IR 05000387/1995022
| ML17158B043 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 11/21/1995 |
| From: | Pasciak W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17158B042 | List: |
| References | |
| 50-387-95-22, 50-388-95-22, NUDOCS 9511300019 | |
| Download: ML17158B043 (49) | |
Text
4 UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION I
Report Nos.
License Nos.
Licensee:
Facility Name:
Location:
Period:
Inspectors:
50-387/95-22; 50-388/95-22 NPF-14; NPF-22 Pennsylvania Power and Light Company 2 North Ninth Street Allentown, Pennsylvania 18101 Susquehanna Steam Electric Station Salem Township, Pennsylvania September 19, 1995 November 1,
1995 M. Banerjee, Senior Resident Inspector, SSES B. McDermott, Resident Inspector, SSES C. Poslusny, Project Manager, NRR N. Perry, Senior Resident Inspector, Limerick N. Blumberg, Project Engineer, DRP, Region I J.
Caruso, Operations Engineer, DRS,'egion I
L. Scholl, Reactor Engineer, DRS, Region I A. Lohmeier, Senior Reactor Engineer, DRS, Region I
R. Harris, NDE Technician, DRS, Region I Approved By:
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Date 9511300019 951121 PDR ADOCK 05000387
Operations'XECUTIVE SUNDRY Susquehanna Inspection Reports 50-387/95-22; 50-388/95-22 September 19, 1995 - November 1,
1995
The Unit 2 refueling operation was executed in a careful and controlled manner following procedures.
Start-up activities were safely performed by knowledgeable operators, with excellent communication, good management oversight and conservative decision making.
(Sections 2.2 and 2.3)
Naintenance/Surveillance The inspectors'bservation of the control rod drive hydraulic control unit dragon vent valve repair with freeze seal isolation identified some necessary enhancements in the licensee's work plan and procedure.
Some of the workers were aware of a contingency plan to stop leakage of reactor water in case of a freeze seal failure.
However, this contingency plan was neither documented in a work plan, procedure or instruction, nor was the equipment needed to implement the contingency staged.
The inspector concluded that formally including the contingency. plan in a procedure, worker.pre-brief, and training on the contingency plan would be a necessary enhancement.
(Section 3;1. 1)
Appropriate controls had been used to prevent foreign materials from being lost in the suppression pool and to evaluate inadvertent entry of foreign material.
The suppression pool inspection activity was conducted in a well controlled and monitored manner.
Excellent health physics and engineering support for this evolution 'was observed, and the inspection results confirmed the absence of debris in the pool that could block the suction strainers.
(Secti on 3.1. 2)
Based on a review of the status of the maintenance backlog on October 26, 1995, the inspector concluded that the backlog was being adequately prioritized, monitored and controlled by the licensee.
(Section 3. 1.3)
Engineering/Technical Support The T-10 offsite power supply on-line maintenance outage work was well planne'd, appropriately conducted with good management oversight and support, and mitigative measures met the NRC safety evaluation assumptions, (Section 4.1)
The licensee's correcti've action process functi'oned well with regard to the main turbine electro-hydraulic control relay card (KT106) problem.
The unexpected movement of the control valve/bypass valve was identified in a
timely fashion, investigated, and corrected before the condition worsened to the point of initiating a more severe plant transient.
(Section 4.2)
'e The inspector concluded that the corrective actions taken in the 1992 time frame for heat damaged cables in the motor operated valves (HOVs) did not include the HOVs in high temperature environments outside containment.
Previous NRC and PP8L evaluations have identified narrowly focused corrective actions, and the Condition Report process now in place is expected to.provide for broader corrective actions in 'the future.
The inspector considered appropriate the licensee's plans to re-evaluate the environmental qualification and qualified lives of all the affected HOVs.
The inspector did not consider this problem an immediate safety/operability concern because the as-found condition of the heat damaged cables did not impact the ability of the HOV to function.
Further, this issue deals with the qualified life of the components which includes expected normal service conditions for forty years, and hence is a longer term issue.
(Section 4.4)
The core shroud ISI program at Susquehanna is well planned, controlled, and executed and meets the minimum requirements of Codes and regulatory standards.
The analytic results of General Electric (GE)
Company and Structural Integrity Associates confirmed the licensee's assessment that the Unit 2 core shroud would be functional through the next two operating cycles (3.5 years) without repair of the known cracks.
The licensee's actions, based on the findings of cracks in the Unit 2 core shroud, are cons1stent'with the guidelines and recommendations of GE, Boiling Water Reactor Vessel and Internals Project (BWRVIP) group, and Electric Power Research Institute.(EPRI).
(Section 4.5. 1)
A recent visual examination of 160 control rod drive (CRD) bolts in 20 CRDs indicated that 19 bolts contained "star" shaped pitting and tear-like
.cracking.
Recurrent bolt cracking has been found since 1988.
The licensee believes there is no impact on CRD operability because all rejectable bolts from removed drives'have been replaced with defect free bolts.
Remaining bolts in the drives were considered by the licensee to be adequate in performing their specified function.
The licensee is planning a total exchange of bolting to a new design and material provided by GE that will be completed over several future refueling outages.
The inspectors found the licensee evaluation of the material deficiency and.the corrective action taken to be consistent with good engineering practice.
(Section 4.5.2)
PPKL performed a thorough root cause analysis of the cause of 4. 16 kV circuit breaker failures that occurred in September 1995.
When the analysis identified that the motor cutout switches were a common cause of two of the recent failures, an aggressive program to inspect and replace the switches was developed and implemented.
Excellent'communications and cooperation between the maintenance, operations, site engineering and corporate engineering personnel was evident in the resolution of the breaker failures.
(Section 4.6)
The condensing chamber vent design modification proposed by the licensee to resolve the issue of non-condensible gases causing inaccurate reactor vessel level instrument reading during a rapid depressurization event was different from the "keep-fill" design developed in accordance with the guidance from the BWR Owner's Group.
Based on a review of the design, and an inspection of the
installation of the modification, the NRC staff concluded that the licensee's design was acceptable, and the modification was installed as designed.
(Section 7.2)
Safety Assessment/equality Verification The licensee's corrective actions taken to improve performance in the areas of status control and permit and tagging were found to be effective.
(Section 6.1)
SUMMARY OF FACILITY ACTIVITIES 1. 1 Susquehanna Unit 1 Summary W
Unit 1 remained at 100K power throughout most of the inspection period.
Ninor power reductions were made to perform routine valve testing and control rod pattern adjustments.
On November 1, the licensee identified that the main generator's hydrogen gas was leaking into the main generator's stator water cooling system.
The leak was detected using a new stator water monitoring system that had been installed during the last refueling outage.
There were no anomalous readings from other generator monitoring instruments and the licensee began monitoring generator temperatures once per shift.
1.2 'usquehanna Unit 2 Summary The inspection started on day six of the Unit's 7'" refueling outage.
On September 25th the residual heat removal (RHR) shutdown cool.ing system was shutdown for planned maintenance and the temporary supplemental decay heat
, removal system (SDHR)
was placed in service.
The refueling outage work was completed by October 20th and the reactor startup commenced; however, a failed safety relief valve acoustic monitor resulted in a Technical Specification required shutdown before reaching the run mode (condition 1).
After repairs were completed inside containment, the unit startup was recommenced.
The reactor was made criti.cal on October 21, and officially completed the refueling outage with synchronization to the grid on October 22.
The power ascension was delayed due to problems with the new integrated plant computer system and the 'B'eactor feed pump turbine governor.
Full power operation was reached on October 28th and vibration monitoring tests at core flow greater than 100 million pounds mass per hour were in progress at the end of the report period.
1.3 Reportable Events On September 20, 1995, with Unit 2 in cold shutdown, the licensee reported that the main steam isolation valves (NSIV) had failed a local leak rate test (LLRT).
The as-found minimum path leakage was 27.4 standard liters per minute (SLN) which exceeded the Technical Specification limit of, 21.7 SLN.
After restroking the valves, the valves tested satisfactorily.
On October 1,
1995, with Unit 2 in refueling, the licensee reported that a
momentary loss of voltage to the 'B'eactor protection system (RPS)
bus caused a Division 2 half scram.
Engineered safety feature (ESF)
systems responded as expected given their condition prior to the event (eg. valves that did not move were either previously deenergized or already closed.)
There was.zo loss of cooling to the reactor vessel or spent fuel pool since the supplemental decay heat removal system was in service.
On October 3, 1995, with Unit 1 at 100X power and Unit 2 in refueling, the licensee reported that fire penetration seals had not been tested in accordance with ASTN-E-119, as described in the Fire Protection Review Report.
The penetrations were tested in accordance with IEEE-634, a similar industry
standard that has been approved for use at other facilities.
The licensee reported this finding since all provisions of the Fire Protection Review
.
Report were not maintained as required by the.facility operating license.
On October 14, 1995, with Unit 2 in cold shutdown, the licensee reported an unexpected ESF actuation when the reactor vessel head spray valve automatically closed during a pressure test.
The valve closure, although caused by a test procedure, was not identified as an expected result of the procedure.
The valve isolated, as designed, on a high (98 psig) reactor pressure signal.
On October 20, 1995, with Unit 2 in startup, the licensee reported commencing a Technical Specification required shutdown due to an inoperable safety relief valve (SRV) acoustic monitor.
2.
PLANT OPERATIONS (71707, 92901, 93702)
2. 1 Plant Operations Review The inspectors routinely observed the conduct of plant operations to independently verify that the licensee operated the plant safely, and according to station procedures and regulatory requirements.
