IR 05000387/1986018
| ML17146A640 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 10/31/1986 |
| From: | Strosnider J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17146A639 | List: |
| References | |
| 50-387-86-18, 50-388-86-19, NUDOCS 8611110014 | |
| Download: ML17146A640 (25) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION I
Report Nos.
50-387/86-18 50-388/86-19 Docket Nos.
50-387 CAT C 50-388 CAT C
License Nos.
NPF-14 NPF-22
.Licensee:
Penns lvania Power and Li ht Com an 2 North Ninth Street Allentown Penn s 1 vani a 18101 Facility Name:
Sus uehanna Steam Electric Station Inspection At:
Salem Townshi Penns lvania Inspection Conducted:
Se tember
1986 - October
1986 Inspectors:
L.
R. Plisco, Senior Resident Inspector J. Stair, Resident Inspector Approved By:
Strosnider, Chief, Reactor Projects Section 1B, DRP date Ins ection Summar
Areas Ins ected:
Routine resident inspection of plant operations, licensee events, Unit 2 First Refueling Outage activities, allegation followup, open item followup, surveillance, and maintenance.
Results:
Erosion was identified on the Unit 2 RHRSW heat exchanger inlet flanges (Detail 6.2); the material surveillance program neutron dosimeter was not found in the RPV (Detail 6.3);
an emergency Technical Specification change was issued to allow core reloading on Unit 2 (Detail 6. 4);
a procedural defi-ciency was noted in an LLRT procedure (Detail 6.5); metal shavings were found in the RHR and FW lines which were a result of poor work practices (Detail 6.6);
and an allegation concerning work authorizations was found unsubstantiated.
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DETAILS 1.0 Fol 1 owu on Pr evi ous Ins ection Items Closed Construction Deficienc Re ort 388/83-00-18:
Construction Deficiency Report 388/83-00-18 dated November 23, 1983, notified the NRC that certain Pacific Scientific Shock Arresters were subject to capstan spring failures due to improper spring forming.
It was determined that this was not of immediate concern since test-ing showed evidence that spring failure would not occur until after a
significant number of full load cycles.
It was decided that repair or replacement of the affected shock arresters could be delayed until the first refueling outage since the snubbers would not be subject to the fai lure threshold cycles.
This was made a license condition and was identified in NRC Inspection Report 50-388/83-32.
All of the capstan springs or shock arresters identified in NCR 83-1355 were replaced during the Unit 2 first refueling outage.
The inspector verified completion of the licensee's action by review of the NCR package and work authorization documentation.
1.2 U date MSIV Jet Im in ement Anal sis 387/86-09-02:
Section 4.5 of inspection report 50-387/86-09 discussed NCR 86-0019 that identified a deficiency during a review of jet impingement effects on the main steam isolation valves (MSIVs) in the event of a postulated recirculation system pipe break.
Specifically, the NCR indicated that the steam/water jet impingement resulting from a postulated break of the 28" reactor recirculat,ion suction line at the reactor pressure vessel nozzle NIA pipe-to-safe end weld could affect the operability of two inboard MSIV's (B21-1F022A and B21-1F022D).
On may 9, 1986 PORC approved an SER that dispositioned the NCR as a conditional release pending completion of a formal
"leak-before-break" evaluation.
The basis for that evaluation was discussed in Inspection Report 50-387/86-09.
On September 17, 1986, the licensee, upon the inspector's request, transmitted a letter to NRR (H. Keiser, PPAL, to E. Adensam, NRC)
describing results of further analyses they had performed in this area.
The letter stated that a reassessment of postulated breaks and the assumed form of the associated jets (conical verses fan shaped jets) indicated that the postulated breaks presented a threat to the operability of seven inboard containment isolation valves.
NCRs 86-0345, 86-03-0346, 86-0384, 86-0386, and 86-0385 were issued to address these findings.
The postulated breaks involved are at the terminal end welds of one 28 inch reactor recirculation suction line and four 12 inch reactor recirculation jet pump supply lines.
The steam/water jets associated with these postulated breaks would be deflected by sacrificial shield doors and focused on inboard
containment isolation valves thereby potentially affecting their ability to operate.
The licensee's letter stated that this situation constituted an apparent violation of General Design Criteria
(GDC 4)
and FSAR commitments.
The NRC Office of Nuclear Reactor Regulation met with the licensee on October 6, 1986, to discuss this issue.
