IR 05000213/1989016
| ML19332C656 | |
| Person / Time | |
|---|---|
| Site: | Haddam Neck File:Connecticut Yankee Atomic Power Co icon.png |
| Issue date: | 11/08/1989 |
| From: | Haverkamp D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML19332C649 | List: |
| References | |
| 50-213-89-16, GL-88-17, IEIN-89-065, IEIN-89-65, NUDOCS 8911280389 | |
| Download: ML19332C656 (20) | |
Text
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r JU.S. NUCLEAR REGULATORY COMMISSION
' REGION I' , er IDocket'No.
50-213/89-16
License No.
OPR-61x L Licensee:; Connecticut Yankee Atomic Power Company , ~P. O. Box 270- . Hartford, Connecticut 06141
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. i Facility: Haddam Neck Plaj
- Location:
Haddam' Neck, Connecticut y - -Dates:- Sep'tember 6, -' October 17, 1989 - '
- Inspectors:
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- Andra'A'. Asars, Resident Inspector John.T.'Shediosky, Senior Resident Inspector Peter J. Habighorst, Resident Inspector, Millstone 2
' Approved by: /m[M // /P/P4 d < Donald R. Haverkamp, Chief Reactor-ProjectsSection4Ag~ Date
,* Division of Reactor Projects ' Inspection Summary: Inspection on September 6 - October 17, 1989 (Inspection Report No. 50-213/89-16) l
1 Areas Inspected:. Routine safety inspection by resident inspectors of plant - j' operations; events occurring during the inspection period including elevated ' -reactor-coolant system. activity; radiological controls; maintenance and sur-ve111ance activities ~ including core support barrel removal and inspection, fuel j inspection and cleaning, containment spray nozzle flow testing, and containment < ' penetration leak rate testing; security; engineering and technical support , activities,' including steam generator tube plugging and plug: repair; safety ' assessment 1and quality verification activities, including Plant Operations Review Committee meetings and written reports; and licensee response to Generic , ' Letter 88-17, Loss of Decay Heat Removal (TI 2515/101).
Results: This inspection period covered the first seven weeks of the 1989 , , L Refueling Outage. The management decision to delay reactor disassembly in
%X . response to high reactor coolant system activity was prudent. Appropriate ' ' consideration was given to ALARA controls and personnel safety reviews, though' the'~ delay impacted the outage schedule (Section 2.2.1).
The outage schedule l. ' subsequently was greatly impacted by difficulties encountered during core i-support barrel removal. The-licensee also thoroughly and deliberately aval-l uated that situation and reacted prudently (Section 4.1.1).
Enforcement '
L discretion is being taken for a violation of the station procedure governing ' ' ' radiation worker responsibilities in which a worker entered Containment without-signing on to the appropriate Radiation Work Permit (Section 3). No new Unresolved Items were ider.tified.
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TABLE OF CONTENTS'- ' ' '
o . 'Page h 1.
Summary of Facility Activities (71707)*..............
2.- Plant Operations- (71707, 71710, and 93702). -............
k 2.1 Operational Safety Veri fication.................. I fl 2.2 Followup of Events Occurring During Inspection Period..... 2-p 2.2.1 Elevated Reactor Coolant System Activity........
t " 2 2.2 TurbineLAutostop 011 Mercoid Switches Fail Surveillance.
. W 3.
Radiological Controls (71707)..........,.....,...
' 4.
Maintenance and Surveillance (61726, 62703, and 71707).......
, 4.1 Maintenance Observation...
............-..... 4.1.1-Reactor Core-Support Barrel Removal and Inspection...
4.1.2 Fuel Inspection and Clea'ning....... .c
...... 4.1.3 Reactor Upper' Internals Stand Misplacement.
...... 4.2 Surveillance Observation...................
, ~4.2.1 Containment Spray Nozzle Flo,i Test.
.......... '4.2.2 Containment Penetration -Leakage Testing... ,
' .... " S.- i. Security 0 1707) .........................
6.
-Engineering and Technical Support (37700, 37828, and 71707)....
' 6.1 Stea a Generator Tube _ Plug Repair Fixtures......... .
-6.2. Steam Generator Tube Plugging....,............
'7.
Safet,/ Assessment and Quality Verification (40500, 71707, 90712, , and 92700)............................
7.1 Plant' Operations Review Committee...............
- 7.2. Review of Written Reports..
................. 8.
Generic Letter 88-17, Loss of Decay Heat Reraoval (TI 2515/101)...
p-8.1 Training...........................
8.2 Containment Closure......................
l 8.3 Reactor Coolant System Temperature Indication...
...... L 8.4 Reactor-Coolant System Level Indications...........
8.5 Reactor Coolant System Perturbations.............
I 8.6. Reactor Coolant System Inventory.
.............. L8.7 Hot - Leg Fl ew Pa ths..................
, ... l 8.8 Loop Stop Valves......
................. ' 8.9 Conclusion.........
................. L L 9.
Exit Interview (92703).......................
The NRC Inspection Manual inspection procedure or temporary instruction
L that was used as inspection guidance is listed for each applicable report p section.
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Summary of Facility Activities ' l 'At the start of.the inspection period, the plant was in Mode 5 and begin-ning the 15th refueling outage.
Reactor disassembly and entry into Mode 6 , was delayed due to higher than normal reactnr coolant ' system (RCS) radio-nuclide activity. On September 17, following extensive RCS degassing, K purification,_and activity analysis,-the RCS was opened and Mode 6 entered.- The reactor disassembly began on September 21 and defueling completed on September 25.
