IR 05000333/1988017
| ML20206C837 | |
| Person / Time | |
|---|---|
| Site: | FitzPatrick  |
| Issue date: | 11/03/1988 |
| From: | Jerrica Johnson NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20206C827 | List: |
| References | |
| 50-333-88-17, IEB-85-003, IEB-85-3, IEIN-88-003, IEIN-88-3, NUDOCS 8811160432 | |
| Download: ML20206C837 (15) | |
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U.S. NUCLEAR REGULATORY COMMISSION Region I Report No.:
88-17 Docket No.:
50-333 License No.:
DRP-59 Licensee:
New York /ower Authority P.O. Box 41 Lycoming, New York 13093 Facility:
James A. FitzPatrick Nuclear Power Plant location:
Scriba, New York Dates:
Argust 8, 1988 - October 5, 1988 Inspectors:
A. J. Luptak, Senior Resident Inspector R. A. Plasse, Jr., Resident Inspector Approved by: hMS
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N J. R. Johnson, Chief Date Reactor Projects Section No. 2C Division of Reactor Projects Inspection Summary:
. Areas Inspected:
Routine and reactive inspection during day and backshift hours of plant activ-ities, previous inspection findings, Licensee Event Reports review, operational safety verification, surveillance observations, maintenance observations, ef-fects of high lake temperature, a potential part 21 report, cracking of a core spray line, and review of periodic and special reports. This involved a total of 347 inspection hours, which included 31 hours3.587963e-4 days <br />0.00861 hours <br />5.125661e-5 weeks <br />1.17955e-5 months <br /> of backshift/ weekend and holiday l
inspection coverage on August 7, 27 and September 11, 12, 13, 17, 18, 1988.
l Results:
During this period, one violation was identified.
The violation involved several examples of the failure to follow procedures. One example involved the l
use of a drawing to perform electrical checks which was not in the dravving control system (section 6c). Two other examples involved the failure to folicw procedures during refueling which rer,ulted in the inadvertent insertion of an
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unsupported control rod (rection 3d).
In ad('ition, the dropping of a new fuel
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bundle and the licensee's corrective actions are discussed (section 3b).
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discovery of cracking in the core spray piping is also discussed (section 12).
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DETAILS 1.
, Persons Contacted During this inspection period, the inspector interviewed or held discussions with operators, technicians, maintenance, contractor, engineering, admin-i istrative, and supervisory personnel.
2.
Sumary of Plant Activities
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The inspection period began with the plant operating at about 86% power which was limited to maintain main condenser vacuum due to elevated lake inlet temperatures.
Power was varied between 86% and 80% until' August 19, 1988 due to lake temperature. On August 19, power was reduced to 50% due t
to an increase in drywell leakage. On August 20, a' reactor shutdown was
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commenced due to an increase in drywell leakage (still below Technical
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Specifications limit), and the inability to identify the source.
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the shutdown, the source was identified and the drywell leakage was reduced
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by electrically backseating W 1eaking valve. The plant was returned to
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the maximum achievable power. As the lake temperature decreased, the plant operated near 92% power in a coastdown mode during the remainder of the operating cycle, restricted by maximum core flow. A plant shutdown was
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conduc'ced on August 26 to begin a scheduled seven week refueling outage.
During this inspection period, a complete core offload was conducted to
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support maintenance activities.
Major maintenance activities conducted included decontamination of the recirculation system, installation of Anticipated Transient Without Scram (ATWS) modifications, installation of Regulatory Guide 1.97 modifications, replacement of numerous valves for Local Leak Rate Test improvement, replacement of 29 control rod blades, o
and replacement of the 'A' low pressure main turbine rotor.
On October 3,
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the licensee began refueling the core.
3.
Review of Plant Events (93702)
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a.
On August 5, the licenses noted an increase in the drywell floor leak rate from 1.6 gpm to 1.9 gpm. Technical Specification Section 3.6.D limits the leakage to 5 gpm. The le6k rate continued to slowly increase as the licensee attempted to stop the leakage by electri-cally backseating valves located inside the drywell. On August 8, the leak rate stabilized at about 3.1 gpm.