The inspectors conducted regular tours of the various plant areas and periodically reviewed logs and records to ensure compliance with station procedures, to determine if entries were correctly made, and to verify correct communication of equipment status.
These records included various operating logs, turnover sheets, blocking permits, and bypass logs.
The inspector observed plant housekeeping controls including control and storage of flammable material and other potential safety hazards.
Posting and control of radiation, high radiation, and contamination areas were appropriate.
The inspectors performed backshift and deep backshi,ft inspections during the period.
The deep backshift inspections covered licensee activities between 10:00 p.m. 'and 6:00 a.m.
on weekdays, weekends, and holidays.
2.2 Unit 2 Post-Refueling Startup The inspectors observed various activities associated with the Unit 2 startup from the refueling outage.
The observed activities were well controlled, with very good management oversight.
Operation's shift briefings were thorough and appropriate.
Problems encountered during startup were addressed very well.
In two instances, when control rod position was lost, response and coordination of activities between operators, reactor engineers, and IKC personnel were very good.
Personnel and management did not rush the activities.
Operations response to events was very good.
During the ADS valve manual actuation test, when the L SRV was still indicated open by its acoustic monitor, operators immediately verified the indications and took appropriate and timely actions to close the valve and verify its closure.
Operators were
very sensitive to the technical specification 2 minute time limit.
Additionally, they got 18C personnel involved in troubleshooting immediately.
The inspector noted that plant management had the unit shut down in order to make a drywell entry to repair the SRV acoustic monitor.
In another instance, operations management halted the startup for approximately 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> in order to ensure that the rod control system was functioning properly, when they did not get a rod block that they expected.
For this, they also used the simulator to help with the troubleshooting, and consulted 'with GE to verify their results.
Communications in the control 'room were excellent.
Operators properly used repeat backs (three-part communications),
and the supervisors ensured that all personnel in the room understood the "big picture" before, during and after activities.
Observed surveillances, in the control room, were well conducted by knowledgeable operators, including a trainee, and were adequately supervised.
, The operators were observed to be using very good self check techniques.
The operations prebrief for the 18 month ADS valve manual actuation surveillance was very good; in particular, the two minute technical specification time limit for an open SRV was discussed.
This proved to be very important, since the fifth valve. tested failed to fully close when demanded.
Operators quickly identified this using all available'ata, and properly verified its closure using redundant indications, since the acoustic monitor had failed high,
.falsely indicating an open position for the valve.
The surveillance was ultimately successfully completed, and the failed acoustic monitor was evaluated by maintenance personnel.
The inspector concluded that the start-up activities were safely performed by knowledgeable operators, with excellent communication, and good management over sight and conservative decision making, 2.3 Unit 2 Refueling Operation The inspectors observed refueling operations from the refueling bridge during both core shuffle segments of the outage schedule.
The refuel bridge and mast were operated in accordance with procedures.
Fuel moves were executed in a controlled and careful manner with close attention to indications of hardware malfunction.
Several control rod position indication transponder cards failed during the course of the core shuffle that stopped fuel movements.
Operators correctly responded to the failures and bridge control'lockups in accordance with the applicable off-normal procedure, ON-081-002.
The inspector concluded that the refueling operation was executed in a controlled manner following procedures.
3.
MAINTENANCE AND SURVEILLANCE (62703, 61726, 92902)
3. 1 Naintenance Observations The inspector observed and/or reviewed selected maintenance activities to evaluate whether the work was conducted in accordance with approved
,
procedures, regulatory guides, Technical Specifications, and industry codes or
0'
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 and 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 controls were implemented; fire protection controls were implemented; and the equipment was verified to be properly returned to service.
Maintenance observations and/or reviews included:
TP-059-001 Suppression Pool and Strainer Inspection, September 21-22, 1995 WA V53650 HCU 14-51 Dragon Vent Valve Rework, October 2, 1995 WA S517373 SGTS 'A'an Inlet Damper Actuator Replacement, October 17, 1995 Based on observation of selected portions of the above maintenance, the inspector concluded that the work was conducted and completed appropriately, with due concern for plant safety and procedures.
3. 1. 1 Unit 2 Dragon Vent Valve Repairs
\\
On October 2-3, 1995, the inspectors observed corrective maintenance for small leaks that had developed in several hydraulic control unit dragon vent valves during the last operating cycle.
The inspectors reviewed the programmatic controls associated with the freeze seal and any contingency plans available to the workers in the event of a.seal failure.
Several observations were made.
On October 2nd, workers did have the freeze seal procedure at the job location, but were not aware of any seal failure contingency plans.
On October 3rd, the workers did not.have the procedures at the job site, but were
"aware of a contingency plan.
Further, when the inspector requested to see th'
ball valve and fitting necessary to implement the contingency plan, it took workers approximately 15-20 minutes to find it.
The inspectors considered the contingency plan a prudent measure in light of past site and industry problems with freeze seals.
However, this contingency was not documented in any work plan, procedure or instruction, and was not known to at least one group of workers.
In addition, the inspector considered the staging of the equipment to implement the contingency plan, at a,readily accessible location, essential.
The inspector concluded that formally including the contingency plan in the procedure, tailboard briefing, and training for the dragon vent valve maintenance would be an enhancement of the licensee's program for these repairs.
3. 1.2 Unit 2 Suppression Pool Diver's Inspection As part of the licensee's continuing analysis of generic suppression pool suction strainer clogging issues, a diver's inspection of the Unit 2 suppression pool was conducted during the refueling outage.
This was the first Unit 2 suppression pool debris inspection since the initial plant startup in 1985.
The inspection plan included retrieval of small debris,
obtaining sludge and water samples, and close inspection/cleaning of all suction strainers.
A remotely operated underwater camera, known as a mini-rover, was used to map dose rates and help identify debris on the floor of the suppression pool prior to the diver's inspection.
Thirty items removed from the suppression pool can be classified as either small items (eg. tools, tags, etc.) that were probably dropped from the suppression pool catwalk, or hoses dropped through downcomers during drywell system draining evolutions.
The licensee concluded none of these items impacted past operability of any suction strainers.
Eight irretrievable items were identified du} ing the diver and mini-rover inspections.
These items were evaluated as acceptable to remain in the pool based on their size (insignificant surface area)
or based on their weight (heavy metal items that would remain at the bottom of the pool).
The video tape recorded inspection showed that there was only a minimal dusting of silt on the surface of the suction strainers.
The suppression pool floor was cover ed by a layer of sludge that was easily disturbed by the diver's movements.
The licensee estimated that, on the average, the sludge layer was approximately 1/8 inch thick, with some floor areas being lightly covered and corners having more accumulation.
Unlike.the last Unit 2 suppression pool inspection, no sheets of visqueen or other materials having large surface area were found that could potentially block the pump suction strainers.
The licensee's preliminary chemical analysis of the sludge and pool water did not identify significant amounts of fibrous material.
The licensee'believed the residue to be concrete residue, quartz, mica, and calcium.
They also identified a few."hair like" strands measuring less than 0.01 mm in diameter and varied in length from 0.5 mm to 1.0 mm.
The sample debris in the samples was noted to easily break apart and was, in all cases, smaller than the strainer hole size of 3. 175 mm (I/8 inch).
The inspector observed portions of the mini-rover and diver inspections, reviewed foreign material exclusion (FHE) controls, and toured the suppression chamber.
The inspector made a final tour following the licensee's suppression
'hamber closeout inspection and noted a generally thorough cleanup had been completed.
Adequate control of materials entering the suppression chamber was noted during observation of various outage related work evolutions.
Based on
'these observations and review of the FHE logs, the inspector concluded that appropriate controls had been used to prevent foreign materials from being lost in the suppression pool and to evaluate inadvertent entry of foreign material.
The suppression pool inspection activity conducted by the licensee was done in a well controlled and monitored manner.
Excellent health physics and engineering support for this evolution were observed and the inspection results confirmed the absence of debris in the pool that could block the suction strainer.1.3 Maintenance backlog The inspector reviewed the status of.the maintenance backlog on October 26, 1995.
The total number of open work code 1 (non-outage, non-modification related, power generation system components)
corrective maintenance work authorizations (WAs) on that date was 594.
This number was consistent with past backlog that was found to run between 500 and 600.
Out of these 594 WAs, 265 were safety/maintenance rule related.
Approximately 200 were more than six months old, and approximately 35 were more than 18.months old.
The code
items were further.prioritized in three priorities, with priority 1 being the most urgent and is usually immediately taken care of, such that there was no backlog.
The licensee's goal was not to keep any priority 1 and
WAs open for more than two weeks.
However, a backlog between two and sixteen priority 2 WAs, over two weeks old, were noted during the last three months.
'uring a plant tour on November 6, 1995 (a date outside the inspection report period),
the inspector noted that the power supply to the Appendix R emergency lighting in the B emergency diesel generator (EDG) room was disconnected, thus leaving the backup battery discharged.
Upon further questions,. the inspector found that a
WA (S51367)
was written on October 13, 1995, to address tripping of the essential lighting panel lEP3 that supplied the B
EDG room lighting including the emergency lighting.
Licensee's troubleshooting identified a
short in the cable from the lighting panel breaker to the B
EDG room.
A separate-WA was written on October 30, 1995 to complete the emergency lighting related work.
The inspector noted that the item was not entered in the control room Unit Supervisor's log, and the Unit and Shift Supervisors did not know about the issue, although a control room operator was aware of the problem.
The inspector discussed the issue with licensee management, and concluded the overall prioritization of the work, including communication of the issue, did not reflect the appropriate significance of emergency lighting.
