IR 05000387/1991002
| ML17157A677 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 04/24/1991 |
| From: | Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17157A676 | List: |
| References | |
| 50-387-91-02, 50-387-91-2, 50-388-91-02, 50-388-91-2, NUDOCS 9105020103 | |
| Download: ML17157A677 (28) | |
Text
UNITED STATES.NUCLEAR REGULATORY COMMISSION Inspection Report Nos.
REGION I
50-387/91-02; 50-388/91-02 License Nos.
Pennsylvania Power and Light Company 2 North Ninth Street Allentown, Pennsylvania 18101 Facility Name:
Inspection At:
Susquehanna Steam Electric Station Salem Township, Pennsylvania Inspection Conducted:
February 12, 1991 - March 25, 1991 Inspectors:
G. S. Barber, Senior Resident Inspector, SSES J. R. Stair, Resi ntInspe r, SSES Approved By:
J.
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hite, Chief eactor Projects Section No. 2A 2 /
Dat Areas Inspected:
Routine inspections were conducted in the following areas:
operations, radiological controls, maintenance/surveillance testing, emergency preparedness, security, engineering/technical support, safety assessment/quality verification, and Licensee Event Reports, Significant Operating Occurrence Reports, and Open Item Followup.
~Result:
During this inspection period, the inspectors found that the iicensee's activities were directed toward nuclear and radiation safety.
No violations or deviations were identified.
An Executive Summary is included and provides an overview of specific'inspection findings.
9105020103 910425 PDR ADOCK 05000387 Q
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SUMMARY Susquehanna Inspection Reports 50-387/91-02; 50-388/91-02 February 12, 1991
- March 25, 1991 Qier;ltion<> (30702, 60710, 71707, 71710)
Operators effectively controlled plant evolutions and identified plant problems.
Increased operator attention was devoted to outage activities.
Operator responses to an unexpected "A" Standby Gas Treatment System initiation and a loss of the "A" Reactor Protection System bus were prompt and effective.
Radiolo ical Control (71707)
Individual workers and Health Physics personnel implemented radiological protection program requirements.
Periodic inspector observation noted no inadequacies in the licensee's implementation of the radiological protection program.
Maintenance/Surveill nce (60710, 61726, 62703)
The licensee exercised good control of maintenance and surveillance activities.
No scrams or ESF actuations were attributable to maintenance or surveillance activities.
A review of maintenance practices related to reactor recirculation pump oil leakage indicated that maintenance activities were thorough and accurate.
The licensee resolved two unusual problems which occurred in Unit 2 during the period, i.e.,
unidentified material found in the reactor vessel, and excessive leakage from control rod drive 38-31 during mechanism changeout.
The licensee handled both problems in a planned, systematic manner consistent with the significance of the problems, Emer enc Pre aredne s (82301)
No emergency preparedness issues emerged during the period.
~ecurii (71707)
Routine observation of protected area access and egress control indicated good control by thelicensee.
111
En ineerin /Technical u
r (71707, 92720, 93702)
Plant technical support staff engineers aggressively responded to a concern regarding the Standby Liquid Control (SLC) System Net Positive Suction Head (NPSH) capability, due to a problem identified at Quad Cities.
Existing test results prove that adequate SLC NPSH will be pr'ovided during accident conditions.
The licensee addressed a safety issue concerning the potential for back-leakage through a previously unidentified release path in the control rod drive hydraulic (CRDH) system.
A seismic island with two series check valves had been previously installed in the CRDH system which would prevent this leakage.
afe As essment/Assurance of ualit (90712, 92700, 92701)
A total of 7 Licensee Event Reports were. reviewed during the period.
The inspector found the reports well written and in compliance with applicable reporting requirements.
A total of 95 Significant Operating Occurrence Reports were reviewed during the period, 3 of which were followed up in this repor DETAKS 1.
SU1VBCARY OF OPERATIONS 1.1 Inspection Activities The purpose of this inspection was to assess licensee activities at Susquehanna Steam Electric Station (SSES) as they related to reactor safety and worker radiation protection.
Within each
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inspection area, the inspectors documented the specific purpose of the area under review, the scope of inspection activities and findings, along with appropriate conclusions.
This assessment is based on actual observation of licensee activities, interviews with licensee personnel, measurement of radiation levels, independent calculation, and selective review of applicable documents.
Abbreviations are used throughout the text.
Attachment 1 provides a listing of these abbreviations.
1.2 Susquehanna Unit 1 Summary Unit 1 operated at or near full power during the inspection period except for March 22 through March 25. At that time power was reduced to 80 percent to perform a modification to the "B" reactor feedwater pump secondary seal chamber to alleviate oil intrusion problems.
Scheduled power reductions were also conducted during the period for control rod pattern adjustments, surveillance testing, and maintenance.