The leak rate began to slowly increase again on August 16. When the leak rate reached 4 gpm on August 19, the licensee reduced power to 50%. On August 20, with the leak rate at 4 gpm and when all attempts to reduce it failed, a plant shutdown was initiated at 8:00 a.m.
During the shutdown at 8:50 a.m., the licensee electrically backseated 29 M0V-102, Reactor Head Vent isolation valve.
Drywell pressure immediately decreased and the floor leak rate dropped to 2 gpm. The shttdown was terminated and the plant was returned to the maximum achievable power of 92%. A packing leak on 29 MOV 102 was identified during the shutdown on August 27 and was subsequently repaired during the outag.
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b.
On August 22, the licensee inadvertently dropped 3 new fuel bundle approximately 2 feet onto the new fuel vault rack.
This occurred while attempting to lift the bundle from the new fuel vault to the fuel preparation machine with the overhead crane.
The cause of the drop was a failure of the swivel stud which connects the general purpose grapple to the cverhead crane hoist cable. A Senior Reactor Operator (SRO) was attempting to place another fuel bundle from the fuel preparation machine into the spent fuel pool with the refueling bridge at the same time. The cable rail for the monorail hoist on the refueling bridge snagged the overhead crane cable as the new fuel bundle was being lifted out of the new fuel vault. When the operator became aware of the snag, he moved the bridge to release the cable.
Shortly after begirning to lift the bundle again, the connector broke.
The licensee replaced the grapple and placed the new fuel bundle back in its original location in the new fuel vault.
The top of the new fuel vault support rack sustained slight damage.
The licensee suspended all fuel mcvements pending completion of corrective actions to prevent recurrence and procure-ment of an additional swivel stud.
The licensee disassembled and shipped the new fuel bundle to the General Electric fuel fabrication plant for a detailed inspection.
The inspection resulted in replacing two fuel rods, upper and lower tie plates, all spacers, expansion springs, finger springs, locking tab, and hex nuts. A new fuel channel has also been procured.
The licensee sent the swivel connector to Battelle Labs for metallur-gical examination to determine the failure mechanism.
The examina-tion indicated that the failure was caused by an overload from a combination of bending and tension stresses and that no evidence of fracture propagation arrests were observed. The battelle report concluded that the material was Inconel x750 which was verified to be the correct material with the manufacturer.
The licensee reviewed the existing procedure for Receiving and Handling of Unirradiated Fuel (RAP-7.1.1) and a revision was imple-mented to provide additional detail in performing the task, provide cautions concerning overhead hoist and bridge interface, and to provide additional rigging inspection including a load test of the swivel connector.
Additional NDE checks, including radiography, were performed on the cable connection for the control rod latch tool, control rod grapple tool, grid guide, jet pump grapple, LPRM instrument tool, all purpose grapple, fuel support piece grapple and channel transfer grapple.
All NDE results were acceptable.
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Two new cable terminals (swivel connectors) have been dye penetrant tested, radiographed and load tested to 1250 lbs..
The cable on the 1000 lb. reactor building crane has been replaced with a new, load tested cable.
RAP-7.1.* was revised to procure and install a currently tested swivel connector on the 1000 lb. hoist prior to transferring new fuel from the new fuel vault to the spent fuel pool.
Crane / hoist training is planned to be included in the operator con-tinuous training program.
Until this training is completed, the maintenance department is designated to operate the overhead 1000 lb.
hoist to transfer new fuel from the New Fuel Vault to the fuel pre-paration machine in the spent fuel pool.
These corrective actions were completed and reviewed by the inspector on September 17.
The licensee commenced new fuel transfers on September 18.
The inspector reviewed the new fuel transfers from the refuel bridge.
The licensed operator operating the refuel bridge had an additional "spotter" on the bridge to assist in monitoring bridge operations in parallel with the overhead crane operations.
This was not a procedure requirement, however, the Operations Superintendent conmitted to continue tc use a spotter and make this a procedural requirement to ensure all parallel fuel movements comply with this commitment to prevent recurrence of this event.
No violations were identified during this review.
c.
On September 14, while performing radiography en the High Pressure Coolant Injection Steam Isolation Valve, 23-MOV-16, the radiography source became detached from its drive cable outside of the shielded container (camera).
