IR 05000387/1993013
| ML17157C525 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 10/20/1993 |
| From: | Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17157C524 | List: |
| References | |
| 50-387-93-13, 50-388-93-13, NUDOCS 9310280143 | |
| Download: ML17157C525 (29) | |
Text
UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION I
Inspection Report Nos.
50-387/93-13; 50-388/93-13 License Nos.
Pennsylvania Power and Light Company 2 North Ninth Str'eet Allentown, Pennsylvania 18101 Facility Name:
Inspection At:
Susquehanna Steam Electric Station Salem Township, Pennsylvania Inspection Conducted:
August 18, 1993 - October 4, 1993 Inspectors:
G. S. Barber, Senior Resident Inspector, SSES D. J. Mannai, Resident Inspec r, SSES
- 7 Approved By:
J.
hite, Chief eactor Projects Section No. 2A, f< wa p~
Date Ins ection Summa:
This inspection report documents routine and reactive inspections (during day and backshift hours) of station activities, including:
plant operations; surveillance and maintenance; engineering and technical support; plant support; and safety assessment/quality verification.
Findings and conclusions are summarized in the Executive Summary.
Details are provided in the full inspection report.
'I
'F310280143 931020 PDR ADOCK 05000387 G
EXECUTIVE SUMMARY Susquehanna Inspection Reports 50-387/93-13; 50-388/93-13 August 18, 1993
- October 4, 1993 Operations (30702, 71707, 71710)
The inspector observed the performance of the Unit 1 Main Turbine Torsional Vibration Testing and determined that the testing was performed in a safe controlled manner.
The licensee implemented recommendations from an INPO SOER that addressed performance problems with this test at another facility. Section 2.2.1 pertains.
During the period, the inspector identified that while the CRD system was out-of-service for tie in of a plant modification the available procedures for reactor vessel level make up did not address the current cold shutdown conditions.
Although operators were aware of the make up path, the fact that available procedures did not specifically address the circumstances was considered a weakness.
Once identified, the licensee took action to modify the existing procedure.
Section 2.2.2 pertains.
Maintenance/Surveillance (61726, 62703)
The licensee generally exercised good control of maintenance and surveillance activities.
h Engineering/Technical Support (71707, 92720, 93702)
During the period, an unplanned ESF actuation occurred when a Circle Seal solenoid operated valve failure resulted in a primary containment isolation valve closure.
The inspector reviewed licensee response to the failure.
The inspector concluded the corrective actions taken or planned were appropriate.
Section 4.2.1 pertains.
Safety Assessment/Assurance of Quality (40500, 90712, 92700, 92701)
During the period, the inspector reviewed licensee activities per Temporary Instruction (TI)
2500-28, Employee Concerns.
The licensee's procedure provides a framework to address employee concerns.
As a result of a recent third party audit, the licensee has agreed to reevaluate their existing program to increase its effectiveness and responsiveness.
This TI was closed.
Section 6.2 pertain TABLEOF CONTENTS EXECUTIVE SUMMARY
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SUMMARYOF OPERATIONS....
1.1 Inspection Activities ~......
1.2 Susquehanna Unit 1 Summary
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1.3 Susquehanna Unit 2 Summary
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OPERATIONS 2.1 Inspection Activities. ~....................
2.2 Inspection Findings and Review of Events 2.2.1 Unit 1 Main Turbine Torsional Test 2.2.2 Alternate Vessel Level Make-up..........
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3.4 Inspection Findings 4.
ENGINEERING/TECHNICALSUPPORT 4.1 4.2 Inspection Activity...................
Inspection Findings 4.2.1 Solenoid Operated Valve Failure MAINTENANCE/SURVEILLANCE 3,1 Maintenance and Surveillance Inspection Activity,.....,,
3.2 Maintenance Observations 3.3 Surveillance Observations
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PLANT SUPPORT........
5.1 Radiological Controls..
5.2 Emergency Preparedness 5.3 Security
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SAFETY ASSESSMENT/QUALITYVERIFICATION.................
6.1 Open Item (OI) Followup....... ~....... ~........ ~.....
6.2 (Closed) Temporary Instruction 2500/28, Employee Concerns Program
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MANAGEMENTAND EXIT MEETINGS.......................
7.1 Resident Exit and Periodic Meetings................ ~......
7.2 Inspections Conducted By Region Based Inspectors...... ~.......
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1.