At the meeting the licensee stated their intention to submit, by October 17, 1986, a
request for exemption from GDC 4 and the existing FSAR commitments based on leak-before-break evaluations of the subject welds.
On October 7, 1986 PORC approved safety evaluation providing a basis for continued operation pending resolution of the NCRs.
This safety evaluation was reviewed by NRC Region I and NRR.
On October 8, 1986, NRR informed the Region that the SER in conjunction with additional information presented to NRR during the October 6, 1986 meeting with the licensee provided adequate justification for continued operation of the Susquehanna Units until'RR had reviewed and made a determina-tion on the licensee's pending exemption request.
Region I concurred with this position.
The bases for allowing continued operation are:
1)
The low probability of a postulated break occurring prior to completion of NRR review of the exemption request and supporting analyses.
This position is supported by a) the quality assurance requirements to which the piping was fabricated and installed; b) pre-service inspections performed on the subject welds; c)
existing leak detection systems and leak rate limits; d) exist-ing water chemistry controls; e) actions such as safe-end replace-ments, internal cladding, and induction heating stress improvement directed at reducing susceptibility of the subject welds to stress corrosion cracking; and f) the short service life of the two units.
2)
The licensee stated at the October 6, 1986'eeting with NRR that completed analyses to be submitted in support of the exemption request demonstrate that leak-before-break would be the expected failure mode for the welds in question.
3)... In the event that a postulated double ended guillotine break were to occur and disable an inboard isolation valve or valves, the outboard isolation valves would still be available to provide containment isolation.
4)
The potentially affected systems are closed outside the primary containment and would serve as an additional containment barrier.
Furthermore, with the exception of the MSIVs, any release would be into the reactor building where it could be processed by the standby gas treatment system.
This item will remain unresolved pending NRR's review and evaluation of the licensee's exemption reques '4 I
2.0 Review of Plant 0 erations 2.1 0 erational Safet Verification The inspector toured the control room daily to verify proper manning, access control, adherence to approved procedures, and compliance with LCOs.
Instrumentation and recorder traces were observed and the status of control room annunciator s was reviewed.
Nuclear Instrument panels and other reactor protection systems were examined.
Effluent monitors were reviewed for indications of releases.
Panel indications for onsite/offsite emergency power sources were examined for automatic operability.
During entry to and egress from the protected area, the inspector observed access control, security boundary integrity, search activities, escorting and badging, and availability of radiation monitoring equipment.
The inspector reviewed shift supervisor, plant control operator and nuclear plant operator logs covering the inspection period.
Sampling reviews were made of tagging requests, night orders, the bypass log, Significant Operating Occurrence Reports (SOORs),
and gA nonconfor-mance reports.
The inspector observed several shift turnovers during the period.
No unacceptable conditions were identified.
2.2 Station Tours The inspector toured accessible areas of the plant including the control room, relay rooms, switchgear rooms, cable spreading rooms, penetration areas, reactor and turbine buildings, diesel generator building, ESSW pumphouse, the security control center, and the plant perimeter.
During these tours, observations were made relative to equipment condition, fire hazards, fire protection, adherence to procedures, radiological controls and conditions, housekeeping, security, tagging of equipment, ongoing maintenance and surveillance and availability of redundant equipment.
No unacceptable conditions were identified.
3.0 Summar of 0 eratin Events 3.1 Unit
On August 16, unidentified RCS drywell leakage started gradually increasing.
Prior to reaching the Technical Specification limit of 5.0 GPM, the unit was shutdown to facilitate a drywell entry to repair a reactor water cleanup (RWCU) 1FOOl valve packing leak at 10:39 p.m.
on September 12.
The unit reached Operational Condition 4 at 12:04 p.m.
on September 13.
After completion of repairs, the unit was restarted on September 22, 1986.
Unit 1 operated at or
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near full power for the remainder of the inspection period.
Scheduled power reductions were conducted throughout the period for control rod pattern adjustments, surveillance testing, and scheduled maintenance.
3.2 Unit 2 3.3 Unit 2 continued with its first refueling outage which commenced on August 9, 1986.
Core reloading commenced on September 14, when Condition 5 was reentered.
Core reloading was completed on September 21.
The reactor vessel head was replaced and tensioned with Condition 4 being reached at 2:55 p.m.
on October 1.
The Operational Hydrostatic Leak Test (1000 psig)
was completed on October 5.
The outage activities are discussed in Detai 1 6.0.