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The radiography equipment is licensed to Combustion Engineering (CE)
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who was conducting the radiography.
The 89 Curie, IR 192 source I
became detached wh'le it was being retracted into the camera and l
based on licensee surveys, was located where the guide tube enters l
the camera.
The event was discovered when the individual retracting i
the source heard a snap while the source was being retracted and confirmed through radiation measurements that were taken to verify the source was properly stowed.
l The area where the radiography was taking place was in the drywell j
entrance near the personnel air lock.
This is an enclosed area, therefore, access is easily controlled.
Access to the area following l
the event was stopped and surveys outside the drywell entrance indi-cated normal radiation levels.
Radiation levels inside the drywell
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entrance varied from an on-contact reading where the source was apparently in the guide tube of 360 R/hr and decreased significantly to 300 mR/hr in the general area of the camera.
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A Radiation Safety Officer from CE arrived on-site and following a detailed review by the Plant Operations Review Committee, a course of action was established.
The source was returned to the shielded camera by attaching a plunger to a drive cable and attaching this to the end to the guide tube. With the remote crank of the drive cable, the source was pushed back into the camera and locked in place.
Total exposure for the radiography work and the recovery of the source was approximately 120 mR whole body.
The highest extremity dose was 490 M to one hand of a worter.
The exposures were well within 10 CFR 20 exposure requirements to an individual of 3 Rem /Qtr whole body dose and 18.75 Rem /Qtr dose to extremities (hands),
d.
On October 4, the licensee inadvertently inserted control rod 14-15 during fuel reloadino.
The fuel cells surroundi;g rod 14-15 had not been loaded and a control rod blade guide to previde lateral support for the rod was not installed.
The fuel reload was being performed in accordance with Reactor Analyst Procedure RAP-7.1.24, Spiral Of f-load /Onload Refueling.
At the time of the inadvertent insertion, the Shift Supervisor (SS) had given two licensed operators involved in the evolution permission to restore the hydraulic control unit (HCU)
for cell 14-11. After restoring HCu 14-11, the operators, without SS permission, began to precharge HCU 14-15.
Based on earlier delays with the. evolution, the operators felt that charging the HCU would help speed up the evolution in progress.
RAP 7.1.24, Step 7.7.3 has a caution which states "Do not attempt to precharge the nitrogen side of a discharged accumulator before the scram valves are closed.
Nitrogen precharging may cause inadvertent insertion of the control rod."
The licensed operators did not recall this caution and did not have a copy of the procedure at the HCU.
They did have a copy of the
procedure sign off sheet, but this did not contain the caution state-
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meet.
The procedure specifies steps to be taken to return the accum-ulator to service.
The caution was not heeded.
Procedure steps to verify, with the control room, the HCU to be restored and that the scram valve were shut were not followed. Also, the HCU drain valve HCU-107 is required to be opened, this valve was danger tagged shut for HCU 14-15.
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The inspector asked the licensee how the licensed operators had per-
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formed the charging procedure. He was told that the operators had moved ahead to the precharging procedure in Section G.2 of F-0P-25,
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Control Rod Drive Hydraulic System.
The inspector determined that Procedure F-OP-25 could not have been performed as written.
Step G.2.a requires that the water side of the accumulator be dischargcd.
This could not have been performed with valve HCU-107 danger tagged
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The inspector asked why the operators would 5 ave been using F-0P-25 when it is not specifically invoked by RAP 7.1.24.
The inspector was told that the use of F-0P-25 was implied by Step 7.7.3.14 which verifies that the HCU accumulator low pressure alarm has cleared after the water side of the accumulator has been vented.
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The deficiencies outlined above dealing with failure to follow procedures RAP 7.1.24 and F-0P-25 are two examples of a violation of TS 6.8.(a) which requires procedures be implemented that meet Section 5 of ANSI 18.7 and Appendix A of Regulatory Guide 1.33-1972 (50-333/88-17-01).
Upon receiving indication in the control room that red 14-15 was moving, the operators at the HCUs were contacted.