SM1MARY OF OPERATIONS Details 1.1 Inspection Activities The purpose of this inspection was to assess licensee activities at Susquehanna Steam Electric Station (SSES) as they related to reactor safety and worker radiation protection.
Within each inspection area, the inspectors documented the specific purpose of the area under review, the scope of inspection activities and findings, along with appropriate conclusions.
This inspection included actual observation of licensee activities, interviews with licensee personnel, measurement of radiation levels, independent calculation, and selective review of applicable documents.
1.2 Susquehanna Unit 1 Summary Unit 1 began the inspection period in cold shutdown (Condition 4) in day 38 of a forced outage.
The forced outage was necessary to repair damage caused by bucket failure internal to the "C" low pressure turbine.
See NRC Region 1 Inspection Report 50-387/93-11 for details.
On August 25, the drywell vent inboard isolation valve closed while a purge of the drywell was underway.
This valve is a containment isolation valve and its closure constituted an engineered safety feature (ESF) actuation.
Section 4.2.1 pertains.
Also on August 25, the outboard isolation valve of Reactor Water Cleanup (RWCU) isolated on a high flow signal during the realignment of the suction source.
The licensee originally reported the event as an ESF actuation but, subsequent investigation has shown the event was an invalid ESF isolation of the RWCU system and, therefore, not reportable.
On August 28, the reactor was placed in Condition 2 at 10:36 a.m. and reached criticality at 11:40 p.m.
On August 29, the reactor was placed in Condition 1 at 4:55 p.m.
On August 31, the licensee synchronized the main generator to the grid three times, encountering problems each time.
The licensee identified a bad connector on the ¹3 control valve linear variable differential transformer (LVDT)and replaced it. No further oscillations were observed.
The main generator was finally synchronized to the grid on September 1.
The unit was returned to 100% power on September 5.
On September 12, the lA201 ESS bus was momentarily de-energized which resulted in the loss of the "A" reactor protection system (RPS), a division 1 half scram, Nuclear Steam Supply Shutoff System (NSSSS) isolations,'and an "A" diesel generator start.
The ESF actuations and isolations occurred as designed.
The 1A201 bus de-energized during the performance of SO-104-001, "Monthly Bus 1A201, 1A202, 1A203, 1A204, and OB565 Degraded Voltage Channel Functional Test."
Operators entered ON-104-201, "Loss of 4KV Bus 1A(1A201)." The licensee suspected that the test bypass of the 93% undervoltage ESS
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bus trip relay failed to function, The inspectors initial review of this event did not identify any unresolved or unaddressed safety issue.
The event constituted an unplanned ESF actuation.
The inspector will assess licensee root cause determinations and corrective actions during review of the Licensee Event Report (LER).
On September 21, the Reactor Core Isolation Cooling (RCIC) system steam line isolated during performance of excess flow check valve surveillance testing.
This constituted an unplanned Engineered Safety Feature (ESF) actuation.
The RCIC system was in the standby alignment at the time of the event.
The isolation occurred during restoration of the test and the exact cause was under investigation at the end of the inspection period.
The inspectors initial review of this event did not identify any unresolved or unaddressed safety issue.
The inspector will assess licensee root cause determination and corrective actions during review of the LER.
On September 24, the licensee commenced plant shutdown due to Technical Specification 3.0.3.
On September 24, the ECCS Low Pressure Permissive Switch B21-IN021D failed.
Instrumentation and Control (ISAAC) technicians determined the switch was in the tripped condition and the bellows had failed.
The failed switch rendered Division 2 LPCI mode of Residual Heat Removal (RHR) and Core Spray (CS) inoperable.
At 2:55 a.m., the licensee began reducing power to shut Unit 1 down.
By 7:43 a.m., the switch was replaced, tested and returned to service.
The licensee exited the TS action statement and stopped the plant shutdown.
Power remained at 25%.
The inspectors initial review of this event did not identify any unresolved or unaddressed safety issue.
The inspector willreview the licensee's root cause determination for the failed pressure switch during review of the LER.
On September 25 at 2:35 a.m., the main turbine generator was manually tripped for a scheduled refueling and inspection outage.
Operators manually scrammed the reactor from 20% power at 3:27 a.m.
The unit entered Condition 4, Cold Shutdown at 11:40 p.m.
Condition 5, Refueling was entered at 10:44 a.m. on September 27.
The unit remained in Condition 5 at the conclusion of the inspection period.