The licensee initiated a condition report, and is currently reviewing the event for necessary corrective actions.
The inspector reviewed the list of priority 2 open WAs and reviewed a sample of the list of priority 3 open WAs, and did not identify any other concerns.
The inspector concluded the above item was a departure from the normal prioritization scheme used by the licensee, and that the maintenance item backlog is otherwise adequately prioritized, monitored and controlled by the licensee.
3.2 Surveillance Observations The inspector observed and/or reviewed the following surveillance tests to determine whether the following criteria, if applicable to the specific test,
.
were met:
the test conformed to TS 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 were accurate and complete; removal and restoration of the affected components were properly accomplished; test results were s
appropriately communicated with regard to TS and procedural requirements; deficiencies noted were reviewed and appropriately resolved; and the surveillance was completed at the required frequency.
Surveillance observations and/or reviews included:
WA P46154 VOTES Testing of RHR Shutdown Cooling Valve F009, observed on September 26, 1995 SO-253-002 18 Month SLC'nitiation and Injection Demonstration, observed on September 26, 1995 SO-283-002 18 Month ADS Valve Manual Actuation, revision 6, observed October 19, 1995 SO-259-002 Monthly Operability Check of Suppression Chamber Drywell Vacuum Relief Breaker Valves', revision 6, observed October 19, 1995 SO-250-002 quarterly RCIC Flow Verification, revision 14,,
observed October 20, 1995 Based, on observation of selected portions of the above surveillances, the inspector concluded that they were completed with appropriate consideration for safe plant operation and administrative control.
3.2.1 Partial Flooding of the Unit 2 HPCI and RCIC Rooms Upon completion of the reactor plant hydrostatic test on October 14, 1995, reactor vessel water level was lowered to below the main steam lines to allow draining of the main steam lines.
While this drain dow'n was in progress, an individual performing an effluent walkdown of the Unit 2 Reactor Building observed approximately 1" of water on the floor of both the HPCI and RCIC rooms.
The apparent cause of this water was that some water being drained to the hot well "short circuited" to the HPCI and RCIC systems steam drain lines.
The valves in the steam lines were open as well as the system drain lines..
Water then drained to the floor drains; however, the floor drain valves were shut causing a backup of water in both the HPCI and RCIC rooms.
Significant contamination was caused in both rooms.
The apparent cause of this event was that the hydrostatic test procedure did not take into account the HPCI and RCIC steam drain valves; hence, they were not shut.
Pressure in the reactor vessel may have been sufficient to redirect some water down these drain lines.
The licensee has initiated Condition Report 95-541 to evaluate the root cause and corrective actions.
The inspector will continue to follow the licensee's action.
ENGINEERING (71707, 37551, 92903, 73753)
4. 1 T-10 and Star tup Bus 10 On-line Maintenance The Susquehanna offsite power supply consists of a tap from the 230 KV Hontour-Hountain line feeding the startup transformer T-10, and a 230 KV tap from the 500-230 KV tie line that feeds the startup transformer T-20.
During the Unit 2 7'" refueling outage the offsite power supply to the transformer T-10 was modified to improve its reliability.'he modification consisted of.
three elements:
1) separating the 47 mile Hontour-Mountain 230 KV line into two separate lines, 2) constructing a T-10 tap switchyard with a four bay one and one-half breaker arrangement, and 3) separating the relaying and control circuits for transformers T-10 and T-20 into two separate panels from a common panel in the control room.
A significant gain in reliability of offsite power sources was calculated to result from these changes.
The plant Technical Specification allowed outage time (AOT) for offsite power sources (either T-10 or T-20) is up to 3 days before a reactor shutdown was required.
PP8L requested a temporary extension of the AOT from 3 to 7 days.
This was granted by the NRC, based on a licensee analysis that showed that increasing AOT from 3 to.7 days does not increase the. consequences of a LOOP event or a station blackout if mitigating measures were taken.
The NRC safety evaluation listed the mitigative measures.
The inspector reviewed the licensee's test procedure and the risk assessment, and verified plant system status and ongoing activities to ensure that control room operators had a good understanding of the mitigative measures, and the systems that were assumed to be operable in licensee's risk assessment were maintained as such.
The inspector verified that the prerequisites were met, and deviations from the risk assessment assumptions were properly reviewed and concurred by Nuclear Systems Engineering.
The inspector noted that plant management decided to delay work start due to a'forecast of bad weather until better weather was expected.
The inspector concluded the T-10 on-line maintenance outage work was well planned, appropriately conducted with good management oversight and support, and mitigative measures met the NRC safety evaluation assumptions.
4.2 Modification Of EHC Relay Card (KT106)
On January 21, 1995 Unit 1 was operating at lOON power when the main turbine control valves closed slightly and the ¹1 and ¹2 bypass valves opened for less than one second.
On February 9, 1995, the problem occurred a second time and the licensee formed an'vent Review Team (ERT)', which included a General Electric representative, to investigate the event.
The ERT tracked the problem to a high contact resistance on a normally closed contact on the KT106 relay card.
According to the vendor representative, this finding was consistent with industry experience.
As immediate corrective action, the relay card was replaced with Unit 1 in operation to reduce the chances for an unexpected turbine trip/reactor scram.
As long-term corrective action, the licensee implemented GE's recommended modification during the Unit 1 8'" refueling outage which ended Hay 6, 199 The modification entailed wiring an unused normally closed contact in parallel with the subject contact.
This modification was implemented on Unit 2 during the unit's 7'" refueling outage which ended October 22, 1995.
The inspector concluded that the licensee's corrective action process functioned well with regard to this electro-hydraulic control (EHC) problem.
The control valve/bypass valve anomaly was identified in a timely fashion,,investigated, and corrected before the condition worsened-to the point of initiating a more severe plant transient.
4.3 Preservation Of Failed Components For Analysis On August 29, 1995, the Unit 2 reactor protection system (RPS) electrical protection assembly (EPA) breaker '2A-E'ailed to trip as expected during performance of surveillance S0-258-003, Revision 7, Semi-annual Division I RPS EPA Functional Test.
Maintenance personnel disassembled the breaker in an-attempt to determine why the breaker had failed to trip and subsequently the licensee was not able to positively identify the failure mechanism.
Nuclear System Engineering (NSE) was not contacted until after.the failed breaker had been disassembled.
On October ll, 1995, the Unit 2 EPA breaker '2A-A'ailed to trip as expected during performance of the same surveillance.
NSE was contacted by Operations in this case, however, the failed breaker was not maintained in its as found condition as requested the breaker was manually opened, per normal practice, prior to its removal.
The '2A-A'PA breaker was sent offsite for failure analysis but the fact that it was disturbed from it'
failed closed position may hinder the analysis.
The inspectors noted two previous examples of failure to preserve failed components.
In January 1995, a pressure relief valve on the 150 psig containment instrument gas system was refurbished before the NSE engineer had completed testing the valve.
An update to Unit 1 Licensee Event Report 91-015, issued on August 8, 1995, stated that PP8L was unable to perform engineering analysis on a repeat HPCI steam poppet valve failure because the broken component was inadvertently discarded.
(LER 91-015-01 is reviewed in Section 7.1)
The inspector discussed these examples with licensee management because it was not apparent that existing programs, or their implementation, were effective in preserving the physical evidence necessary for detailed analysis of.complex or repetitive failures.
The inspector discussed the importance of prompt identification of the failure to the correct individuals,.clear communication of the desired action, and implementation of necessary controls with licensee management.
The inspector concluded that this issue could impact the licensee's timely development of effective corrective actions to prevent recurrence.
The NSE manager agreed to look into this matter and the resident inspectors will continue to monitor performance in this area.
4.4 NOV Limit Switch Compartment Heaters On September 23, 1995, electrical maintenance identified several heat damaged wires terminating in the limit switch compartment (LSC) of HV-241F019, a main steam to condenser motor operated valve (HOV) in Unit 2.
This safety related steam isolation valve is located in the main steam tunnel.
The licensee's
immediate corrective action was to remove the last three inches of conductor from each damaged cable (which encompassed the damage)
and reterminate the connections.
PP8L Condition Report 95-458 documented this finding.
Limitorque actuators are supplied with small resistance type ceramic heaters installed in the LSC to prevent moisture problems during storage and prior to service.
In some cases, the HOV motors are supplied with a similar heater.
The heaters are not required for the actuator's environmental qualification (Eg)
and were not tested by the manufacturer during Eg testing.
Industry experience has shown that energized heaters can cause heat damage and accelerate aging of control and power wiring internal to the LSC or motor.
At Susquehanna, all safety related HOVs originally had LSC heaters but, not all safety related HOVs had motor heaters.
According to plant drawings, the LSC and motor heaters are supplied from the same electrical circuit.
In 1992, heaters for HOVs inside containment on both Units were de-energized based on the discovery of heat damaged wires in the LSC's of several HOVs.
This corrective action was narrowly focused and did not address the HOVs outside containment.
'lthough not yet complete, the licensee's assessment regarding HV-241F019 indicates that the HOVs located in the steam tunnels, outside containment, were overlooked in 1992.
A generic modification, due in 1996, will de-energize and remove all LSC heaters during routine HOV maintenance.
Since this could take a number of years to complete, the licensee is evaluating more timely actions for approximately seventy three HOVs in high temperature environments (>130'F).
E The inspector concluded that the corrective actions taken in the 1992 time frame did not have a broad enough perspective to capture the HOVs in high amb'ient temperatures outside containment.