The operators informed the control room that they were in the process of charging the accumulator for rod 14-15. The Refuel Floor Supervisor verified that rod 14-15 was full in and vertical. A double blade guide was inserted in cell 14-15 to support the control rod. All refueling operations were secured and a critic,ue was held to discuss the event.
The HCUs were not tagged out in such a manner as to prevent the ability to drive in any of the 137 control rods during the offload.
HCV-111 valves were not tagged to prevent charging the accumulators with nitrogen. After this event, special conditian tags were immediately installed on all HCU 111 valves, to instruct individuals to ensure the scram valves are reset and closed prior to recharging the HCU.
The licensee has committed to revise RAP-7.1.24 prior to the next spiral offload.
Control rod 14-15, adjacent fuel bundles, neutron monitoring instrumentation, and fuel support castings were visually inspected for damage prior to the resumption of fuel movement.
This visual inspection was documented by videotape.
The inspector revi2wed the licensee's visual inspection procedure and associated :nspection documentation.
The licensee retrained all operators involved in refueling on RAP-7.1.24 performance and critique lessons learned prior to restarting refueling. No unacceptable conditions were noteu.
4.
Previous Inspection Findings (92701)
i (Closed) INSPECTION FOLLOWVP ITEMS (83-28-03) (84-02-01): Both items d al with administrative errors noted with Technical Specification Table 3.7-1, Process Piping Penetrating Primary Containment.
The inspector verified l
that these errors have been corrected in a proposed Technical Specification Amendment. The licensee has committed to submit this amendment to the NRC by December 1988 (per memc JPN-88-042, dated August 19, 1988). These items are considered closed.
5.
Licensee Event Report (LER) Review (90712)
The inspector reviewed LERs to verify that the details of the events were clearly reported.
The inspector determined that each report was adequate to assess the event, the cause appeared accurate and was supported by
details, corrective actions appeared appropriate to correct the cause, and generic applicability to other plants was not in question.
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During this inspection period, the following LERs were reviewed:
LER 88-07, reported the failure to reinstall pipe supports following maintenance on both low Pressure Coolant Injection pump minimum flow lines.
The details of this event are discussed in Inspection Report No.
50-333/88-15.
LER 88-08, reported excessive leakage of primary containment isolation valves found during local leak rate testing.
The leaking valves were in the High Pressure Coolant Injection turbine exhaust line.
The leakage exceed 3d the allowable limit of.6 La or 3216 standard cubic feet per day (SCFO). As-found leakage for the two valves was 3,736 SCFD (inboard) and 7,014 SCFD (outboard).
Replacement of the valves had already been planned before the outage. A valve of a different design is being installed during the current outage.
No new violations were identified during this review.
6.
Operational Safety Verification (71707)
a.
Control Room Observations Daily the inspector verified selected plant parameters and equipment availability to ensure compliance with Technical Specifications limiting conditions for operation.
Selecteo lit cnnunciators were discussed with control room operators to verify that the reasons for them were understood and corrective action, if required, was being taken. The 1.9spector observed shift turnovers biweekly to ensure proper control room and shift manning.
The inspector directly observed the operations listed below to ensure adherence to approved procedures:
i Routine power operations.
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I The reduction of power for a plant shutdown on August 20, and the
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return to power after the shutdown was terminated.
Plant shutdown on August 26 to begin the r efueling outage.
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Defueling of the reactor.
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l Issuance of Radiation Work Permits and Work
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Request / Event / Deficiency forms.
f Ouring the plant shutdown on August 26 to begin the refueling outage,
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a delay in the shutdown was encountered due to problems with the Rod Sequence Control System (RSCS).
The licensee held power at about 25'.
while attempting to troubleshoot and repair the RSCS.
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Technical Specification 3.7.A.7.a states that the differential pressure between the drywell and suppression chamber shall be maintained greater than 1.7 psid except as noted in 3.7.A.7.a(1).
TS 3.7. A.7.a.(1) states that the differer.tial pressure shall be established within a 24 period subsequent to placing the reactor in the run mode (during startup).
In addition, the differential pressure may be reduced to less than 1.7 psid 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to a scheduled shutdown.