Debris-induced fuel damage was identified during fuel' inspection on September 27.
Fuel inspection, cleaning and r reconstitution activities were immediately initiated. On September 28, -- several' unsuccessful attempts were made to remove the core support barrel i (CSB)- from the reactor vessel for inspection.
It was later identified that four dowel pins'were backed.out and one bolt was missing from the CSB i! thermal shield modifications made during the 1987 Refueling Outage. One of the dowel _ pins was' bent when it came in contact with a hot leg nozzle during the attempted CSB removal. At the end of the inspection period, fuel inspection and cleaning was continuing, while preparations were being - made to cut the other three protruding CSB dowel pins to permit CSB removal.
.NRC' Commissioner Kenneth Rogers visited _the facility on September 25. He was accompanied by Malcolm Knapp, Director of the Division of Radiation Safety and Safeguards of Region-I. A tour of the plant was made with raembers of station management and the resident inspectors. Areas toured included the steam generator mock-up facility, control room, switchgear rooms, and containment.
2.
Plant Operations 2.1 Operational Safety Verification The inspector observed plant operation and verified that the plant - -was operated safely and in accordance with licensee procedures and regulatory requirements.
Regular tours were conducted of the following plant areas: control room primary access point -- r --
primary auxiliary building protected area fence --- -- vital switchgear. room yard areas -- -- radiological control point intake structure -- -- Appendix R switchgear building diesel generator rooms -- -- j auxiliary feedwater pump room turbine building ' -- -- Control room instruments and plant computer indications were observed for correlation between channels and for conformance with plant technical specification (TS) requirements. Operability of engineered safety features, other safety related systems and onsite and offsite L power sources were verified. The inspector observed various alarm ,
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F , p"' conditions and confirmed that operator response was in accordance with plant ' operating procedures.
Routine operations surveillance testing was also observed.
Compliance with TS limiting conditisns for operation and implementation of appropriate action statements for - equipment out of service was inspected.
Plant radiation monitoring ' system indications and plant stack traces were reviewed for unexpect- . ed changes.
Logs and records were reviewed to determine if entries were accurate and properly identified equipment, status or deficien-cies. These records included operating logs,- turnover sheets, system , tagouts, and the jumper and lifted lead book.' Plant housekeeping controls were monitored, including control and storage of flammable o material and other potential safety hazards. The inspector also examined.the condition of various fire protection, meteorological, , , and seismic monitoring. systems.
Control room and shift manning were compared.to-regulatory requirements and portions of shift turnovers.
' were observed. Control room access was properly controlled and a . professional atmosphere maintained.
> ( . In addition to normal utility working hours, the review of plant ' operations was-routinely conducted during portions of backshifts C (evening shifts) and deep backshifts (night shifts between 10:00
p.m. and'5:00'a.m. and weekend shifts).
Extended coverage.was provided for 29 hours during backshifts and 18 hours during deep backshifts.. Operators were alert and displayed no signs of inatten-tion to duty or fatigue.
2.2 Followup of Events Occurring During Inspection Period During the inspection period the inspectors provided onsite coverage l and followup of unplanned events.
Plant parameters, performance of i safety systems, and licensee actions were reviewed.
The inspectors confirmed that the required notifications were made to NRC.
During-event followup the inspector reviewed.the corresponding plant information report package, including the event details, root cause analysis, and corrective actions taken to prevent recurrence. The j following events were reviewed: ' ! 2.2.1 Elevated Reactor Coolant System Activity, Prior to shutdown for refueling, the plant had conti-uously ' operated for 461 days and reactor coolant system (RCS) activity was stable at about 0.02 pCi/ml (micro Curies / milliliter).
Following plant shutdown, activity peaked at about 11 pCi/ml.
. The licensee elected to delay reactor disassembly and opening of ' the RCS for about two weeks to ficilitate additional RCS degas-i sing, purification, and activity analysis.
Frequent RCS gas and liquid saaples were taken and results trended. A fuels and chemistry expert from the fuel vendor (Babcock & Wilcox) met with station management on September 15 to discuss the increased activity.
It was concluded that the system purification ion exchangers were saturated and therefore ineffective at further reducing system activity.
The ion exchangers were changed and RCS activity subsequently reduced.
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s Prior,to opening of.the RCS, additional personnel safety pre-cautions were taken in anticipation of increased area gas-activity. These measures included _ clearing containment of.
nonessential personnel and wearing respirators. The RCS was
opened on September 17 without' incident.
.The inspectors attended the September'15 meeting and monitored ' the licensee's review and evaluation of the elevated RCS activity.. The decision to delay reactor disassembly and the-actions taken for personnel safety and'ALARA concerns were s prudent and conservative, n 2.2.2 Turbine'Autostop 011 Mercoid Switches Fail Surveillance During outage calibration on September 22, the turbine autostop - (AST) oil mercoid switches were found out of calibration in 'the nonconservative direction.
Initially, the licensee determined this'to be reportable in accordance with 10 CFR 50.72 - ' . (b)(2)(iii) as an event or condition that alone could have prevented the fulfillment of the safety function of a system.
'; needed to shut down the reactor.
This determination and the required reports were made on September 23.
Further licensee review concluded that this was not reportable because the AST mercoid switches are not taken credit for or. required in the event of a turbine / reactor trip. The emergency notification system ENS report was rescinded on October 6.