Unit 1 Reactor Shutdown Due to Hi h
RCS Leaka e
On August 16, unidentified RCS leakage started to gradually increase in the Unit 1 drywell.
The leak rate continued to increase through-out the period at a rate of about 0 '
gpm per day.
As the leakage rate approached the Technical Specification limit of 5 gpm, the li-censee commenced activities to identify the source of the leakage.
Testing on September 8 utilizing procedure ON-100-005 localized the leak to the packing on the RMCU F001 valve and an evaluation was per-formed to quantify the leakage in order to reclassify it as identified leakage.
A conservative estimate of the valve leakage was calculated with the valve temporarily backseated, but the leakage rate continued to gradually increase.
On September 3, the 'B'rywell sump pump was not cycling properly and an investigation was conducted.
At one point, the pump ran for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and 24 minutes but the sump only partially drained.
Troubleshooting determined that the pump was not operating properly probably due to malfunctioning discharge check valves.
The other pump had been previously tagged out due to other mechanical probelms.
To correct the pumpdown problem the pump start and stop setpoints were changed, to allow satisfactory pumpdowns.
Based on the increasing leak rate, problems with drywell sump pumps and other needed repairs in the drywell, the licensee elected to shutdown the unit to repai r the leak prior to exceeding the Technical Specification requirement.
The unit was manually scrammed from 24 percent power at 10:39 p.m.
on September 12.
During the outage the valve stem and bonnet to the FOOl valve were replaced.
In addition, a modification to the safety relief valve wiring was performed, repairs were completed on the drywell sumps and pumps, motor leads to 15 valves were spliced with Raychem kits to correct an E(} deficiency concerning terminal blocks, and several valve indication problems were repaired.
The unit was started up on September 22, when criticality was reached at 1:00 p.m.
Following startup, unidentified RCS leakage returned to its normal level, less than 1 gp ~/
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3.4 S i 11 in the Radwaste Bui ldin At 11:30 a.m.
on September
a rupture disc installed on a spent resin transfer line relieved and discharged approximately 1200 gallons of water and spent resin on the floor of the common Radwaste building.
Spent resin was being transferred at the time for processing at the disposal station.
Two rooms, the spent resin tank/pump room and the phase separator room, and a portion of the adjacent hallway were con-taminated.
An area of approximately 900 square feet was contaminated.
No personnel contaminations occurred and there was no airborne con-tamination.
No offsite release occurred and the spill was contained within the Radwaste building.
Dose rates one inch above the spilled resin were approximately 200 mrem/hr.
The leakage was stopped im-mediately by securing the transfer.
The licensee elected to issue a
press release describing the spill and made an ENS notification due to the press release.
In addition, a significant operating occurrence report (SOOR) (1-86-260)
was issued to investigate and resolve the event.
The rupture disc had been recently installed under modification PMR 83-059 in order to correct a piping code requirement deficiency.
This was the first resin transfer to be performed with the new disc installed.
Upon completion of the transfer, the operators shut the discharge valve, and apparently a pressure increase occurred, since the pump immediately tripped on high pressure.
The spent resin flow should have continued uninterrupted following termination of the transfer due to a two-inch recirculation line which returned to the spent resin tank.
Since the rupture disc was installed on the recirculation line which penetrated the lower portion of the tank, the level of spent resin and water above the penetration drained out of the line through the rupture disc, which is at a lower elevation.
A check valve is not installed in the recirculation line.
The cause of the pressure spike has not yet been determined and the licensee placed all resin transfers on hold pending completion of the investigation.
The licensee performed functional testing of the system, using added instrumentation, to help determine the cause, and the data is being evaluated.
As an interim measure, blind flanges were installed in place of the rupture discs, and a flange was installed in place of the recirculation line orifice.
In addition, operating procedures have been revised, supplementary instrumentation has been provided, and a design review of the system has been initiated.
The long term corrective actions will be tracked by the SOOR, and wi 11 be reviewed during routine inspection activitie.0 Licensee Re orts 4. 1 In-Office Review of Licensee Event Re orts The inspector reviewed LERs submitted to the NRC:RI office to verify that details of the event were clearly reported, including the accuracy of description of the cause and adequacy of corrective action.
The inspector determined whether further information was required from the licensee, whether generic implications were involved, and whether the event warranted onsite followup.
