRC requirements; test results and/or supporting information are consistent with design predictions and perfomance specifications; planned corrective action is adequate for resolution of identified problems; detemination whether any infomation in the report should be classified as an abnormal occur-rence; and the validity of reported infomation. Within the scope of the abcve, the following periodic reports were reviewed by the inspector:
Monthly Operating Reports Unit 1 and 2, September 1980.
---
7.
Verification of TMI - Task Action Plan Category "A" Requirements The inspector reviewed the implementation of commitments made by the licensee to satisfy the Category "A" requirements of TMI-2 Lessons Learned Task Force. Those requirements are contained in NUREG - 0578, dated July 1979 and NRC Letters to All Operating Plants dated
,
l September 13, 1979, and October 30, 1979. The licensea committed to implement those requirements and documented the action taken in letters l
to tfie NRC dated December 31, 1979, and January 31, 1980. Those actions were evaluated by the NRC and reports of those evaluations
l were documented in NRC letters dated April 18, 1980 (Unit 1) and l
February 25, 1980 (Unit 2). The Lessons Learned Task Force requirements
were republished in NRC Action Plan Developed as a Result of the l
TMI-2 Accident, NUREG - 0660 May 1980 and Revised August 1980.
Preliminary Clarifications to the action Plan (TAP) was issued by NRC letters dated September 5, 1980 and September 19, 1980.
NUREG - 0737 published the Clarification of TMI Action Plan Requirements and was transmitted to Operating Power plants by letter dated 11/13/80.
These NRC requirements, clarifications, and licensee commitments were used as the basis for inspection.
~
_
Technical Specifications have not yet been issued to address Category "A" requirements.
The following summarizes the inspection findings of Category "A" requirements.
For reference, the NUREG 0578 and TAP numbers are stated after the topic title - (NUREG 0578/ TAP).
Emergency Power for Pressurizer Heaters (2.1.1/II.E.3.1)
Unit 2 - The description of the power supply design for the pressurizer heaters, submitted by the licensee, was verified during onsite inspections.
Those documents correctly identified the power supplies for each of two banks of proportional heaters as Class IE, 480 volt AC buses (Z1-22E2, Z-2-22F7), which have onsite emergency power avail-able.
Breaker control is provided through Class 1E,120 volt DC buses (Z1-201A-1V,Z2-201B-1V).
Proportional heater control is accomplished through the operator selected one of two instrument channels. Those instrument channels are powered by two regulated instrument panels (VR11,VR12). The instrument channels and instrument buses are not Class 1E but receive their power from Class 1E buses.
-
Emergency Power Supplies for Pressurizer Relief Valves, Block Valves and Level Instruments (2.1.1/II.G.1)
Unit 1 - Main Steam Relief Valves are operated by the Instrument air and Class 1E DC power in the Automatic Pressure Relief (APR or ADS) mode.
The description of the power supply design for the relief valves was verified by onsite inspections. The instrument air compressor is supplied by a 480 volt AC Class 1E bus. The station service air compressor is powered by a non-Class 1E 480 volt AC bus. That bus is supplied from a non-Class 1E 4160 volt bus which has power available to it from the emergency gas turbine generator.
Unit 2 - The description of the pressurizer level instrument channel and pressurizer relief and block valve power supply design was verified during onsite inspections. Power to the PORV's is Class 1E 120 volt DC
(RC 402 Z1-201A-2, RC 404 Z2-201B-2).
Power to the PORV Block Valves is Class 1E 480 volt AC (RC403 Z1 MCC 22-1E, RC 405 Z2 MCC 22-1F).
Pressurizer level control is accomplished thrcugh the selected one of two instrument channels. Those instrument channels are powered by two regulatedinstrumentpanels(VR11,VR12). The instrument channels and instrument buses are not Class 1E, but receive their power from Class 1E buses.
Direct Indication of Safety and Relief Valve Positions (2.1.3a/II.D.3)
Units 1 and 2 - Acoustic flow monitoring devices have been installed at both plants. Separate instrument channels monitor each Safety / Relief valve in Unit 1 and each Safety or PORV in Unit 2.
Each instrument
_
-
.
.
channel consists of an accelerometer on valve discharge piping, a preamplifier and monitoring unit. The monitoring units are located in the control rooms and will activate main control board annunciators.
A common annunciator is used for all 6 channels at Unit 1 and individual annunciators are used for the 4 channels at Unit 2.
