IR 05000387/1987002
| ML20207S320 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 03/05/1987 |
| From: | Wiggins J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20207S312 | List: |
| References | |
| 50-387-87-02, 50-387-87-2, 50-388-87-02, 50-388-87-2, NUDOCS 8703190270 | |
| Download: ML20207S320 (23) | |
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U.S. NUCLEAR REGULATORY COMMISSION
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REGION I
Report Nos.
50-387/87-02; 50-388/87-02-Docket Nos.
50-387 (CAT C); 50-388 (CAT C)
License Nos.
Pennsylvania Power and Light Company 2 North Ninth Street Allentown, Pennsylvania 18101 Facility Name:
Susquehanna Steam Electric Station Inspection At:
Salem Township, Pennsylvania Inspection Conducted:
January 6, 1987 - February 17, 1987 Inspectors:
L. R. Plisco, Senior Resident Inspector J. R. Stair, Resident Inspector G. Evans, Reagtor Engineer Approved By:
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T.~ Wiggl hief, Reactor Projects dat6 S tion IB, Inspection Summary:
Areas Inspected:
Routine resident inspection of plant operations, licensee event followup, ESF system walkdown, open item followup, surveillance,
. maintenance, followup of industry events, and Fifth Diesel Generator test program.
Results: A Unit 1 HPCI valve was found not locked as required by the system procedure (Detail 2.3); a Unit 1 RWCU isolation valve will be leak rate tested during the next available outage (Detail 3.3); two HPCI isolations occurred due to I&C technician errors (Detail 3.6); the licensee has taken effective action in response to industry pipe thinning concerns (Detail 5.4); and the diesel interdependence testing needs further review (Detail 6.0).
No violations were identified, n703190270 8703 PDR ADOCK 050
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DETAILS
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1.0 Followup on Previous Inspection Items
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1.1 (Closed) Unresolved Item (388/80-12-02): Design Requirements for
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Containment Atmosphere Monitor Sampling Lines
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In July 1980, the inspector determined that the design of the containment atmosphere radiation monitor sampling lines did not incorporate the recommended design requirements of ANSI N13.1
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for obtaining a representative sample.
In December 1983, a similar finding was identified in Inspection
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Report 50-387/83-28 and 50-388/83-30.
Inspector Followup Item 387/83-28-01; 388/83-30-02 was opened to evaluate the ability of the q
monitors to collect representative samples. The licensee's evaluation was performed and reviewed by NRC Region I inspectors in
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Inspection Report 50-387/86-17 and 50-388/86-18 and the item was
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closed.
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Based on the previous review of this identical concern by regional specialists, this item is also closed.
1.2 (Closed) Inspector Followup Item (387/82-09-16): Provide Records j
Storage Facilities Which are in Compliance With Current Requirements t
In March 1982, the inspector determined that the licensee did not have an approved storage facility onsite or at the corporate office in full compliance with ANSI N45.2.9 - 1979, " Requirements for Collection, Storage, and Maintenance of Quality Assurance Records
for Nuclear Power Plants". Without approved storage facilities,
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completed QA records, transmitted to the Document Control Center for r
interior storage prior to microfilming, duplication, and distribution were not provided adequate fire protection. The records storage problem had been previously identified by the
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licensee during QA Audits performed on the Records Management
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System, i
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The following corrective actions were performed in response to the findings:
A two-hour fire resistive fileroom was constructed at the plant
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in conjunction with the expansion of the Service and Administration Building.
A two-hour fire resistive fileroom was constructed in the
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corporate office complex.
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An in-depth evaluation of the Quality Record Storage Facilities
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was conducted by the licensee in May 1986. The report
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described the current facilities and verified compliance to the various storage facility requirements.
Based on the review, several recommendations were made to correct identified deficiencies. The recommendations needed to comply with the requirements were later implemented.
The inspector reviewed the evaluation of the record storage facilities and verified portions of the corrective action, including a walkdown of the on-site storage facility.
The licensee currently has three storage facilities constructed, located, and secured to prevent destruction of the records by fire, flooding, theft, and deterioriation by environmental conditions.
1.3 (Closed) Inspector Followup Item (388/84-33-03): Restart Problems with RPS MG Set Upon Restoration of Power During Unit 2 Startup Test ST-31.1, Loss of Turbine Generator and Offsite Power, performed on August 7, 1984, the 'A' RPS MG set could not be restarted _following power restoration and hence, the scram could not be reset. The MG set was subsequently restarted.
Licensee review determined that the probable cause of the inability to immediately restart the RPS MG set was related to tripping of the motor thermal overloads. With the motor operating at normal load, the overloads were warm prior to the trip, and the large starting current required to start the MG set resulted in a trip of the motor thermal overloads when an immediate restart was attempted.
The motor thermal overloads are designed to reset automatically after a sufficient cooldown period. The licensee revised the RPS Operating Procedures OP-158(258)-001, to alert the operators to the automatic reset of the thermal overloads. The note states that if the motor fails to come up to speed on a restart, to wait for the thermal overloads to reset and then initiate the start sequence again.
The inspector reviewed the revised procedure, and reviewed event history files and verified that the problem has not recurred.