The following LERs were reviewed:
Unit
86-029, Tripping of Electrical Protection Assembly Breakers (EPA)
Cause Engineered Safety Feature Actuations
"86-030, Entry Into LCO 3.0.3 to Perform Surveillance Testing 86-031, ESF Actuations When Circuit Breaker Opened for Planned Maintenance Unit 2 86-012, LCO 3.0.3 Entered to Perform Surveillances on Excess Flow Check Valves
- Further discussed in Detail 4.2.
4.2 Onsite Followu of Licensee Event Re orts For those LERs selected for onsite followup (denoted by asterisks in Detail 4. 1), the inspector verified that the reporting requirements of 10 CFR 50.73 had been met, that appropriate corrective action had been taken, that the event was adequately reviewed by the licensee, and that continued operation of the facility was conducted in accordance with Technical Specification limits.
The following findings relate to the LERs reviewed on site:
4.2. 1 LER 86-030 Entr into LCO 3.0.3 to Perform Surveillance
~Test i e On August 25, 1986, the licensee entered LCO 3.0.3 in order to perform survei llances on the Unit
4KV Engineered Safeguard System (ESS)
buses.
To perform the monthly degraded voltage channel functional tests on the ESS buses, all degraded voltage protection on the bus is taken out of service although the bus remains energized.
Technical Specifications require two channels of degraded voltage protection per bus, and both channels must be
The loss of both channels is not addressed by the action statement, therefore entering LCO 3.0.3 is required.
This same event was also reported in LER's86-019, 86-025, and 86-027.
Proposed Amendment No. 86 to License NPF-14 and No.
to License NPF-22 were submitted on September 29, 1986 to NRR to request changes to the 4. 16KV ESS Bus Undervoltage Technical Specification.
The proposed change adds an action statement to address the configuration of two in-operable channels, so that LCO 3.0.3 does not have to be entered during routine surveillance testing.
The change also provides a
2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> time window for surveillance test-ing, where the action statement is not entered.
This change will prevent unneeded entry into LCO 3.0.3 during this routine monthly surveillance test.
4.3 Review of Periodic and S ecial Re orts Upon receipt, periodic and special reports submitted by the licensee were reviewed by the inspector.
The reports were reviewed to deter-mine that they included the required information; that test results and/or supporting information were consistent with design predictions and performance specifications; that planned corrective action was adequate for resolution of identified problems; and whether any in-formation in the report should be. classified as an abnormal occurrence.
The following periodic and special reports were reviewed:
Monthly Operating Report - August 1986, dated September 12, 1986.
Monthly Operating Report - September 1986, dated October 13, 1986.
Special Report
'C'iesel Generator Non-Valid Failure, dated October 8, 1986.
The above reports were found acceptable.
5.0 Monthl Surveillance and Maintenance Observations S. 1 Surveillance Activities The inspector observed the performance of surveillance tests to deter-mine that: the surveillance test procedure conformed to technical specification requirements; administrative approvals and tagouts were obtained before initiating the test; testing was accomplished by qualified personnel in accordance with an approved surveillance pro-cedure; test instrumentation was calibrated; limiting conditions for
operations were met; test data was accurate and complete; removal and restoration of the affected components was properly accomplished; test results met Technical Specification and procedural requirements; deficiencies noted were reviewed and appropriately resolved; and the surveillance was completed at the required frequency.
These observations included:
SE-224-207, Division 2, Diesel Generator Automatic Initiation Upon,Loss of Offsite Power With a LOCA, performed on October 1,
1986.
TP-256-006, HPCI Overspeed Trip Testing Using Auxiliary Steam, performed on October 3 and 10, 1986.
On October 1, the inspector witnessed surveillance test SE-224-207, the 18-Month Division 2 LOOP/LOCA initiation.
During the performance of the test, it was determined that the procedure had been incorrectly written, placing several steps in the incorrect sequence.
With the emergency loads being powered on the 'B'nd 'D'KV buses by their associated diesel generators, Step 6 '
was to be performed to demon-strate that the Non-Emergency mode trips are bypassed in the emergency mode.
This step consisted of depressing the emergency stop pushbutton at the local panel.
Unexpectedly, the 'B'iesel generator tripped.
Investigation by the test director determined that a previous step had reset the LOCA/LOOP signals, thereby removing the emergency mode signal.
The response of the diesel generator was determined to be correct, but the test procedure was inadequate.
The procedure had recently undergone a major revision, and the steps were incorrectly sequenced.