Previous NRC inspection findings and PP8L self assessments have identified narrowly focused corrective actions and the Condition Report process now in place is expected to limit similar problems in the future.
The inspector considered appropriate the licensee's plans to re-evaluate the environmental qualification and qualified lives of all the affected HOVs.
Timely actions to address the HOVs in high ambient temperatures, with their heaters still energized, will help to minimize the penalty on qualified life of their components.
The inspector did not consider this problem an immediate operability concern because the as-found condition of the heat damaged cables in HV-241F019 did not impact their ability to function.
Further, this issue deals with the qualified life of the components which includes expected normal service conditions for forty years and post accident conditions.
4.5 Inservice Inspection During the period of October 16-20, 1995, inspectors conducted an independent inspection of the on-site inservice inspection (ISI) activity at Susquehanna.
The major focus of the inspection was on the ultrasonic test examination (UT)
findings and evaluation of the acceptability of the Susquehanna Unit 2 core
ll shroud in light of the finding of cracks in circumferential welds.
In addition, the inspectors reviewed the evaluation and corrective action taken to resolve the continuing issue of control rod drive bolt cracking.
4.5. 1 Unit 2 Reactor Vessel Core Shroud Inspection and Evaluation Sco e of Ins ection and Evaluation The objective of this inspection was to assess the adequacy of the licensee's inservice inspection (ISI) program in examining the Unit 2 core shroud welds for cracks and determining the extent of such cracking.
The inspectors also reviewed the analytic procedures used by the licensee in determining any necessary corrective action to assure that the core shroud will safely continue its operating function.
Back round The history of core shroud cracking began in Switzerland in 1990, when cracks were discovered by visual examination (VT) adjacent to a circumferential weld.
The cracking mechanism was identified as intergranular stress corrosion cracking (IGSCC). Subsequently, this was found to be an industry-wide problem of IGSCC and irradiation-assisted stress corrosion cracking (IASCC) of BWR system welds.
'Concern for this type of degradation led to industry wide programs by groups such as the Boiling Water Reactor Vessel and Internals Project (BWRVIP), the Electric Power Research Institute (EPRI),
and General Electric (GE)
Company, and the development of non-destructive e'xamination procedures and corrective action 'guidelines to identify, characterize, and repair the co} e shroud cracking.
Desi n Descri tion The core shroud is a series of vertical stainless steel cylindrical plates and rings welded together to provide a non-pressurized boundary surrounding the reactor core.
Should loss of water occur (due to a recirculation line break)
in the annulus between the core shroud and reactor vessel wall, reactor 'water level will be held over the core region for some time after the break.
The core shroud also prevents lateral movement of the core during a seismic event.
Review 'of the shroud fabrication information by the inspectors found the welds connecting the vertical series of cylindrical plates and rings to be double J, double butt, single and double V, double U,
and fillet circumferential welds.
The vertical cylindrical plate sections are fabricated by means of vertically welding cylindrical sectors.
The lower, intermediate, and upper shroud is made of 2 to 4 inch thick SA240TP304L hot rolled plate and solution heat treated.
The shroud support baffle plates and support legs are made of SB168 Inconel 600, annealed, and are 2.5 to 3 inches thick.
Carbon content of the plates ranges from.020 to.027 percent.
Host welding is shielded metal arc (SHA), although gas tungsten arc (GTA) and submerged arc (SA) were used at a
few sections.
The inspectors found the core shroud material specifications, heat treatment, and welding processes and material., to be retrievable by means of the comprehensive documentatio Core Shroud Examination Procedures
The Code of Federal Regulations (CFR), Title 10, Part 50.55a (10 CFR 50.55a(g)),
requires ISI of safety-'related equipment to identify system degradation.
The licensee generated program of inspection was submitted for review and approval by the NRC under the authority embodied in
CFR 50.55a(g)(4)(iv).
The required inspections are detailed in the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code,Section XI, for Inservice Inspection per
CFR 50.55a(b).
The inspectors reviewed automated ultrasonic examination data submitted by the licen'see of the core shroud welds. This examination was conducted by the licensee's contractor GE, utilizing their automated UT system
"Smart 2000" per the approved procedure GE-ISI-447, Rev.0 The inspectors reviewed a sample of manual and automated data collected during the recently completed Unit 2 refueling outage.
The inspectors also reviewed NDE certifications and qualifications for each NDE technician performing core shroud examination.
The data packages were 'appropi iately signed and dated, indicating acceptance of the contractor personnel certification by the licensee.
The NDE technician qualification packages are independently reviewed by the ASME Code Authorized Nuclear Inservice Inspector (ANII).
The NRC inspectors reviewed a sample of the NDE technician's data packages and the ANII log and confirmed that qualification/certification documentation for NDE technicians performing examinations for the ISI program were properly reviewed.
Core Shroud Examination Ins ection Findin s
The inspectors reviewed the findings of the UT inspection of the circumferential core shroud welds.
the welds are designated Hl, H2, H3, H4, H5, H6a, H6b, and H7.
Hl is the uppermost weld location, and H7 is the lowest weld location having been UT examined.
The results of the weld UT are as follows:
WELD Hl H2 H3 H4 H5 H6a H6b H7 UT RESULTS 21.52 degrees cracked (41.38 inches)
94. 11 degrees cracked (180.98 inches)
No recordable indications 70.04 degrees cracked (134.69 inches)
4.69 degrees cracked (8.48 inches)
No recordable indications 120.47'degrees cracked (210.98 inches)
No recordable indications The extent cracked shown above is a cumulative value of the distribution of cracks around the circumference of the weld.
There are two other circumferential welds (H8 and H9) at the bottom of the core shroud that were examined visually by means of remote enhanced visual inspection.
No indications were noted in these welds.
The vertical welds connecting the cylindrical shroud sectors were not examined by UT. The inspectors found documented justification of not performing UT of these weld Review of the foregoing data-by the inspectors indicated that the most significant cracking occurred in welds H6b(in the lower radiation affected zones)
and H4 (in the high radiation zone).
The inspectors reviewed, in detail, the documented results of the UT inspection of each of these welds and found the resulting reports of the extent of cracking to be correct.
Included in the review were the total length, flaw depth, remaining ligament through the wall, and the flaw type.
In weld H6b at the lower shroud, below the core level, the flaws were IGSCC. In weld H4, in the high fluence core level, the flaws were both IGSCC and IASCC.
The depths of flaws in these two sections ranged from.05 to.75 inches in a 2 inch thick plate.
The examination system used was the GE Smart 2000 system with 45 degree shear wave, OD creeping wave, and 60 degree refracted longitudinal wave search units.
The inspectors found that the documented results of the Smart 2000 examinations of the welds were of excellent quality and allowed data to be retrieved simply for analysis and evaluation of the shroud cracks.
Evaluation of the Ins ection Data Review the assessment of the UT inspection results by the inspectors indicated that, for the most extensively cracked welds (H6b and H4),
a conservative estimate of the cross-sectional area of the weld remaining is as follows:
The weld cross sectional area now cracked is 2.3% for H4 and 4.9Ã for H6b.
The projected weld cross sectional area cracked after two operating cycles. (3.5 years) is 71.3X for H4 and 73.9X for H6b.
The conservatism, simply stated, lies in the assumptions related to crack size used in the area computation.
The crack is assumed to be through wall, two adjacent cracks within a prescribed proximity are assumed
.connected, and corrective factors are added to the crack segment lengths based on analytic studies of detection capability reviewed by the inspectors.
I Fracture mechanics studies by Structural Integrity Associates demonstrated that the rate of progression (enlargement)
of existing crack sizes would allow operation for at least one cycle.
The licensee's assessment considered the effect of reactor fluence in determining the ability of the core shroud material to sustain design loading.
The licensee found that the required shroud cross-sectional area needed to sustain the design normal, upset, and faulted loading conditions was less than 10N.
The inspectors reviewed the analytic results of GE and Structural Integrity Associates confirming.the licensee's assessment that the core shroud would be functional through two operating cycles (3.5 years).
The inspectors found that the licensee actions were consistent with the guidelines and recommendations of GE, BWRVIP group, and EPRI.
The core shroud ISI program at Susquehanna was well planned, controlled, and executed.
It met the minimum requirements of the ASNE Code.
The documented results of the Smart 2000 examinations of the welds were of excellent quality and retrievable.
Continued operation of Susquehanna Unit 2 for the next 3.5 years
with the known core shroud cracks was based on conservative assumptions and analysis regarding flaw characterization, analytical calculation,.and past operating experience with similar units having cracks in the core shrouds.
4.5.2 Control Rod Drive Bolting Cracking CR 45-457 During a recent visual (VT-I) examination of 160 bolts in 20 control rod drives (CRDs), it was reported by the licensee that 19 bolts contained "star" shaped pitting and tear-like cracking.
The inspectors reviewed the evaluation and corrective action taken by the licensee to resolve the continuing issue of control rod drive bolt cracking.
The documentation related to the bolting cracking reviewed by the inspectors included relief requests, technical justifications, metallurgical examinations of the crack, and vendor notification by the manufacturer..
.BBkB d
Review of the documentation related to this bolting indicated that the problem with bolt cracking was first identified in 1988 during the Unit 2 second refuel outage.
The bolts were all replaced.
In 1989 all bolts were replaced in Unit 1 during its 4th refuel outage.
In 1990, subsequent Magnetic Testing (MT) found rejectable bolts again in Unit 1.
Similarly, in 1991, during its 4th refuel outage, visually rejecte'd bolts wer e replaced in Unit 2.
.The inspectors reviewed a 1989 licensee report evaluating the causal factors contributing to the CRD bolt cracking.
