IR 05000245/1982005
| ML20052B345 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 04/14/1982 |
| From: | Elsasser T, Lipinski D, Shedlosky J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20052B336 | List: |
| References | |
| 50-245-82-05, 50-245-82-5, 50-336-82-07, 50-336-82-7, NUDOCS 8204300314 | |
| Download: ML20052B345 (18) | |
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U.S. NUCLEAR REGULATORY COMMISSION Region I 50-245/82-05 Report No.
50-336/82-07 50-245 Docket No.
50-336 DPR-21 License No. DPR-65 Priority Category C
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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 Inspection conducted: February 7 thru March 27, 1982 Inspectors: 4[
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. T. Shedlosky, S Resident Inspector dats signed flikk2 s-a D. R.'Lipinski, Resident Inspector date signed date signed
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Approved by:
T. C. Elstuudr, Chief
'date signed Reactor Projects Section IB, Division of Project & Resident Programs Inspection Summary:
Unit 1:
Routine facility safety inspections, February 7 thru March 27, 1982 (Report Number 50-245/82-05) including:
evaluations of plant operations, equip-ment alignments and readiness, radiation protection, physical security, fire protection, plant operating records, maintenance and modifications, surveillance testing and calibrations, and reporting to the NRC. The inspection involved 127 hours0.00147 days <br />0.0353 hours <br />2.099868e-4 weeks <br />4.83235e-5 months <br /> of onsite, regular, backshift, and weekend inspection effort by two resident inspectors.
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Results: No Violations were identified.
Unit 2:. Routine facility safety inspections, February 7-thru March 27, 1982 (Report Number 50-336/82-07) including:
evaluations of plart operations, equipnent alignments and readiness, radiation protection, physical security, fire protection, plant operating records, maintenance and modifications surveillance testing and calibrations, and reporting tc the NRC. The inspection involved 169 hours0.00196 days <br />0.0469 hours <br />2.794312e-4 weeks <br />6.43045e-5 months <br /> of
- onsite, regular, backshift, and weekend inspection effort by two resident inspectors.
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Results: No Violations were identified.
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DCS IDENTIFICATION NUMBERS NRC INSPECTION NO. 50-245/82-05 50-336/82-07 No, Report Paragraph 50336 - 820323
50245 - 820211
50245 - 820115
50245 - 820115
50245 - 820217 3 & 10 50245 - 820212
50245 - 820224 4 & 10 50245 - 820212
50336 - 820106
50336 - 820104
50336 - 820126
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L_ETAILS 1.
Persons Contacted
The below listed tednical and supervisory level personnel were among those contacted:
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A. Cheatham, Radiological Services Supervisor J. Crockett, Unit 3 Superintendent F. Dacimo, Quality Services Supervisor E. C. Farrell, Station Services Superintendent B. Granados, Health Physics Supervisor H. Haynes, Unit 2 Instrumentation and Control Supervisor R. J. Herbert, Unit 1 Superintendent J. Kangley, Chemistry Supervisor
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J. Keenan, Unit 2 Engineering Supervisor J. J. Kelley, Unit 2 Superintendent E. J. Mroczka, Station Superintendent V. Papadopoli, Quality Assurance Supervisor R. Place, Unit 2 Engineering Supervisor R. Palmieri, Unit 1 Engineering Supervisor W. Romberg, Unit 1 Operations Supervisor S. Scace, Unit 2 Operations Supervisor F. Teeple, Unit 1 Instrumentation and Control Supervisor W. Varney, Unit 1 Maintenance Supervisor P. Weekley, Security Supervisor 2.
Status of Unresolved and Open Items
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New Items:
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Unit 1 245/82-05-01, (0 pen Item), Replacement of General Electric Type HFA relays supplied with Lexan coil spools (paragraph 4). -(Replaces 245/81-05-02.)
l 245/82-05-02, (Unresolved), Analysis and modifications to assure conformance with 10CFR 50.44, Standards for Combustible Gas Control (paragraph 5).
Unit 2 I.
336/82-07-01, (0 pen Item), Replacement of General Electric Type HFA relays supplied with Lexan coil spools (paragraph 5).
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Unit 1 245/81-16-01. (Closed), Operators have been trained in computer displayed
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core thermal limits.
Inspector has reviewed lesson outline and attended a training session.
245/81-14-02. (Closed), Calibration program revised to provide feedback to previous users of gauges and instruments found out of tolerance.