1.4 { Closed) Construction Deficiency Report (388/83-00-16): Insufficient Corrosion Allowance in ESW Piping to RHR Motor Oil Coolers On November 2, 1983, the licensee reported that there was insufficient corrosion allowance for the Emergency Service Water (ESW) piping to and from the Residual Heat Removal (RHR) pump motor oil coolers.
FSAR Section 9.2.5.2 states that ESW piping has 0.25 inches of corrosion allowance.
Licensee design specification M-199
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also requires 0.25 inches corrosion allowance. However, the piping to and from the RHR pump motor oil coolers has a corrosion allowance i
of only 0.080 inches.
This item was included as a license condition in Facility Operating License NPF-22 dated March 23, 1984. The license condition requires the corrective action for the ESW piping be completed by 1988.
This open item is closed and the licensee's corrective actions will be tracked by the license condition.
1.5 (Closed) Weakness (388/83-19-02): Weakness in Unit 2 Configuration Control Due to Undocumented Items (Closed) Weakness (388/83-19-06): Degree of Licensee Staff Involvement in PSI Program In October 1983, a special inspection of completed construction of several Unit 2 safety-related systems was performed. The inspection noted several weaknesses in the licensee's construction programs.
First, the control of the configuration of the plant was found to be less than adequate in that not all maintenance and calibration activities involving equipment removal were well tracked.
Secondly, the licensee's staff involvement in developing and implementing the Preservice Inspection Program was minimal.
TSe licensee submitted a written statement to NRC Region I addressing their actions taken to address these areas.
The above items were addressed by the licensee, and since the completion of the construction phase, they are no longer relevant to plant operations and are considered closed.
1.6 (Closed) Violation (387/84-27-01): Failure to Train All Emergency Response Personnel In August 1984, the inspector determined that two members of the TSC/ EOF on-call list had not completed the annual required training in accordance with station procedures. The cause of the violation was that a notification system did not exist to notify individuals of retraining courses which must be taken prior to specified expiration dates.
The licensee provided a response to the violation on October 12, 1984. Training on the required courses was completed for the two individuals on August 3, 1984.
The training documentation was reviewed by the inspector after completion of the inspection.
To prevent recurrence the licensee implemented a course expiration notification system on January 1, 1985. The computerized system will notify individuals of 90, 60 and 30 days prior to the expiration date of the cours.
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In addition, a review was conducted of Nuclear Department Instruction 6.6.2, Selection, Training and Certification of i
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Emergency Response Personnel, to determine if a procedural change I
was warranted. The procedure was revised on March 11, 1985, expanding the sections on retraining requirements and certification
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requirements.
The inspector reviewed the revised procedure and verified that the
notification system has been implemented.
1.7 (Closed) Unresolved Item (387/82-39-03): Discrepancies on Control Room Drywell Temperature Recorders
In September 1982, the inspector identified that the control room
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operators had difficulty reading the data points on the drywell
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temperature recorders. The difficulties were caused by inadequate labeling, improper chart paper, and an incomplete surveillance
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procedure, i
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i The licensee completed the following corrective actions to resolve this issue:
The four temperature points on each recorder were color coded
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and improved labels were installed which accurately identify the points and recorders.
The chart paper in the recorder has been changed to be
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compatible with the installed scales.
l The surveillance procedures 50-100(200)-007 were revised to
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specifically identify the temperature points on the recorder.
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The inspector observed the new labels and verified that the I
compatible chart paper had been installed. The new procedures were also reviewed, and were verified to be consistent with the recorder nameplates.
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1.8 (Closed) Unresolved Item (387/85-18-03): Surveillance Procedure
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Deficiencies Concerning Average Drywell Temperature i
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In June 1985, the inspector followed up an anonymous allegation
concerning the method used to calculate drywell average air j
temperature.
The review identified several procedural deficiencies j
in the surveillance program.
The licensee's initial corrective actions were previously reviewed in Inspection Report 50-387/86-02; 50-388/86-01, but additional discrepancies remained in surveillance i
procedures 50-100/200-007, and in the governing Technical Specifica-
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tion.
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The licensee submitted Proposed Amendment 85 to License No. NPF-14 and 40 to License No. NPF-22 on August 5, 1986 (PLA-2698). This
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Proposed Amendment will correct the confusing asterisked note in the Technical Specification to provide clearer instructions for performing the surveillance.
The surveillance procedures 50-100/200-007 were also revised to clarify the averaging method and to emphasize that the highest four readings should be used (one per pair), unless both detectors at a particular elevation are inoperable.
The inspector reviewed the revised procedures and the Proposed Technical Specification Amendments.
These changes should clarify the drywell temperature surveillance requirements.
2.0 Review of Plant Operations 2.1 Operational Safety 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 annunciators 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 (500Rs), and QA nonconformance 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, adhcrence to
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procedures, radiological controls and conditions, housekeeping,
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security, tagging of equipment, ongoing maintenance and surveillance and availability of redundant equipment.
No unacceptable conditions were identified.