An Engineered Safety Features (ESF)
actuation occurred during the period when the "A" Standby Gas Treatment System unexpectedly started.
See Section 2,2.1 for details of the event.
Another ESF actuation occurred on March 21 when power was lost to the "A" Reactor Protection System bus causing isolations of several plant systems, and automatic starts of the "A" Standby Gas Treatment System and "A" Control Room Emergency Outside Air Supply System..
1.3 Susquehanna Unit 2 Summary Unit 2 entered the inspection period in coastdown at just under 100 percent power.
Prior to reducing power on March 8, power had coasted down to less than 91 percent.
The fourth refueling outage commenced on March 9 when the main generator was taken off-line at 2:31 a.m., and the mode switch was placed in shutdown at 8:23 p.m. following all rod insertion.
No major operational problems were encountered prior to entering the outage.
Shutdown of the unit was uneventful.
Cold Shutdown was reached at 7:00 a.m. on March 10.
The refueling mode was entered at 2:50 p.m. on March 11, when the reactor vessel head was detensioned.
While in Condition 5 (Refueling), unidentified foreign material was discovered in the reactor vessel during disassembly.
See Section 4.6 for details.
Also, a spill occurred in the Unit 2 drywell due to the inability to properly seat Control Rod Drive Mechanism 38-31 during control rod drive changeouts.
See Section 4.7 for detail Major work accomplished during the inspection period included Main Steam Isolation Valve Local Leak Rate Tests, Residual Heat Removal and Core Spray Division 1 valve work and room cooler changeouts, Control Rod Drive Mechanism exchange, Division 1 4KV Bus outages,- Standby Liquid Contr'ol System testing, main generator rotor disassembly and rewinding, 24V, 125V and 250V DC battery testing, Main Steam Relief Valve removal and shipment, Recirculation System work, High Pressure Coolant Injection and Reactor Core Isolation Cooling valve work and testing, and Engineering Service Water and Residual Heat Removal S'ervice Water system valve work.
Other major activities completed by the end of the inspection period were vessel disassembly and complete core offload.
2.
OPERATIONS 2.1 Inspection Activities The inspectors verified that the facility was operated safely and in conformance with regulatory requirements.
Pennsylvania Power and Light (PPkL) Company management control was evaluated by direct observation of activities, tours of the facility, interviews and discussions with personnel, independent verification of safety system status and Limiting Conditions for Operation, and review of facility records.
These inspection activities were conducted in accordance with NRC inspection procedure 71707.
II The inspectors performed 26.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> of deep backshift inspections on February 18 from 7:00 a.m. to 4:00 p.m.; February 20 from 2:00 a.m. to 6:00 a.m.; March 3 from 8:00 a.m. to 3;30 p.m.; March 8 from 2:00 a.m. to 6:00 a.rn.; and, March 15 from 2:00 a.m. to 6:00 a.m.
2.2 Inspection Findings and Review of Events 2.2.1 SGTS Unanticipated Automatic Initiation - Unit I On March 9, 1991, while returning the "A" SGTS to standby, the "A" fan auto-started due to an indicated charcoal high temperature condition.
The "A" SGTS fan had been previously shut down after completing a purge of the Unit 2 Drywell. When the hand switch for the fan was placed in standby, the fan immediately started.
No alarms or other indications of charcoal high temperature were received in the control room.
Personnel were dispatched to the local panel and noted that the "Outlet Sensor Detection Prealarm" light was lit. However, a visual inspection of the area and equipment showed no actual high temperature.
During investigation by Instrumentation and Control personnel, the local alarm was cleared and the system was successfully returned to its normal standby condition.
The required 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Emergency Notification System call per 10 CFR 50.72 was made within 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> following the even The root cause of this event was related to weaknesses in the modification process that established the two distinct setpoints for the two different automatically initiated SGTS cooling modes.
These cooling modes were believed to be necessary to cool the SGTS charcoal that would be fully loaded with fission products post-LOCA.
The first.cooling mode was designed to open the SGTS fan common suction damper to allow the opposite running SGTS fan to cool down the loaded charcoal.
This action would provide cooling air flow across the charcoal since the opposite fan was presumed to be running to maintain secondary containment at a slightly negative pressure.
The second cooling method would be implemented iftemperature continued to increase with the first method operating.
It required securing the original lineup, opening a larger suction damper and then starting the in-line SGTS fan.
The original design did not provide the required logic to initiate the two different cooling modes at two distinct setpoints.
Thus, the licensee had to install a modification to accomplished this.
The modification was installed in 1983 and it separated the functions of the Allison temperature unit to allow it to activate the desired cooling modes.