Data sheets are keyed to inform the appropriate groups.
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245/81-11-07, (Closed), The electrical pressure regulator servo-motor has been replaced and its response time adjusted.
However, a February 11, 1982, Group I (MSIV) gain resulted in a pressure decrease to the setpoint of the reactor trip a containment isolation. The Technical Specification setpoint is greater than or equal to 880 psig Main Steam Line pressure. A setting of 89216 psig has been established to allow for instrument drift between tests. This is within 32 psi of the post trip main steam pressure. The licensee is evaluating a reduction in setpoint pressure and may propose a Technical Specification Amendment. The pressure regulator and Group I i
isolation subsystems are operating properly, therefore, this item is Closed.
245/81-11-05, (Closed), New annunciator is actuated by trip of either Reactor Recirculation Pump Motor-Generator field breaker.
245/81-05-01, (Closed), Surveillance procedure SP672.1, Manual ATWS Functional Test, Revision 0, dated June 2,1981, trips each logic division including Reactor Recirculation Pump Motor-Generator field breaker and Alternate Rod Insertion Backup Scram Valve Reactor Trip. Testing is performed once per operating cycle during the refueling outage.
Complete coverage of the ATWS system is provided by overlap with instrument channel surveillance and calibration procedures SP408M & N.
Unit 2 336/81-10-03, (Closed), Primary to Secondary Steam Generator leak rates were monitored during the remainder of the last operating cycle.
Leak rates of 0.04 and 0.02 gpm were calculated by primary to secondary isotopic ratios.
During the refueling outage, each steam generator was found with one leak in a plugged tube, plug to tube-sheet weld.
Both were on the hot leg side.
Plugs were replaced and welded.
Steam Generator status is addressed in paragarph 6.
336/81-01-09, (Closed), Containment Hydrogen Monitor span gas is available only wi.th a nitrogen carrier to avoid creating a combustible mixture. Nitro-gen must be used as the zero gas. This results in a 0.4 percent positive offset when the monitors are returned to an air atmosphere.
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336/81-01-07, (Closed), The licensee has completed the twelve month testing program of insulation resistance checks and local leak rate tests.
No unacceptable conditions were noted.
336/81-01-05, (Closed), Safety Injection Tank #1 has been repainted following overheating in January 1981.
336/81-10-02, (Closed), Two fuel assemblies were returned to the vendor and were reworked along with three assemblies which had never left the shop.
This brought the assemblies within gauge tolerance to insure an interference free fit between nozzle posts and the upper core plate. The problem was due to improper top nozzle post alignment.
Control Element Assembly (CEA) free path was below specification due to guide tube deformation caused by excessive swagging pressure. However, measured free path is sufficient to prevent CEA to guide tube interference.
Licensee audits of fuel fabrication will insure that vendor design changes and manufacturing procedures will prevent reoccurrence.
Combined Units 1 & 2 245/81-07-01 & 336/81-06-01, (Closed), QA inspections for each waste shipment include verification for proper labeling.
245/80-20-01 & 336/80-22-02, (Closed), Data base library has been updated to include Sb-125 and verified against the nuclides listed in NUREG/TM-102,
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Nuclear Decay Data for Radionuclides Occurring in Routine Releases....
The July thru December,1980, Radioactive Effluent Release Report contains a correction to include Sb-125 during the first two quarters 1981, 3.
Review of Plant Operation - Plant Inspection (Units 1 and 2)
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The inspectors reviewed plant operations through direct inspection and observation of Units 1 and 2 throughout the reporting period.
Unit 1 operated at full power through the inspection period with the exception of a reactor trip on February 11 and minor power reductions for surveillance testing.
Unit 2 completed a maintenance and refueling outage and was taken critical on March 11. The unit reached full power on March 20, following startup and power ascension testing. A reactor trip occurred on March 23.
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Instrumentation Control room process instruments were observed for correlation between channels and for conformance with Technical Specification requirements.
No unacceptable conditions were identified.
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Annunciator Alanns 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 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 was observed to be in confonnance 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 pcrsonal monitoring devices. There were no unacceptable conditions identified.
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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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Fire Protection / Prevention
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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.
There were no unacceptable conditions identified, g.
Control of Equipment During plant inspections, selected equipment under safety tag control was examined.
Equipnent conditions were consistent with information in plant control logs.