2.3 Engineered Safety Feature (ESF) System Walkdown On February 5 and 6, the inspector performed an independent verification of the High Pressure Coolant Injection (HPCI) system lineup by performing a complete walkdown of accessible portions of the system. The walkdown included the following:
Confirmation that the licensee's system check-off list matched
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plant drawings and as-built configurations.
Identification of equipment conditions.
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Inspection of breaker interiors.
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Verification of properly valved-in instrumentation.
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Verification of valve position, breaker position, and locking
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mechanisms.
The following discrepancies were noted:
Valve 155017, FPCI Pump Discharge Fill Line PCV Bypass, was
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open, as required, but not restrained with a lock as specified by the Check-Off List (CL-152-0012).
Instrument isolation valve OP1 PT1N019/PI1R004 was open, but
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the required lock wire which had been installed was broken and removed.
Check-Of f List (CL-152-0012) redundantly lists valves OP1
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PTIN019/PIR004 and OP1 PTIN009/PI1R001 on pages 7 and 8.
On page 7 it incorrectly lists them as four separate valves.
Upon notification of these discrepancies by the inspector, the licensee took prompt corrective action to place a lock and chain on the handwheel of valve 155017 and to replace the broken lock wire on valve OP1 PTIN019/PI1R004.
In addition, the licensee stated that they would revise the check-off list procedure to correct the redundancy of the two valves mentioned above.
During the review, the inspector identified that a note had been made on the Master Check-Off List in the control room that a lock was needed on valve 155017.
The note was apparently made at the time the Active Check-Off List was signed and approved (June 10, 1986).
The deficiency should have been noted and action taken
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immediately prior to approval of the check-off list. The inspector discussed his concerns with licensee management and recommended that
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the licensee perform a review of all Master Check-Off Lists to assure no other notes exist which have not been corrected. The licensee will also discuss this subject with the appropriate personnel to assure that deficiencies noted are properly documented and resolved prior to approval of the Check-Off List.
3.0 Summary of Operating Events
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3.1 Unit 1 Unit 1 operated at or near full power for most of the inspection period.
Scheduled power reductions were conducted throughout the period for control rod pattern adjustments, surveillance testing and scheduled maintenance.
On January 9,1987 at 5:03 p.m., several ESF isolations of the RWCU system occurred when restoring the system following completion of scheduled maintenance. The isolations occurred on high system flow.
The system was filled and vented and returned to service.
(See Detail 4.2.1).
On January 27, 1987 at 3:00 a.m., the 'A' Emergency Diesel Generator (EDG) lost all local alarm functions, soon after the
'B'
EDG had been removed from service for scheduled maintenance. With two diesels out of service, both units were placed in a Shutdown LCO.
The 'B' EDG was returned to service at 4:00 p.m. and the 'A'
EDG was repaired and made operable at 7:45 p.m. on January 27.
(See Detail 5.2).
On February 3, 1987 at 7:30 p.m., an inadvertent HPCI isolation occurred due to an I&C technician error during surveillance testing, q
The system was immediately restored.
(See Detail 3.6).
On February 6, 1987 reactor power was decreased to 57 percent to facilitate repairs to the RWCU Suction Outboard Containment Isolation Valve and to perform a rod sequence exchange.
Following completion of repairs, reactor power was returned to 100 percent on February 12.
(See Detail 3.3).
On February 7, 1987 at 9:08 p.m., the 'O' Emergency Diesel Generator automatically started with no initiation signals present.
The diesel was shutdown five minutes later and maintenance investigated the failure.
The automatic start was found to be caused by a defective relay base for a LOCA start relay.
The relay was replaced and the LCO cleared at 12:00 p.m. on February.
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3.2 Unit 2 I
On January 11, 1987 at 1:54 a.m., Unit 2 was manually shutdown, as required by Technical Specifications, due to an inoperable containment isolation valve. The Reactor Building Chilled Water (RBCW) Loop 'B' Return Valve would not stroke closed during a quarterly valve exercising surveillance, and was declared inoperable.
Following repairs to the valve, the unit returned to operation on January 13.
(See Detail 4.2.2).
On February 5,1987, reactor power was reduced to 60 percent due to a bearing failure on the isophase bus duct cooling fan.
Following repairs, power was returned to 100 percent on February 7.
3.3 Reactor Water Cleanup Isolation Valve Leakage (Unit 1)
On January 9, 1987 the licensee identified that the Unit 1 Reactor Water Cleanup (RWCU) Suction Outboard Isolation Valve (HV-1441F004)
was leaking by its seat. During the performance of corrective maintenance on the non-regenerative heat exchanger end bell, operators noted that it took an abnormally long time to depressurize the system when using the 1F004 valve as an isolation boundary. The inboard isolation valve was then closed and the system was depressurized.
Based on the evidence of potential leakage the licensee developed special test procedure, TP-161-016, Pressure Leak Test of HV-1441F004, to leak check the RWCU valve by measuring the pressurization rate of a defined test boundary downstream of the valve with full reactor pressure on the valve. The test procedure was performed on January 30, and the test results were transmitted to Nuclear Plant Engineering for evaluation. The licensee's calculations determined that the valve was leaking approximately 3 GPM at accident pressure (49.5 psig).
