IR 05000245/1980004
| ML19318B239 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 05/01/1980 |
| From: | Keimig R, Shedlosky J, Zimmerman R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML19318B234 | List: |
| References | |
| 50-245-80-04, 50-245-80-4, 50-336-80-03, 50-336-80-3, NUDOCS 8006250157 | |
| Download: ML19318B239 (13) | |
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O U.S. NUCLEAR REGULATORY COMMISSION
0FFICE OF INSPECTION AND ENFORCEMENT
Region I 50-245/80-04 Report No. 50-336/80-03 50-245 Docket No. 5 3-336 D'R-21 I
License No.DPR-65 Priority Category C
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Licensee:
Northeast Nuclear Eneray Company
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P. O. Box 270 Hartford, Connecticut 06101 Facility Name:
Millstone Nuclear Power Statig, Units 1 & 2 Inspection at:
Waterford, Connecticut 06385 Inspection conducted: Marc 1 thru March 29, 1980 Inspectors:
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Y MMC
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T. Shediosb, Sr Resident Inspector
'date ' signed S h k--.rn..n..
also f 8 o
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R. P.
erman, Resident Inspector date signed date signed Approved by:
,-eEf'
4'- / - [6 fr. R. Keimiy,1, R Chie Reactor Projects date signed Section Ne'.
S Branch i
Inspection Summary:
Inspection on March 1 thru March 29, 1980 (Combined Report Nos. 50-245/80-04 and 50-336/80-03)
Areas Inspected:
Routine, onsite, regular and backshift inspection by two resident inspectors (84 hours9.722222e-4 days <br />0.0233 hours <br />1.388889e-4 weeks <br />3.1962e-5 months <br />, Unit 1; 112 hours0.0013 days <br />0.0311 hours <br />1.851852e-4 weeks <br />4.2616e-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 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.
Region I Form 12 (Rev. April 77)
800625'O Y'5 7
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'DEfAILS 1.
Persons ~ Contacted The below listed technical and supervisory level personnel were among those contacted:
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J. M. Black, Superintendent, Unit 3 P. Callaghan, Unit 1 Maintenance Supervisor F. Dacimo, Quality Services Supervisor E. C. Farrell, Superintendent, Unit 2 J..Bangasser, Station Security Supervisor H. Haynes, Unit 2 Instrumentation and Control Supervisor R. Herbert, SLperintendent, Unit 1 J. Kelly, Unit 2 Operations Supervisor E. J. Mroczka, Superintendent, Plant Services J. F. Opeka, Station Superintendent V. Papadopoli, Quality Assurance Supervisor R. Place, Unit 2 Maintenance Supervisor P. Przekop, Unit 1 Engineering Supervisor W. Romberg, Unit 1 Operations Supervisor S. Scace, Unit 2 Engineering Supervisor F. Teeple, Unit 1 Instrumentation and Control Sup'.cvisor 2.
Review of Plant Operation - Plant Ir.;pections The inspector reviewed plant operations through direct inspection and observation during routine power operation of Units 1 and 2.
During this inspection, activities in progress at Unit 1 included modifi-cations to core spray system pipe restraints; at Unit 2 activities included recovery from reactor trips on 3/12, 3/21 and 3/23 and the replace-ment of the B-charging pump.
a.
Instrumentation Control room process instruments were observed for correlation between channels and for conformance with Technica~l Specification requirements.
No unacceptable conditions were identified.
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b.
Annunciator Alarms The inspector observed various alarm conditions which had been received and acknowledged. These conditions were discussed with shift personnel who were knowledgeable of the alarms and actions required. During plant inspections, the inspector observed the condition of equipment associated with various alarms. No unacceptable conditions were identified.
c.
Shift Manning i
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 adninistrative 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. 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 contamination.
There were no unacceptable conditions identified.
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f.
Fire Protection / Prevention
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The inspector examined the condition of selected pieces of fire
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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 examihed.
Equipment conditions were consistent with information
in plant control logs.
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Instrument Channels Instrument channel checks recorded on routine legs were reviewed.
An independent comparison was made of selected instruments.
No unacceptable conditions were identified.
1.
Equipment Lineups The inspector examined the breaker position on all switchgear and motor control centers in accessible portions of the plant. Equipment conditions were found in conformance with Technical Specifications
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and operating requirements.
j. Reactor Trips - Unit 2
At 0034 hours3.935185e-4 days <br />0.00944 hours <br />5.621693e-5 weeks <br />1.2937e-5 months <br /> on March 12, Millstone Unit 2 experienced a reactor trip from 100% power due to low level in the No. 2 steam generator.
l The reactor was operating at 100%, primary and secondary parameters were normal for that power level.