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Instrument Channels Instrument channel checks recorded on routine logs were reviewed. An independent comparison was made of selected instruments. No unacceptable j
conditions were identified.
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Equipment Lineups The inspector examined the breaker position on switchgear and motor control centers in accessible portions of the plant. Equipment
conditions, including valve lineups, were reviewed for conformance with Technical Specifications and operating requirements. No unacceptable conditions were identified.
j. Reactor Trip - March 23 (Unit 2)
The reactor tripped from 98 percent power, 0949, March 23, due to Electro-Magnetic Interference (EMI) from shifting the Chemical Volume Control System Mode Select Switch from Dilute to Borate. Post trip testing found that the EMI impulse affected the following instrumentation:
- Pressurizer Pressure and Level
- Letdown Pressure
- Steam Generator Feedwater Regulating Valve Lockup
- Reactor Coolant Loop Tc, which affected:
- Tavg-Tref Deviation
- Delta T-NI power Deviation
- Thermal Margin / Low Pressure Set Point The post trip sequence of events log had the RPS Trip Thermal Margin / Low Pressure preceded by a Tc high alarm; where plant process instrumentation recorded stable primary, secondary and turbine-generator parameters up to the trip. Other than alarms associated with the above listed instruments, all safety related equipment operated properly.
The EMI source was found to be the DC solenoid operated valve controlling the Boric Acid Flow Control Valve. A pulse was generated when the solenoid was de-energized shifting the Mode Select Switch to Borate through Manual. The solenoid energized in manual. A transient suppression varistor across the solenoid
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was replaced with a diode which eliminated the problem.
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Reactor Trip - February 11 (Unit 1)
The reactor tripped from 90 percent power, 2357, February 11 due to low reactor water level.
Reactor Feedwater Regulating Valve (FRV)-B
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had been shut one-half turn in local manual mode for inspection and maintenance of its positioner. FRV-A, which remained in automatic, opened then fully shut causing vessel level to drop to the trip point. An investigation found that FRV-A air operator had been assembled with its piston inverted during prior maintenance. An 0-ring seal between the piston and piston rod was not seated in a groove cut on the proper side of the piston. The valve shut when the 0-ring failed.
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Along with repairs, Maintenance Procedure 716.2 has been modified to include a caution statement on proper piston orientation.
4 During the transient following the tri 880 psig actuating the Group I (MSIV) p, reactor pressure dropped to Isolation. All other safety related systems including the reactor pressure regulating system performed properly.
(See Paragraph 2, open item 245/81-11-07.) There were no unacceptable conditions identified.
1.
SwitdgId Fire (Units 1 and 2)
i At 0557, February 17, one phase of a circuit switcher located in the 345 Kv switchyard failed under load resulting in a phase-to-phase fault. Damage was confined tn that device. Prior to the failure, breakers were opened i
to isolate the Yorth (A) 345 Kv bus. That caused all power supplied to the Millstone-Card (383) line to go through the circuit switcher (15G-2T-6).
To isolate the device, yard breaker 15G-3T-2 was opened at 0700, de-energizing the Reserve Station Service Transformer. At that time incoming power was not available from any 345 Kv line. Unit 1 was operating at full power, its electrical loads supplied by the Normal Station Service Transformer; Unit 2 was shuunn for a refueling outage, loads were also supplied through its Normal Stat $on Service Transfomer.
In accordance with Technical Specifications 3.9.B.2 and 1.K, the Unit 1 emergency diesel generator and emergency gas turbine generator were started and placed in parallel with their output buses. Disconnects associated with the faulty circuit switcher
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were opened to allow the Unit 1 Reserve Station Service Transformer to be energized at 0800.
There were no unacceptable conditions identified.
4.
Potentially Generic Failure Mode of General Electric'HFA Mlays'(Units 1'& 2)
During routine surveillance conducted on February 24, 1982, of General Electric (GE) Type HFA relays, the licensee discovered that the front of the Lexan coil spool of a relay associated with Unit 1 containment isolatio loaic circuitry, wasmissing.Therelayde-energizestocauseamainsteamisolat15nvalve closure (Group I Isolation) on main steam line high radiation. The logic requires one of two channels in each of two trip systems to de-energize and cause the isolation.
It was found that the normally energized relay would not open its contacts when power was removed from the coil. The Lexan (a polycarbonate)
material appears to have cracked, a fragment lodging between the amature and coil pole. A failure analysis conducted by General Electric, Philadelphia, concluded that melted Lexan was holding the relay amature against the coil pole, preventing the contacts from opening.