The RWCU isolation valves are designed to remain water filled post-LOCA and are leak tested with water in accordance with Technical Specifications. Technical Specification LCO 3.6.1.2 states that the primary containment leakage rates shall be limited to a combined leakage rate of less than or equal to 3.3 GPM for all containment isolation valve in hydrostatically tested lines which penetrate the primary containment, when tested at 1.10 Pa, 49.5 psig.
The total combined leakage of the remaining penetrations in hydrostatically tested lines was 0.28 GPM, which when added to the most conservative calculated RWCU leakage of 3 GPM was less than the Technical Specification limit.
Therefore the licensee determined that the valve remained operable.
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The licensee decided that because of the degraded condition of the valve, and the proximity to the leakage limit, the valve should be
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repaired at the next available opportunity, but if the valve was reworked a unit shutdown would be required to perform post-maintenance Local Leak Rate Test (LLRT) as required by Section XI of the ASME Boiler and Pressure Vessel Code. Article IWV-300, Test Requirements, of Section XI states that when a valve or its control system has been replaced or repaired or has undergone maintenance that could affect its performance, and prior to the time it is returned to service, it shall be tested to demonstrate that the performance parameters which could be affected by the replacement, repair, or maintenance are within acceptable limits.
The licensee's Pump and Valve Inservice Inspection Testing Program, which implements the Section XI requirements, states that valve leakage rate testing and acceptance criteria will be based on 10 CFR 50 Appendix J requirements as discussed in Technical Specification 3.6.1.2.
The licensee ther held discussions with NRR and Region I to determine if relief of the post-maintenance LLRT requirement could be granted until the next available outage to prevent shutting down the unit for this valve repair. The alternative was to not perform maintenance on the valve, keeping the valve operable, although only marginally acceptable.
It was agreed that it would be more prudent to repair the valve, and resolve the adequacy of containment i
isolation function capability by an alternate test method until the commencement of the next available outage when a LLRT would be performed.
On February 4, 1987, the licensee submitted an IST Relief Request (PLA-2797) to request a one time relief from performing a LLRT on the 1F004 valve as required by the Inservice Testing Program. The relief request stated that prior to the valve maintenance, a special test will be performed to evaluate water leakage into a defined test boundary through the 1F004 valve.
Following completion of the maintenance, the same test would be performed to allow a qualitative assessment of the pre-work and post-work leakage from that boundary.
The Type 'C' LLRT would be performed at the first available outage of sufficient duration which necessitated containment entry. A telephone conference was also conducted on February 6 between the licensee, NRR, and the Senior Resident Inspector to further discuss the alternate test method.
The licensee agreed to submit additional information on the test procedure.
The valve repairs were performed on February 7,1987, and the cause of the leakage was determined to be a piece of a nut lodged in the seat of the valve. The nut was removed, and the valve disc was replaced due to some minor flaws noted during disassembly.
The repairs were completed on February 10, and the alternate leak test was performed.
The inspector witnessed the retest of the valve, and no evidence of leakage was noted during the pressurization test.
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The LC0 on the valve was cleared at 2:25 p.m. on February 10, 1987.
The Reactor Water Cleanup system was then restored and returned to i
service.
The results of the LLRT will be reviewed in a subsequent inspection (387/87-02-01).
3.4 Missed Surveillance on "B" TIP Detector (Unit 1)
On January 16 the licensee reported that a surveillance requirement concerning leak tests on fission chambers had been missed.
Technical Specification 4.7.5.2(c) requires fission chambers to be tested for leakage within 31 days prior to being subjected to core flux. During a changeout of the Unit 1 'B' TIP Detector on December 21, 1986, a leakage test of the TIP Fission Chamber was not performed prior to installation. Apparently, the I&C technicians performing the installation did not request HP to perform the leakage test. The requirement was not specified in the I&C procedures.
Licensee review of HP records found that the TIP Detector installed (TJVB-1-105) had been previously leak tested on August 10, 1986 during procedure SH-000-001.
The detector met the acceptance criteria.
In addition, I&C records verified that acceptable pre-use checks during procedures IC-078-001 and IC-078-003 were performed.
Reactor Engineering verified normal calibration checks when operating the replacement TIP on January 5,1987.
Based on the prior leak test and the calibration results, the licensee determined that the integrity of the detector was confirmed, although the required leak check had not been performed. Once irradiated, the TIP detectors cannot be leak tested.
The inspector reviewed the previous leak test data performed on August 10, 1986 and discussed the missed surveillance with the I&C supervisor.
The licensee's corrective action includes revising the I&C procedures to require the leak test by HP prior to installation.
Since this violation was identified by the licensee and meets the criteria of 10 CFR 2 Appendix C, a notice of violation will not be issued.
3.5 Fire Protection System Test During the performance of surveillance test SE-013-003, Eighteen Month Carbon Dioxide Functional Test, on January 29, 1987, a test engineer found it difficult to breathe in the Unit 2 Upper Relay Room while verifying flow from the discharge nozzles. The engineer immediately exited the area, leaving the doors open. The carbon dioxide total flooding system was reset, terminating the release and the fire dampers were reopened restoring ventilation.