1.3 Susquehanna Unit 2 Summary Unit 2 began the inspection period at 100% power.
During August 26 through 29 and August 31, there were five small (1-4%) power reductions due to high condenser back pressure.
They varied in duration from two to eight hours due to high ambient temperature conditions.
Operators returned power to 100% as ambient conditions permitted.
On September 6, power w'as reduced for ten hours to as low as 92% due to a Minimum Generation Emergency implemented by the Power Control Center (PCC).
Power was returned to 100% on the same da On September 8, the "A" reactor recirculation pump tripped which resulted in a power reduction to 47%.
Operators immediately entered ON-264-002, "Loss of Reactor Recirculation Flow" and GO-200-009, "Single Recirculation Loop Operation."
The pump trip occurred when a cleaning person inadvertently bumped the motor/generator (M/G) set panel.
The cleaning person immediately notified the control room.
The Generator "C" Phase Overcurrent relay momentarily picked up, which resulted in a M/G set lockout.
The plant responded per design.
The pump was restarted and power was returned to 100% on September 9.
Operators conducted several other routine power reductions during the period to facilitate control rod pattern adjustments, surveillance testing, and maintenance.
No reactor scrams or ESF actuations occurred during the inspection period.
Unit 2 finished the period at 100%
power.
2.
OPERATIONS 2.1 Inspection Activities The inspectors verified that the facility was operated safely and in conformance with regulatory requirements.
Pennsylvania Power and Light (PP&L) Company management control was evaluated by direct observation of activities, tours of the facility, interviews and discussions with personnel, independent verification of safety system status and Limiting Conditions for Operation, and review of facility records.
These inspection activities were conducted in accordance with NRC inspection procedure 71707.
The inspectors performed 23.0 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> of deep backshift inspections during the period.
These deep backshift inspections covered licensee activities during between 10:00 p.m. and 6:00 a.m. on weekdays, and weekends and holidays.
2.2 Inspection Findings and Review of Events 2.2.1 Unit 1 Main Turbine Torsional Test The inspector observed the performance of the Unit 1 Main Turbine Torsional Vibration Testing.
The test was performed in accordance with TP-193-027.
The procedure was performed to validate the detuning of the Unit 1 turbine-generator system away from 120.4 Hz following the addition of the inertia ring. The installation of the inertia ring was initiated as a corrective action following the turbine trip on high vibration.
See NRC Inspection Report 50-387/93-11 for further details.
The licensee determined the testing was a special, infrequent complex test.
This designation implements stringent licensee administrative controls governing the activity. The briefing was conducted in accordance with the NDAP-QA-0020, Special Infrequent or Complex Tests/Evolutions.
The briefing stressed reactor safety as the priority. The activity manager
properly addressed briefing guidelines listed in the NDAP-QA-0020.
The briefing emphasized communications and clearly designated who was in charge and responsible for the test.
The inspector attended the briefing and concluded the briefing was well attended and understood by all personnel involved with the test.
The INPO Significant Operating Experience Report (SOER) that addressed the torsional test performance problems associated with this test at another facility was covered.
The inspector reviewed the INPO SOER and concluded the INPO recommendations were properly and effectively implemented, during the test at Susquehanna.
The inspector concluded the torsional testing was performed in a safe, controlled manner.
Personnel involved with the test were knowledgeable on the test procedure and were aware of their responsibilities.
Test personnel maintained excellent communications throughout the test.
The inspector identified one concern to the test director. The procedure required operating the turbine at 1900 rpm.
This is approximately 105.5% of rated speed.
This speed (1900 RPM) is close to the overspeed trip settings and the turbine is accelerated
RPM/minute by temporary control circuitry during the test.
The procedure did not contain any contingencies to take corrective actions ifthe speed went above 1900 to avoid challenging the overspeed protection devices.
This, also, was not discussed by the operators prior to operating the turbine at 1900 RPM.
When questioned by the inspector, the test director stated that operators would take action to prevent challenging the turbine overspeed protection systems, but to strengthen the procedure the licensee agreed to incorporate a procedural enhancement to address this issue for the Unit 2 torsional testing.
The licensee concluded that preliminary test data indicated that the turbine generator system was successfully detuned away from the natural resonant frequencies.
The inspector had no further questions.
2.2.2 Alternate Vessel Level Make-up On August 19, during a routine control room walkdown, the inspector observed that the Control Rod Drive (CRD) system was out-of-service to allow tie in of a reactor vessel water level backfill reference leg modification. With the CRD system out-of-service, the normal method of vessel level make-up was removed for Condition 4, cold shutdown conditions.