The failure was detected during a monthly visual inspection for cracking of Lexan coil spools. The cracking problem was described in NRC infomation notice 81-01 and GE Service Advice 721-PSM-152.1 and 152.2. By letter dated May 18,1981, the licensee notified Region I that of the 710 HFA relays used, 222 exhibited cracking to various degrees. That letter documented an analysis of the problem and the licensee's surveillance and replacement programs. Testing during that investiga-tion program did not identify a failure mechanism which would prevent the relay contacts from opening.
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During a visual inspection of all reactor protection system relays on February 24, four additional relays were identified with a very slight amount of melting of Lexan material.
This was occurring at the relay pole copper shading ring; all of the relays have 115 volt AC coils. None of the relay coils had failed.
The defective relays have been replaced with those using the GE Century Series magnetic assemblies with Tefzel spools, high temperature wire and impregnated insulation. The licensee is inspecting HFA relays with Lexan coil spools at Units 1 and 2 on a schedule based on the extent of cracking. Those which are normally energized and are in safeguards applications are inspected weekly.
The program to replace these relays is on an accelerated schedule.
The replacement of HFA relays with Lexan spools had been identified as an open item, 245/81-05-02.
To update its status, this item is replaced with 245/82-05-01 and 336/86 07-01.
5.
Compliance with 10 CFR 50.44, " Standards 'for Combustible Gas Control" (Unit 1)
This rule requires that means be provided for the control of hydrogen gas gen-erated following a Loss of Coolant Accident (LOCA); the gas may evolve from the metal-water reaction, radiolytic decomposition or corrosion.
During rule-making, the original section 50.44 was published (43FR50162) on October 27, 1978, to be effective on November 27, 1978.
Based on the results of analysis specified in the rule and the date on which the notice of hearing on the appli-cation for a construction permit was published, certain actions and systems were required.
An analysis must show that following a LOCA, but prior to gas control system operation, either uncontrolled hydrogen-oxygen recombination would not take place, or the plant could withstand the consequences of that reaction. Con-tainment inerting is required if neither of these conditions can be shown. The quantity of hydrogen gas generated is assumed to be the greater of either five times the amount calculated in demonstrating compliance with 50.46(b)(3),
or the amount resulting from the reaction of all the metal in the outside sur-faces of the cladding surrounding the fuel to a depth of 0.23 mills. Because the notice of hearing on the application for the Millstone Unit 1 Construction Permit was publisted before December 22, 1968, the licensee is required to provide a combustible gas control system designed to conform with the General Design Criteria 41, 42, and 43.
Purge or purge and repressurization systems are also to be designed to meet the dose calculations specified in part 100.11(a)(2).
Criterion 41 states that each system have suitable redundancy to assure that its safety function can be accomplished, assuming a single failure and the loss of on-site or off-site electrical power.
10 CFR 50.44 also limits repressuriza-tion to 50 percent of containment deign pressure.
The Millstone Unit 1 Provisional Construction Permit (CPPR-20) was issued on November 10,1?f5, the Provisional Operating License (DPR-21) on October 7, 1970.
On Septe.ber 1, 1972, the licensee applied to convert from Provisional to Full-Term Operating License.
In support of these, the licensee has pub-lished several analyses concerning post-accident combustible gas contro _ _.
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The Final Safety Analysis Report (FSAR),Section V, Containment Systems, paragraph 2.3.9, addresses the containmen.; capability to withstand a hydrogen burn without exceeding design pressure. The containment is assumed not to be inerted. The allowable containment capability was calculated at a 19% metal-water reaction if no containment sprays were available, all non-condensible gasses are stored in the suppression chamber, and there was no hydrogen burn. The burning of hydrogen gas increases the allowable metal-water reaction to 35%. These limits are increased when containment spray is initiated. This analysis had been presented to demonstrate the integrity of the containment in the event that an excessive amount of hydrogen was produced in a non-inerted atmosphere.
The September 1,1972, Application for a Full-Term Operating License (FTOL)
addressed conformance with the General Design Criteria, which was in effect on May 21, 1971. When addressing Criterion 41 - Containment Atmosphere Cleanup, the licensee concluded that the two containments (primary containment and reactor building) act as fission product barriers.