Evolutions in progress were re-lated ta weekly testing of the "A" steam generator feed pump turbine I
control oia protective devices.
That test included exercising the turbine emergency governor and trip lockout. Following the reset of the overspeed trip circuit, which is locked out during testing, the turbine tripped. The plant operator at the feedwater pump, in coordination with the control room operator, reset the trip and returned the feedwater pump to service.
During the approximate 15 second time interval between the feed pump turbine trip and the return of feedwater flow from the "A" pump, both steam
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generator levels dropped from the normal 65% to 55%. As steam generator levels recovered to the level set point, the No. I steam generator feedwater regulating valve took control of the steam generator
level. Control room operators observed that the No. 2 steam generator I
feedwater regulating valve remained full open. An attempt was made to shut the valve by shifting the controller to manual. At 87% level, the set point for the steam generator water level control system high level override, the valve shut fully. The operator was unable to regain control of the No. 2 steam generator feedwater regulating valve after the level dropped below the override reset point. Although feedwater flow was reestablished, level continued to drop.
Following a reactor scram at 36%, level shrink dropped the level below the indicating range for about 50 seconds.
Following the reactm-trip and the accompanying turbine trip, quick actuating signals opened main steam atmospheric dump and turbine bypass valves. However, as average reactor coolant temperature decreased to 535 F, one of four turbine bypass valves failed to shut.
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The control room operator placed the steam dump - Tavg controller in manual. The valve shut terminating the cooldown..The rela-tively rapid cooldown of the reactor cook.nt system caused indicated pressurizer level to drop below 0% level for two minutes. At that time, pressurizer pressure dropped to a minimum of 1680 psia.
Pressurizer pressure recovered with pressurizer level and reactor coolant system temperature.
The minimum subcooling calculated by the inspector was 83 F which corresponds to values displayed by the subctoling calculator and observed by the control room operators.
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Subsequent investigation identified mechanical deficiencies in the
"A" feedwater pump trip sub-system and control oil sub-system.
Excessive wear was found in the cylinder of the No. 2 steam generator feedwater regulating valve. That valve is a piston or plug operated valve.
In adition, a broken valve position feedback link was found in the turbine bypass pneumatic positioner.
The reactor was made critical at 2050 hours0.0237 days <br />0.569 hours <br />0.00339 weeks <br />7.80025e-4 months <br /> on March 12.
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At 0849 hours0.00983 days <br />0.236 hours <br />0.0014 weeks <br />3.230445e-4 months <br /> on March 21, the unit tripped from 100% power due to low level in both steam generators. During preparation for cali-brating a gage on the "B" feedwater pump, a technician incorrectly isolated the low suction pressure pump trip switch. When the line was vented in preparation for inserting a test signal, the pump
tripped. The pump was not reset quick enough to avoid a reactor trip on low steam generator level. The "B" turbine bypass valve failed to close when reactor coolant temperature decreased to 535 F, as during the trip on 3/11. The valve was shut by placing the controller in manual.
The reactor was made critical at 2050 hours0.0237 days <br />0.569 hours <br />0.00339 weeks <br />7.80025e-4 months <br /> on March 21. During the ascension to 100%, the control room operators noted abnormalities in steam generator feedwater flow. High feedwater pump discharge pressure, low feedwater header pressure and low feedwater regulating valve differential pressure caused an investigation which resulted in finding the 1A high pressure feedwater heater inlet valve shut.
This had caused all feed flow to pass through the IB heater.
Extraction steam was being supplied to the heater; feedwater flow was established.
i The motor operated feedwater inlet valves are controlled and indi-cated only at a local panel. The valve position error may have been due to mechanical vibration at that panel causing inadvertent valve operation. During the 3/21 shutdown, the feedwater system was placed on long path recirculation. Valve manipulation for that
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operation is accomplished from that same local panel. The 1A heater feedwater inlet valve may have been inadvertently shut when going into or securing from long path recirculation.
As power was increased, vibrations were noticed in the 1B heater.
At 0045 hours5.208333e-4 days <br />0.0125 hours <br />7.440476e-5 weeks <br />1.71225e-5 months <br />, 3/23, with reactor power at 94%, a load reduction was started to take the unit off the line and investigate the
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heater problem. A reactor trip occurred at 0655 hours0.00758 days <br />0.182 hours <br />0.00108 weeks <br />2.492275e-4 months <br /> from 18%
power when oscillations occurred in No.1 steam generator level.