For this modification, the designer assumed that the inlet sensor would be the first to see the high temperature when, in fact, the inlet temperature detector was set higher than the outlet.
This led to a reversal of the desired cooling mode functions with respect to their setpoints.
This deficiency was not'detected during post-modification testing.
The post-modific'ation testing program verified the two different cooling modes based on the detectors physical location and identification and did not include setpoint verification.
When I&Cverified the setpoints they were found to be within specification, but the design did not match the proper setpoint with its respective cooling mode.
The lower setpoint (224') was supposed to be designed to open the outside air cooling damper and a SGTS fan common suction damper to allow the opposite train's fan to cool the charcoal. Ifthis was unsuccessful, the lineup was to be secured, and the in-line SGTS fan started, after the normal outside air supply damper opened.
This feature was to actuate when the higher setpoint (230 F) was reached, to provide a higher cooling flow rate.
While having a low safety significance in this case, the failure to detect this transposition error indicates weaknesses in the licensee's design review process.
In addition, the licensee's testing program did not detect this transposition error, since the test did not verify design function as related to the corresponding'temperature setpoint.
This design error remained undetected until the spurious start caused the licensee to do further investigation.
This is the second occasion that this type of error has been identified.
Previously, the MSIV differential temperature detectors were found to be miswired as a result of a similar flaw in the design review process.
See Inspection Report 50-387/88-15 for details.
The detection, correction, and prevention of these types of errors, relative to the design review and post modification testing process is unresolved pending further action by the licensee and review by the NRC.
(UNR 50-387/91-02-01(Common))
2.2.2 Licensed Operator Medical Exams NRC Information Notice (IN) 91-08 documented certain deficiencies'ith the conduct and documentation of Licensed Operator (LO) Medical Exams.
Two licensees had not provided sufficient management guidance or oversight to examining physicians to ensure complete, accurate, and timely medical examinations for licensed operators.
Both of these licensees had attested on the Certificates of Medical Examination (Form NRC-396) submitted with their applications for operator licenses that the guidance contained in ANSI/ANS 3.4-1983 was followed, when in fact it was not.
The inspector questioned the licensee on the completeness of their medical exam relative to the information provided in NRC Information Notice 91-08.
Previously, the licensee reviewed IN 91-08 to determine ifany of the identified concerns applied to their program.
The medical exams for all licensed operators were evaluated.
The licensee determined that all of the medical exams were current, and that no Licensed Operator (LO) had any debilitating medical condition that would have prevented satisfactory completion of licensed duties.
In the course of the review, the licensee noted that the physicals were not complete in all material respects.
Certain tests, previously considered by the licensee to be of low consequence because of their subjective'nature, were not performed (such as odor detection and running in place).
Consequently, the tests were added to the physical requirements; and all 70 licensed operators were reexamined to ensure that they met all the requirements.
In addition, an Nuclear Quality Assurance (NQA) audit was performed to ensure that all of the new tests were comprehensive and met all established requirements.
The licensee's review of the new physicals identified no unacceptable medical conditions.
The licensee is continuing to review the LO physicals to ensure that no other problems exist.
The inspector determined that the licensee took prompt action to address the concerns mentioned in IN-91-08.
The inspector also verified that there were no LOs with medical conditions that would have impaired their ability to operate, based on the licensee's medical examinations.
No unacceptable conditions were identified.
3.
RADIOLOGICALCONTROLS 3.1 Inspection Activities PPE.L's compliance with the radiological protection program was verified on a periodic basis.
These inspection activities were conducted in accordance with NRC inspection procedure 71707.,
3.2 Inspection Findings Observations of radiological controls during maintenance activities and plant tours indicated that workers generally obeyed postings and Radiation Work Permit requirements.
No significant inadequacies were noted.
4.
MAINTENANCE/SURVEILLANCE 4.1 Maintenance and Surveillance Inspection Activity On a sampling basis, the inspector observed and/or reviewed selected surveillance and maintenance activities to ensure that specific programmatic elements described below were being met.
Details of this review are documented in the following sections.
4.2 Maintenance Observations The inspector observed and/or reviewed selected maintenance activities to determine that the work was conducted in accordance with approved procedures, regulatory guides, Technical Specifications, and industry codes or standards.
The following items were considered, as applicable, 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; quality control hold points were established where required; functional testing was performed prior to declaring the involved component(s)
operable; activities were accomplished by qualified personnel; radiological and fire protection controls were implemented as necessary; and the equipment was verified to be properly returned to service.
These observations and/or reviews included:
Instrument Air Compressor ZK107A Nine Month Preventive Maintenance and Inspection per WA P04850 on February 27.
Installation of Heat Tracing Conduit and Supports for the Unit 2 Containment Atmosphere Control System per WA C10073 on February 27.
Snubber Functional Testing per WA Y00444 on March 11.