Nitrogen inerting the primary containment precluded the combustion of hydrogen from metal-water reactions. Hydrogen and oxygen production was evaluated using the criteria of AEC Safety Guide 7 (which preceded Regu-latory Guide 1.7).
To prevent a hydrogen burn, assuming an initial oxygen concentration at the Technical Specification limit of 5%, nitrogen makeup would be required one day after a LOCA.
The same analysis concluded that venting would not be required for control of combustible gas. Although containment pressure would be increased by nitrogen addition. The containment pressure 40 days after a LOCA would be 50% of design assuming no venting and no containment leakage during the period.
If a containment leak rate of 20% or more of Technical Specifica-tions allowable was assumed, the analysis concludes that venting would never be required as out leakage would exceed nitrogen addition rates.
(Typical containment leakage rates measured during testing are at about 60% of Technical Specifications allowable.)
Millstone Unit I has an installed nitrogen supply system to allow contain-ment atmosphere dilution (CAD). Nitrogen is supplied to the primary con-tainment drywell or suppression chamber purge supply lines. Post acci-dent containment venting is accomplished through two-inch valves, which bypass the eighteen inch drywell and torus inboard containment isolation valves, and through the Stand-By-Gas Treatment System to atmosphere via the plant vent stack. These systems and components are used frequently during plant operation to regulate containment pressure and maintain drywell to suppression chamber differential pressure. Although an operator must place the liquid nitrogen evaporator in service locally in the yard outside of the reactor building, all other operations are performed from the control room.
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Although the SGTS and containment isolation system can sustain a single failure, the ability to add nitrogen for oxygen dilution or containment venting for pressure control is not so protected. The installed nitrogen addition system does not conform with General Design Critorion 41 in that it lacks redundancy.
Specifically, there is a single storage tank, evapora-tor and supply line. Purge exhaust lines from drywell and torus combine through a single outboard containment isolation valve in the purge supply line to the SGTS.
The purge supply and exhaust containment isolation valves are air operated open, spring shut. The station instrument air compressor is supplied from a safeguards electrical bus which is powered by the emergency diesel generator in the event of a loss of off-site power. The station service air compressor is supplied by a bus which is powered by the emergency gas turbine generator during a loss of off-site power. The station service air compressor will preferentially serve the instrument air system.
In addition, air may be supplied by Unit 2 with an installed cross-tie.
Instrument air supply headers are also not redundant.
The licensee has established an administrative minimum volume of 100,000 scf in the 800,000 scf liquid nitrogen storage tank. The re-order volume is 400,000 scf. These minimums have been established to provide a post accident source of nitrogen and are called out in Operations Form 10.10, Revision 38, Change 2, Daily Shift Surveillance.
Containment System Operating Procedure, OP-311, Revision 11 Change 2; and Emergency Action Procedures OP-506, Revision 2, Change 2; Loss of Coolant and OP-513, Revision 7, Change 1; Primary Containment High Pressure were found to address the assumptions and conclusions of the licensee's
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safety analysis, which was referenced above.
Requirements are established to monitor hydrogen and oxygen concentrations following a LOCA.
Limits for hydrogen and oxygen concentrations in the containment have been established below combustion levels.
Procedures direct the operation of nitrogen addition equipment to maintain these limits.
Interim requirements relating to hydrogen control were published on December 2,1981,(46FR58484). These revised 10 CFR 50.44(c) and estab-lished a schedule for implementation of new requirements for inerting containments, recombiners and reactor vessel head and reactor coolant system high point vents.
In addition, proposed changes to 10 CFR 50.44(c)
(3) were published on December 23, 1981 (46FR62281). These proposed changes require assuming a larger metal-water reaction in specific types of reactors.
In light of these additional requirements, the licensee has docketed letters dated December 28, 1981, and January 26, 1982 (both W. G. Counsil, Senior Vice President, Nuclear Engineering and Operations Group, NNEC0, to W. J. Dircks, Executive Director for Operations, NRC).
Included in these letters is a commicment to submit to the NRC on, or about, March 26, 1982, the licensee's proposed actions to assure compliance with 10 CFR 50.44.
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Correspondence between the licensee and the NRC Office of Nuclear Reactor Regulation indicates that post accident combustible gas control systems including Air-CAD Systems have been under review since prior to the final rule being published on October 27, 1978.