The licensee stated that the defects noted were up to.025 inches deep and violated the allowed corrosion depth of
.020 inches.
The licensee stated that the total removal and replacement of all CRD bolts were not necessary, since the CRD operation can be maintained with only three of the eight bolts, arid the probability of the crack proceeding all the way through the bolt was low.
The report recommended continued examination of the bolts to confirm that the cracks did not progress to affect the functionality of the bolts.
Corrective Action It was stated by the licensee that there is no impact on the operability of the CRD system because all removed bolts have been replaced in kind with visually acceptable defect free bolting.
Remaining bolts in the drives were considered by the licensee to be adequate in performing their specified function.
GE provided a new design and. material for bolting that is now in the process of being installed at a rate of 160 bolts in 20 CRDs at each future refueling outage.
GE improved the material by going from 4140, grade steel to 4340 grade steel with low phosphorous and sulphur.
GE also increased the fillet radius and the bolt socket wall thickness.
The licensee asked GE to redesign the washer to facilitate drainage away from the bolt. The total exchange of bolting to the new design will be completed over several future refueling outage Conclusions The inspe'ctors found the licensee evaluation of the material deficiency and the corrective action taken to be consistent with good engineering practice.
4.6 4 KV Circuit Breaker Failures 4.6.1 Background Between April and September 1995, several problems occurred involving the failure of 4.16'V circuit breakers to close on demand.
Of these failures, three occurred within one week during September.
The affected components were Westinghouse Model 50-DH-P250 magnetic air circuit breakers.
The following is a summary description of the problems:
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April 23, 1995 - the 'D'us alternate feed breaker failed to close.
PP8L determined the failure was the result of high contact resistance on the motor cutout limit switch.
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July 6, 1995 - the 'C'mergency service water (ESW)
pump failed to start and then started after a delay of several seconds.
PPKL attributed the cause of this failure to intermittent contact on the control switch and the electrical portion of the switch was replaced.
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July 9, 1995 the 'C'SW pump failed to start and then started after a
time delay.
The mechanical portion of the control switch was replaced to correct the problem.
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September '7, 1995 - the 'C'SW pump exhibited a delayed start.
The pump started several seconds after the operator depressed and.held the start pushbutton.
PPKL suspected that the delayed start was due to a
problem with the floor tripper mechanism and the circuit breaker was replaced with a spare.
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September 14, 1995 the 'B'SW pump failed to start (circuit breaker did not close).
PP&L determined that the failure was the result of high contact resistance on the motor cutout limit switch.
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September 15, 1995 the '28'ore spray pump failed to start.
The operators racked the circuit breaker out and back in, and pump started successfully.
The problem was also determined to be high contact resistance on motor cutout limit switch.
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The motor cutout switch is operated by mechanical linkage in the circuit breaker.
The switch has two pairs of normally-open and normally-closed contacts.'hese contacts are in series with the spring release coil that operates the closing mechanism.
Two spring loaded plungers operate a movable contact piece for each of the pairs of contacts.
The moveable contact makes up either the normally-open or normally-closed contacts based on the condition of the breaker operating spring, i.e., spring-charged or release e
Three sets of contacts are utilized in the circuit breaker control scheme.
One set of normally-closed contacts controls the operation of the spring-charging motor.
The second set of normally-open contacts operates a blue light located on the switchgear circuit breaker cell.
The blue light provides indication that the operating spring is charged and the breaker is ready to be closed.
The other set of normally-open contacts are connected in series with the spring release coil.
The spring release coil, when energized, initiates the breaker closure.
The motor cutout switch contacts permit the operation of the spring release coil when the closing spring is in the fully charged position.
A high value of electrical resistance on these contacts can reduce the current through the spring release coil and thereby prevent actuation of the closure mechanism.
The purpose of the floor tripper is to trip the breaker and to maintain it in the trip-free position when the breaker is moved from the test and connected (racked-in) positions.
This prevents accidental closing of the breaker when it is in an intermediate position.
The floor tripper lever is operated by cam plates that are welded to the switchgear cell floor.
4.6.2 PP8L Troubleshooting and Root Cause Analysis During the initial investigation of the '10'us alternate feeder breaker problem in April 1995, an apparent minor misalignment of the breaker and the switchgear cubicle was noted.
The breaker was removed from the cubicle and then reinstalled to correct any possible misalignment and following this action the breaker closed on demand.
Although the breaker then functioned, subsequent troubleshooting of the breaker identified a high resistance on the motor cutout switch contacts.
Racking of the breaker caused cycling of the switch contacts that might have helped breaker operation by temporarily improving contact resistance situation.
The identified cause of the failure of the 'B'SW pump and the '28'ore spray pump breakers was also determined to be high contact resistance of the motor cutout switch.
In April 1995, PPKL performed a review of previous events associated with breakers failing to close.
This review identified several cases where the cause of the breaker failures was attributed to problems with the motor cutout switch.
Additional investigation of the problem, with maintenance personnel
'nd the circuit breaker vendor, identified that the motor cutout switch operation was sensitive to minor dimensional tolerances that could result in inadequate contact between the moveable and stationary switch contacts.
At the time of the NRC inspection in October 1995, PPLL was continuing their root cause investigation for the problems associated with the 'C'SW pump circuit breaker.
Additional shop testing of the circuit breaker was planned to confirm the cause of the failure.
The preliminary result of the investigation was that the delayed closures resulted from alignment problems with the floor tripper mechanism.
PP8L's preliminary conclusion was that the tripper lever was in a position between the trip and reset, and the mechanical
1 7 agitation that occurred during circuit breaker operations resulted in spurious breaker trips due to the action of the. floor tripper lever.
The bases for the conclusion were:
An electrician observed that the floor tripper lever appeared to be higher than the spring release lever, indicating that the floor tripper lever was not clear of the floor cam plate, as it should be with the breaker racked-in.
I If the breaker was in a trip-free position when a close signal was initiated, the closing spring would release but the main and auxiliary breaker contacts would not close.
Without the auxiliary contacts operating, the anti-pump relay would not be energized and therefore as long as the closing circuit is maintained (by holding the push button),
the breaker would attempt to close as soon as the closing spring recharged.
Also, during the spring-charging sequence, the breaker trip would be reset, assuming the floor tripper lever was in a. "reset" position.
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The spring-charging motor recharges the spring in approximately three seconds.
This would account for the time delay.as the closing spring initially.released, the spring recharged (causing a reset of the breaker trip mechanism)
and then the spring released on a subsequent attempt and successfully closed the breaker.
No other breaker trip signals were present during the problems with the breaker operation.
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Troubleshooting of the control circuitry did not reveal any other time delays due to possible circuit component malfunctions.
The inspector found that the troubleshooting efforts and testing performed in July 1995 for the 'C'SW pump problem, with the circuit breaker in the test position, were reasonable.
However, the actual root cause was not identified at this time because intermittent problems caused by the floor tripper would only occur with the breaker fully racked in, and thereby make troubleshooting and identification of the root cause difficult. Also, since no other in-service breaker failures of this type had been experienced by PPRL, the floor tripper was not initially considered to be a possible cause of the problems.
As part of the root cause analyses for the September fail.ures, PP8L again reviewed the maintenance history for the 4. 16 kV breakers and found that since 1984 there were approximately nine in-service circuit breaker failure-to-close problems that were related to problems with the motor cutout switch.
Other problems with the motor cutout switches were identified during preventive maintenance activities and also resulted in the replacement of switches. 'n-
'ervice problems where the blue light indications were lost also occurred.
However, since the blue light is operated by a different set of contacts than the contacts that are in series with the closing coil, those problems did not result in a breaker operability concer During the root cause analyses, PP&L identified two conditions that could affect the proper operation of the motor cutout switches.
One finding was that there were three types of motor cutout switches installed in the breakers.
However, all three types had the same part number.
One difference between the three switch types was the dimension of the switch contacts.
In the most recent version of the switch, the normally-open contact dimensions were larger than the previous versions.
This results in an earlier closing of the contacts during the switch plunger travel, and a resultant increased spring force on the contacts for the same amount of switch plunger travel.
The more recent version of the switch also had slightly larger exterior dimensions that should result in an increase in the travel of the operating plungers (i.e.,
increased spring force on the contacts)
with the operating springs in the charged condition.
The second condition identified by PP8L that could affect the operation of the motor cutout switch was the size of a spring in the circuit breakers.
When the circuit breaker spring charges, the mechanical linkage, that operates the motor cutout switch plungers, depresses the switch plungers through the action of a spring.
PP8L has found that there are two different size springs installed in the breakers with one being larger than the 'other and having a
correspondingly higher spring for ce.
The higher spring force acting on the switch plungers results in a greater contact pressure between the moveable and normally-open contacts.
As was the case with the motor cutout 1'imit switches, both springs have the same part number.
4.6.3 Corrective Actions In April 1995, engineering requested that operations notify the maintenance department when breaker failures are encountered to permit troubleshooting of the problem before any actions are taken that may prevent the identification of the root cause of the failure.
In particular, troubleshooting should be
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performed prior to performing any actions such as racking the breaker out and then back into the switchgear.
(Racking the breakers out and back in had been found in some'ases to result in subsequent successful breaker operation.)
For circuit breakers whose closure was important during an accident or transient, such as emergency core cooling system pump breakers, this practice was generally not used to resolve problems.
In these cases, a spare breaker was installed and the affected breaker was repaired prior to subsequent installation into the switchgear.