"C" Core Spray Room Cooler Replacement 2V-211C per WA C04353 on March 11.
4.3 Surveillance Observations The inspector observed and/or reviewed the following surveillance tests to determine that the following criteria, ifapplicable to the specific test, were met:
the test conformed to Technical Specification requirements; administrative approvals and tagouts were obtained
before initiating the surveillance; testing was accomplished by qualified personnel in accordance with an approved 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 procedural requirements; deficiencies noted were reviewed and appropriately resolved; and the surveillance was completed at the required frequency.
These observations and/or reviews included:
SE-24-001A, Monthly Diesel Generator "A" Operability Test, performed on February 12.
SE-270-011; Eighteen Month Secondary Containment Drawdown and Inleakage Surveillance Test of Zones II and III, performed on March 8.
TP-259-008, Local Leak Rate Testing of MSIV penetrations X-7A, X-7B, X-7C, and X-7D, performed on March 15.
4.4 Inspection Findings The inspector reviewed the listed maintenance and surveillance activities.
The review noted that work was properly released before its commencement; that systems and components were properly tested before being returned to service and that surveillance and maintenance activities were conducted properly by qualified personnel.
%here questionable issues arose, the inspector verified that the licensee took the appropriate action before system/component operability was declared.
No unacceptable conditions were identified, 4.5 Reactor Recirculation Pump Oil Leaks - Review of Maintenance Practices The inspector reviewed maintenance involvement in correcting oil leakage from the Unit 2
"B" reactor recirculation pump due to concerns of potential weaknesses in maintenance practices which resulted in recurrent shutdowns from the same problem.
Forced shutdowns of Unit 2 were required in December 15, 1990 and January 5, 1991, due to "B" reactor recirculation pump oil leakage from the lower motor bearing oil reservoir.
Previously, the licensee experienced a Hi/Lo Oil Level Alarm for the "B" reactor recirculation pump on September 7, 1990.
Subsequently, oil was added to the reservoir, and the leak rate was evaluated.
The licensee determined that the leak rate was such to allow continued operation until the next planned refueling outage (March 9, 1991); and intended to periodically evaluate the leak rate in the interim.
On December 15, 1990, the licensee experienced another Hi/Lo Oil Level Alarm, indicating that the leak rate might have unexpectedly changed.
Accordingly, the unit was shutdown to
evaluate the "B" recirculation pump.
The licensee found that the total leakage from the lower reservoir was within the expected range and that the leak rate had not increased appreciably.
After inspecting the pump and adding oil (6 3/4 quarts) to the lower reservoir, the unit was returned to service.
The licensee elected to wait until the Unit 2 refueling outage to replace the 0-ring from which the leak was occurring.
The unit was again forced to shutdown on January 5, 1991, due to another Hi/Lo Oil Level Alarm on the "B" recirculation pump.
An investigation of the cause revealed that an excessive amount of oil had leaked out of the lower motor bearing oil reservoir due to a cracked oil drain pipe.
Since this was the second shutdown due to oil leakage from'the "B" reactor recirculation, pump, the licensee elected to replace the 0-ring and the cracked drain pipe prior to placing the unit back in service.
The licensee also modified the alarm circuitry to allow identification of the alarming level switch, thereby enhancing troubleshooting capabilities.
Normally, any out-of-tolerance oil level condition annunciates a Hi/Lo Level Alarm. The alarm modification provided for the identification of four possible conditions: high level in either upper or lower motor bearing oil reservoir; and a low level in either upper or lower motor bearing oil reservoir.
The previous alarm circuitry did not allow for such differentiation among the four oil level sensors that could cause an alarm.
The inspector concluded that although two shutdowns of Unit 2 resulted from oil leakage from the "B" reactor recirculation pump motor bearing lower oil reservoir, different root causes were involved; and no weakriess in maintenance effectiveness was identified.
Review of maintenance documentation of the oil leakage problem indicated that the licensee's evaluation of the problem was thorough and accurate, and that there was basis for their decisions relative to this matter.
No relationship was found between the licensee's decision on December 15, 1990, to delay repair of the 0-ring and the subsequent forced shutdown on January 5, 1991.
The inspector had no further questions on this subject.
4.6 Foreign Material Found in the Reactor Vessel At approximately 2:00 p.m. on March 12, the licensee observed foreign material resting on top of a reactor vessel feedwater sparger during reactor vessel disassembly.
Disassembly was being performed in preparation for fuel off-loading. While performing visual verification of shroud head bolt unlatching, what appeared to be a coil of white rope was observed resting on top of a feedwater sparger at about 170 degree azimuth and under 20 feet of water.
Shift Supervision was notified and NCR 91-0068 was initiated.