By letter from the NRC dated August 27, 1979e the licensee was infonned that NRC review work on proposed CAD System design was suspended because of events involving the TMI-2 Lessons Learned Task Group. Combustible gas control has been the subject of NRC reviews of Category "A" TMI-2, Item 2.1.5.a; TMI Task Action Plan, Task II.B.7; the Systematic Evaluation Program, Topic VI-5; and Unresolved Safety Issue A-48.
The correspondence and review programs referenced above were included during the inspector's review of station design and procedures. This review was based on the requirements of 10 CFR 50.44 and published Safety Analysis Reports. The lack of redundancy in certain compcients of the purge supply nitrogen addition system is considered to be Unresolved (82-05-02). This topic will be reviewed during future inspections and will include the information which the licensee committed to prov.de on, or about, March 26, 1982.
Steam Generator Inspection and' Maintenance Pitting of tubes was detected through eddy current testing for the first time this outage.
Surveillance Specification 4.4.5, Table 4.4-6 required inspections of all tubes identified in the licensee's letter dated February 12, 1982. As a result, 424 tubes in No.1 Steam Generator and 280 in No. 2 were plugged due to having imperfections greater than or equal to 40 percent nominal wall thickness. An additional 250 tubes in No. 1 Steam Generator and 75 in No. 2 had recorded indications less than 50 percent nominal wall thickness. The 704 unacceptable tubes were plugged with a permanent, but removable mechanical tube plug.
Filling the Steam Generator's secondary side resulted in finding 35 previously installed tube plugs in the No. 1 Steam Generator and 33 in No. 2 with weld defects in the tube plug to tube-sheet weld. These were repaired by re-plugging.
(461 tubes in the No.1 Steam Generator and 319 in No. 2 were plugged due to being located in high stress areas prior to the support plate rim cuts or due to denting. They had not been plugged due to tube defects).
Segments from three pitted tubes were removed from the No. 1 Steam Generator. Sludge samples and bore-scope examinations were taken in these tube locations, i
l Following the return to power, steady-state primary to secondary leak rate for the No.1 Steam Generator is 0.01 gpm and no leakage in the No. 2 Steam Generator.
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The inspectors observed various phases of the inspection and plugging, including:
training in full scale Steam. Generator mock-ups for ALAR.8 considerations; Quality Control in tube plugging; qualifications of tube plugs and procedures; QC inspections; health physics preparations, pro-cedures, surveys and monitoring to support Steam Generator entries. The qualification program for the tube plug design may be addressed in future inspections. There were no unacceptable conditions identified during this inspection.
7.
Containment' Liner Plate Bulge - (Unit 2)
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During the Unit 2 refueling outage, a bulge in the containment liner plate
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was discovered by QC personnel on an inspection of liner plate paint conditions.
The bulge consists of two areas, each approximately the same size (1 X 10 foot) one on the -3'6" level, and the other above it on the la'5 level. The bulge is located at 1200 azimuth adjacent to the east electrical and piping penetrations.
The liner plate consists of 1/4" carbon steel plate reinforced with vertical 2 x 3 x 1/4" angles spaced at 15" intervals in the affected area.
During construction of the containment, the liner plate structure is erected and then used as the inner form for pouring the concrete containment shell.
Originally the angles are designed to act as reinforcement for the free-standing liner plate structure; then strength the angles serve as anchors,as the concrete is set and develops in the concrete for the liner plate.
The liner plate itself acts as a leak-tight boundary for the containment atmosphere during operation. Non-destructive testing of high stress areas was performed by magnetic particle; there were no defects identified. Also a negative pressure soap box test was completed with satisfactory results.
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The inspector reviewed a licensee report and analysis of the containment liner bulge dated February 12, 1982. That report was based on information presented in the FSAR Sections 5.2.3.3.7, 5.2.4 and 5.2.4.5 and in Bechtel design report BC-TOP-1.
Based on reference data, the licensee concludes that the bulge was probably caused by compressive loads in shrinkage of the concrete shell over the past few years.
Loads for the liner plate were calculated assuming that this area had a one-eighth inch inward curvature during construction.
Inspections and tests show that the bulge is occurring between reinforcing vertical angles. The licensee has concluded that:
(1) the bulge has no detrimental effect on the function of the liner during normal and LOCA conditions; (2) no modifications or testing are required; (3) distortions are expected to occur at other locations; (4) recommended inspection for growth or change as a precautionary measure.