The procedure had been appropriately reviewed and approved by the required individual s and PORC.
Following the trip of the 'B'iesel generator, the test engineer wrote a procedure change to revise the test sequence to ensure the diesel generator remained in the emergency mode.
The remaining portions of the test were completed satisfactorily.
In addition, the test for the other Division was revised prior to its performance.
On October 3, the inspector observed attempts to perform the Unit 2 HPCI overspeed trip test using auxiliary steam.
Problems were en-countered with the turbine governor and control room controller which initially prevented the test from being completed.
A new controller was replaced because the installed controller was blowing fuses.
The turbine governor initially did not respond when the auxiliary steam supply valve was opened, thus preventing steam input to the turbine.
After manual cycling, the governor responded, but was sluggish.
Ad-ditional difficulties were experienced in getting the turbine to trip at the correct speed and in resetting the overspeed trip.
The vendor was called in for resolution of the problems with the governor and overspeed trip device.
It was determined that the sluggish operation
of the governor was caused by increased viscosity of the oil due to lower than normal temperature in the HPCI pump room.
Problems with the overspeed trip device were caused by binding of the tappet as-sembly head in the valve body due to swelling, as a result of extended exposure to lubricating oil.
The temporary corrective action was to replace the failed tappet with one with a smaller diameter collar which allows freedom of movement after swelling.
In addition, periodic testing of the tappet for free movement will be performed.
A Rapid Information Communication Services Information Letter (RICSIL) dated May 23, 1986, was issued to provide guidance on inspecting tappet movement and removal of the tappet if binding occurs to remove any excess material and ensure freedom of movement.
This is temporary corrective action until a permanent resolution is determined.
The licensee was aware of this RICSIL and had performed previous checks on both units in June, 1986.
6.0 Unit 2 Refuelin Outa e Activities 6.1 Refuelin Outa e Summar During this period, Unit 2 continued its first refueling outage which began on August 9, 1986.
Major outage work during this period consisted of RPS modifications, 4KV bus modifications, RHR throttle valve replacements, local leak rate testing, HP turbine overhaul, snubber inspections, and valve maintenance.
Problems were encountered with the RHR throttle valve replacement due to repeated radiograph test failures.
Invessel inspections were completed with no service failures identified.
Core reload commenced at 2: 15 p.m.
on September 14, and Operational Condition 5 was reentered utilizing an emergency Technical Specification change (See Detail 6.4).
Following completion of core reloading, the reactor vessel head was repositioned on the reactor vessel and tensioned, establishing Condition 4 at 2:55 p.m.
on October 1.
However, Condition 5 was reentered for a brief period when one stud was detensioned due to incorrect initial elongation measurements.
Condition 4 was reestabli shed following retensioning of the subject stud.
The drywell head was placed in position on the drywell on October 6.
6.2 RHR Service Water Flan e Erosion On September 3, the licensee reported significant erosion on the inlet pipe flange to the Unit 2 Residual Heat Removal Service Water Heat exchangers.
During tube inspections of the heat exchangers the erosion was visually detected from the inside of the heat exchanger piping.
The erosion damage was on the flange to which the inlet throttle valve (butterfly valve) is bolted.
The damage to the
'B'eat exchanger was the most extensive, with the worst case metal loss determined to be approximately 1/2 inch by ultrasonic testing.
The 'A'eat exchanger metal loss was approximately 3/8 inch.
The
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inlet piping is 20 inch diameter and the flange thickness is ap-proximately 4 inches.
Ultrasonic testing performed on both Unit
heat exchangers on September 4 did not identify any evidence of erosion.
The licensee replaced both of the Unit 2 flanges during the outage and is conducting an evaluation to determine if any long term corrective action is required and to identify the root cause of the erosion.
Review of the licensee's evaluation will be performed in a subsequent inspection.
(388/86-19-01)
6.3 Missin Incore Dosimetr On September 4, the licensee reported that during the Unit 2 Invessel Inspections, it was determined that the material surveillance program RPV neutron dosimeter was not in its holder.
The dosimeter was to be removed after the first cycle of operation to verify the fluence-to-thermal power output assumed in the plant design.
The licensee performed further searches in the reactor vessel with underwater cameras, but could not locate the dosimeter.
A non-conformance report (NCR 86-511)
was written to address the potential problem with a loose part.
The dosimeter is installed in accordance with 10 CFR 50 Appendix H and associated ASTM standards.