The breaker maintenance procedure HT-GE-005, "Circuit Breaker and Switchgear Inspection and Maintenance 5 and 15 kV," was revised in April 1995, to permit the addition of shims between the switch and the breaker mounting surface to provide complete actuation of the switch contacts.
Directions for the lubrication of the sliding parts to eliminate excessive friction were also added by this change.
After the September failures, PP&L developed an inspection guide to inspect the motor cutoff switch to ensure that the switches were properly installed and had low contact resistance.
The guideline verified circuit continuity of the switch contacts with the plungers depressed to within 3/32 inches of full travel.
Then, with the switch installed in the circuit breaker and the spring
charged, the switch mounting was checked to verify that the plungers were depressed to within 1/16 inch or less of full travel.
Shims were inserted as necessary to achieve this configuration.
These checks and mounting adjustments ensured that there was at least 1/32 inch of over-travel of the switch plunger past a point where contact continuity had been verified and that the as-left contact resistances were less than one ohm.
The use of shims to optimize the mounting position of the switches had been reviewed and approved by the vendor.
PP&L plans to incorporate the more comprehensive inspection guideline switch checks with appropriate gC hold points into the maintenance procedure.
This would result in the checking of the motor cutout switch at least once every three years.
The inspection guideline also ensured that the larger style spring is installed and dimensional information on the floor tripper rails are collected for use in the root cause evaluation for the 'C'SW pump breaker failure.
Shortly after the September problem, PP&L expedited the purchase of replacement switches and springs, and established an aggressive schedule for the performance of the inspection and repair of all of the 4. 16 kV breakers.
The work on the circuit breakers was prioritized based on risk significance of the systems as developed in the Individual Plant Evaluation (IPE).
The replacement switches that were utilized were the later style with the larger dimension normally-open contacts.
PP&L also plans to (1) review the breaker 'maintenance procedure to assure that other problems identified in the breaker failure history are addressed in the preventive maintenance (PH) procedure, (2) review the breaker mechanism design to determine if design modifications would be appropriate to improve the breaker performance, (3) eliminate the practice of racking a breaker out and back in to resolve a failure-to-close problem, unless warranted by operating conditions, and (4) investigate the change in part design enhancements by the vendor that appear to have occurred without notification to PP&L.
PP&L provided information to other utilities on the motor cutout switch problems through the issuance of an operating experience report on the nuclear network.
Also, through information obtained from Westinghouse and several other utilities, PP&L found that the type of motor cutout switch used on the breakers at SSES was not commonly used in the industry.
This appears to be the result of the SSES switchgear design that incorporates the blue light
"Spring Charged" indication operated by a dedicated set of limit switch contacts.
4.6.4 NRC Review and Assessment The inspector discussed the circuit breaker problems with plant maintenance and engineering personnel, reviewed associated procedures and documents, and observed the performance of circuit breaker work utilizing the inspection guideline.
The inspector noted that the existing circuit breaker PH procedure checked the continuity of the motor cutout switch contacts with the switch removed from the circuit breaker and with the electrician depressing the switch plungers.
PP&L still needs to i'ncorporate the more comprehensive inspection guideline switch checks into the maintenance procedur Additionally, the results of the motor cutout switch checks showed that most of the older style switches failed the continuity test with the plunger depressed to the 3/32 inch point.
As a result, the new style switches were being installed in all of the circuit breakers, and more contact over-travel was achieved to improve contact continuity.
The inspector concluded that the licensee had appropriately investigated the cause of the circuit breaker failures and initiated corrective actions to prevent additional failures.
When the additional failures occurred in September 1995, the corrective 'actions were expanded to include a
comprehensive switch checkout and replacement, on an aggressive schedule to minimize the potential for additional failures.
The root cause analyses were thorough and identified appropriate recommended corrective actions to prevent recurrence.
Excellent communication and cooperation between the maintenance, operations, site engineering and corporate engineering departments was evident in the resolution of the circuit breaker failures.
5.
PLANT SUPPORT (71750, 71707, 92904)
5. 1 Radiological and Chemistry Controls During routine tours of both units, the inspectors observed the implementation of selected portions of PP&L's radiological controls program to ensure:
the utilization and compliance with radiological work permits (RWPs); detailed descriptions of radiological conditions; and personnel-adherence to RWP requirements.
The inspectors observed adequate controls of access to various radiologically controlled areas and use of personnel monitors and frisking methods upon exit from these areas.
Posting and control of radiation areas, contaminated areas and hot spots, and labelling and control of containers holding radioactive materials were verified to be in accordance with PP&L procedures.
Health Physics technician control and monitoring of these activities was sati.sfactory.
Overall, the inspector observed an acceptable level of performance and implementation of the radiological controls program.
5.2 Security PP&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.
The inspector reviewed access and egress controls throughout the period.
No significant observations were made.
6.
~SAFETY ASSESSMENT/EQUALITY VERIFICATION (90700, 90712)
6.1 Open Item (OI) Followup (Closed)
URI 50-387;388/93-18-01, Status Control Problems This item had been left unresolved due to continuing concerns that corrective actions to maintain control of valve positions (status control)
had not been fully effective.
At the time this item was opened, the NRC inspector had
reviewed various licensee self-assessment reports and previously issued NRC inspection reports that identified status control as an area of weakness.
In addition, the NRC inspector.identified seven more examples at the time that indicated status control was a continuing problem.
The inspector reviewed the licensee's corrective actions taken to improve performance in the areas of status control and permit and tagging, and concluded that the licensee's efforts have been effective.
The inspector noted that a number of programmatic changes have been implemented in the past two years.
A performance improvement team was formed by:the licensee to study the problem.
The team visited six plants that have good. status control programs.
As a result several procedures (NDAP-(A-0302, "System Status and Equipment Control" and NDAP-(A-0502, "Work Authorization System" ) were revised to tighten and improve equipment status controls.
Training was conducted on the changes prior to implementation.
The inspector reviewed the condition reports (CRs)
issued to date in 1995 and concluded the number of problems involving status control type problems has steadily decreased over the past several years indicating the licensee's corrective actions have had some positive impact (i.e., in 1995 there were a
total of twenty-eight status control problems identified as of late October, in 1994 there were fifty-three problems, and in 1992 and 1993 there were sixty-seven problems each year involving status control).
In addition, the inspector concluded that, in general, the 1995 CRs that were reviewed indicated an appropriate threshold for reporting and documenting problems, good root cause investigations, and appropriate corrective actions.
All but two of the twenty-eight 1995 CRs reviewed had very low to no safety significance.
The two problems identified by the inspector as having some potential safety significance included CR 95-181 which would have prevented full load shed, if the plant had,been operating,and off-site power had been
" lost, and CR 95-325 which involved a potential loss of instrument air pressure.
The inspector reviewed various independent assessments conducted by the licensee in the areas of status control and permit and tagging, and concluded that the licensee is attempting to self-audit and asses's performance in these areas on an regular basis.
The inspector noted that, in addition to the twenty-eight CR ite'ms reviewed, the licensee's quality control group identified one status control deviation in April 1995 during a final review of a work activity (CWA C50185) that left states links open that should have been closed as part of the modification package closeout.
Action was promptly taken at the time to close the links and investigate the cause for the incorrect actions.
The inspector further noted that the licensee's nuclear safety assessment group reviewed 30 maintenance activities in 1994 and
activities between October 2 6, 1995 with no identified status control problems for the work activities reviewed.
Finally, the inspector reviewed fifteen surveillance reports of maintenance and operations issued in 1995 by the nuclear assessment services group that reviewed performance in the areas of system status controls and permit and tagging and identified no weaknesse In summary, the inspector review concluded that the licensee'.s corrective actions taken to date to improve performance in the areas of status control and permit and tagging have been effective in decreasing the number of status control related problems.
However, the inspector further concluded that there's room for continued improvements in these areas.
The Manager of Operations agreed with the inspector's conclusions and was planning to reestablish an improvement review group before the end of the year to assess the effectiveness of the current programmatic controls with the objective of identifying opportunities for implementing additional improvements.
(Closed)
VIO 50-388/93-07-01, Unit 1 HPCI Turbine Exhaust Vacuum Breaker Test Valve closed but not locked, contrary to procedure and technical specification This problem was identified during as engineered safety feature walkdown of the unit 1 high pressure coolant injection (HPCI) system conducted by an NRC inspector.
The inspector reviewed the corrective actions taken by the licensee which included revision of nuclear training procedure (NTP-(A-32. 1),
"ASO/NPO Operator Training and gualification Program", operator training on existing procedural controls and expectations on valve locking.and status control, and demonstration of proper valve locking during operator rqqualification training.
The inspector concluded that these corrective actions were appropriate and noted that there was one problem documented to date in 1995 with a locked valve found out of the required position (CR 95-137).
Action was promptly taken at the time to correct the valve misposition and to investigate the cause for the incorrect actions.
6.2 Review Of Unit 2 Outage Schedule In preparation for the Unit 2 outage, the inspector reviewed the outage schedule to assess the licensee's plans for ECCS'vailability during operations with the potential for draining the reactor vessel (OPDRV).
PP8L's administrative controls for work scheduling require that ECCS technical specification (TS) limiting conditions for operation are satisfied and that an additional named backup for each function is identified and maintained operable/Functional for each outage time frame.
The licensee refers to this as their N+1 ECCS policy, where N is the number of TS required ECCS systems, In reviewing the Unit 2 7'" refueling outage schedule, the inspector noted that the 'B'ore spray system was designated as the
"ECCS Available" during an OPDRV created by replacement of 20 control rod drive mechanisms on September 27-29, 1995. 'uring this evolution the 'B'ore spray loop was the only high capacity system available for makeup to the reactor cavity, equipment laydown cavity, and connected spent fuel pools.