There were no unacceptable conditions identified. This report may be the subject of future NRC inspections.
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Quality Assurance ~ Program' Topical Report' ' Revision '4'(Units '1 & 2)
Changes to the draft Quality Assurance Program Topical Report - Revision 4 were transmitted to the NRC by letter March 18, 1982. These were reviewed and no unacceptable conditions identified.
9.
Review of Plant Operations '-' Logs and Records - (Units 1 & 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 2/7/82 through 3/27/82
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Jumper and Lifted Leads Log
- all active entries Maintenance Requests and Job Orders
- all active entries Construction Work Pennits all active entries
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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 restoration 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 requirements; and logs and records are maintained in accordance with Technical Specification and Administrative Control Procedure requirements.
There were no unacceptable conditions identified.
10.
Licensee Event Reports (LERs)
The inspector reviewed the following LERs to verify that the details of the event were cleaHy 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 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.
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Unit 1 82-01 Setpoint drift of 2 of 16 main steam line high flow pressure switches.
82-02 Inoperable Emergency Service Water Pump "B" due to marine fouling.
82-03 Fire in switchyard leading to loss of Reserve Station Service Transformer (Paragraph 3.1).
82-04 Inoperable Isolation Condenser condensate return valve 1-IC-3 due to mechanical binding at valve seat. The valve had been torqued shut manually while hot following surveillance. The valve was freed and the surveillance procedure modified to include a caution against manually torquing the valve until temperatures have stabilized.
82-05 Failure of one and degradation of four other General Electric Type HFA Relays supplied with Lexan coil spools (Paragraph 4).
82-06 Setpoint drif t in 1 of 8 Main Steam Isolation Valve hydraulic actuators.
Valve 1-MS-2C was found to shut in a period 0.2 seconds greater than allowed by Technical Specifications. The hydraulic operator has been adjusted for correct timing.
Unit 2 82-02 Loss of shutdown cooling due to spurious overpressure isolation caused by blown power supply fuses.
82-03 Inoperable radiation monitors caused isolation of containment purge system. The monitors were rendered inoperable by failure of a fan (F39A).
82-04 Instrument drift in 1 of 2 shutdown cooling high pressure isolation instruments.
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 the inspector. This review included the following considerations:
the report includes the infomation required to be reported by NRC requirements; test results and/or supporting
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information are consistent with design predictions and performance specifica-
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tions; planned corrective action is adequate for resolution of identified problems; determination of whether any information in the report should be classified as an abnormal occurrence; and the validity of reported information.
Within the scope of the above, the following periodic reports were reviewed
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by the inspector:
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Review of Periodic and Special Reports (Cont'd)
Annual Operating Report, January 1,1981, to December 31, 1981,
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Millstone Units 1 and 2.
Monthly Operating Report Units 1 and 2, January 1982.
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Monthly Operating Report Units 1 and 2, February 1982,
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12.
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; the test was performed 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 1 Low Pressure Coolant Injection System Operability per SP622.7, on March 11.
Unit 2 Steam Generator secondary inspection. Steam Generator tube inspections by eddy current testing.
Low Power Physics Testing per special test T82-1, Revision 0 on March 11 and 12.
13.
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 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 reportability as required by Technical Specifications. In a similar manner, the implementation of design changes and modifications were reviewed, including the associated 10 CFR 50.59 safety evaluation.
Compliance with requirements to update procedures and drawings were verified and post modification accept-ance testing was evaluated. The following activities were included in this review: Unit 1 Replacement of HFA relays with Lexan cell spools.
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Emergency service water pump maintenance.
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--- Reactor feedwater regulating valves' operator, positioner, lockup solenoid and pressure regulator maintenance,
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Plant Maintenance and Modifications (Cont'd)
Unit 2 Steam Generator nozzle dam modification.
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Steam Generator tube section removal.
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Steam Generator welded tube plug repair.
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Steam Generator welded tube plug installation.
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Steam Generator mechanical tube plug installation.
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Repair of steam turbine driven auxiliary feed water pump.
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14, Emergency Planning ' Exercise'(Units '1 & 2)
Emergency Planning Exercises were conducted on March 15 and 19. Offsite agencies participated in the second drill. The resident inspectors served as observers in the Emergency Operations Facility on March 15, and in the Control Room and Technical Support Center on March 19. NRC Inspection Report 50-245/81-07 and 50-336/81-09 contain the findings.
15.
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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