The fluence data is used to verify fluence predictions used to generate the pressure-temperature operating curves.
In addition, FSAR Section 5.3. 1.6.4 states that GE provides a separate neutron dosimeter so that fluence measurements may be made at the vessel ID during the first fuel cycle to verify the predicted fluence at an early date in plant operation.
The measurement is made over this short period to avoid saturation of the dosimeters.
The licensee performed an evaluation to determine the safety impact of not having the fluence verification data, and determined that there was not an impact.
The conclusion was based on the fact that the Unit 1 fluence data was available, and that the other three capsule dosimeters installed will not saturate prior to the first withdrawal.
The licensee's review also found that the additional dosimeter was not a regulatory requirement, as long as the other capsules contained dosimetry.
In accordance with ASTM E185-73, the three material surveillance capsules contain dosimeters.
The vendor, GE, provided the licensee with a letter stating that the capsule dosimeters should not saturate before 10 years of operations The first capsule is scheduled to be removed at six effective full power years (EFPY).
The Unit 1 first cycle dosimetry data verified that the actual Unit 1 fluence was less than the predicted value.
GE also provided data from six other BMR's with the same vessel ID and fuel bundles and the measured fluence was equal to or less than measured in all six cases.
Based on the above, the licensee determined that there was no benefit in installing the neutron dosimeter for the second cycl '
In addition, the process of installing the dosimeter was considered a
difficult task with a high risk of dropping the new dosimeter in the vessel during installation.
I The inspector reviewed the licensee's technical evaluation and supporting documentation provided by GE.
The information was also discussed with NRR, and it was determined that the licensee's approach was acceptable.
The licensee agreed to provide NRR with a letter describing the loss of the dosimeter, and a
summary of their corrective action and justification.
In addition, the FSAR is to be changed to correctly reflect the fluence verification method to be utilized.
The licensee submittal and FSAR change will be reviewed in a subsequent inspection.
(388/86-19-02)
Core Reloadin Emer enc Technical S ecification Chan e
On September 11, the licensee discussed with the NRC the interpre-tation of Technical Specification 3.9
~ 11. 1 which requires one shut-down cooling loop of RHR to be operable and in operation in Opera-tional Condition 5.
RHR throttle valve replacements were being performed on both loops and restoration was approximately six days behind schedule.
The licensee was attempting to determine the appli-cability of Technical Specification 3.0.4 when going from an undefined condition, defueled, to Operational Condition 5, refueling.
Technical Specification 3.9. 11. 1 states that the LCO for a shut down cooling loop is applicable in Operational Condition 5, when irradiated fuel is in the reactor vessel.
Review of the Technical Specification requirements by the resident inspector, regional management and NRR determined that commencement of refueling (i.e. placing fuel in the RPV) is a
mode change into Operational Condition 5 and entry into the condition shall be made without reliance on provisions of the action statements, as required by Technical Specification 3.0.4.
On September 12, the licensee requested an emergency Technical Specification change (Proposed Amendment No. 41) for temporary relief from the provisions of Technical Specification 3.0.4 when in LCO 3.9. 11. 1 for the duration of the refueling outage.
The licensee stated that Unit 2 would be ready to enter Operational Condition
on September 13, and it was projected that a loop of RHR shutdown cooling would not be available until approximately 10 days later.
Without the proposed change, startup of Unit 2 would be delayed by 10 days.
The emergency Technical Specification change was approved and issued by NRR on September 13'he formal issuance of Amendment 29 was transmitted on October 6, 1986.
Core reloading was commenced at 2: 15 p.m.
on September 14, using the Technical Specification 3.0.4 exemptio During the refueling operation, the fuel pool cooling system was utilized as the alternate decay heat removal method, since the fuel pool gates were removed.
In addition, one loop of Core Spray was also available'ne shutdown cooling loop was restored to service on September 28, 1986.
6.5 Local Leak Rate Testin 6.5.1 Sco e of the Review 6.5.2 The inspector reviewed the documents listed below to determine compliance with the regulatory requirements of Appendix J to
CFR 50, Technical Specifications and conformance to applicable industry standards and station administrative guidelines.
The inspector held discussions with the licensee regarding test methods, quantification methods, and valve line-ups used.
Documents Reviewed Technical Specifications 3.6. 1.2, 4.6. 1.2, and 6.8.
Final Safety Analysis Report, Section 6.2.6.2.
AD-QA-OOO, Procedure Changes, Revision 2, January 30, 1986.