Unit 1 monitors are all powered from a Class 1E uninterruptible switchboard (VAC-1).
That switchboard is supplied by the output of an MG Set, which is driven by DC or AC motors. The DC motor is supplied by Class 1E 125v DC power; the AC motor by Class 1E 480v AC which has onsite power available from the gas turbine generator. An alternate supply to VAC-1 is a Class 1E 480v AC bus which has onsite power available from the diesel generator.
Selection is made by an automatic bus transfer switch.
Unit 2 monitors are all powered from a Class 1E uninterruptible instrument panel (VA10). That panel is supplied by the output of a static inverter powered by Class IE 125v DC. An alternate supply to VA10 is a regulated instrument panel (VR11). Selection is made by a static switch.
The licensee committed to qualify all components of the monitors (accelerometers, preamplifiers, cable and monitors) to the requirements of IEEE 323, 344 and 383 by April 1,1980. This is a January 1, 1981, Category B requirement. However, letters from the licensee dated March 28, 1980, September 15, 1980 and October 31, 1980, re-established a date of April 1,1981, to meet this requirement.
Fuses are used as isolation devices between this equipment and Class 1E supplies. The NRC has recognized and documented that this is not in accordance with Regulatory Guide 1.75 (letters dated 4/18/80 - Unit 1, 2/25/80 - Unit 2).
The inspector also verified the implementation of backup procedures to diagnose valve position. Valve discharge temperature elements are used at both units; quench tank level, pressure and temperature are also used by Unit 2.
Instrumentation for Detection of Inadequate Core Cooling (2.1.3b/II.F.2)
Unit 2 - A subcooled margin monitor has been installed. That instrument is powered from a Class 1E uninterruptable instrument panel (VA-20).
That panel is supplied by the output of a static inverter powered by Class 1E 125v DC. An alternate supply to VA20 is a regulated instrument panel (VR21). Selection is made by static switch.
The subcooled margin monitor (SMM) receives temperature inputs from both loop 1 and 2 RPS hot leg RTD'5. The RTD is in an instrument loop 665g ) to the Reactor Regulating whichprovidesanarrowragge(51g)outputstotheSMMbyadualoutput F
system and wide range (150 - 700 F l
I/I transmitter. Wide range temperature is available to the SMM as the l
result of a 1980 refuel outage modificatign. Prior to the 1980 outage,
!
the SMM received narrow range (515 - 665 F) temperature from the RPS
l
'
.
i
.
g
channel through I/I transmitters used as isolation devices.
Pressure information is supplied from wide (0-1600) and narrow range
!
(1500-2500 PSIA) pressurizer pressure instruments.
The SMM displays subcooled margin as a temperature or pressure.
The subcooled margin
.
is computed by using temperature from the highest input and pressure i
from the lowest input.
'
l The licensee has implemented a process computer subroutine which
!
calculates and displays subcooled margin independently of the SMM.
!
Plant parameters,which had been available to the process computer, are used for input to.the calculation.
The highest temperature is selected between both loop narrow range hot leg temperatures, two cold leg narrow range and two wide range temperatures.
The lowest pressurizer pressure between four instruments is selected.
Subcooled margin pressure
!
and temperature are displayed in a dedicated portion of process computer CRT output.
<
As a routine inspection activity, subcooled margin is compared among the SMi, process computer and plant process instruments making use of
'
saturated steam tables.
The licensee has had procedures in place to direct the calculation of subcooled margin, has the reference saturated steam tables available in the control room and has established minimum subcooled margin require-ments for post accident conditions.
Containment Isolation (2.1.4/II.E.4.2)
Unit 1 - The inspector verified the implementation of a modification to containment isolation valve logic. That modification results in requiring that valve control switches are in the closed position to allow a reset of containment isolation signal. That review consisted of equipment inspections and the review of revised control wiring drawings (B-18761', Sheets 478, 479, 816, 817, and 969).
It included MSIV's (8),
Equipment and Floor Drain Valves (4) and Atmosphere Control (9 containment inerting and purge) Valves.
Units.1 and 2 - During 1979 the automatic function of containment sump pump logic was removed for the Unit 1 floor and equipment drains and the Unit 2 normal containment sump. The operators manually operate sump pumps and isolation valves based on annunciated or indicated level.
The inspector reviewed listings of essential and non-essential systems'
containment piping penetrations which were submitted to the NRC by letter dated January 31, 1980. There was no information identified as being incorrect.
l
.