After further evaluation, Work Authorization {WA)V04128 was written to retrieve the material, since it appeared to be a piece of rope.
The retrieval was begun at 7:00 p.m.,
March 12 using an underwater pole with a hook.
When the hook was placed under the object and raised, the material parted.
A subsequent attempt had the same result.
The licensee
temporarily suspended further direct retrieval attempts, since the object tended to disintegrate when handled.
An underwater camera was set up and lowered into the reactor vessel by In-Service-Inspection personnel at approximately 12:30 a.m., March 13.
The increased resolution of the camera allowed th'e licensee to evaluate the object and tentatively identify it as calcium silicate pipe insulation.
The camera inspection also revealed two other smaller metallic objects beneath the insulation and situated between the vessel wall and the feedwatei sparger.
One object appeared to be a special purpose fastener with a diameter of about 0.5 inches, and the other appeared to be either a hex nut or bushing.
Based upon this examination, the licensee determined that the objects were in a stable configuration and would not readily move.
Accordingly, the licensee elected to continue reactor vessel disassembly based upon: (1) the stable configuration of the foreign material; and (2) the Maintenance and Health Physics recommendation to resume retrieval efforts after cavity floodup to reduce personnel radiation exposure.
Subsequently, reactor vessel disassembly continued; and the foreign material was not affected.
Following reactor vessel disassembly, the objects and material were retrieved by using undeiwater vacuuming equipment.
A detailed plan was developed which included contingencies in the event the material fell further into the reactor vessel.
The material was successfully vacuumed with no visible debris or material falling into the reactor vessel.
Continued material identification was underway at the end of the inspection period.
The specific safety impact represented by this event remains unresolved pending final identification of the foreign material and assessment by the licensee.
(UNR 50-387/91-02-02)
4.7
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Control Rod Drive Mechanism 38-31 Leakage - Unit 2 While uncoupling and removing Control Rod Drive Mechanism (CRDM) 38-31 on March 18, excessive leakage from the guide tube housing occurred resulting in a spill of approximately 500 gallons of reactor water onto drywell elevation 704.
Changeout of the drive mechanism was completed, but a leakage rate of between 2 and 4 gpm continued from the flange of the drive mechanism due to the inability to get a flange 0-ring to seat properly.
Because of the spill, the licensee halted CRDM changeouts until after the drywell floor could be cleaned up and the leak permanently directed to the suppression pool.
Two workers were subject to low level personnel contamination due to the leakage from the CRDM change-out effort, but were readily decontaminated.
As a prudency measure, the licensee decided to complete core offload prior to attempting to correct the CRDM 38-31 leakage.
Following the completion of core offload on March 22, another attempt to seat CRDM 38-31 and stop the leakage was made.
However, the effort
was unsuccessful.
During the attempt, the control rod blade was removed and a guide tube seal was lowered and seated within the control rod guide tube in an effort to stop the leakage and allow removal of the drive mechanism.
However, the guide tube seal did not stop or reduce the leakage when the drive mechanism was unbolted and lowered.
Consequently, the drive mechanism had to be reinserted and bolted to the flange.
At the end of this inspection period, the licensee was continuing evaluation and planning relative to the resolution of this matter.
To date, the licensee's actions relative to analysis, evaluation, planning, and control pertaining to this matter appear to be adequate and effective.
The inspector willcontinue to monitor and review the licensee's efforts to resolve this matter.
5.
EMERGENCY PREPAREDNESS 5.1 Inspection Activity The inspector reviewed licensee event notifications and reporting requirements for events that
'ould have required entry into the emergency plan.
5.2 Inspection Findings No events were identified that required emergency plan entry. No inadequacies were identified.
6.
SECURITY 6.1-Inspection Activity PP8.L's implementation of the physical security program was verified on a periodic basis, including the adequacy of staffing, entry control, alarm stations, and physical boundaries.
These inspection activities were conducted in accordance with NRC inspection procedure 71707.
6.2 Inspection Findings The inspector reviewed access and egress controls throughout the period.
No unacceptable conditions were noted.
7.
ENGINEERING/TECHNICALSUPPORT 7.1 Inspection Activity The inspector periodically reviewed engineering and technical support activities during this inspection period.
The on'-site Technical (Tech) section, along with Nuclear Plant
Engineering (NPE) in Allentown, provided engineering resolution for problems during the inspection period.
The Tech section generally addressed the short term resolution of problems; and NPE scheduled modifications and design changes, as appropriate, to provide long-term problem correction. The inspector verified that problem resolutions were thorough and directed to preventing recurrences.
In addition, the inspector reviewed short term actions to ensure that the licensee's corrective measures provided reasonable assurance that safe operation could be maintained.