1 The inspectors reviewed lthe licensee's reportability evaluation.
The AST mercoid switches are designed to initiate a reactor trip-on low turbine autostop oil pressure. 'The switches are not QA Category 1, are not taken credit fer in the accident analysis, and are not part of the reactor protection system technical specif.ications. Additionally, the as-found setpoints were with-in 1 psig of the acceptance criteria and would have performed , i their intended-function.
The initial determination that this was a reportable event was in accordance with EPIP 1.5-1, l Emergency Assessment, Attachment 12.7, which identifies this trip as a reactor protection system trip or actuation signal.
i jj The licensee is evaluating changes to this EPIP.
l The inspectors concurred with the determination that this event ' is not reportable and found the licensee's evaluation and corrective actions acceptable.
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3.
R_idiological Controls During routine tours of the accessible plant areas, the inspectors observed the implementation.of selected portions of the licensee's radio- ' logical controls program. Utilization and compliance with radiation work permits (RWPs) was reviewed to ensure that detailed descriptions of radio-logical conditions were provided and that personnel adhered to RWP require- . -.-, ,r
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4 ments. The~ inspectors observed controls of access to various radiologi-cally controlled areas and use of personnel monitors and frisking methods-upon exit from those areas.
Posting and control of radiation areas, contaminated areas and hot spots and labelling and control of containers n..s - > holding radioactive materials were verified to be in accordance with' L11censee procedures. During this inspection-period radiological controls j .for four major work activities were observed, including: , steam generator inspection and repair _ activities, -- -split pin modifications, -- fuel inspection ar.d reconstitution, and l -- core support barrel removal and inspection.
-- ' On October 15, health physics (HP) technicians identified that a radiation worker had entered containment without_ signing in on an RWP.
The worker i ' was a contractor employee supporting steam generator (SG) inspection and i repair activities. The individual was acting as an escort for other l workers to the SG loop 3: gate, located in the contain,eent lower level ! outer annulus.
A worker briefing was conducted at the SG checkpoint, ! -which is where workers must sign on to the SG RWPs.
The individual i escorted the workers to the SG loop 3 locked, high radiation gate and i L remained outside the gate (4 to 15 mr/hr area) as the high radiation gate l n watch for a. period of about 75 minutes.
Upon exiting containment, the ' ' individual was unable to sign off the appropriate RWP because he had not ! signed on. Additionally, his pocket dosimeter was reading offscale. The.
, individual's TLD was read and indicated no exposure.
Radiological defi- ! ciency report 89-10-11 was issued.
All steam generator work activities
were discontinued'until the situation was resolved the'following day.
( Licensee HP supervisory personnel immediately interviewed the individual to determine if he had signed on to a RWP and which areas of containment.
- he had entered. The individual stated that he had not entered any areas other than the lower level outer annulus and did not know his RWP number.
- Following the interview, the individual's site access was terminated.
The HP technicians reviewed all RWPs to determinc if the worker had signed on to any permit other than RWP 8900428, Support Work for SG.
The individual was signed on to RWP 8900554, Non High Radiation, Non Conta-
minated Areas in RCA Excluding Containment. This RWP does not cover i activities inside of containment.
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' ^ ' ~ m.V.,0 .ProcedureRPML2:1-6,RadiationWorkerRWP'Responsibilitiestrequiresthati ^ ' ' '. . < ' ' ,allfpersons-woEkingin'aradiologically; controlled [areamustdoso.undsr ,an approved RWP. - Eachiindividual~is required to initialithe RWP_to-
. J signifyf thatlhelhas -read understood,Tand agrees;to comply:with the-RWP _
t m ' ', m - requirements.1 Although the failure to: follow proc'edures constitutes:a . g,
Jviolatiori,y noLNotice of Violation is being issued'in accordance with the
E P-fprovis_ ions ~of 10 CFR Part 2, Appendix. C Section V.G.1, _ Exercise of Dis- ' m, lv "P, W 1cretion (NCV 89-16-01). The seriousness of.this_ violation is mitigated byi ! J the fact:that?the; individual did not enter a'high radiation area and did " inot accumulate any exposure.
' 'On' October 16,' station man ~agement held a meeting with HP and engineering. ' ' ' .' department supervision to discuss-this incident: ~The licensee representa - ' *
- tives7 determined that communication and coordin'ation during SG work'needed-
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- to beiimproved' (The responsibilities
- of control over SG activities were M
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- reemphasized. : Additionally,'a' radiation safety posting was distributed
.onsite which reemphasized the need for_ attention to detail when workinglin '. <> radiation areas, radiation worker responsibilities and.a-description of J
p receht radiological controls deficiencies.
! ' Theiradiologically controlled area-is divided'into; zones.
The containment ' building'is.a zone with two' additional zones within the building,athe
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- steam lgeneraturs and the-loop ~ areas. A radiation worker entering either
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- of ?the inner zonesimust pass Lthe containment zone check p'oint and. proceed i
f to the' appropriate inner zone: check point for briefing and-RWP. sign Lin.
j > ' The ability-to gain access to containment without checking in'at.one of d -
- the -inner zone: check _ points:provides a vulnerability to personnel error.
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iThe-inspector discussed'this with:a HP supervisor. The control of the' , - containment zones is:being evaluated by'the licensee.
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- lists 71n the/NRC Region I;0ffice.