The inspector questioned operators on what method would be utilized and what procedures exist to govern reactor vessel make-up in this condition.
The operators stated condensate transfer through Residual Heat Removal (RHR) Shutdown Cooling Suction Fill would be used for alternate vessel makeup per OP-149-002 Section 3.10.
The inspector reviewed the procedure and noted that the prerequisite did not agree with the current plant conditions.
OP-149-002 prerequisites required Emergency Operating Procedures (EOPs) be entered prior to using this procedure to provide an alternate injection flow path.
The inspector determined the procedure did not cover the existing circumstances.
Thus, the inspector brought this to
the shift supervisor's attention.
The shift supervisor instructed an operations review which determined that a procedure change was required.
Operations prepared a procedural change to OP-149 (249)-002 Section 3.9 that allowed the use of RHR Shutdown Cooling Fill as an alternate vessel makeup during cold shutdown operations.
The inspector determined that the operators were aware of how to make up water to the vessel, ifrequired.
However, since the modification was planned and no specific procedure addressed the vessel make up path, the inspector considered this a weakness.
Once identified, the licensee took action to prepare an appropriate procedure.
The inspector had no further questions.
3.
MAINTENANCE/SURVEILLANCE 3.1 Maintenance and Surveillance Inspection Activity On a sampling basis, the inspector observed and/or reviewed selected surveillance and maintenance activities to ensure that specific programmatic elements described below were being met.
Details of this review are documented in the following sections.
3.2 Maintenance Observations
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The inspector observed and/or reviewed selected maintenance activities to determine that the work was conducted in accordance with approved procedures, regulatory guides, Technical Specifications, and industry codes or standards.
The following items were considered, as applicable, during this review:
Limiting Conditions for Operation were met while components or systems were removed from service; required administrative approvals were obtained prior to initiating the work; activities were accomplished using approved procedures 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.
These observations and/or reviews included:
WA 33394, Install Pipe Spool SP-DCD-121-1 to Control Rod Drive Master Control Station.
WA 33394, Install-Pipe Spool to Control Rod Drive Master Control Station for Reactor Water Level Modification, dated August 19.
WA 34336, Disassemble, clean, repair, reassemble Containment Instrument Gas (CIG) Pressure Control Valve PCV 1264 WA 37042, Replace Reactor Water Level Reference Leg Backfill Needle Valve HCV-142041 with New Valve, dated September 17.
WA 33598, Rebuild Hydraulic Control Unit (HCU) 14-19 Accumulator, dated October 4.
3.3 Surveillance Observations The inspector observed and/or reviewed the following surveillance tests to determine that the following criteria, ifapplicable to the specific test, were met:
the test conformed to Technical Specification 'requirements; administrative approvals and tagouts were obtained before initiating the surveillance; testing was accomplished by qualified personnel in accordance with an approved procedure; test instrumentation was calibrated; Limiting Conditions for Operations were met; test data was accurate and complete; removal and restoration of the affected components was properly accomplished; test results met Technical Specification and procedural requirements; deficiencies noted were reviewed and appropriately resolved; and the surveillance was completed at the required frequency.
These observations and/or reviews included:
SO-250-002, Quarterly Reactor Core Isolation Cooling Flow Verification, dated September 2.
SI-180-207, Eighteen Month Backfill of Reactor Water Level Condensing Pots, dated September 25.
SO-155-003, Eighteen Month Scram Discharge Volume Vent and Drain Valve Operability Check, dated September 25.
3.4 Inspection Findings The inspector reviewed the listed maintenance and surveillance activities.
The review noted that work was properly released before its commencement; that systems and components were properly tested before being returned to service and that surveillance and maintenance activities were conducted properly by qualified personnel.
Where questionable issues arose, the inspector verified that the licensee took the appropriate action before system/component operability was declared.
The inspectors had no further questions on the listed activitie.
ENGINEERING/TECHNICALSUPPORT 4.1 Inspection Activity The inspector periodically reviewed engineering and technical support activities during this inspection period.
The on-'site Nuclear Systems Engineering (NSE) organization, along with Nuclear Technology in Allentown, provided engineering resolution for problems during the inspection period.
NSE generally addressed the short term resolution of engineering problems; and interfaced with the Nuclear Modifications organization to schedule modifications and design changes, as appropriate, to provide long term corrective action.