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Following the turbine trip, the "B" turbine bypass valve had to be shut by placing the controller in manual.
Due to excessive seat leakage of the "B" turbine bypass valve, its isolation valve has been shut pending repairs to the bypass valve. An investi-i gation revealed that a flow divider plate in the feedwater head of the 1B heater had been damaged. The reactor was made critical at 2005 hours0.0232 days <br />0.557 hours <br />0.00332 weeks <br />7.629025e-4 months <br />, 3/23, and power increased to 50% while repairs were made '.o the divider plate. The 1B heater was placed in scivice on 3/24.
3.
Review of Plant Operations - Logs and Records
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During the inspection period, the inspector reviewed operating legs and records covering the inspection time period against Technical Specifications and Administrative Procedure Requirements.
Included in the review were:
daily during control room Shift Supervisor's Log
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surveillance 3/1 through 3/29/80 Plant Incident Reports
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all active entries Jumper and Lifted Leads Log
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all active entries Maintenance Requests and Job Orders
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all active entries Construction Work Per: nits
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all active entries Safety Tag Log
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daily during control room Plant Recorder Traces
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surveillance
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daily during control room Plant Process Computer Printed
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Output surveillance daily during control room Night Orders
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surveillance The logs and records were reviewed to verify that entries are properly made; entries involving abnormal conditions provide sufficient detail to comunicate equipment status, deficiencies, i
corrective action restoration and testing; records are being reviewed by management; operating orders do not conflict with the Technical Specifications; logs and incident reports detail no viola-tions of Technical Specification or reporting requirements; logs and
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records are maintained in accordance with Technical Specification
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and Administrative Control Procedure requirements.
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Several entries in these logs were the subject of additional review and discussion with licensee personnel. No unacceptable conditions were identified.
4.
Licensee Action on Previous Inspection Findings (Closed)
Inspector Follow Item (336/79-04-01):
Loss of Shutdown Cooling.
Operating Procedure (0P) 2310, Shutdown Cooling, has been revised through a procedural change to include the action required on a total loss of Shutdown Cooling. The procedural change will be incorporated in the next formal revision to OP 2310.
(Closed) Unresolved Item (336/79-04-02): High Power Calibration.
Technical Specification Amendment 40 requires the lower trip point to be set at less than or equal to 15% rated thermal power. Procedure
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SP-2401X, High Power Calibration, maintains the lower trip setpoint at 14.36% of full power.
l (Closed) Unresolved Item (245/79-27-03):
Recording of "As Found" Data. Health Physics Procedure 912, Area Radiation Monitor Cali-bration, was deleted on February 6, 1980.
Health Physics Procedure 904/2904D, Calibration of Fixed Monitors, Revision 0, February 13, 1980, incorporates the calibration of area radiation monitors and requires recording "as found" and "as left" readings on the cali-bration data sheet.
(Closed) Unresolved Item (245/79-27-04):
PORC Procedure Review.
Procedure IC-414A, Control Rod Drive Module Instrument Calibration, i
received PORC approval at meeting 79-122 and became effective on
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December 7, 1979.
(Closed) UnresolvedItem(336/77-08-04): The licensee has completed
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an engineering analysis and determined that the maximum thermal
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displacement rate for one length of Steam Generator (S/C) piping
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exceads the existing snubber lockup rate. This condition could have imposed an unevaluated stress on the S/G pipe. The licensee generated EWR-405 requesting an evaluation to determine if the piping had been overstressed, postulating previous occurrences of lockup on initiation of blowdown flow to a-cold line. The final results for the analysis indicate that no overstress condition l
associated with (S/G) piping occurred. The evaluation also revised l
the lockup and bleed rate acceptance criteria for 36 snubbers to l
account for ambient temperature expected during operation and for pipe thennal expansion velocities. These criteria were all incor-porated into SP-2733B, Hydraulic Snubber Functional Testing, and for all snubbers where acceptance criteria w~ere ' changed, the revised criteria. were implemented.
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(Closed) Unresolved Item (336/77-31-04): The licensee is currently observing' snubber piston settings on an18-month frequency. The acceptance criteria, however, have not been. fully developed for verification in that the snubber is not at its mechanical stops. The inspector reviewed draft procedure MP 2721V Hydraulic Snubber Piston Setting Verification, which incorporates a piston measurement and provides verification of snubber operability with appropriate acceptance criteria.
(Closed)
Deficiency (245/79-15-04): The inspector reviewed MP 739.1, Revision 3, Hydraulic Shock Suppressor and Sway Arrestor Repair and Testing, Change 1.