AD-QA-412, Leakage Rate Tests Program, Revision 5, July 30, 1986.
AD-QA-480, System and Component Pressure Testing, Revision 1, February 27, 1986.
AD-QA-481, System Leakage Quantification Program, Revision 0, July 30, 1986.
PE-000-002, Operation of Leak Rate Monitor Model 14342 and Surge Tank Assembly, Revision 0, February 7,
1985.
SE-259-026, Local Leak Rate Testing of Feedwater Line
'A', Penetration Number X-9A, Revision 4, August 8, 1986.
SE-259-027, Local Leak Rate Testing of Feedwater Line
'B', Penetration Number X-9B, Revision 4, August 8, 1986.
SE-259-031, Local Leak Rate Testing of RHR Shutdown Return Penetration X-13A, Revision 3, January 22, 198 SE-259-032, Local Leak Rate Testing of RHR Shutdown Return Penetration X-13B, Revision 3, January 14, 1986.
SE-259-043, Local Leak Rate Testing of Mini Purge to Recirculation Pumps Penetration Number X-31B, Revision 1, January 14, 1986.
SE-259-066, Local Leak Rate Testing of Chilled Mater to Recirculation Pumps Penetration Number X-86B, Revision 1, January 14, 1986.
SE-259-070, Local Leak Rate Testing of Purge Exhaust Valves Penetration X-202, Revision 1, January 9,
1986.
6.5.3 Selected Piping and Instrumentation Drawings.
Test Witnessin On September 26, 1986, the inspector witnessed portions of a type 'C'LRT of penetration X-9B, feedwater line
'B'enetration.
The test was being conducted in accordance with approved procedure SE-259-037, Local Leak Rate Testing of Feedwater Line 'B'enetration X-9B, Revision 4.
The method used to pressurize the test volume was changed and the required form, Procedure Change Approval Form (PCAF),
was properly filled out and approved.
The method was changed because of the difficulty in seating a
The new method involved permitted reverse flow to shut the valve and maintaining an air pressure ( less than 45.5 psig)
on the valve while the system is drained to assure that the check valve will remain closed.
The inspector ascertained that test prerequisites were met, proper precautions were taken, measuring and test equipment was calibrated, and that the technician involved in the test was knowledgeable of requirements and use of the test instruments.
No unacceptable conditions were identified.
6.5.4 Procedure Review During the review process, the inspector noted a potential problem concerning the licensee's current policy of not performing a pre-LLRT on valves that are considered
"non-problem" valves during non-ILRT outages.
There is the potential for performing work on one isolation valve on a penetration without a pre-LLRT and then having the other isolation valve fail an LLRT. If this occurs it
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would be considered a seriously degraded condition and have to be reported under
CFR 50.72 to the NRC.
This issue is further discussed in Inspection Report 50-388/86-25.
6.6 In reviewing the completed test procedure SE-259-043, Local Leak Rate Testing of Mini Purge to Recirculation Pumps, Penetration X-31B, the inspector noted that the method used to close an excess flow check valve was not a formalized method specified in the procedure.
The inspector requested the licensee to verify the normal method of isolating the valve and to formalize the method in their procedure.
This is an unresolved item.
(388/86-19-03)
Metal Shavin s in the RHR S stem On September 10, 1986, while maintenance technicians were performing repairs on the 'A'HR loop injection check valve HV251FOSOA (WA-V64376), metal shavings were discovered in the bottom of the valve.
The workers attempted to remove the chips with a magnet, but this failed since the shavings were non-magnetic.
Later, the debri s was removed with a vacuum.
The metal shavings were determined to be from the installation of a vent valve between the 1F050A and 1F060A valves under modification PMR-9055.
Although the internal cleanliness of the piping was adequately documented following the modification work (CWO C-66557),
the identification of the debris questioned the adequacy of the internal inspections.
Similar modifications were performed downstream of the 1F050A valve, on the other RHR loop, and on the feedwater system.
Based on the identification of the metal chips, Nonconformance Report 86-0590 was issued to resolve the condition.
The initial disposition of the NCR was to perform a visual inspection of the inside of the lines.
The 'A'oop inspection was performed via the bonnet of the 1F050A valve and the 'B'oop was performed by cutting a vent line and using a fiberoptic scope.
The visual inspections were performed on the 'A'oop on September 10, 1986, and verified that metal chips and particulate debris were visible in the pipe.