7.2 Inspection Findings 7.2.1 Potential Unidentified Release Path Due to Backleakage Through the Control Rod Drive Hydraulic System NRC Information Notice (IN) 90-78 documented potential problems pertaining to a previously unidentified release path from the control rod drive hydraulic system that could potentially lead to post-accident dose rates in excess of those specified in the FSAR.
This IN evaluates the potential backflow that would result from leakage through the double seals of the Control Rod Drive (CRD) through the Control Rod Drive Hydraulic (CRDH) system and outside secondary containment.
Since portions of the plant's CRDH system supply piping is outside secondary containment, the system could be susceptible to the potential failure mechanisms described in the IN.
The licensee was previously aware of this concern and installed a modification in both units to mitigate the effect of a potential failure. A "Seismic Island" was installed which consisted of ASME Section III, Class 3 piping, two (2) ASME Section IIIcheck valves and the necessary test connections and block valves.
The island is located just inside secondary containment to prevent bypass leakage from reaching the Turbine Building, which is outside secondary containment.
The Seismic Island uses a water seal to minimize leakage.
Specifically, it uses clean water trapped between the Seismic Island and the reactor vessel as a 30 day water seal against the post-LOCA water reaching the Turbine Building. The Seismic Island check valves are periodically tested to ensure leakage is limited to less than 508 ml/hr, to ensure a 30 day water seal is maintained.
The test frequency is every 40 months.
This modification was installed and the associated testing performed to ensure minimum secondary containment bypass leakage.
This type modification was installed in lieu of containment isolation valves since failure of automatic isolation valves could prevent successful completion of the scram function.
The inspector reviewed the licensee's design to ensure that it adequately addressed the minimization of secondary containment bypass leakage and responded to the events described by IN 90-78.
Additionally, the inspector noted that Unit 1, TP-155-010; and Unit 2, TP-255-03, were written to require verifying leakage was less than 508 ml/hr to ensure that a 30
day water seal was maintained.
Previous successful tests were conducted on June 7, 1986 and October 10, 1989 for Unit 1 and February 21, 1986 and April 27, 1989 for Unit 2.
These licensee actions provided reasonable assurance that secondary containment bypass leakage through the CRDH system is minimized.
No inadequacies were noted.
7.2.2 Review of Standby Liquid Control System NPSH Adequacy NRC Information Notice No. 90-12 documented cavitation of the SLCS pumps due to loss of NPSH at Quad Cities Unit 1 during a special test performed on February 11, 1991.
Cavitation o'ccurred at 22 minutes of single pump run when temperature reached 112 degrees F.
Evaluation of this event determined that the system would not be capable of injecting.
enough sodium pentaborate to achieve cold shutdown with one or both SLCS pumps within 20 minutes.
P.P.& L. evaluated SLCS operability based on the above information notice and additional information received from their INPO network system.
As a result, P.P.& L. determined that the SLCS at Susquehanna is not susceptible to a loss of NPSH such as occurred at Quad Cities.
This conclusion was based on differences in system design and the fact that preoperational NPSH testing at Susquehanna was performed at storage tank temperatures between 115.8 and 119 degrees F; and with level in the storage tanks reaching a minimum of 2 1/2 inches above the suction line center line, with no indication of cavitation.
Modifications implemented to meet the ATWS rule (10 CFR 50.62) for both units included the addition of separate suction lines of.the same size (and at the same elevation) as those previously existing, and increasing minimum boron concentration in the storage tanks to compensate for the inability to achieve'86 gpm flow in the discharge lines.
Further, the
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control switch for SLCS was modified to automatically start both pumps.
No NPSH testing was performed following the modifications, but an evaluation was performed and confirmatory calculations were completed to show that NPSH was not significantly affected by the modifications.
System operability was demonstrated post-modification and at 18 month intervals.
This testing includes injecting from the test tank into the reactor vessel at normal operating pressure with both pumps operating simultaneously, The inspector noted that, based on the licensee's assessment, it appears that both Susquehanna units SLCSs would be capable of injecting the required amount of. boron to attain shutdown; and would not be susceptible to loss of NPSH leading to pump cavitation as occured at the Quad Cities facility.,
8.
SAFI<'TY ASSESSMENT/QUALITY VERIFICATION 8.1 Licensee Event Reports (LER), Significant Operating Occurrence Report (SOORs), and Open Item (Ol) Followup
8.1.1 Licensee Event Reports The inspector reviewed LERs submitted to the NRC office to verify that details of the event were. clearly reported, including the accuracy of the description of the cause and the 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:
I w
iJnit i 90-030-01 V
Entries Into Condition 2 Without Completed Surveillances on Unit 1 and Unit 2.
LER 90-030-00 was documented in IR 90-26 and the event was initially discussed in IR 90-25.