Further licensee investigation found the bypass / equalization valve around the carbon dioxide tank manual isolation valve (022404) to be ope *
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The surveillance procedure tests the carbon dioxide fire protection system by manual and simulated initiation.
Service air is substituted for carbon dioxide by using a temporary test manifold connected to the service air system and manually isolating the carbon dioxide tank.
After cross-connecting, the automatic functions of the system are checked for proper operation.
Both the Unit 1 and Unit 2 Lower Relay Rooms were successfully tested on January 28, 1987. On January 29, the test procedure was resumed.
Prior to starting the test, an operator was instructed to close the carbon dioxide tank isolation valve and its bypass valve.
The operator informed the test director that the action was complete.
The Unit 1 Upper Relay Room was first tested satisfactorily without incident.
The Unit 2 Upper Relay Room was then tested.
It appears that the carbon dioxide was first introduced into the carbon dioxide header when the Unit 1 Upper Relay Room was tested. Apparently, the bypass valve around the carbon dioxide tank isolation had not been closed, as reported by the operator.
Because the bypass was still open, carbon dioxide slowly started to pressurize the header during the Unit I room test. Carbon dioxide was not evident during the first test probably because the bypass line is small (1/2 inch) but was introduced into the Unit 2 room during its test.
Following the event, all further testing of the carbon dioxide system was halted pending management review.
The inspector discussed the event with licensee management.
Since the procedure had been designed to perform testing on many areas, the testing took a significant time period (i.e. several days), and it did not adequately verify the carbon dioxide isolation prior to each subtest. The system was periodically restored in between subtests to keep the system operable. The licensee stated that the procedure had been revised to verify that the carbon dioxide isolation valves were closed prior to performing the test in each individual space.
The inspector reviewed the procedure revision and had no further questions.
3.6 Two Inadvertent HPCI Isolations During Surveillance Testing On February 3, 1987 at 7:30 p.m., an inadvertent Unit 1 Division I HPCI isolation occurred during surveillance testing. During the performance of surveillance test SI-152-205, Monthly Channel Functional Test of HPCI Equipment Room Differential Temperature Channels, an I&C Technician bypassed the RWCU Isolation logic instead of the HPCI isolation logic.
The RWCU Isolation bypass keylock switch is located directly under the HPCI Isolate test push-button on a control room backpanel.
The HPCI Isolation bypass switch which should have been manipulated is located to the immediate right of the HPCI Isolate test pushbutton.
The control room operators were
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not able to detect the error because a common alarm is utilized for the HPCI, RHR and RWCU Leak Detection logic.
The isolation resulted
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in closing of the HPCI Inboard steam supply valves. The isolation was immediately recognized by the control room operators and the isolation was cleared. HPCI was immediately restored to operable status.
On February 14, 1987 at 5:30 p.m., an inadvertent Unit 2 Division I HPCI isolation occurred during surveillance testing. During the performance of Surveillance Test SI-283-028, Main Steam Line (MSL)
Tunnel High Temperature Indication, an I&C technician inserted an artificial high temperature signal into the HPCI Emergency Area Cooler High Temperature logic instead of the MSL logic. 'The isolation resulted in closing the HPCI Inboard Steam Supply Valve.-
The isolation was immediately recognized by the operators and the system was restored in several minutes.
The inspector discussed the two events with licensee management to determine what corrective actions were planned. Both events were caused by personnel error, where the surveillance procedures and component labeling were clear. The licensee's corrective actions will be reviewed in connection with the LER's that will be submitted.
4.0 Licensee Reports 4.1 In-Office Review of Licensee Event Reports 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 1 86-041, Entry Into LCO 3.0.3 to Perform Sampling of Suppression Chamber 86-042, Entry Into LCO 3.0.3 to Perform 4KV Bus Surveillances
- 87-001, RWCU System High Flow Isolation Due to Improper Filling / Venting 87-002, Entry Into LC0 3.0.3 to Perform 4KV Bus Surveillances
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Unit 2
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- 87-001, Reactor Shutdown Required by Technical Specifications Due to a Failure of the Reactor Building Chilled Water System Inboard Isolation Valve
- Further discussed in Detail 4.2.
- Previously discussed in Inspection Report 50-387/86-27; 50-388/86-30.
4.2 Onsite Followup of Licensee Event Roports 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 87-001, RWCU System High Flow Isolation Due to Improper Filling / Venting At 4:24 p.m. on January 9, 1987, the Unit 1 Reactor Water Cleanup (RWCU) system was manually isolated and depressurt:ed to allow installation of a shroud around the non regenerative heat exchanger end bell to collect leakage. At 5:03 p.m., during an attempt to restore the system following completion of the maintenance, several automatic ESF isolations occurred due to a system high flow signal.
The licensee determined that the system was not properly filled and vented by operations personnel prior to system restoration, and the high flow isolations were caused by the filling of partially voided piping in the system.
Following the isolations, the licensee filled and vented the system, and returned it to service without further incident.
The licensee verified that the cause of the high flow isolations was not because of system leakage, and determined that no water hammer had occurred.