.
Recombiner' Procedures (2.1.5c/ - )
Unit 2 - Recombiners are located inside containment.
NRC agreed that no modifications are required.
Systems Integrity (2.1.6a/III.D.1.1)
Units 1 and 2 - The licensee has taken credit for administrative control procedures and ASME Section XI Inservice Inspection to identify and correct system leakage. Those controls have been in place and are implemented by procedures SP 635.1, Rev. 1 dated 1/2/80, Ops Form 10.09 dated 7/3/80, Administrative Control Procedures Addressing Maintenance and the Inservice Inspection Program.
The inspector verified the completion of the following modifications the need for which had been identified by the licensee:
Unit 1 - Reactor Building Railway Access Floor Drain marked to inform personnel that it does not go to liquid radwaste.
Unit 2 - Concrete Cofferdams a) Around Spent Fuel Pool Skimmer Pumps - Auxiliary Building 14'6" el b) Across entrance to Volume Control Tank Room - Auxiliary Building 5' el c) Across entrance to Boric Acid Evaporator Room - Auxiliary Building 5' el d) Across entrance to Letdown Heat Exchanger Room 5' el e)
Drain of Solidification Chemical Day Tank Room plugged Automatic Initiation of Auxiliary Feedwater (AFW) (2.1.7a/II.E.1.2)
The licensee installed control logic to automatically start auxiliary feedwater pumps on low steam generator level. This system was described in a letter dated 12/6/79. The licensee requested by letter dated 11/30/79 that the implementation of this item be deferred pending licensee analysis and NRC review and evaluation of a main steam or feedwater line break with the failure to limit flow to the affected steam generator.
The NRC confirmed agreement with a delay in implementation by letter dated 12/21/79. A letter dated March 27, 1980, updated the NRC position on Category A and B requirements on auxiliary feedwater. Additional infonnation on system design was provided to the NRC in letters dated 1/25/80, 4/11/80, 5/20/80 and 10/31/80. That information included the justification to include only the two electrically driven auxiliary feedwater pumps in the automatic initiation scheme.
.
L
.
The inspector confirmed that the installed auxiliary feedwater auto-initiation logic conformed to the requirements and commitments in the above referenced documents.
Category A requirements were met with implementation of PDCR's 2-182-79 and 2-186-79. Those design
-
changes covered equipment and cable to automatically start the two electric driven AFW pumps.
Isolated instrument loops were driven by RPS level transmitters and used as input to bistables.
Each bistable received two level signals from each generator. The bistable outputs are matrixed in two out of four logic. Matrix output instantaneously
.
operates an annunciator and through a time delay relay, the actuation of the time delay fully opens AFW regulating valve and starts the
,
i associated AFW pump. Block switches are provided to allow taking control
of regulating valves or stopping an AFW pump or blocking the automatic start feature. A start position on the block switch will start the
.
AFW pump and open regulating valves with no time delay.
Pcwer to logic
!
j systems is Class 1E uninterruptable instrument panels VA10 and VA20.
j In the event of a loss of off-site power, AFW pumps were added to l
load sequence step four.
Non qualified components of the auto-initiation logic were replaced with Class 1E devices. Modifications accomplished during the 1980 refuel j
outage included PDCR 2-125-80.
Four channels of steam generator level transmitters and the associated 10-50 ma. instrument loops were i
replaced with qualified transmitters and 4-20 ma instrumentation. A 1-5v de voltage, developed across a 250 ohm resistor, is the input for RPS bistables. Additionally,the instrument loop current source produces
!
a 0-10v de output through an internal I/V converter. The voltage
signal drives main control panel level indicators through Class 1E j
V/I converters. The panel indicators are not qualified.
In each of the four instrument channels, an auctioneering circuit passes the lowest
'
steam generator level to the AFW auto-initiation bistable.
Relays driven l
by the four bistables are arranged in ladder logic matrix to provide l
a two out of four trip.- The logic matrix is supplied by Class 1E uninterruptable panels VA10 and VA20, two independent power supplies and isolation diodes. In the event of the loss of power to safeguards, electrical buses pump start is inhibited by_ the diesel generator load
'
sequencer until step four.
When the normally energized logic matrix is de-energized, an annunciator is actuated instantaneously and two trains of 3 minute 25 second time delays started.