On August 26 at 12:44 p.m., the suppression chamber to drywell differential pressure was reduced to less than 1.7 psid to perform a
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once per cycle required surveillance test, F-ST-39-E, Drywell to Suppression Chamber Vacuum Breaker Leak Test.
The shutdown began at 8:00 p.m. as scheduled.
However, the shutdown was halted at 12:30 a.m. on August 27 due to the RSCS proolems and did not begin again until 11:15 a.m.,
after the cause was determined and repairs were made.
Therefore, the shutdown could not be completed within the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period when differential pressure had been less than 1.7 psid.
The licensee was not clear on the TS requirenent and was considering tripping the reactor to place the plant in a shutdown condition within the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period. After further review by the licensee, it was concluded based on the action statement of T3 3.7.A.7.a (3),
(applicability of which was not clearly esti.blished) and TS 3.0.C (which is the motherhood action statement) chat the plant would be required to be placed in cold shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
The licensee continued the normal shutdown and the plarc was placed in cold shut-down within the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period.
Although the licensee's initial intent was based on a conservative interpretation ot the TS, the TS is ! -,ingly unclear in this regard.
The licensee has committed to r ew and prepare an amendment to the specification.
This will be r viewed in a subsequent report.
No violations were identified.
b.
Shift Logs and Operating Records Selected shift logs and operating records were reviewed to obtain information on plant problems and operations, detect changes and trends in performance, detect possible ennflicts with Technical Specifications or regulatory requirements, determine that records are being maintained and reviewed as required, and assess the effectiveness of the communications provided by the logs.
No violations were identified.
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Plant Tours During the inspection period, the inspector made tours of the control room and accessible plant aieas to monitor station activities and to make an independent assessment of equipment status, radiological conditions, safety and adherence to regulatory requirements.
On September 27, 1988, during a routine plant tour, the inspector noticed a project engineer was performing electrical continuity checks on various circuits associated with the Alternate Rod Insertion System biodification (F1-85-053).
The project engineer was performing the electrical checks by utilizing system drawings as a guide. The drawings were stamped "uncontrolled." After discussion with the engineer, it was determined that the drawings were not made from a controlled print in the plant's drawing control system but were drawings the engineer had received from the Architect Engineer, Gilbert Associates, Inc. (11825-FE-3EAB, Rev. 0A; 11825-FE-3EAA, Rev.
0A; 11825-SE-9ADT, Rev.0A).
l Work Activity Control Procedure, WACP 10.1.9, Control of Plant Orawings, steps 7.3.1 and 7.3.2, give specific instructions on how to procuce an uncontrolled drawing to be used in the field. WACP 10.1.9 requires that drawings fr a the controlled print sticks or aperture cards be used and uncontrolled copies be made from the aperture cards for use in the field.
This was not complied with in that the uncon-trolled drawings were not made from a controlled print in the drawing control system.
This is another example of the violation of TS 6.8(a)
which requires procedures be irrplemented that meet standards of Section 5 of ANSI 18.7 and Appendix A of Regulatory Guide 1.33-1972 (50-333/88-17-01).
Upon discussing these findings with the Quality Assurance supervision, work was stopped and a "itique held to review the circumstances.
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drawings the project engineer was using were from the architectural
engineer ( AE) and were easier to work with than the drawings in the drawing control system.
The reason the project engineer's drawings were easier to work with it
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because they were accurately updated by the AE and had the changes (ECN's) alraady incorporated, while the controlled drawings had the changed sections released to the field via ECN's.
Using the controlled drawings therefere required the use of numerous drawings (controlled and ECNs).
The nroject engineer stated that he attempted to place the drawings he utilized into the Drawing Control System, but the Drawing
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Control Supervisor instructed him that this was not acceptable ano that the changes should be released as ECN's.
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10 The licensee is evaluating the current drawing control system to determine what, if any, changes need to be made to release drawings similar to these to the field for use rather than using ECN's to relay changes.
d.
Tagout Verification The inspector reviewed the following safety-related protective tagout records (PTRs) to verify that breaker:, switches and/or valves were in the required positions.
PTR 881475 'D' Emergency Diesel Generator System.
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PTRs 881458, 881459 'B' Residual Heat Removal System.
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PTR 881657 Neutron Monitoring System.