In order to prevent recurrence, the licensee will review the event as part of operator training with emphasis upon procedure adherence and the importance of verifying a
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system properly filled and vented. System restorations performed subsequent to the event occurred without l
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4.2.2 LER 87-001, Reactor Shutdown Required by Technical Specifications Due to a Failure of the Reactor Building Chilled Water System Inboard Isolation Valve (Unit 2)
At 5:30 p.m. on January 10, 1987, the Unit 2 Reactor Building Chilled Water (RBCW) Loop 'B' Return Inboard Containment Isolation Valve (HV-287-82B1) was determined to be inoperable during surveillance testing.
During the performance of surveillance test 50-234-004, Quarterly Reactor Building Chilled Water Valve Exercising, the RBCW valve would not stroke close from its normally open position. After several attempts, the air operated solenoid valve was declared inoperable and the appropriate Technical Specification action statement was entered. The penetration could not be isolated within four hours per the action statement since drywell temperature could not be maintained on one loop of drywell cooling, and therefore the unit was required to shutdown, power had t
been reduced to 60 percent previous to the event to facilitate condenser tube leak repairs.
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manually scrammed at 1:54 a.m. on January 11 from 19 percent power and Operational Condition 4 was entered at 9:05 a.m. the same day.
Troubleshooting of the valve during the outage could not identify the cause. When operations personnel attempted to restroke the valve following the shutdown, it operated satisfactorily.
However, the solenoid valve on the air operator was replaced.
Repairs were completed on January 12 and the unit returned to operation on January 13, 1987.
The licensee reviewed past valve performance for possible
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trends, but none were found. They determined that the probable cause for the valve failing to stroke was an intermittent failure of the solenoid valve.
The Itcensee plans to perform further tests and inspections on the removed solenoid valve.
4.3 Review of Periodic and_Special Reports Upon receipt, periodic and special reports submitted by the licensee were reviewed by the inspector.
The reports were reviewed to determine that they included the required information; that test results and/or supporting information were consistent with design
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predictions and performance specifications; that planned corrective
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action was adequate for resolution of identified problems; and whether any information in the report should be classified as an abnormal occurrence.
The following periodic and special reports were reviewed:
Monthly Operating Report - December, 1986, dated January 14,
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1987.
Monthly Operating Report - January, 1987, dated February 10,
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1987.
The above reports were found acceptable.
5.0 Monthly Surveillance and Maintenance Observations i
5.1 Surveillance Activities The inspector observed the performance of surveillance tests to determine that: the surveillance test procedure conformed to Technical Specification requirements; administrative approvals and t
tagouts were obtained before initiating the test; testing was accomplished by qualified personnel in accordance with an approved surveillance procedure; 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
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procedural requirements; deficiencies noted were reviewed and appropriately resolved; and the surveillance was completed at the required frequency.
These observations included:
TP-152-018, HPCI Overspeed Trip Test, performed on February 2,
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1987.
50 216-003, RHRSW Pump 28 Monthly Flow Test, performed on
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February 2, 1987.
No unacceptable conditions were identified.
5.2 Maintenance Activities
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The inspector observed portions of selected maintenance activities to determine that the work was conducted in accordance with approved procedures, regulatory guides, Technical Specifications, and i
industry codes or standards.
The following items were considered during this review:
Limiting Conditions for Operation were met while components or systems were removed from service; required administrative approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and QC hold
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points were established where required; functional testing was performed prior to declaring the particular component operable;
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activities were accomplished by qualified personnel; radiological controls were implemented; fire protection controls were implemented; and the equipment was verified to be properly returned to service.
These observations included:
Troubleshooting Activities on the 'A' Diesel Generator
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Annunciator Circuits performed on January 27, 1987.
Troubleshooting Activities on the 'B' Diesel Generator Field
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Flash Circuit performed on January 29, 1987 Post-Maintenance Testing on the Unit 1 RWCU 1F004 Valve
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performed on February 10,1987(TP-161-016).
At 3:00 a.m. on January 27, 1987, the 'B' Emergency Diesel Generator (D/G) was taken out of service for scheduled maintenance and modification.
The remaining three D/G's were satisfactorily tested in accordance with Technical Specification 3.8.1.1 by 4:30 a.m.
At 7:58 a.m. the 'A' D/G tripped alarm was received in the control room although no activities were performed on the 'A' D/G.
The alarm could not be reset at the local panel, and the D/G was declared inoperable.
Since two D/G's were inoperable. Technical Specifications required three 0/G's to be restored to operable status within two hours or both units were to be in Hot Shutdown within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
Troubleshooting was immediately performed on the 'A' D/G and the cause of the alarm was determined to be a fault in the annunciator and non-emergency trip circuits.
The emergency start and load capability remained operable, but the licensee elected to declare the diesel inoperable since the remote and local alarms were not functioning and the local / remote switch was needed to be in local to perform troubleshooting.
The scheduled maintenance work was halted on the 'B' D/G and the diesel was restored.
The 'B' diesel was declared operable at 4:00 p.m. on January 27 af ter successful surveillance testing, and the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> LCO was cleared.