The completion of each time delay will full AFW feed regulating valve and start the associated AFW pump.yopen anThat log is sealed in until a bypass switch is used to reset the logic. All components are qualified Class.1E except the eight main control board l
level instruments, matrix power supplies (model LCS-B-120) indicator i
lamps and surge supressors.
A qualification program is in progress for the power supplies. The levei instruments are-isolated by' Class 1E V/I converters.
!
.
+
.
Auxiliary Feedwater Flow Indication (2.1.7b/II.E.1.2)
Unit 2 - Auxiliary feedwater flow is displayed on the main control board for each steam generator. The instrument channels are original plant equipment. The instrument channels are regulated instrument panels VR11 and VR12.
Post-Accident Sampling (2.1.8a/II.B.3)
Units 1 and 2 - By letter dated December 31,197N the licensee stated that post accident primary coolant and containment atmosphere samples could not be obtained to meet the NUREG - 0578 source term requirements.
Again by letter dated January 31, 1980, the licensee committed to having a post accident sampling procedure in place.
'
The inspector verified that OP 501/2501, the " Emergency Plan Procedure
contained Appendix Q " Post Accident Sampling", Revision 0, dated 1/31/80.
That procedure met the comitments of above referenced documents.
High Range Radiation Monitors (2.1.8b/III.D.3.3)
Units 1 and 2 - The licensee committed to the implementation of interim procedures and equipment for estimating noble gas and radio-iodine release rates in the event that existing instrumentation is driven off-scale.
Those commitments were made by letter dated 12/12/79. The licensees actions were ' clarified in letters dated 12/31/79 and 1/31/80.
The inspector verified the presence of high range radiation monitors.
Unit 1 - A GE ARM with detector located in contact with the outside wall of the vent stack.
Readout is in the control room. Power is supplied from a Class 1E uninterruptable switchboard (VAC-1).
Unit 2 - An Eberline RD-16 monitor with remote detector (RD-17) located in contact with the Unit 2 stack plenum.
Readout is locally at the monitor in the spent fuel storage area.
Power is non-Class 1E, the unit contains an internal backup battery supply.
During the inspection, the inspector discovered that the battery tested at less than full capacity. Corrective action has been taken by the licensee.
OP501/2501 the " Emergency Plan Procedure", Appendix F, " Dose Estimates for Airborne Accidental Releases", Revision 1 dated 1/1/80 provides calculational methods to estimate release rates if the normal monitor goes off-scale. Unit I releases may be estimated through the vent
,
stack or by containment activity; Unit 2 releases through the vent stack, I
the Unit 2 stack or by containment activity.
i
!
l l
l
'
.
.
'
-
The NRC evaluation of Unit 2, Category "A" items dated 2/25/80
.
stated an additional comitment to provide monitoring of noble gas releases from the steam dump valves.
OP501/2501, Appendix G.
"On-Site Team #1", Revision 2, dated 3/14/80 contains a special monitoring procedure to be used in the event of fuel failure and possible use of the steam dump.
Dose rate readings from accessible areas below the main steam lines are converted to release rates.
The procedures determine radio-iodine release rates by using the noble gas monitor and presupposed ratios of iodine to noble gas based on
,
the type of accident. This procedure is stated in OP501/2501,
'
Appendix F.
Improved Iodine Instrumentation (2.1.8c/III.D.3.3)
Units 1 and 2 - The licensee comitted to providing dedicated iodine monitoring instrumentation for the Control Rooms and the Technical Support Centers. Those commitments were stated in letters dated 12/7/79 and 1/31/80.
.
The inspector verified that the instrument, an Eberline PING-3, was available and kept for exclusive use in the Unit 1 or 2 Control Room, Technical Support Center complex. Silver impregnated silica-gel cartridges were available to allow iodine collection and minimizes the effects of noble gases. A copy of procedure HP908/2908D " Continuous Air Monitoring", Revision 3, dated 1/1/80 was available for operation.
j Shi ft Supervi sor Responsi bil i ti es ' (2. 2. la/I. A.1. 2)
Units 1 and 2 - The licensee stated his comitment to establish the responsibilities and authorities of the Shift Supervisor by letter dated 12/31/79. The licensee stated his intention to define a line of comand and delineate comand decision authority of the shift-supervisor. Also the shift supervisor is to remain in the control room at all times during an accident situation.
Plant procedures state authorized persons to relieve the shift supervisor or to assume l
the shift supervisors duties temporarily.
l The inspector verified the implementation of the licensees comitments
'
in ACP QA 1.02, " Organization and Responsibilities", Revision 10 dated 1/1/80. The licensee's position was also promulgated by letter to all Shift Supervisors from the Vice President of Nuclear Engineering and Operations.