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PTR 881763 Control Rod Drive Hydraulic System.
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PTR 881780 'B' Emergency Diesel Generator System.
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No violations were identified, e.
Emergency System Operability; ESF System Walkdowns The inspector verified operability of the following systems by ensuring that each accessible valve in the primary flow path was in the correct positica, by confirming that powcr supplies and breakers were properly aligned for components that must activate upon an initiation signal, and by visual inspection of the major components whose failure might prevent fulfillment of the functional requirements:
'A' Standby Gas Treatment System.
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Standby Liquid Control System.
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'A' Core Spray System.
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Emergency Diesel Generator System.
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No violations were identified.
7.
Survc111ajce Observations (61726)
The inspector observed portions of the surveillance procedures listed below tc verify that the test instrumentation was properly calibraced, approved procedures were used, the work was performed by qualified personnel, limiting conditions for operations were met, and the system was correctly restored following the testing.
F-ISP-72, Source Range Monitor Instrument Trip Function Calibration,
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Rev. 11, datud August 24, 1988, performed Augusc 26, 1988.
F-ST-20F, Refuel Interlocks Functional Test / Control Rod Drive
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Maintenance Test, Rev. 12, dated June 24, 1987, performed September 1, 198 _ _ _ _ _ _ _ _ _ _ _ _.
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F-ISP-201A, Reactor Protection System, Primary Containment Isolation
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System Reactor Level Transmitter Calibration and Channel Function Test, Rev. 3, dated September 21, 1988, performed September 26, 1988.
F-IMP 71.18A, Reactor Protection Syscem Type HFA Relay Post Relay Work
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Trip Logic Verification, Rev. 5, dated July 22, 1988, performed September 29, 1988.
The inspector also witnessed all aspects of the following surveillance test
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to verify that the surveillance procedure conformed to specification requirements and had been properly approved, limiting conditions for cperation for removing equipment from service were met, testing was performed by qualified personnel, test results met technical specification requirements, the surveillance tast documentation was reviewed, and equipment was properly restored to service following the test:
F-ST-98, Emergency Diesel Generator Full Load Test and Emergency
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Service Water Pump Operability Test, Rev. 22, dated January 7, 1987, performed August 24, 1988.
No violations were identified.
8.
Maintenance Observations (62703)
a.
The inspector observed portions of vartous safety-related maintenance
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activities to determine that redundant components were operable, that these activities did not violate the limiting conditions for opera-tion, that required administrative approvals and tagouts were
obtained prior to initiating the work, that approved procedures were used or the activity was within the "skills of the trade," that appropriate radiological controls were properly implemented, that ignition / fire prevention controls were properly implemented, and that equipment was properly tested prior to returning it to service, b.
During this inspection period, the following activities were observed:
-- WR 93/60677, Troubleshoot and repair air start motor failure on B Emergency Diesel Generator.
-- PM WR 89/60290, Replace diaphragms on Hydraulic Control Unit scram valves.
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-- WR 02/56956, Reactor vessel disassembly.
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-- WR 00/63454, Fuel sipping.
-- WR 07/64402, Replace Source Range and Intermediate Range Neutron Monitor Ori'a Relays.
-- WR 00/61918, Recovery of radiography source.
-- WR 00/60635, Move fuel from naw fuel vault to spent fuel pool.
No violations were identified.
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9.
Licensee Action on NRC Bulletins and Information Notices (92703)
The inspector reviewed licensee records pertaining to the NRC Bulletins and Notices identified below to verify that: the Bulletins and Notices were received and reviewed for applicability; written responses were provided,
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if required; and the corrective action taken was adequate.
Irformation Notice 88-03: Cracks in shroud support access hole cover welds.
This notice alerted licensee to the potential for cracks in the welds of
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the shroud support access holes within the reactor vessel.
The cracks could result in weld failure with resulting formation of loose parts and i
core by pass flow. An Ultrasonic Testing (UT) examination was recommer.ced by GE because cracks initiated at the root of the weld cannot be detected by visual inspection techniques until a through-wall crack has developed.
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Recent inspections at similar BWRs have detected no cracking other than
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cracks identified at Peach Bottom Unit 3.