Repairs were later completed on the 'A' D/G and it was restored to service at 7:45 p.m. and the remaining LCO was cleared.
The inspector observed the performance of the troubleshooting activities by the electrical maintenance technicians, and discussed the activity with the responsible engineers who were also involved.
The activity was adequately controlled and the problem was promptly correcte..
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5.3 Secondary System Pipe Wall Thinning
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IE Information Notice No.86-106, Feedwater Line Break, was issued on December 16, 1986 to alert licensees of a potentially generic problem with feedwater pipe thinning.
The licensee was requested to review the information for applicability, and to consider actions, if appropriate, to preclude similar problems.
As a result of continuing NRC concerns related to steam, feed and condensate system piping integrity, a survey was conducted by NRC Region I to determine what actions the licensee may have taken as a result of the IN.
The licensee's program was reviewed to determine if a program had been established to evaluate whether their large diameter steam, feedwater, condensate and connected system piping is subject to thinning of the piping wall.
The inspector discussed the current program with licensee representatives responsible for developing and impler..enting the program. The licensee has established a Piping Erosion / Corrosion.
Examination program to determine whether large diameter piping in the Balance of Plant (80P) is subject to thinning of the piping wall.
The inspections are done in accordance with Tecnni:al Specification M-1414 " Inspection of Non-Q Piping for Moisture Erosion / Corrosion".
The original program, prior to the feedwater pipe rupture event at Surry, included inspections of the following:
Extraction Steam Piping;
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Feedwater Heater Drain Lines;
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Extraction Drain Lines; and,
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Feed Pump Drain Lines.
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These inspections, which include 43 examinatiki' locations in each unit, have been placed in the outage scheduling program.
The Extraction Steam Piping, Feedwater Hester Drein Line, and Extraction Drain Line categories have been perfermed on both units to establish a baseline. A second inspecticn of the Extraction Stu m Piping category was performed on Unit 1 during the second retnciling outage, which was completed in April, 1986.
The Feed Pump Drain Line category was recently added to the program and no inspections have yet been performed on eithee unit. This category, which includes six locations, was added due
- .o reported erosion in a feed pump turbine drain line.
Licensee review of the inspections completed to date has identified six locations which show some signs of erosion.
Four of the locations are on Extraction Steam Lines and show some erosion on both units.
The other two locations are a Unit 1 Feedwater Heater Drain Line, and a Unit 2 Feedwater Long Path Line. All six of these locations are currently scheduled to be reinspected during the naxt refueling outage for each unit in order to confirm the erosion and to calculate the erosion rate. Although evidunce of erosion has
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l been idaniifiede t k piping measured wall thickness is acceptable
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-based on review Dy hPE. Twenty-one of the locations inspected during the two_ Unit 1 cutages and the Unit 2 outage did not detect
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'e any erosion, and these locations have been extended to a three year (
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reinspection interval. The erosion / corrosion inspections are being
' gerformed by ultrasonic testing. The licensee currently utilizes Southwest Research Institute (SWRI) TDAS System to perform the inspections.
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Following an extensive review of'the program since the Surry event, f-22 additional inspection locations have been added to the program.
The new inspecticie locations are in the condensate and feedwater lines with a heavy concentration around the feedpump suction and e
discharge. Twenty locations are in the feedwater system, in piping ranging from 6 to 20 inches in diameter. The two other locations are in che condensate, system in piping of 16 and 48 inch diameter.
Two relevant feedwatpr piping areas were already incorporated in the
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existing inspection"programt
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Five areas of concern regarding pipe wal.1 thinning were addressed
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during the evaluation of the feedwater piping rupture event at Surry:
Pump piping subject to recirculation / cavitation or low
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Flow orifice discharge piping subject to cavitation.
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High points in pipe subject to void formation / collapse.
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Off-normal flow paths.
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Feedwater piping in high personnel traffic areas.
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The 22 additional inspections will first be performed during the Unit I third refueling outage, currently scheduled for September,1987. '
Based on discussions with responsible engineers and a review of the c
inspe; tion program documentation, the inspector determined that the licensee has taken effective action,in response to the pipe thinning coPCerns.
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N 6.0 Modifications to Class 1E Electrical System
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6.1 EDG "E" Test Program Review Scope The inspector reviewed the licensee's administrative procedures to verify that formal administrative measures have been established to control the conduct of the Standby Emergency Diesel Generator (EDG) "E" post-modification test including:
a description of the test program and assignment of
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responsibilities;
a method to control turnover of systems from the constructor to
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the preoperational testing phase and then to the startup testing phase;
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a formal method to control test procedure format, content,
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review and approval, and changes to procedures; a formal method to control interruption of testing and retest
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requirements; and,
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a method to control lifted leads, jumpers, safety tagging, and
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Discussion The EDG "E" project is daemed a major capital modification project sufficient to warrant its own administrative control program.
Licensee procedure AD-TY-465, "EDG Project Startup Program",
establishes the control program.
In addition, AD-TY-465 describes the on-site organization dedicated to the EDG "E" project and invokes the required interim generic administrative procedures to be used during the various system startup phases of the modification.