!
,
!
l
-
.
'
Shift Manning - Overtime Limits (---/I.A.1.3)
Units 1 and 2 - IE Circular 80-02, " Nuclear Power Plant Staff Work Hours" stipulated certain limits for extending normal working hours.
The inspector verified that ACP 1.12. " Scheduling of Station Personnel Working Hours", Revision 1, dated 8/29/80 implemented those limits.
Short Tenn Accident & Procedures Review (---/I.C.1)
Units 1 and 2 - NRC letters dated 9/13, 9/27,10/10,10/3 and 11/9/79 required the licensee to develop procedures and emergency operating instructions to handle small break loss of coolant accidents. Those procedures were to assist the operating staff to recognize and prevent conditions which result in inadequate reactor core cooling, and to recover from a condition in which a core has experienced inadequate cooling.
The inspector reviewed the following procedures and found that the Category A requirements were implemented:
OP 506, Loss of Coolant, Revision 1, dated 4/23/80 OP 2505, Primary System Leakage, Revision 3, dated 10/78 OP 2506, Loss of Coolant, Revision 9. Change 3, dated 6/18/80 OP 2509, Main Steam Line Rupture, Revision 6, Change 2, dated 6/18/80 OP 2515, Steam Generator Tube Rupture, Revision 7, Change 1, dated 6/13/80 Revisions may be necessary after the installation of additional TMI Action Plan equipment and pending NRC review and acceptance of the BWR Owners Group procedure guides.
Shift Technical Advisor-STA- (2.2.lb/I.A.1.1)
Units 1 and 2 - The licensee stated his commitment to establish an STA at each of the units in letters dated 12/10/79 and 12/31/79.
These documents established qualifications for those indiv%als filling the STA position. The licensee has implemented those connitments through ACP-QA 1.11 " Interim Shift Technical Advisor", Revision 1, dated 4/11/80.
The inspector has verified that the 'STA has been in place at each unit, except when in cold shutdown or refuel modes, since 1/1/80. The licensee has met the stated requirements and commitments for STA qualifications, training and personnel location.
.
.-%
-
Shift Relief and Turnover Procedures (2.2.1c/I.C.2)
-
Units 1 and 2 - The licensee committed to providing a checklist for oncoming and offgoing control room operators and the Shift Supervisors by letter dated 12/31/80. That commitment stipulated the content of the checklist.
The inspector has verified that the checklist,has been in use since 1/1/80, and its content satisfies the licensees commitments. The checklist is included in the Control Room Daily Surveillance, Unit 1 Ops fonn 10.10, Revision 34; Unit 2 Ops Form 2619A-4 Revision 1.
Control Room Access (2.2.2a/I.C.4)
Units 1 and 2 - The licensee has committed to provisions for limiting access to control rooms to certain individuals and to establish a clear line of authority in the event of an emergency.
These commitments were stated in a letter dated 12/31/79.
The inspector verified that these had been implemented and were found stated in ACP-601, " Control Room Procedu.re", Revision 5, dated 4/1/80; ACP-QA 1.02, " Organization and Responsibilities", Revision 10, dated 1/1/80, and OP 501/2501 the Emergency Plan Procedure.
Onsite Technical Support Center (2.2.2b/III.A.1.2)
Units 1 and 2 - The licensee committed to and provided a description of the Technical Support Centers (TSC) in letters dated 12/31/79 and 1/31/80.
The inspector had verified that the TSC were established to comply with 1/1/80 requirements.
Equipment including CCTV, plant process computer terminals, dedicated telephone lines, ventilation, dedicated dose rate meters, air samplers and microfich files of plant drawings were all verified as being in place in the TSC. Telephone lines included extensions of the NRC Emergency Notification System (ENS), Connecticut State Police, Waterford Police and the TSC, Control Room, Emergency Operations Center intercom lines.
Onsite Operational Support Center (2.2.2c/III.A.1.2)
Units 1 and 2 - The licensee has designated an area adjacent to each unit's control room as the onsite operational support center. This was reported by letter dated 12/31/79 and concurred within NRC evaluations dated 2/25/80 and 4/18/80.
,
e
.-_
,
8.