This change deleted paragraphs
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which required the licensee to record fluid levels and piston rod emergence. The reason stated for the change was that these parameters were not required. The inspector concurred with this change.
5.
Review of Radioactive Material Shipments The inspector reviewed Radioactive Materials Shipment Records (RMSR) for the period October,1977 through March,1978 for Units 1 and 2.
In addition to review of records for low specific activity shipments, the records associated with the shipment of seven used control rods, RMSR No. 78-31-1, to Barnwell, South Carolina, on February 16, 1978, were reviewed.
For the above period, the inspector found no record of shipment of special nuclear material from the Millstone site.
Additionally, the inspector reviewed radioactive material records for the shipment of Segmented Test Rods from Unit 1 following the 1977 and 1978 refueling outages to the General Electric Company, Vallecitos Nuclear Center, in Pleasanton, California, for examina-tion and research purposes.
--- RMSR 77-67-1,.22 Segmented Test ' Rods shipped March 4 and received March 8, 1977;
--- RMSR 78-191-1, 28 Segmented Test Rods shipped June 8, 1978 and received June 12, 1978.
No items of noncompliance were identified.
6.
Core Spray System "A" Pipe Restraint Modifications - Unit 1
The inspector reviewed the implementation of pipe restraint modifications and repairs to the Core Spray. System "A" injection line, and the LPCI test return line.
Damage to these restraints l
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i was noted duri.ng a plant inspection on 2/19. The cause of the damage has been attributed to water hammering of the system on
pump start duri.ng surveillance testing.
Seat leakage through the Core Spray A injection valves had resulted in pressurizing the system with hot water. To main-tain system pressure below the pump running pressure set point of the ADS logic,a btleed-off path was established through the test
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flow line. However, on pump start water hammering occurred at
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the two-phase interface. The licensee's corrective action was to establish a second keep-fill injection point at the high point of the "A" process line. That injection point is adjacent to the leaking injection valves. The effectiveness of this change was demonstrated by temperature recorders on the A and B process lines.
This work was completed on March 6.
Additionally, the licensee i
is planning to replace the inner isolation valves along with the stainless steel piping during the 1980 refueling outage.
The system has been successfully tested, without water hammering.
There were no unacceptable items identified.
7.
Plant Maintenance 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 qualifications; radiological controls for worker protection; fire protection; retest requirements and ascertain reportability as required by Technical Specifications. The following activities were included during this review:
Unit I Inspection of the Emergency Condensate Transfer Pump to
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l investigate broad band flow noise.
l Repair and modification of Core Spray "A" pipe and Low Pressure l
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l Coolant Injection test return pipe supports.
Modification to Core Spray "A" keep-fill system.
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Service Water Pump "A" overhaul.
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Unit II Repacking of Charging Pump "C".
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Emergency Diesel Generator 12U Output breaker investigation
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of manual synchronization problem.
Bolt replacement pipe restraints 490007 and 490002-12.
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8.
Thread Engagement of Concrete ~ Expansion Bolts
' Unit 2
During plant inspections, less than full thread engagement of attachment nuts on concrete expansion bolts was observed at some restraint base plates. During followup, licensee representatives referenced engineering calculations of Hilti Quik Bolt tensile capacity with two threads short of full thread engagement. That calculation demonstrates the acceptability of thread tensile strength to the required bolt strengths stated in Teledyne Engineer-
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ing Services Report TR-3501-40, dated 7/26/79.
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The licensee's position does not confom with the requirements of j
ANSI N45.2.5-1974, paragraph 5.4 or ASME Section III NF4711.
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The licensee's representative agreed to infom the NRC of the
basis for this position in future correspondence concerning Bulletin 79-02.
9.
Licensee Action on IE Circulars The inspector reviewed records relating to IE Circulars and discussed with licensee personnel those actions taken to adequately address and resolve the issues raised by the IE Circulars.
Circular 78-13: Inoperability of Service Water Pumps, dated July 10, 1978, described a problem that could lead to a loss of Service Water cooling due to the combined effects of ice and
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silt accumulation in the Service Water Bays.
The Service Water Bays are routinely inspected by contracted divers, with no significant silt / sand buildup noted. Additicnally, i
with seawater as the heat sink, severe icing problems have not
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been experienced.
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Circular'79-04: Loose Locking Nut on Limitorque Valve Operators,
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dated March 16, 1979, addresses specific Limitorque Type SMB and l
SMC valve operators which were found not to have the locking nut fastened securely in accordance with the manufacturer's recomendation.