However, the
"ECCS Available" zone on the schedule also indicated that both the 'A'nd 'B'ore spray loops would be inoperable for twelve hours on September 27th for performance of SE-251-001, the Core Spray Division I Logic Functional Test.
'lthough TS did not require any ECCS to be operable during this time, the inspector questioned the licensee regarding this plan because of the risk associated with OPDRV evolutions and because it appeared contrary to PPLL's administrative requirement The licensee investigated the apparent conflict and determined that although the 'B'oop of core spray was not TS operable, it was available.
SE-251-001, inhibits the low reactor pressure permissive logic that effects both Divisions of CS, thus preventing the 'B'oop's injection valve from opening on an automatic 'signal.
However, operator training addresses the failure of the injection valve to open and operators can easily bypass the low pressure permissive from the main control board after checking indicated reactor pressure.
For this reason the 'B'oop was still considered available.
According to CR 95-0434, the issue was first recognized during the Unit 1 8'"
refueling outage, and was addressed through revision of administrative procedures.
The procedure revisions allowed use of a functional system, vice a TS operable system, to satisfy the backup system requirement.
The use of a functional system as a backup is reviewed by Operations management tu ensure that only reasonable operator actions are assumed and that sufficient guidance exists.
During a review in response to the inspector's questions, the licensee recognized that step 2.8 of NDAP-00-0612, Outage Scope And Schedule Development And Control, had been overlooked during the previous procedure changes.
Step 2.8, required that one loop of CS and its attendant systems be maintained operable.
This procedure was subsequently revised to be consistent with other administrative procedures, requiring the system to be
"operable/functional".
The inspector concluded that the licensee's policy on the availability of N+1 ECCS systems was more conservative than the TS requirements for ECCS systems during refueling outages.
The inspector had no further questions.
7.
REVIEW OF LICENSEE EVENT REPORTS (90712)
7. 1 Licensee Event Report Review The inspector reviewed Licensee Event Reports (LERs) submitted to the NRC office to verify that details of each event were clearly reported, including the accuracy of the description of the cause and the adequacy of corrective action.
The inspector considered whether further information was required from the licensee, and whether generic implications were involved.
Ins ection Followu In inspection report 95-12, the inspector identified a number of LERs in which PPKL had identified the need for supplemental information and which were not updated in a timely manner.
Subsequent to the inspection, the licensee indicated that it would review each of the items and issue supplemental LERs as required.
(URI 50-387; 388/95-12-02)
In discussions with the licensee, it.
was noted that the eight LERs identified in the inspection report had been reviewed and determined that all but three had been addressed by the submittal of supplemental LERs.
The three outstanding are Unit 1:94-008, which is expected to be supplemented by November, Unit 1: 94-015, which is expected to be supplemented early in 1996, and Unit 2: 93-008'which is expected to be
.
supplemented early in 199 The inspector reviewed three. of the eight supplemental LERs and found them to be adequate to close out each item from a tracking and technical perspective.
Unit
91-015-00 High pressure Coolant Injection System (HPCI) Inoperable On November 7, 1991, the HPCI was declared inoperable based on the failure of the quarterly Flow Surveillance.
Inspection revealed that the head of the ¹1 poppet (pilot valve)
had broken off.
The licensee replaced the broken poppet and also inspected the other fou} poppets and dye penetrant tested them as well.
This was the second broken poppet at Susquehanna, the first occurring in 1986.
The poppet was replaced, a satisfactory 'surveillance was conducted, and the HPCI was declared operable.
The licensee committed in the LER to conduct an engineering failure analysis of the poppet to determine the failure mode and the overall root cause.
This effort was to include a metallurgical evaluation as well as an evaluation of the procurement/manufacturing data.
The inspector reviewed a copy of the Significant Operating Occurrence Report
¹1-91-290 (ll/91, 7/93)
and noted that PP&L had developed a detailed work scope for the failure analysis in the 1991 timeframe and subsequently it was determined that the subject poppet had been mistakenly discarded.
In addition, the licensee also stated in the report that in 1991, industry feedback indicated that the instance's of poppet failure were limited to Susquehanna.
The licensee noted that the 1991 replacement poppet had a slightly different design.
At the location of the previous failure, the vendor had changed the design to include a curved transition between different stem diameters.
The inspector believed this slight change would relieve stress in this region, Subsequent to the 1991 replacement, no poppet valve failure had occurred at Susquehanna.
The inspector concluded no current safety concerns exists. at Susquehanna regarding this poppet valve failure.
On August 8, 1995, the licensee issued supplement 1 to LER 91-015 and included information indicating that the poppet had been inadvertently discarded and the failure analysis could not be performed.
The performance aspect of inadvertently discarding the failed poppet is discussed in Section 4.3 of this report.
The LER update was administrative in nature, and the issuance of the LER supplement closed out the item from a tracking standpoint.94-008 Class 1E 125 VDC, 250 VDC, and 480 VAC Load Centers Outside Dynamic Design Basis On March 21, 1994, the licensee'etermined that breaker lifting devices mounted on station class 1E 125 VDC and 250 VDC, and 480 VAC load centers caused each load center to be outside the dynamic (seismic and hydrodynamic)
qualification design basis.
The licensee prepared an Engineering Discrepancy Report (EDR)
and removed the lifting devices.
The Mar'ch 1994 operability assessment of the EDR verified that the load centers were outside their dynamic qualification design basis with the lifting devices installed, but both the AC and DC load centers were operable with the devices removed.
It
was also determined that the. lifting devices had been installed during the original construction per the design documents and had not been included in the dynamic analyses performed for the load centers.
In the LER it was stated that the drawings along with installation and operating manuals for the load centers would be revised to indicate that the lifting devices are not part of the load centers.
The licensee also committed to review other safety related
.
equipment.
On August 4, 1995, the licensee issued Supplement 1 to LER 94-008.
In that document it was stated that the drawings and manuals had been updated and a
review of other safety related equipment had been completed.
No additional safety related equipment was found to contain maintenance accessory equipment.94-012 Loss of Fire Detection/Suppression On August 2, 1994, the Fire Protection Simplex System was disabled (detection and fire suppression)
by a lightning strike.
The Technical Specification action statements were entered and compensatory measures were begun by the licensee.
Since a number of fire barriers were already inoperable because of the Thermo-Lag issue at the plant, continuous fire watches should have been begun within one hour after entering the action statement.
However, it was not determined until 0730 the next morning that continuous rather than hourly watches were required.
As indicated in.the LER, the root causes were inadequate action to prevent recurrence from previous events involving Simplex problems, mis-communication and inadequate communication during assessment of the impact.of the event and resulting required action.
Corrective actions included development of a comprehensive instruction, conduct of training for operations personnel, evaluation of potential improvements to fire protection TS, and a review of the Simplex system for design improvements.
A detailed discussion of licensee's corrective actions and NRC assessment are provided in inspection report 95-18.
On August 3, 1995, the licensee issued Supplement 1 to LER-94-012.
In that document the corrective action was updated to include emphasis on TS compliance.
The Supplement also indicated that management reviewed their expectations regarding communication with appropriate Nuclear Department personnel.
7.2 Response To NRC Bulletin 93-03 (TI 2515-128)
As a result of NRC Bulletin 93-03,
"Resolution of Issues to Reactor Vessel Water Level Instrumentation in BWRs", licensees were required to assure that non-condensible gas in the reactor vessel water level reference legs would not come out of solution and cause inaccurate reactor vessel level readings during a rapid de-pressurization event.
In response to this event, many licensees, including Susquehanna, installed "keep-fill" systems to the reference legs of reactor vessel level measuring systems.
In 1994, Susquehanna designed and installed a modified passive level system which included a vent line to each condensing chamber, and no longer required an active "keep-fill" system.
Further description of this design change is given belo PP8L modified the upper and lower condensing chambers of.their level instrumentation to reduce the concentration of non-condensible gas in the condensing chambers; thereby, reducing the concentration of non-condensible gas dissolved in the water in the reference legs.
The modification to the
.lower condensing chambers provided an un-insulated vent path to the variable leg.
The steam condensation in the vent leg induces flow from the condensing chamber to the vent path, which transfers non-condensible gases to the vent leg.
The non-condensible gases accumulate near the interface in the vent leg and dissolve in the vent leg.
There is a small flow of water from the vent leg to the variable leg which convects the dissolved non-condensible gases back to the reactor vessel.
This configuration prevents interaction between the incoming steam from the Reactor Pressure Vessel (RPV) to the condensing chamber and the condensate returning from the chamber.
This avoids stripping of non-condensible gases from the condensate return which could occur in the previous configuration causing the accumulation of non-condensible gases in the condensing chambers and reference legs.
The modification to the upper condensing chambers provides a continuous supply of steam through the condensing chamber which is"vented to the steam line.
This continuous flow of steam entrains non-condensible gases in the condensing chamber and transports them to the steam line which prevents accumulation of non-condensible gases in the condensing chamber and in the reference legs.
On August 9, 1994, NRR staff from projects and the reactor systems branch visited the corporate 'office of Pennsylvania Power
& Light (PP8,L)
Company in Allentown, Pennsylvania to conduct an inspection of the design change and sppporting files for the passive reactor vessel (condensing chamber)
instrumentation modification.