This revision reflects the shutdown on, January 5 for which the TS required IRM, APRM, and SRM surveillance tests were not performed until after entry into Conditions 2 (Startup) and 3 (Hot Shutdown)
from Condition 1 (Power Operation).
The unit's technical specifications require these tests be performed prior to entry into conditions 2 or 3 when shutting down.
The NRC recognized that enforcing this requirement would force the imposition of half scrams and rod blocks, and consequently increase
'he potential for a reactor scram.
While enforcement action is not warranted, an amendment of the Technical Specification willbe expedited, upon submission, to prevent recurrence.
90-032-00 90-033-00 Compensatory Security Measures Not Completed Expeditiously following Loss of the Security Data Management System.
A loss of the security computer systems occurred on December 7 due to a component failure.
Compensatory measures were not promptly completed.
The licensee has revised the security force response action plan to ensure completion of compensatory actions.
'!
Diesel Generator "D" Piston Pin Bushing Failure.
This event was reviewed, in NRC Inspection Report 50-387/90-25, which documented the discovery and investigation of a broken piston pin bushing in the "D" DG.
91-001-00 Isolation Pressure Switch Operation Prohibited by Technical Specifications (TS) During Retest.
This LER documents the necessity of withdrawing from a TS action statement to perform a post-replacement surveillance on a main condenser low vacuum MSIV isolation pressure switch.
TSs do not presently recognize or allow for the removal of an installed trip signal imposed due to action requirements.
However, the TS surveillances must be performed to restore the instrument to operable status.
The licensee has committed to pursue a change to their TS to allow removing an installed trip signal.
91-002-00 HPCI System Declared Inoperable Due to Failure of Outboard Steam Supply Line Isolation Valve to Stroke Open.
This LER documents a failure of the
1F003 valve to open during a routine valve exercising test on February 7, which led to the inoperability of the HPCI system.
Investigation by the licensee could not determine a root cause.
The valve was subsequently stroked successfully several times and the system returned to operable status.
The valve was stroked three times the week following the event with no problems and the valve exercising 'test frequency was increased to monthly for the next quarter to ensure proper operation.
iit it 2 91-001-00 Inadvertent Isolation of Shutdown Cooling Mode of Residual Heat Removal System.
This LER documents an automatic isolation of the RHR system while in the shutdown cooling mode during pressure switch replacement, as a result of inadequate work instructions.
This event was reviewed in NRC Inspection Report 50-388/90-26.
91-002-00 HPCI Outboard Steam Supply Containment Isolation Valve Declared Inoperable Due to Incorrect Torque Switch Setting.
This LER documents a
reevaluation of the operability and reportability determinations previously made concerning the HPCI 1F003 valve incorrect closing torque switch setting discovered in August 1990.
The reevaluation determined that the valve was, in fact, inoperable and was therefore reportable.
This event was reviewed in NRC Inspection Report 50-388/90-15.
No unacceptable conditions were identified.
8.1.2 Significant Operating Occurrence Reports SOORs are provided for problem identification and tracking, short and long term corrective actions, and reportability evaluations.
The licensee uses SOORs to document and bring to closure problems'identified that may not warrant. an LER.
The inspectors reviewed the following SOORs during the period to ascertain whether:
additional followup inspection effort or other NRC response was warranted; corrective action discussed in the licensee's report appears appropriate; generic issues are assessed; and, prompt notification was made, ifrequired:
Unit l 54 SOORs, inclusive of 1-91-009 through 1-91-06 Unit 2 41 SOORs, inclusive of 2-91-017 through 2-91-060.
No unacceptable conditions were identified.
The following SOORs required inspector followup:
1-91-054 Unexpected start of the "A" SGTS fan.
See Section 2.2.1 for details.
2-91-047 Discovery of foreign material in the reactor vessel during vessel disassembly, See Section 4.6 for details.
2-91-060 Excessive leakage from control rod drive 38-31 while replacing the drive mechanism, See Section 4.7 for details.
9.
MANAGEMENTAND EXITMEETINGS 9.1 Routine Resident Exit and Periodic Meetings The inspector discussed the findings of this inspection with station 'management throughout and at the conclusion of the inspection period.
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.
9.2 Status Meeting Relative to Licensee Activities Involving Emergency Diesel Generators On March 14, 1991, licensee representatives, including their contractors from MPR Associates, and a manufacturer's agent from Cooper-Bessemer, Incorporated, met with NRC
, staff members to discuss the status of their activities relative to root-cause determinations for several events involving the Emergency Diesel Generators (EDGs) at Susquehanna Steam Electric Station.
The items discussed were crankcase overpressurization events which occurred in September and October of 1989, involving the "B" and "C" EDGs; and the piston bushing failure involving the 7R piston of the "D" EDG, found on December 19,
1990.