The inspector verified that problem resolutions were thorough and directed at preventing recurrence.
In addition, the inspector reviewed short term actions to ensure that they provided reasonable assurance that safe operation could be maintained.
4.2 Inspection Findings 4.2.1 Solenoid Operated Valve Failure On August 25, the drywell vent inboard isolation valve (HV-15713) closed while a nitrogen purge of the drywell was in progress.
The valve is a primary containment isolation valve and its closure constituted an unplanned engineering safety feature (ESF) actuation, The licensee reported the condition in accordance with 10 CFR 50.72.
Licensee investigation revealed a failed solenoid operated valve on the valve actuator.
The valve is a Circle Seal AC solenoid operated valve (SOV). PP&L determined that no valid actuation signal caused the valve closure.
The licensee documented this event in Significant Operating Occurrence Report 93-249, The valve was disassembled and inspected.
Some signs of heat damage were present.
To attempt to determine the failure mechanisms, the licensee performed a bench test.
After it was energized, its coil temperature rose from 105'F to 258'F in five minutes, at which time the valve was deenergized.
Because of the excessive heatup, the licensee sent the valve to an independent laboratory for failure analysis.
Subsequent to the August 25 failure, the licensee experienced in-service failures of other dissimilar non-safety related AC Circle Seal solenoid valves.
These failures heightened licensee concern relative to current SOV performance.
The valve that failed was previously installed on August 20, 1993 and had been energized for approximately 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> when the valve failed.
This was the first installation of this model Circle Seal SOV at Susquehanna.
This model (NP30-2) was modified (diode rectifier bridge external to operating coil) to eliminate heat related failures experienced in an earlier model (SV31-9101-3) which had the diode rectifier bridge embedded in the coil.
Based on these failures and a previous history of problems with Circle Seal SOVs, the licensee formed an Event Review Team (ERT) to evaluate the failures and establish a plan for corrective actio The licensee witnessed vendor testing of the new design valves which included a 40 hour4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> burn-in test at the vendor facility. The licensee was concerned that the valve failed while operating for a very short duration.
The laboratory (Detroit Edison) concluded the failure of the solenoid valve was due to a breakdown of the core wire insulation.
The analysis did not determine the exact cause of insulation breakdown.
This may,be related to a new coil design installed by Circle Seal in SOVs produced after 1989.
The coil manufacturer changed fabric wrap, diode and epoxy for the operating coil in 1989.
The licensee indicated the post-1989 Circle Seal SOVs contain these coils.
Circle Seal stopped making the SV-31-9101-3 (internal diodes) with the post-1989 coil as they concluded this model was unreliable.
The licensee experienced a high failure rate of post-1989 SOV's during bench test and burn-in.
The licensee has experienced very few coil failures with the pre-1989 coil design.
The coil supplier to Circle Seal (Rodan) no longer makes the coil supplied with the pre-1989 Circle Seal SOV's.
The ERT recommended long term actions to obtain a reliable supply of solenoid valves.
These recommendations were to work with Circle Seal to resolve the recent coil failure problem and in parallel search for another acceptable SOV manufacturer.,Short term recommendations included having sufficient valves in stock to supply the current set of refueling outages.
The licensee has changed the acceptance criteria during factory functional test and burn-in to include hourly coil current and temperature readings.
The inspector reviewed the licensee's actions for this Circle Seal SOV failure and noted that the utilityprudently performed a post-failure inspection followed by a bench test to analyze the potential failure mode.
The independent lab identified the premature breakdown of the core wire insulation under normal duty as the cause of the failure.
This failure is of concern since it may have generic implications.
The licensee committed to submit an update to their LER providing details of their SOV failure analysis and additional corrective actions.
A history of design changes and associated problems with safety-related Circle Seal solenoid valves utilized at Susquehanna will also be included.
The licensee considered this failure of the model NP30-2 SOV an isolated case, however, given the previous Circle Seal SOV problems, the licensee is pursuing more comprehensive corrective actions.
Though this matter was reported in accordance with 10 CFR 50.72, the licensee is evaluating the need to report this condition in accordance with 10 CFR 21.
The inspectors continue to follow the licensee's actions on this matter.
5.
PLANT SUPPORT 5.1 Radiological Controls PP&L's compliance with the radiological protection program was verified on a periodic basis.
These inspection activities were conducted in accordance with NRC inspection procedure 71707.