The phases are construction, turnover, properational testing, system y
transfer and startup testing. AD-TY-465 specifically addresses the major activities performed during each phase including a distinct
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event upon which the phase is terminated.
The termination of a certain phase initiates and/or terminates the applicability of
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certain permanent and/or interim administrative procedures.
Findings Upon review of the permanent and interim administrative procedures, the inspector verified that the attributes identified above were adequately addressed in the procedures.
No deficiencies were identified.
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6.2 Preoperational and Startup Test Procedure Review
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Scope The test procedures listed below were reviewed for technical and administrative adequacy and for verification that testing is planned to adequately satisfy regulatory guidance and licensee commitments.
They were also reviewed to verify proper format, test objectives, prerequisites, initial conditions, test data recording requirements and system return to normal.
TP-024-013, EDG "E" Properational Test, draft dated October 24,
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1986.
TP-024-062, EDG "E" for "A" Startup Test, draft dated December
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27, 1985.
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TP-024-063, EDG "E" for "B" Startup Test, draft dated December 27, 1985.
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TP-024-064, EDG "E" for "C" Startup Test, draft dated December 27, 1985.
TP-024-065, EDG "E" for "D" Startup Test, draft dated December
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27, 1985.
TP-024-071, M-K Factory Test, Part 18, approved October 20,
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1986.
Discussion The inspector reviewed the above procedures and compared the tests'
acceptance criteria with the requirements of Regulatory Guide 1.108,
" Periodic Testing of Diesel Generator Units Used As Onsite Electric Power Systems at Nuclear Power Plants", Revision 1, August 1977.
The inspector verified that all EDG testing addressed in Regulatory Guide 1.108 appeared to be adequately tested in the above procedures with the exception of the testing discussed in Section 2.b of the Regulatory Guide. This section requires in part, that during testing subsequent to any plant modification where EDG unit interdependence may have been affected, a test should be conducted in which redundant units are started simultaneously to help identify certain common failure modes undetected in single EDG unit tests.
This testing requirement is also included in both units' Technical Specifications. The inspector questioned licensee representatives as to how this testing will be conducted.
They stated that preoperational and surveillance test procedures were being written to perform this testing. The planned test method would probably be to manually start all five diesels simultanecusly.
The inspector questioned the need to perform the test four times, substituting EDG
"E" for each of the other EDG's, and also to simultaneously start
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the EDG's with an emergency initiation signal as opposed to a manual start. The licensee representative stated that he would reevaluate
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the testing needed to meet the requirements of Regulatory Guide 1.108, Section 2.b prior to issuance of the properational and surveillance test procedure.
Findings No violations were identified. However, the EDG interdependence testing discussed above is considered unresolved pending licensee reevaluation and further NRC review of the appropriate testing method.
(387/87-02-02)
7.0 Potential Generic Problem With Cooper-Bessemer Diesels On December 23, 1986, a diesel generator failure occurred at Palo Verde NPS due to a manufacturing defect.
The failure occurred on a
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Cooper-Bessemer Model KSV-20-T diesel generator similar to those currently installed at Susquehanna when a connecting rod developed a crack and eventually was thrown out of the diesel through the crankcase covers. The KSV-20 is the same model as the Fifth Diesel generator, which is currently undergoing properational testing. The_ inspector discussed the potential generic problem with the responsible licensee engineers and station management to determine if adequate corrective action had been taken to assure a similar problem was not present at Susquehanna.
The oiesel generator failure at Palo Verde was caused by the use of iron electroplating to correct a defective machining operation. A connecting rod failure origii;ated as a fatigue crack at a junction of the iron electroplating " a a drilled oil hole in one of the main connecting rods where it connects to the main crank shaft. Prior to 1981 the vendor, Cooper-Bessemer, used electroplating with iron as a general practice to correct errors in the machining process.
If the stresses are sufficiently high, cracking could start in that portion of the surface and progress into the base metal.
The licensee carefully reviewed the event and discussed the specific details of the failure with the vendor and responsible engineers at Palo Verde. Since the licensee's diesel generators were manufactured prior to 1981, when the procedure for correcting manufacturing defects was changed, they were concerned that a suspect connecting rod was likely to be installed. After receipt of the initial failure mode information, the licensee contacted the vendor to determine which of the diesel generators may contain potentially defective connecting rods. The vendor stated that Susquehanna did not have any iron plated rods. The vendor also stated that the licensee may have nickel sprayed repair coatings on some rods, which was the new repair process implemented since 1981.
Initial information indicated that the nickel thermal spray is less likely to initiate a fatigue failure. The vendor has stated that this method of repair was adequate for this specific application.
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NRC review of the traceability of the connecting rods determined that traceability records were well maintained and that there was good i
assurance that Susquehantia did not have an iron plated connecting rod installed.
Based on discussions with licensee management and the responsible engineers, the inspector determined that the licensee has taken adequate precautions to ensure a similar defect is not present at Susquehanna, and that they are thoroughly reviewing the information from Palo Verde to determine any other lessons learned to be incorporated into their program.
8.0 Exit Meeting On February 23, 1987 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 representatives, it was determined that this report does not contain information subject to 10 CFR 2.790 restrictions.