It'wa's~ determined that the licensee's _ responselto this-i_ncident and corrective actions were' adequate. With'the'
, ' ? i i exception of this isolated incident, healt_h physics technician control and -{ y monitoring of the activities observed were determined to be adequate.
' ' f4. : Maintenance and Surveillance
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& -4~1 Maintenance Observation - The. inspector observed various maintenance and problem investigation activities for compliance with procedures, plant technical specifi- ' cations,'and applicable codes and standards.
The inspector also > verified the appropriate quality services department (QSD) involve- % ment, safety tags, equipment alignment and use of jumpers, radio- ! , ?: .. logical and fire prevention controls, personnel qualifications, + w post-maintenance testing, and reportability.
Portions of seven ' , maintenance activities were reviewed, including: , 'G - ( '. D Js .
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sten generator manway removal, -- , reactor disassembly, --. , service water pump' replacement, -- emergency diesel generator outage maintenance,- -- containment air recirculation fan cooler maintenance, -- I core support barrel removal, and -- fuel inspection and cleaning.
' -- 4.1.1 Reactor Core Support Barrel Removal and Inspection j On September 28, the licensee made several-unsuccessful' attempts ! to remove'the core support barrel (CSB) from the reactor vessel .
for inspection of the modifications made during the 1987 refuel-
ing outage.
During these lift attempts, a protruding dowel pin came in contact with a hot leg nozzle and was bent. All attempts to remove the CSB were halted and an inspection of the i interference initiated.
i During the 1987 refueling outage,,as part of the second ten year l inservice inspection interval, the licensee performed an exami- ! nation of the1CSB.
Following removal of the CSB, several-l defects in the thermal shleid attachments were observed and ! debris.was found in the bottom of the reactor vessel.
CSB l inspection and modifications made during the previous outage are
discussed in NRC Inspection Reports 50-213/87-25, 87-27, 87-31, ! and 88-02.
Repair and modifications were made under plant j design change record (PDCR) 920, Thermal-Shield Support System ! Repair, and included replacement of support block dowel pins and.
j bolts, relocation of reactor vessel irradiation surveillance material specimens, and installation of six limiter keys and i keyways on the upper rim of the thermal shield.
.i i Following the initial CSB removal attempts and with the CSB in j
the reactor vessel, the licensee inspected the interference
! using underwater cameras. A preliminary visual inspection was made of all six support blocks and limiter keys and keyways.
J Three abnormalities were identified, including: , three dowel pins were protruding at the 128 limiter key -- (one of these pins was bent during attempts at CSB removal); one dowel pin was protruding from the 210 support block; -- and, one bolt was missing from the 270 support block.
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L At the end of the inspection period, the licensee was preparing I D to cut the three dowel pins at the-128 limiter key as those pir.s interfere with CSB removal from the reactor vessel.
Following removal of the pins, the CSB_will be removed from the vessel and inspected. At that time the full extent of the damage will be known and repair plans can be made.
The-inspectors monitored portions of the attempted CSB lifts and . inspection of the interference with the reactor vessel, and i attended several associated Plant Operations Review Committee.
meetings. Activities were well coordinated and deliberately executed.
4.1.2 Fuel Inspection and Cleaning During this inspection period, the licensee conducted ultrasonic testing (UT) of all once-and twice-burned fuel assemblies which will be replaced into the reactor.
Preliminary results indi- .cated 213 leaking fuel pins in 67 assemblies.
A total of 109 assemblies were inspected.
' , Visual inspection of the assemblies revealed small fingernail-sized metal chips and shavings accumulated in the region between the lo~wer nozzle and the first spacer grid; an area less than two inches high. All 109 assemblies are being thoroughly inspected and cleaned by the fuel vendor, Babcock & Wilcox.
The - inspection process includes a close visual inspection of all four sides and the bottom of the assembly.
The use of back-lighting permits a thorough inspection between the fuel pins.
The debris is being removed with a' pick and collected at the -! bottom of the inspection and cleaning stand.
The entire clean- - ing and inspection-process is-being videotaped. Dependin'g on the amount of debris present, one to eight assemblies can be completed during one shift.
. During the inspection and cleaning, any fuel pins near debris ' which was difficult to remove are being marked for eddy current inspection during reconstitution.
Following inspection and cleaning, the eddy current testing and reconstitution will begin.
The licensee has elected to replace the once-burned pins - with similar pins from a donor assembly. The twice-turned fuel pins will be replaced with stainless steel dummy pins.
The inspector observed portions of the UT and visual inspections l.
.and the cleaning process. Although this effort is the outage L critical path activity, the process is being performed deli-berately and thoroughly.
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, , .! l i' '.4'.1.3' Reactor Upper Internals Stand Misplacement . 10n September 21, when the. licensee'placed the reactor upper .i internals on its stand to. support, split _ pin modifications, one , 'of the fuel assembly guide. pins was-damaged. The upper inter-nals. remained suspended from tne-polar crane during the investi- ~ gation and inspection which followed.
It was determined that.
". the upper internals stand had been. mispositioned in the refuel- ! ing cavity, o ' . The upper internals package has' two fuel assembly guide pins for ' each fuel assembly, which provide for equivalent spacing between 'the fuel assemblies.
The guide pin atitne A9 position was ' damaged when it came into contact with the upper internals stand. : Visual inspection of the upper internals identified no j additional damage.
- Licensee' review of the circumstances which led to damage of this . ' . - pin -identified that the exact requirements for the upper internals: stand placement were not specified by procedure.