The licensee then decided to clean the piping sections between the 50 and 60 valves through the disassembled check valves, which was completed by'ork Authorizations V64376 and V64489.
The cleanliness inspections were documented in gCIR's 86-3783 and 86-4037.
The construction department conducted an investigation to determine the method used to drill through the pipe for the vent and drain valves in PMR's 86-9054 and 86-9055.
During the installation process, magnetic drill bits and vacuums were used to assist in removing the metal chips.
However, due to leakage of the manual isolation valves (251F060A 5 B), and the vacuuming process used,
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some of the chips were apparently displaced.
Therefore, when the internal cleanliness inspection was performed through the 1 1/16 inch diameter hole, no metal chips were visible.
Only visual inspections with flashlights were performed without the assistance of optic equipment.
No flushes were performed.
In order to further evaluate the potential impact, mock-ups were constructed to determine the maximum amount of metal chips which could have been introduced into the system.
Based on the mock-up results and the cleanup performed inside the lines, the maximum amount of metal chips by weight, that could have remained in the system was determined to be approximately 1.26 grams.
NPE was requested to evaluate the effect of the metal chips if they were transported into the reactor vessel.
Their evaluation was performed assuming a quantity, by weight, of 8 ounces.
Although the evaluation stated there could be potential problems with the metal chips, the maximum amount that could have been introduced was less than 1 percent of the amount evaluated by NPE.
The evaluation stated that all the pipes should be cleaned of the debris to the extent possible, which was completed.
Based on this information, the licensee determined that the remaining amount should not have any adverse effect to the operation and safety of the unit.
Similar discrepancies were later identified in the feedwater lines when one feedwater check valve 241F010A was disassembled as a result of excessive leakage during an LLRT.
Metal filings were found in the seat, which were probably from a previous modification activity (PMR 85-3143).
NCR's 86-0655 and 86-0656 were issued to correct the condition in both feedwater lines.
The metal filings were removed and the appropriate inspections were performed.
In order to prevent recurrence, the licensee plans to discontinue the practice of drilling pilot holes, and to ensure all drilling material is removed just prior to break-through in the pipe.
Internal memos were distributed to all Catalytic and IEG personnel, emphasizing the importance of system cleanliness and providing guidance on how to prevent debris from entering the system.
A memo to the IEG Engineers states that Construction Work Order (CWO) work instructions for this type of work should include such options as borescope or fiberoptic inspection, vacuuming, and bagging under the work area.
'The long term corrective actions and a review of the adequacy
.of internal inspections will,be reviewed in a subsequent inspection.
(388/86-19-04)
During the inspection period, an allegation was received by NRC Region I describing the above problems and stating that the inital gC inspections were inadequate.
Based on NRC review of the events, the allegation was substantiated, but the licensee has taken adequate corrective action to address the issue.0 Alle ation Mork Authorization Pro ram An allegation was received by the NRC on August 25 concerning the possible falsification of a work authorization (WA).
The primary concern identified was that a Quality (Q) notification point on the instructions accompanying the Work Authorization (WA) was not present at the time the work was per-formed, but was added subsequent to job completion.
No QC inspectors ap-peared at the job site to perform an inspection.
Additional concerns raised involved unauthorized changes to MAs and Weld Travelers (WTs),
welding being performed by unqualified welders, non-Q welding rods being used, and supervisors not responding to concerns identified by workers during the performance of work.
The inspector reviewed various Work Authorizations (WA), Procedure AD-QA-502 Work Authorization System, and General Melding Requirements, GWR-N, Revision 3.
The inspector also discussed the WA system with several individuals from mechanical maintenance and quality control.
All The review did not identify any cases of welding being performed by unqualified welders.
WAs and WTs reviewed had appropriate approval where changes were made.
The specific Q notification point discussed by the alleger was found not required to be performed since the associated WA steps were not applicable to the actual job performed.
In conclusion, the primary concern with regard to falsification of WA records was unsubstantiated.
Investigation of the remaining concerns determined that either they were not of safety significance or were unsubstantiated.
Improved training for individuals using WAs may be needed to clarify the use of the Action Taken Continuation Sheets due to concern on the part of the individuals as to their purpose.
On October 17, 1986 the inspector discussed the findings of this inspection with station management.
Based on NRC Region I review of this report and discussions held with licensee representat,ives, it was determined that this report does not contain information subject to
CFR 2.790 restrictions.