Follow-up of Bulletins 80-14 and 80-17 (Unit 1)
The NRC issued Bulletin 80-14 " Degradation of BWR Scram Discharge Volume Capability on 6/12/80,Bulletin 80-17 " Failure of Control Rods to Insert During a Scram at a BWR" on 7/3/80 and Supplements to that Bulletin on 7/18/80, 7/22/80 and 8/22/80.
The inspector reviewed actions taken by the licensee to implement commitments made to bulletin requirements during this inspection period and Inspection 50-245/80-11. The licensee had taken action to fulfill those comitments.
Inspection findings are sumarized:
SDV vent and drain valves (80-14.3) - Station procedures have been revised to require testing prior to startup and after any scram (0P201, Revision 8. Change 2, dated 7/16/80) and to verify valve position once per day (OPS 10.10 Revision 34 dated 10/1/80).
Damaged SDV level switch float is to be reported to the NRC per SP 408D, Discharge Volume High Water level, Revision 3 dated 8/8/80.
Emergency Procedures require that the operator take action stipulated in Bulletin (80-17.4)
OP 502A, ATWS, Revision 2, dated 7/11/80 was found to implement each action stated in the bulletin.
Surveillance of SDV for residual water (80-17.5; Supp.180-17.5)
Procedures and portable UT equipment are available to monitor SDV for residual water. Testing was performed once daily for the period 7/5 through 7/11, once a week 7/12 through 9/12 and once per shift 9/12 untti the unit was shutdown for a refuel outage on 10/4.
Prompt notification to the NRC when Engineered Safety Features Systems are not fully operable (80-17.6). This reporting requirement is stipulated in administrative controls concerning required reporting to the NRC, SF-113 Revision 1, dated 7/11/80.
l Operators authority to initiate SLCS (Supp. 1,80-17.A2). Operating
!
procedures OP 502A, ATWS, Revision 2, dated 7/11/80 and OP 304, SLC, Revision 9, dated 9/10/80, have been revised to include requirements to initiate SLC and includes a statement of authority allowing operator action.
Action to be taken in the event water is found in SDV (Supp.1,80-17.A3).
Procedure 10.10, Shift Surveillance, has been updated to include requirements for plant shutdown or scram in the event specified amounts of water are found.
-
l
.
e e
-, ~ - -
-
m+
e
---
m--y
-
SLC actuation switch key location (Supp.180-17. A4). Licensee managementhasdirectedthattheSLCkeybekeptintheactuation switch.
System to continuously monitor SDV water levels (Supp.1,80-17. B1) -
.
The inspector has verified that a system has been procured and is to be installed during the current refuel outage.
Requirement for scram immediately in the event of low air system pressure in the event of low air system pressure, multiple rod drift-in alann or a marked change in the number of control rods with high temperature alarms (Supp. 3,80-17.1) - OP 512. " Rapid and Total Loss of Instrument Air". Revision 3, Change 1, dated 8/27/80 implemented these requirements.
Functional testing of SDV instrument volume with water after each scram before returning to power (Supp. 3,80-17.2) - OP 201, 'tApproach to Criticality", Revision 9, Change 2, dated 8/27/80, includes that requirement; Surveillance Procedure SP408D, " Discharge Volume High Water Level Scram", Revision 3, dated 8/8/80.
9.
Inspector Witnessing of Surveillance Tests The inspector witnessed the performance of surveillance testing of selected components to verify that the surveillance test procedure was properly approved and in use; test instrumentation required by the procedure was calibrated and in use; technical specifications were satisfied prior to removal of the system from service; test was
,
I perfonned by qualified personnel; the procedure was adequately detailed to assure performance of a satisfactory surveillance; and, test results satisfied the procedural acceptance criteria, or were properly dispositioned.
The inspector witnessed the performance of:
Unit 2
,
l Engineered Safety Features System Integrated Testing, Facility 2 on l
9/27 and Facility 2 on 10/7.
l l
10.
Review of Radioactive Material Shipments -(Unit 1)
i The inspector reviewed the activities concerning the shipment of l
solidified radioactive waste to the Barnwell, S.C. burial site. Those i
activities included receipt inspections of the shipping cask and liner, solidification of material, radiation surveys and the completion of l
administrative and quality control requirements prior to shipment.
These inspections concerned:
l Solidification of liquid waste - 10/6
--
11.
Exit Interview (
At periodic intervals during the course of the inspection, meetings
,
were held with senior facility management to discuss the inspection l
scope and findings.
I
_
-