This stand.was used.for the first time during the previous refueling outage and placennt had not been incorporated into the reactor disassembly or split pin modification procedurcs.
-Following tSe visual inspection, the stand was repositioned and
the upper internals placed onto it without interference.
Following the upper internals split pin modification, the - damaged guide pin was removed under plant design change record (PDCR) 981, Reactor Vessel Fuel Assembly Guide Pin. Sectioning.
, The pin removal was required-to prevent the possibility that a fuel assembly could be picked up by this pin during a future reactor disassembly.
The inspectors observed portions of the stand placement and guide pin inspection ard attended Plant Operations Review E Committee meetings concerning the stand mispositioning and corrective actions.
No deficiencies were identified.
-i 4.2 Surveillance Observation .i The inspector witnessed selected surveillance tests to determine ' .. whether properly approved procedures were in use; plant technical l-specification frequency and action statement requirements were f satisfied; necessary equipment tagging was performed; test instru-mentation was in calibration and properly used; testing was performed i.
l by qualified personnel; test results satisfied acceptance criteria; l-and, unacceptable results were properly dispositioned.
Portions of four activities were reviewed; including:
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' I L c L emergency diesel generato= testing, -- , containment penetration local leak rate testing, -- service water pump performance testing, and
-- containment spray header test.
--- 4.2.1 Containmcnt Spray Nozzle Flow Test , On September 14, the licensee performed surveillance procedure , ENG 1.7-82, Containment Spray Nozzle Flow Test, sonduct of the test was stopped by a HP technician when large amounts cf dust ,' were introduced into the containment air creating minor airborne contamination. The test was terminated immediately and all perso; '1:1 were evacuated from containment.
Plant information - , report 89-139 was initiated.
f This test was performed for the first time during the 1987 refueling outage as procedure SUR 5.7-107. The test involves admitting ai,- flow to the containment spray piping to verify i that spray neizles are free flowing and not clogged. Test personnel staticned on the polar crane use infrared thermography techniques to verify nozzle flow. The containment spray system is not required for reduction of post accident containment pressures and is not taken credit for in the accident analyses.
. However, the performance of this test is recommended by the i licensee Probabilistic Safety Study.
Air samples taken as flow initiated from the spray nozzle , identified 2.6E-08 pCi/cc of Cobalt 60.
This is equivalent to less than 2% of the maximum wwiesible concentration of Co-60 specified in 10 CFR 20, Appentiix 0, lable I.
Whole body counts of two test personnel who were positioned on the polar crane identified no internal uptakes. Access to containment was restored, however respiratory protection was required for the next several hours.
Station management reviewed the test conduct and procedural
- equirements.
Procedure ENG 1.7-82 does warn of a possible > virborne contamination problem, however this was not expected as it was not experienced during the previous test.
Reccomenda-tions were made for additional test precautions and prerequi- , si r.e s. At tb close of the inspection period the test had not ytt been reperformed.
The inspectors reviewed the test procedure, associated radiation work permits, personnel whole body count results, and the licensee responte to and evaluation of this incident.
The inspectors were concerned that the procedure did not require ' that one containment hatch door be closed during the test to
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prevent a potential unmonitored ground release. The potential for ground release had been evaluated in association with the reactor disassembly and the licensee determined that the worst e , case release would not exceed the allowable limits.
However, the inspectors were informed that this would be included in f L-future test prerequisites. The inspectors had no further concerns.
4.2.2 containment penetration Leakage Testing During this inspection period, many containment penetration local leak rate tests (LLRTs) were conducted.
On September 30, valve VS-CV-1104 was tested by procedure SUR 5.7-57, Air Moni- , toring Sample to Containment Check Valve LLRT.
The test results exceeded the leakage limits permitted by Technical Specification - (TS) 4.4.11.
The appropriate notifications were made to NRC.
The TS 4.4.11 specifies that the allowable sum of all penetra-tion leakage and isolation valve LLRTs be less than or equal to 0.6 La, which is defined as the maximum allowable containment leak rate and is equal to 0.18 weight percent of the air in + containment in a 24-hour period at 40 psig.
This leakage limit is equivalent to 650 pounds-mass / day (ibm / day).
Valve VS-CV-1104 is the inboard containment isolation check valve for , the air monitoring sample system, penetration P-65.
The system - is normally isolated and used only when sampling the containment atmosphere. The licensee was unable to quantify the leakage because it exceeded the measuring capabilities of the Volume-trics instrumer.tation ud therefore exceeded TS leakage limits.
Two additional containment isolation valves in separate pene-trations have failed the LLRT Dst acceptance criteria but not ' the TS leakage limits. The licensee is investigating those failures.
At the end of this inspection period, valve VS-CV-1104 had not yet been disassembled and inspected to determine the cause of failure, and a Licensee Event Report was being prepared.
About 80% of the LLRTs have been completed.
The containment building as-found integrated leakage, which includes the minimum pathway leakage for all penetrations, sas still acceptable at about 134 lbm/ day.
The inspector reviewed the tests and test results for the three failed isolation valves and associated maintenance and surveil-lance histories for these valves.
The leakage tracking methodo-j
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l H logy and corrective actions were discussed with the responsible engineer. The program was found to be effectively implemented < and well-coordinated.
S.
Security During routine inspection tours, the inspectors observed impleinentatiun of portions of the Security Plan. Areas observed included access point search equipment operation, conditior; of physical barriers, site access control, security force staffing, and response to system alarms and de- , graded conditions. Thesc areas of program implementation were determined to be adequate.