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With the locking nut not secure, it is possible for the nut to loosen and allow the stem nut to move axially to.the point that the splines are disengaged, resulting in a loss of drive to the valve stem.
i All Limitorque operators have been inspected by the licensee on j
both Units 1 and 2, and no problems with valve operators were i
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identified. Additionally, all Limitorque operators have been staked
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to insure the stem locking nut is secured in order to prevent drive splines from becoming disengaged. Maintenance Procedures for Units 1
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and 2 have been revised requiring the lock nut to be staked should
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it be removed for disassembly of the operator.
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Circular 79-13: Replacement of Diesel Fire Pump Starting Contactors,
dated July 15, 1979, identifies a generic problem with the starting
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contactors for Cummins Industrial Fire Pump Engines.
Licensee investigation revealed that the Security System Diesel is the only diesel manufactured by Cummins Engine Company.
Further, the DC relay contactors and magnetic switch identified as a problem, do not exist on the Security System Diesel.
10.
Licensee Event Reports (LER's)
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The inspector reviewed the following LER's to verify that the details of the event were clearly reported, including the accuracy of the dcscription of cause and adequacy of corrective action. The inspector determined whether further infonnation was required, and whether generic implications were involved. The inspector also verified that 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 Comittee, and that the continued operation
of the facility was conducted within the Technical Specification limits.
Unit 1
'oTTugus(Updated Report), The licensee updated the original report 79-19, t 6, 1979, regarding corrected as-left leak rates.
Feed water check valyc.9-10A, Shutdown Cooling isolation valve SD-2B and Atmosphere Control valves AC-7, 9, 11 & 12 were involved. Total reported leakage was increased from 108.65 to 109.75 SCFH at 43 PSIG.
80-05, The operation in a degraded mode when the Core Spray Sub-system was removed from an operable status.
(See paragraph 6)
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1 Unit 2
80-04, Out of specification trip unit for RPS Channel B, RCP underspeed. A faulty frequency to voltage converter was replaced.
80-05, The licensee determined that an incorrect assumption was made in the safety analysis which may have resulted in conditions less conservative than assumed in the safety analysis. The boron dilution accident assumed the reactor in cold shutdown with a
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full reactor coolant system and a 1% shutdown margin. The time to become critical of 20 minutes resulted. The analysis did not consider the fact that the reactor coolant system may be dr:ined to the centerline of the coolant hot leg.
Under that condition, the time to become critical was calculated to be 10 minutes.
This did not satisfy the assumption for a 15-minute maximum time for operators to recognize the situation and take action.
The licensee has instituted additional administrative controls, OP2207, Plant Cooldown, Revision' 7, Change 2, dated 3/27/80, has the requirement that when' proceeding to Mode 5, maintain the shutdown
boron concentration at the 200 F valve which is specified on OPS Form 2208-12, Shutdown Boron Concentration vs. Moderator Temperature, Revision 4, dated 5/23/79. This will maintain the shutdown margin greater than 2%. OPS Form 2208-12 has been i
graphed for Cycle 3 Core conditions of Xenon free, and 3.2%
shutdown margin with the maximum worth CEA stuck full out.
80-06, Removal of the "C" Charging Pump from standby service for packing replacement with W "B" pump inoperable for pump replace-ment. The "A" pump was ex%1e and in service. The C pump was started for testing 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> 45 minutes after it had been removed from service for maintenance. The pump was declared operational
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30 minutes later.
80-07, Condensate Storage Tank below minimum Technical Specification volume. This had occurred during a period of high water usage resulting from demineralizer regeneration and increased Steam Generator Blowdown. At the time of the occurrence, the licensee
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verified the availability of backup water systems.
In order to provide more time for corrective action, the tank low level alarm set point has been increased.
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11.
Review of Periodic and Special 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 l
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the inspector. This review included the following considerations:
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the report includes the information required to be reported by NRC requirements; test results and/or supporting information are consistent with design predictions and performance specifi-
cations; planned corrective action is adequate for resolution of identified problems; determination whether any information in the report should be classified as an abnormal occurrence; and the
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Within the scope of the above, the following periodic reports were reviewed by the inspector:
Monthly Operating Report - February,1980.
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Annual Report, 1979.
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Environmental Operating Report, 1979.
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Marine Environment Annual Report,1979.
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Semiannual Report of Radioactive Effluents, July - December, 1979.
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12.
Exit Interview At periodic intervals during the course of the inspection, meetings were held with senior facility management to discuss the inspection scope and findings.
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