The licensee representatives discussed their program to refurbish all engines, evaluate and finalize root causes, and improve EDG reliability. The following provides a summary of the licensee's presentation:
Relative to the crankcase overpressurization events, several potential causes were identified, including, possible lubrication problems, ring wear, pin bluing due to heat stress, piston end cap scuffing, stressful testing of the EDGs, and the adverse affect of
the introduction of cold combustion air through the intake manifold.
The licensee discussed corrective actions taken to address this type of event, which included, changing the brand of oil used in the engine, checking oil passages, checking pins, removing end caps and lower oil rings to facilitate improved lubrication, frequent inspection to verify that removal of the end caps did not introduce any new problems, revision of test procedures, and installation of automatic temperature control valves to regulate intake air temperature.
Relative to the piston bushing failure, the licensee identified the failure to be caused by inadequate bushing support due to an arched piston pin bore that was not detected during the previous refurbishment of the engine ("D" EDG). The arched bore was caused by an operational event (or events) which created abnormal stresses on the piston.
Accordingly, the licensee believes that during operability testing, the outer ends of the bushing overloaded, melted, thermally expanded, and deformed against the piston bore.
Upon shutdown of the engine the bushing contracted over the piston pin, and fractured due to tension.
The licensee identified that upon refurbishment of the piston by Cooper-Bessemer on September 21, 1990, and subsequent installation of the part in the "D" EDG on September 26, 1990, piston bin bore dimension was not checked.
Accordingly, the licensee has established a installation review protocol that includes verification of clearance in lube oil passages, pin bore dimension, pin bore flatness, pin clearance, pin contact area, pin bolt torque, and acceptable piston drag.
The licensee further discussed the importance that is now place on lube oil analysis and enhanced inspection and operability testing of the EDGs.
As a result of this experience, the licensee indicated that there has been substantial improvement in all engines relative to condition and design; and substantial knowledge developed relative to design, maintenance, and operation of the EDGs.
Additionally, the licensee discussed several procedure upgrades that were accomplished, and a predictive maintenance program that was established.
Other topics discussed at this meeting were: (1) the development and function of the Cooper-Bessemer Owner's Group; and (2) th status of a special study in 'progress by the licensee's consultant, MPR Associates, relative to simulation of EDG performance and reliability by the laboratory testing of a similar diesel engine in Sumner, Iowa. A copy of the licensee's presentation is attache ATTACHMENT 1 A rviti nLi AD
- Administrative Procedure ADS
- Automatic Depressurization System ANSI - American Nuclear Standards Institute ATWS - Anticipated Transient Without Scram APRM - Average Power Range Monitor CAC
- Containment Atmosphere Control CFR
- Code of Federal Regulations CIG
- Containment Instrument Gas CRDM - Control Rod Drive Mechanism CREOASS - Control Room Emergency Outside AirSupply System DG
- Diesel Generator DX
- Direct Expansion ECCS
- Emergency Core Cooling System EDR
- Engineering Discrepancy Report EP
- Electrical Protection Assembly ERT
- Event Review Team ESF
- Engineered Safety Features ESW
- Engineering Service Water EWR
- Engineering Work Request FO
- Fuel Oil FSAR - Final Safety Analysis Report ISAAC
- Instrumentation and Control ILRT - Integrated Leak Rate Test INPO
- Institute for Nuclear Power Operations IRM
- Intermediate Range Monitor JIO
- Justifications for Interim Operation LCO
- Limiting Condition for Operation LER
- Licensee Event Report LLRT - Local Leak Rate Test LOCA
- Loss of Coolant Accident LOOP - Loss of Offsite Power MSIV - Main Steam Isolation Valve NCR
- Non Conformance Report NDI
- Nuclear Department Instruction NPE
- Nuclear Plant Engineering NPO
- Nuclear Plant Operator NPSH
- Net Positive Suction Head NRC
- Nuclear Regulatory Commission OI
- Open Item
A breviati n List c ntinued PC
- Protective Clothing PCIS
- Primary Containment Isolation System PMR
- Plant Modification Request PORC - Plant Operations Review Committee QA
- Quality Assurance RCIC - Reactor Core Isolation Cooling RG
- Regulatory Guide RHR
- Residual Heat Removal RHRSW - Residual Heat Removal Service Water RPS
- Reactor Protection System RWCU - Reactor Water Cleanup SGTS
- Standby Gas Treatment System SI
- Surveillance Procedure, Instrumentation and Control SLCS
- Standby Liquid Control System SO
- Surveillance Procedure, Operations SOOR - Significant Operating Occurrence Report SPING - Sample Particulate, Iodine, and Noble Gas SRM
- Source Range Monitor TS
- Technical Specifications TSC
- Work Authorization