6.
Engineering and Technical Support The inspector reviewed selected design changes and modifications made to the facility which the licensee determined were not unreviewed safety questions and did not require prior NRC approval as described by 10 . CFR 50.59. Particular attention was given to safety evaluations, Plant Operations Review Committee approval, procedural controls, the post- .c.odification testing, procedure changes resulting from the modification, operator training, and UFSAR and drawing revisions. The two design changes and modifications reviewed are described in the following report sections, 6.1 Steam Generator Tube Plug kepair Fixtures Plant design change record (PDCR) 89-976, Steam Generator Tube Plug Repair Fixtures, installed mechanical plug retainers in existing mechanical, ribbed steam generator (SG) plugs.
The mechanical ribbed plugs were installed in the SGs during the 1984, 1986, and 1987 refueling outages. The plugs were identified in NRC Bulletin 89-01 (Potential Failure of Westinghouse SG Tube Mechanical Plugs), as susceptible to stress corrosion cracking.
The population of plugs to be repaired with retainers includes 588 installed in the four SG hot legs.
Four of the 588 plugs are not of the identified susceptible heat lot, however no plug-to-tube identification was previously recorded, and therefore those four plugs will also be repaired.
The plug retainer consists of two components: a cap screw and a locking cup.
The locking cup is threaded into the lower plug end and the cap screw is threaded into the plug expander.
Finally, the , locking cup is crimped onto the cap screw.
The design criteria of > the plug retainer are: to prevent a potential loose part, to limit maximum leakage to 0.01 gallon per minute at primary-to-secondary ' operating differential pressure and to withstand accident loading factors detailed in NRC Regulatory Guide 1.121, Bases for Plugging Degraded Steam Senerator Tubes. The plug retainers are manufactured of material not susceptible to stress corrosion cracking.
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~ 'TheIinspector reviewed the modification design inputsc testing. $ . " ' y l records, Land material composition reports from the. vendor. supplier of n Lplug retainers. The design inputs.were well-documented for the plug; <
retainers, f N ' 0As documented'in-NRC Inspection Report 50-213/89-05 (Detail 9.0), the- ' + ilicenseefprepared a Justification l for Lontinued Operation (JCO)- as it p _ . E, related to Westinghouse SG plug's susceptible to stress corrosion Ll ' ' ' @ cracking.,1The JC01 documented 53 susceptible plugs calculated by a-E.' algorithm to potentially. fail during:the past operating cyclet.The; , W1
- expiration of-the?JCO was September, 1989 'The PDCR 89-976 addresses
' T the installation of plug retainers into the 53 susceptible plugs, as: ' ' 'well-as the-remaining WestinD ouse hot. leg plugs from. heat lot a: h , ,'
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h .The integrated safety evaluation was reviewed.
The evaluation con- -fa ,sidered the SG. tube rupture event in the: Update Safety Analysis W", . Report, licensee identified failure modes, structural integrity' , l ' i margins Lin' Regulatory Guide 1.121, technical specification basis, and -
. the seismic evaluations. The, inspector concurred with the licensee's;
7, evaluations that~an unreviewed safety question.does not exist in thist [p' modificationi , 3 The# inspector conducted a walk-down of the SG mock-up.. facility for + p' plug retainer training, robotic manipulation',' installation, and-'ALARA A-controls.. The retainer installation. phase included: ' plug brushing,.
- retainer installation' cap screw installation, visual / audio torque;
, settings:of the' retainer and. cap screw, and crimping tool operation.- . <Each' installation 4 5 top will be conducted by the vendor's robotic ' machine in accordance with procadure VP-456, Field Procedures for s > - s . ,J Installation of SG Mechanical Ribbed Plug Retainers ~. The inspector , had no questions concerning the plug retainer installation steps.
' The: inspector; reviewed the ALARA controls-for plug retainer instal- . . , e"
- 1ation including
- the licensee's pre-outage ALARA overview document,
' discussions with the inservice inspection (ISI) ALARA engineer, daily LALARA; tracking: report. and mock-up walk-downs.. The ALARA action e LitemsLinclude " timed" training at-the mock-up,, lead shielding (around' - ' " (' the pressurizer ~ surge line), use of timed retainer installation steps-for. training qualifications, vendor previous experience, no SG plat - m , - form erection, and SG " half-jumps" for nozzle dam installation. The initial ALARA precicted exposures were based on 1987 SG manway . surveys coupled with vendor estimated time intervals for key instal-- U 1ations. The exposure. estimate is 156 man-rem total for SG eddy k current testing, SG plug installation, retainer installation, anc p Lvisual inspections.
The licensee's ISI ALARA engineer independent F evaluation concluded 138.2 man-rem.
The inspector noted good h licensee utilization / evaluation of independent radiation exposure p, evaluations.
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>- ! At the conclusion of the inspection period, plug retainer installa- - tion was complete for the Nos. 1, 2, and 4 SGs with 69, 169, and 292 > L retainers installed, respectively.
Retainer installations in the .
No. 3 SG were continuing with 46 of 58 retainers installed. Total personnel exposure was about 146 man-rem.
[ ' , The inspectors observed mock-up training, remote SG tube plug visual inspection, preparation and retainer installation, and health physics coverage of SG activities.
No deficiencies were identified.
6.2 Steam Generator Tube Plugging
The PDCR 89-975 documents the licensee's design change for plugging ' defective SG tubes to comply with Technical Specification 4.10.1, Inservice Inspection of Steam Generator Tubes.