The inspection included a review of the
CFR 50.59 package including these following documents:
design inputs and considerations checklist, discussion of performance requirements, applied loads, compliance with R.G. 1.97, discussion of redundancy, diversity and separation, ALARA design review records, a detailed design description change, design review checklists, a
FSAR change request package, a safe shutdown compliance review, supporting calculation worksheets and summaries, design criteria for the modification, pre-,
and post-test requirements, review comment sheets and dispositions, and the safety evaluation report for the modification.
Based on its review, the staff found the design change'package to be complete, comprehensive, and in conformance with PP8L's procedure for developing safety evaluations, NDAP-gA-0726.
Specific observations=included:
The applied load analyses determined that the lower condenser pots could be subjected to a*potential feedwater or core spray LOCA and the upper pots could be subjected to RHR head spray or head vent breaks.
In the dociiments reviewed, the design was shown to accommodate such breaks or have sufficient diversity to maintain the required safety functions given the potential for breaks in the vicinity of installations.
PPKL determined that the modification would not,reduce the range or reliability of post accident monitoring instrumentation and the Regulatory Guide 1.97 instrumentation redundancy would not be affecte ~
Redundancy is provided; by employing two upper and two lower condensate pots.
~
Separation is achieved by'ocating the lower pots at opposite sides of the vessel.
Diversity is achieved by having the lower and upper pots rely on a different mechanism to prevent the buildup of non-condensible gases.
~
PP&L's ALARA reviews were performed well and were updated to reflect an increase in the total estimated dose based on additional effort required for installation in excess of that originally expected.
~
The design description packages reflected an accurate description of the modifications which were carried forth to an FSAR change package.
~
Design review checklists reflected detailed reviewer comments whi.ch were effectively tracked and disposed of by design and system staff.
~
PP8L completed extensive calculations of flow rates within the modified paths, the hydraulic time delay in the system, the vent line water levels, the ratios of surface areas of condensate chambers and vent lines.
A detailed set of test criteria were developed with sufficient conservatism.
The safety evaluation provides a detailed description of the system modifications with a sound rationale for the system changes and functions.
In Section D of the report, PPEL considers potential effects on safety functions and provides an adequate discussion of each scenario and sound justification for its finding of no safety impact 'with no need to modify the operating license.
Analyses and tests of the modifications were performed by PP8L and their contractors.
Sol Levy Inc. (SLI) provided an analysis of the current level instrumentation and the mechanism of non-condensible gas buildup, and proposed the vent modification 'to eliminate this concern.
SLI also performed an analysis to predict the performance of this new 'concept.
These analyses were independently reviewed by two consultants.
In addition, tests in support of the modifications were performed by Continuum Dynami.cs Inc. (CDI).
In addition to the review effort conducted by the NRC staff described above, a
member of Brookhaven National Laboratory staff under contract with the Commission conducted an independent review of the modifications, test descriptions and data, and selected analyses which also found the licensee's design change to be acceptable.
The inspectors reviewed the installation of the licensee's modification for compliance with NRC bulletin 93-03.
NRC Temporary Instruction (TI) 2515/128,
"Plant Hardware Modifications to Reactor Vessel Water Level Instrumentation (NRC bulletin 93-03)" was used as guidance for this inspection.
.28 was written assuming that licensees would install a "keep-fill" system to reactor vessel level reference leg condensing chambers to preclude the flashing of non condensible gases on a rapid de-pressurization.
In its original response to the bulletin, the licensee installed a "keep-fill" system.
However, the licensee later modified its condensing chambers to a new passive design as described above.
The "keep-fill" system, though still installed, has been permanently valved out.
Because Unit 2 was in an outage during this inspection, the Unit 2 modification installation was reviewed.
The inspector observed the narrow range condensing chamber s located in the containment and verified the installation of the new vent lines.
In addition, the installation of the vent lines to the wide range reference. leg was confirmed by observation of the reactor vessel head area.
New piping runs were installed as designed.
The inspector also verified that new piping was tested during the plant hydrostatic test.
In addition, the inspector verified that level instrumentation were re-calibrated using the new design without the "keep-fill"system being used.
Much of the inspection criteria of TI 2515/128 is concerned with the effects of a "keep-fill" system on plant safety and is, therefore, no longer applicable to Susquehanna.
Numerous exi.sting procedures were changed to delete references to the currently installed but no longer used "keep-fill" system.
The "keep-fill" system is permanently valved out.
The manual isolation valves to the narrow range condensing pots are welded open and these valves are 25'bove floor level precluding inadvertent shutting of these valves which could affect narrow range level safety functions.
Based on the above reviews, the licensee's response to NRC Bulletin 93-03 is considered acceptable and TI 2515/128 is closed.
8.
MANAGEMENT AND EXIT MEETINGS (71707)
8. 1 Resident Exit and Periodic Meetings The Resident Inspectors discussed the findings of this inspection with PP&L station management throughout the inspection period to ensure timely communication of emerging concerns.
At the conclusion of the reporting period, the Resident Inspectors conducted an exit meeting summarizing the preliminary findings of this inspection.
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
CFR 2.790 restrictions.
The licensee did not object to any of the findings of the inspection.
In order to integrate the NRC assessment of inspection results from all SALP functional areas, findings from Region based inspections have been included in this report.
Entrance meetings and exit debriefs were conducted by the Region based inspectors and attended by the Resident Inspector The NRC held an open public meeting on Systematic Assessment of Licensee Performance (SALP) with PP8L management on October 6, 1995.
A SALP report on Susquehanna performance was issued on September 20, 1995.
Representatives from the PPKL and NRC management,'public, and media were present.
A copy of the NRC presentation is attache U.S. NUCLEAR REGULATORY COMMISSION
REGION I
SYSTEMATIC ASSESSMENT OF LICENSEE PERFORMANCE (SALP)
SUSQUEHANNA
. ASSESSMENT PERIOD:
FEBRUARY 27, 1994-AUGUST 6, 1996 MANAGEMENTMEETING: OCTOBER 6, 1995 SUSQUEHANNA SLIDE t
SALP PROCESS OBJECTIVES INTEGRATED ASSESSMENT
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MEANINGFULDIALOGUE IDENTIFYSUPERIOR PERFORMERS
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ALLOCATIONOF NRC INSPECTION RESOURCES
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INFORM PUBLIC SUSQUEHANNA SLIDE 3
PERFORMANCE ANALYSISAREAS FOR OPERATING REACTORS A.
PLANTS OPERATIONS B.
ENGINEERING C.
MAINTENANCE D.
PLANT SVPPO,RT SVSQVEHANNA SLIDE 4
SUPERIOR PERFORMERS
~
REQUIREMENTS Category 1 in all 4 SALP function areas.
Contingent upon maintaining superior perform.
RESULTS SALP cycle extended to 24 months.
Reduction in NRC initiative inspection hours.
SUSQUEHANNA SLIDE 6
PLANT OPERATIONS
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OPERATORS PERFORMANCE IN THE CONTROL ROOM CONTINUED TO BE A STRENGTH
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OPERATIONS MANAGEMENTMAINTAINED STRONG INVOLVEMENTAND OVERSIGHT
~
SIGNIFICANTLYSTRENGTHENED MANAGEMENT CONTROL AND PRESENCE DURING REFUELING OUTAGE PREPARATION AND ACTIVITIES
~
REPETITIVE PROBLEMS WITH BLOCKED OPEN FIRE DOORS AND TIMELYPOSTING OF FIRE WATCHES WERE RESOLVED
.
SEVERAL MINOR EVENTS INDICATEDNEED FOR IMPROVEMENT IN COMMUNICATIONAND SELF-CHECKING
~
EVENT REVIEW TEAMS CONTINUE TO BE A POSITIVE INITIATIVE RATING:
CATEGORY 1 SUSQUEHANNA SLlDE 8
ENGINEERING
~
EXCELLENT MANAGEMENTINVOLVEMENTAND EFFECTIVE INDEPENDENT OVERSIGHT-INCLUDINGEARLY INVOLVEMENTIN EMERGING SAFETY AND PROGRAMMATICCONCERNS A NEW CONDITION REPORT PROGRAM IMPROVED UPON PAST PROBLEM-SOLVING ISSUES
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SUPERIOR QUALITYOF TECHNICALWORK AND EXCELLENT RESOLUTION OF SAFETY ISSUES
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ABILITYTO IDENTIFYSUBTLE, COMPLEX, AND RISK-SIGNIFICANTDESIGN ISSUES WAS A STRENGTH
~
ENGINEERING PERSONNEL WERE, WELL TRAINED AND KNOWLEDGEABLE ENHANCED GUIDANCE ON OPERABILITY DETERMINATIONADDRESSED WEAKNESSES OCCASIONALLYSEEN IN THIS AREA RATING:
CATEGORY 1 SUSQUEHANNA SLIDE 10
OVERALLCONCLUSION L
~
OVERALLPERFORMANCE IS SUPERIOR
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STRONG PERFORMANCE IN MAINTENANCE, ENGINEERING AND PLANT SUPPORT AREAS CONTINUED
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IMPROVED PERFORMANCE WAS NOTED IN OPERATIONS AREA
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GENERALLY EXCELLENT COMMUNICATION AMONG DEPARTMENTS, EFFECTIVE COORDINATION OF ACTIVITIES,AND STRONG EVIDENCE OF TEAMWORKIN RESOLVING SAFETY ISSUES
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THE NEW CONDITION REPORT PROCESS WAS A POSITIVE INITIATIVETO IMPROVE CORRECTIVE ACTION PROGRAM EFFECTlVENESS
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STRONG MANAGEMENTIMPROVEMENTAND.
EFFECTIVE TEAMWORK SUSQUEHANNA SLlDE 12