According to the licensee, the Peach Bottom cover plates are 5/8" thick and the FitzPatrick cover plates
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are 2-2.5" thick. During the outage the licensee bas performed a visual inspection with acceptable results.
Based on no other BWRs finding a cracking problem; different types of cover plates installed at FitzPatrick, the visual inspection conclusions, and existing workload of planned invessel inspection during the existing refueling outage, the licensee scheduled UT of the access covers during the March 1990 ref :el outage.
i BU-85-03: As requested by action item e. of Bulletin 85-03, "Motor-0perated Valve Common Mode Failures During Plant Transients Due to Improper $ witch Settings," the licensee identified the selected safety-related valves, the valves' maximum differential pressures and a program to assure valve i
operability in their letters dated May 14, September 4, and October 1,1986, and January 15, 1988.
Review of these responses indicated the need for additional information which was contained in the NRC letter dated April 11, 1988.
Review of the licensee's May 12, 1988, re+ponse to this request for
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additional information indicates that the licensee's selection of the
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applicable safety-related valves to be addressed and the valves' maximum differential pressures meets the requirements of the bulletin and that the program to assure valve operability requested by action item e of the l
bulletin is now acceptable.
The results of the inspections to verify proper implementation of this
program and the review of the final response required by action item f. of the bulletin will be addressed in subsequent inspection report.
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10.
Review Effects of High Lake Temperature (71707)
During the summer of 1988, unseasonably warm and dry weather resulted in higher than normal lake inlet temperatures. Due to these elevated temperatures, the plant operated at reduced power. Power was reduced in order to maintain condenser vacuum at the turbine vendor's recommended 26 inches HG. These reductions began to occur on July 11, and continued until August 19, just prior to the plant shutdown for the refueling outage.
Plant power was varied to maintain the required vacuum as lake temperature increased.
Power gradually decreased throughout this period reaching a low
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of about 80% on August 19.
Other than the reduction of power, no additional actual plant problems were experienced.
The inspector questioned the licensee regarding the affects of the higher-than-normal lake temperature.
A maximum temperature of 79.5 degrees F was recorded.
The inspector was informed that since there were no Technical Specifications on lake temperature and since the reactor building closed loop cooling (RBCLC)
system heat exchanger design temperature limit (specified in Final Safety Analysis Report (FSAR) section 9.5) of 95 degrees F was not exceeded, there was not immediate concern.
The inspector was also informed that the licenree was continuing to evaluate the abnormally high lake temperature.
The inspector reviewed the FSAR safety evaluation for emergency core cooling systems (ECCS), section 6.5.1.
In this section the assumptions used as the basis for Design Basis Loss of Coolant (OBA LOCA) accident are discussed.
These assumptions are used to calculate the containment conditions during the DBA LOCA. One of the assumptions is that service water temperature remains below its maximum possible value of 77 degrees F.
During a DBA LOCA the normal non-safety related service water (SW) system would not be providing cooling to safety related components.
In this situation the safety related emergency service water (ESW) would function to remove the heat from safet/ related components.
The core decay heat would be removed from the suppression pool by the residual heat removal (RHR) system using RHR service water (RHRSW) flow to the heat exchangers.
Section 6.5.1 of the FSAR and the other sections dealing with ESW and RHRSW do not specify the maximum allowable temperature for these systems, although the 77 degrees F limit 14 implied in section 6.5.1.
During normal operation, cooling for safety related loads is provided by SW and RBCLC (which is also cooled by SW).
The inspector asked the licensee to provide the design calculation for ESW, RHRSW, SW and RBCLC systems so that the design temperature conditions can be verified.
This item remains unresolved pending the inspector review of the design calculations requested above (50-333/88-17-02).
The licensee has subsequently taken action to determine the effects of raising the service water inlet temperature limit to 82 degrees F.
The licensee has received analyses frcm Steae and Webster considering this effect on cooling systems and has asked GE to provide documentation for the effects on design basis accident analyses.
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11. Potential Part 21 Reports of Missing Valve Actuator Parts (36100)
On September 8, during pre-installation checks of a new valve and SB-00 Limitorque actuator assembly, the licensee noted peculiarities in the baseline signature while performing MOVATS testing.