The modification is
tounded by the number of plugged tubes per generator to support the accident analysis initial condition of reactor coolant system flow rate.
. The licensee has selected a Babcock & Wilcox rolled mechanical plug ' fabricated from Inconel 600 material.
On September 8, NRC Informa-tion Notice (IN) 89-65, Potential for Stress Corrosion Cracking in Steam Generator Tube Plugs Supplied by Babcock and Wilcox, was 1esued.
The IN 89-65 concludes, until additional evidence becomes available from corrosion tests and/or experience, all Babcock & . Wilcox Inconel 600 heats used for plugs should be considered poten-tially susceptible to stress corrosion cracking.
In this regard, PDCR 89-975 documents the continuous distribution of carbides along the grain boundary based on heat lot microstructure review. The stress corrosion cracking is a function of intermittent distribution of carbides.
The licensee's mcdification documentation further con-
cluded that B&W modified the SG tube plug heat treatment practice and quality control procedures to verify appropriate heat treatment.
, The inspectors reviewed the design input documents and the integrated , safety analysis for PDCR 89-975, and observed portions of SG tube plug installation activities including the eddy current test data ' _ evaluation.
No inadequacies were net;d.
At the end of this inspection period, tube plugging was completed for the Nos. 2 and 4 SCs with 69 and 73 plugs installed, respectively.
Tube inspection was continuing in the Nos. I and 3 SGs.
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Safety Assessment and Quality Verification 7.1 Plant Operations Review Committee The inspector attended several Plant Operations Review Committee (PORC) meetings. Technical Specification 6.5 requirements for required uember attendance were verified.
The meeting agendas included procedural changes, proposed changes to the technical -.
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i , , specifications, plant design change records, and minutes from pre-vious meetings.
The PORC meetings were characterized by frank i discussions and questioning of the proposed changes. _In particular, > consideration was given to assure clarity and consistency among procedures.
Items for which adequate review time was not available i were postponed to allow committee members time for further review and
comment. Dissenting opinions were encouraged and resolved to the , satisfaction of the committee prior to approval. The inspectors , i = observed that PORC adequately monitors and evaluates plant perfor- , mance and conducts a thorough self-assessment of plant activities and , programs.
, 7.2 Review of Written Reports i Periodic and special reports and licensee event reports (LERs) were ! reviewed for clarity, validity, accuracy of the root cause and safety l significance description, and adequacy of corrective action. The , inspector determined whether further information was required. The inspector also verified that the reporting requirements of 10 CFR L 50.73, station administrative and operating procedures, and Technical Specification 6.9 had been met.
The following reports were reviewed: LER 89-13 Design Deficiency Identified in Charging Pump 011 , Cooler Circuit ' , LER 89-14 A & B Service Water Pump Flow Determined Inadequate During Testir.g LER 89-15 EG-2A Emergency Diesel Generator Room Fire Door Inoperable k Haddam Neck Monthly Operating Raport No. 89-08, covering the period August 1, 1989 to August 31, 1989 + , Haddam Neck P.nthly Operating Report No. 89-09, covering the ' period September 1, 1989 to September 30, 1989 Haddam Neck Plant Radioactive Effluents Noble Gas Beta Dose > Limit Exceeded, dated September 26, 1989 Haddani Neck Plant Bimonthly Progress Report No.18 for New Switchgear Building Construction, dated September 27, 1989 No unacceptable conditions were identified.
8.0 Generic Letter 88-17, Loss of Decay Heat Removal
The objective of this review, conducted per NRC Inspection Manual Temporary Instruction (TI) 2515/101, was to verify licensee actions and preparations for reduced reactor coolant system inventory in accordance
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with NRC Generic Letter-(GL) 88-17 dated October 17, 1988.
Specifically, TI 2515/101 addresses the GL 88-17 short-term program entitled "expedi-tious actions." The inspector reviewed the licensee's response and implementation of the expeditious actions, j 8.5 Training q The licensee is required to discuss with appropriate plant personnel the Diablo Cany p event of April 10, 1987, related events, and lessons learned.
Furthermore, the licensee is required to provide training to personnel prior to entry into reduced inventory condition.
The licensee conducted training on mid-loop operations during the licensed operator requalification program and the non-licensea continued training program. All licensed and non-licensed persorme.1 completed training on August 18, 1989. Since issuance of GL 88-17, the licensee has not entered reduced inventory conditions. The mid-loop training topics consisted of cast industry events, reactor coolant system (RCS) level and temperature indication problems, review of mid-loop operations procedure NOP 2.4-10, Reactor Coolant System Mid-loop Operation, emergency RCS fill line-ups, loss of ' residual heat removal (R4R) with/without the reactor vessel head removed, and n. video tape on vortexing.
The inspector reviewed the licensee's training information and i verified licensed and non-licensed attendance at the training exercises.
This item is satisfied.
8.2 C_o_ntainment Closure The licensee is required to prepare procedures and controls to reasonably assure that containment closure will be achieved prior to the time at which core uncovery could occur as a result of a loss of decay heat removal (DHR).
Licensee evaluation C2-517-922-RE Section 4.2 calculates the time to core uncovery as a result of a loss of DHR. The calculation assumes that all loop stop valves are closed and no alternate injection sources. The worst case may occur one day after reactor shutdown
with RCS level at the centerline of the hot leg.
In this case, the ' calculated time for core uncovery is 1.04 hours.
For mid-loop operations, the licensee developed NOP 2.4-10.
Step 4.2 requires . containment closure prior to reduced inventory operations.
Contain-i- ment closure is defined as equipment hatch closed, one airlock door
closed, and each containment penetration closed by a valve or blind ^ flange.
This procedure also provides a graph of hours to core uncovery versus time since shutdown based on the engineering evalua-tion.
Procedure NOP 2.13-5, Estat11shing Containment Integrity, provides specific steps to establish and maintain integrity.
The
' inspector determined that these actions are acceptable.
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! ! 8.3 Reactor Coolant System Temperature Indication ! l During mid-loop operations with the reactor vessel head in place, two c continuous independent temperature indicators representative of core ' exit conditions are required. This information should be available to control room operators or an individual located outside the ' control room with a means for immediate communication with the control room.
g l + g Procedure NOP 2.4-10, prerequisite step 4.7 requires that the inadequate core cooling (ICC) cabinets are operable to provide two independent core exit thermocouples (CETs) to measure RCS tempera- ! tures. The CETs require a jumper for bypassing the missile shield , terminations for the ICC cabinets in order to provide a plant process ' computer print out and alarm function.
The temporary cables were verified available onsite. Adequate assurance exists for the ' installation and implementation of RCS temperature monitors.
. . 8.4 Reactor Coolant System Lavel Indications ' The licensee is required to provide at least two_ independent, continuous RCS water icvel indications whenever the RCS is in reduced
inventory.
On December 23, 1988 the licensee responded to NRC GL 88-17 and l reported that two drain header pressure transducers would provide RCS level indic0tions. On June 20, 1989 the licensee informed the NRC that this commitment would not be completed as part of the expedi-tious actions, but would be completed on a schedule in conformance with program enhancements. Alternate level indication will be provided oy a remote (control room) digital level indicator with a pressure transducer on the RCS drain header and a temporary tygon tubing arrangement from the drain header to the reactor vessel vent , line.
Procedure NOP 2.4-10 requires installation of the level ' instrumentation, verification of r.onsistency in readings during drain ' down, and periodic monitoring. The inspector noted that RCS water
level indication was deferred pending full licensee implementation of , the proposed water level indication as part of the program enhance- , ments described by GL 88-17.
8.S Reactor Coolant System Perturbations The licensee is required to implement procedures and administrative controls to avoid operations that deliberately or knowingly lead to perturbations to the RCS while it is necessary to maintain the RCS in a stable and controlled condition.
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The licensee has established the-controls to avoid RCS perturbations in procedure NOP 2,4-10.
Prerequisite step 4.12 and precaution steps 5.2, 5.6, and 5.8 provide required mid-loop system boundary, valve
line-ups, and agreements between RCS level indications. As docu-mented in detail 8.1 of this report, training on procedure NOP 2.4-10 i lwas provided during licensed operator requalification and non-licensed continued training.
These actions are satisfactory,
8.6 Reactor Coolant System Inventory i: The licensee is required to implement procedures and administrative , controls to provide at least two available or operable means of
adding inventory to the RCS (in addition to the RHR pumps).
- The licensee has provided four means of inventory injection to the i
RCS in addition to the RHR pumps. The preferried means (in order) are: purification pump, charging pump, static pressure head of the volume control tank, and gravity fill from the rtfeel water storage ' tank.
Engineering esiculation C2-517-922-RE assumes the RCS is fully vented in d:ttermining make-up flow requirements. The charging pump
and purification pumps are cold leg injection point sources.
For the charging ramp, make-up is aligned to an isolated or unisolated loop.
The purification pumps are aligned to a high pressure safety injec-tion isolation valve. The capacity and discharge pressure head of both insection sources are sufficient one day after reactor shutdown, , Discussions with licer3 p personnel indicate that procedure NOP 2-4-10 would not be entered until well after one day following reactor shutdown.
No deficiencies were noted, i 8.7 Hot Leo Flow Paths The licensee is required to implement procedures that reasonably assure that all hot legs are not blocked simultaneously by nozzle
dams unless a vent path is provided tc, prevent pressurization of the upper plenu;n of the re&ctor vessel.
Procedure N0p 2.4-10, prerequisite step 4.4 requires one or more RCS loops to be unisolated to ensure all RCS hot legs are not simultaneously blocked by nozzle dams. This satisfies the require-ment of GL 88-17.
, 8.8 Loop Stop Valves Licensees that utilize loop stop valves are also required to implement procedures and controls that assure all hot legs are not blocked sin'ultaneously by closed stop valves unless a vent patn is large enough to prevent pressurization of the reactor vessel upper plenum.
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, F t-Procedure NDP 2. A-10, prerequisite step 4.4 requires one or.more reactor coolant system loops to be unisolated to ensure all RCS hot legs are not simultaneously blocked. This item is satisfied.
. t-8.9 Conclusion l [ The inspector concluded thtt the licensee has adequately addressed p the required expeditious actions of GL 88-17. The implementation of ' two independent reactor vessel level indicators is deferred pending . full implementation. The inspector found the engineering calcula- ' tions for implementation of the mid-loop procedure thorough and well supported.
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Exit li.cerviev During this inspection, periodic meetings were held with station . management to discuss inspection observations and findings. At the close of the. inspection period, an' exit meeting was held to summarize the . conclusions of the inspection. No written material was given to the licensee and no proprietary information related to this inspect'on was ' identified, i l ! i l l l. }}