Cyclic oscillations were noted in the load traces and the measured load was higher than expected.
Although the target thrust could have been achieved without exceeding actuator or motor ratings, the licensee disassembled and inspected the actuator. A thrust bearing was found to be missing between two of the thrust carrying components.
The vendor was not:fied and a service i
representative restored the actuator to an acceptable condition.
Post-work signature testing was completed satisfactorily.
Pre-installation signature analysis is not a normal receipt inspection.
It
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was being performed prior to installation to minimize exposure and provide a baseline for future analysis.
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Reportability of this event under 10 CFR 21 is being reviewed by the vendor and the licensee.
This item is unresolved pending review of the reportability determination (50-333/88-17-03).
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12. Cracking of Core Spray piping (71707)
On September 29, during visual in-vessel inspection of the Core Spray Piping in accordance with IEB-80-13, Cracking of Core Spray Sparg 'rs, an apparent through wall crack was found on a 5 inch B Core Spray line. The crack is located on the lower weld of the upper elbow on the 190 degree
downcomer.
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The circumferential crack is located about 3/16 inch from the weld and measures about 8 inches with a maximum opening of approximately 10 mils.
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Upon review by General Electric, the licensee decided to repair the cracs
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by welding a "clam-shell" over the area of the crack.
This clam-shell is
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essentially 2 halves of a pipe which is welded in place over the cracked
area.
Due to a minimal amount of clearance between the downcomer and the l
vessel wall in this area, it is uncertain when a complete 360 degree weld l
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can be achieved on the clam-shell. GE analysis supports the fact that if
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only a 300 degree weld can be achieved the leakage would be acceptable
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and the B Core Spray system still capable of providing sufficient flow tc l
the core.
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Following the end of this irspection period, but prior to the report i
issuance, the licensee determined that the exact location of the crack as initially thought was in error.
The actual location was on a weld approximately 6 inches below the elbow to pipe weld.
This weld is not
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common on Core Spray downcomers and was completed as a field weld dt.-ing i
construction.
The licensee's actions for repair are essentially the same.
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The acceptance of licensee actions and further review of this occurrence
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is unresolved (50-333/88-17-05).
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13. Assurance of Quality (71707)
This section is included to provide assessment of the licensee's oversight and effectiveness in ensuring activities are conducted in a manner which
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assures quality.
Thezlicenspe's review of the dropped new fuel bundle event, including the engineering review and Quality Assurance root cause analysis were considered to be very detailed.
However, the errors that led to the inadvertent control rod insertion, and the pre-checks and use of uncontrolled drawings during the Alternate Rod Insertion pre-operation test, appear to be examples of the licensee staff initiative to complete work too aggressively without proper care.
Management attention is necessary to assure that work is
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completed safely and correctly while attempting to meet outage schedules.
The licensee management and Plant Operations Review Committee conducted a
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thorough review and well planned approach to retrieving a detached
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radiography source, thereby minimizing exposure to workers.
i An unclear Technical Specification nearly resulted in an unnecessary i
i manual scram of the plant during the process of controlled shutdown.
Continued emphasis should be placed on identifying and correcting unclear i
i Technical Specifications (see Section 6.a).
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14.
Review of Periodic and Special Reports (90713)
Upon receipt, the inspector reviewed periodic and special reports.
The review included the following: inclusion of information required by the NRC; test results and/or supporting information consistent with design l
predictions and performance specifications; planned corrective action for
resolution of problems, and the reportability and validity of reported information.
The following pericdic reports were reviewed:
t July 1988, Operating Status Report, dated August 8,1988.
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August 1988, Operating Status Report, dated September 6, 1988.
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No unacceptable conditions were noted.
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Exit Interview (30703)
At periodic intervals during the course of this intpection, meetings were
held with senior facility management to discuss inspection scope and findings.
In addition, at the end of the period, the inspector met with
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licensee representatives and summarized the scope and findingt of the
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j inspection as they are described in this report.
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Based on the NRC Region I review of this report and discussions held with NYPA representatives during the exit meeting, it was determined that this
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report does not contain information subject to 10 CFR 2.790 restrictions, i
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