Observations of radiological controls during maintenance activities and plant tours indicated that workers generally obeyed postings and Radiation Work Permit requirements.
No inadequacies were note.2 Emergency Preparedness The inspector reviewed licensee event notifications and reporting requirements for events that could have required entry into the emergency plan.
No events were identified that required emergency plan entry.
5.3 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/QUALITY VERIFlCATION 6.1 Open Item (OI) Followup (Closed) Unresolved Item 50-387/91-13-01, Fuel Pool Filter Demineralizer Backwashing Causes Large Area Contamination On August 12, 1991, the 749'nd 762'levations were contaminated during two consecutive Common Unit fuel pool cooling (FPC) filter demineralizer (FD) backwashes.
Operator error, and later an equipment malfunction, led to the pressurization of an inadvertently empty FD with instrument air, which resulted in larger than normal volumes of air blowing down to the FPC backwash receiving tank (BWRT). This air blew out the overflow of the BWRT into the radwaste floor drain, which forced residual contamination in the floor drain system to backup to the 749'nd 762'levations.
Drain traps prevented the contamination from spreading to other elevations.
The licensee decontaminated the area, found no unusual airborne activity in followup air samples, and confirmed that no individuals in the area that day received inhalation doses.
The item remained unresolved pending review of the licensee's causal analysis and corrective actions.
The licensee identified operator error as the cause of the first blowdown.
An operator manually advanced a program timer without being specifically authorized to do so by an approved procedure, contrary to OP-AD-001, Step 6.16.2.
This allowed the operator to perform a backwash on an empty FD, which resulted in the blowdown.
Operators received training not to advance the timer unless directed to do so in the procedure as a corrective action.
An equipment malfunction caused the second blowdown.
During the second backwash on August 12, the automatic timer skipped a step which fills the FD with water prior to pressurization, allowing the FD to be pressurized entirely with instrument air.
The licensee removed, bench tested, and reinstalled the agastat timer relay which controlled the skipped step and identified no problems.
The automatic timer performed properly when
cycled through all program steps under both static and dynamic conditions.
The licensee changed the backwash procedure to show approximate times to complete each program step and submitted a major modification proposal to upgrade the FD monitoring and control logic.
For the first blowdown event the inspector noted that a minor procedure violation resulted when an operator advanced a program timer manually.
However, this licensee-identified procedure violation is not being cited since it meets the criteria specified in Section VII.B. of the NRC enforcement policy.
On July 30, 1993, three elevations of the Unit 1 were contaminated during a Unit 1 FPC FD backwash.
See NRC Region 1 Inspection Report 50-387/93-11 for further details.
The licensee identified that system design, namely the use of pressurized air to move resin and water from the FD to the BWRT, and a partially blocked exhaust filter on the BWRT as the root causes.
The investigation of the 1991 incident did not reveal the system design problem because the 1991 incident involved abnormal backwashes and previous backwashes had been performed without incident.
As part of the corrective actions to the 1993 event, the licensee implemented compensatory actions for future FPC FD backwashes.
These actions included plugging the overflow floor drains and vacating previously affected elevations during backwashes.
The licensee will also evaluate the FPC system design for enhancements and evaluate whether gravity draining can be used during backwashes instead of the present pressurized blowdown.
The inspector concluded that corrective actions were adequate to address the equipment malfunction problem identified in 1991.
The inspector observed a
precoat following the July 30 event.
The operator used the procedure to perform the backwash and advanced the program timer under direction from the system engineer and after review by shift supervision.
The inspector concluded that operator's actions were appropriate.
The inspector questioned whether periodic cleaning of the floor drains would have mitigated the severity of the contaminations.
Based upon floor drain use, Health Physics responded that it was impractical to maintain the drains at a level of cleanliness sufficient to prevent contamination during blowdowns.
Since the root cause identification and corrective actions were appropriate in response to the 1993 event, and addressed the root
- causes identified in 1991, the inspector considered this item closed.
6.2 (Closed) Temporary Instruction 2500/28, Employee Concerns Program The purpose of this Temporary Instruction (TI) was to determine the characteristics of the licensee's employee concerns program (ECP) and to determine whether it provided an alternate path from line management to express potential safety issues or concerns without fear of retribution.
A survey was conducted and is attached for reference (Attachment 1).
The program was also reviewed to determine ifprovisions existed to minimize the potential
"chilling effect" that could result from a negative interaction between a concerned individual and the licensee.
The Energy Reorganization Act, Section 211 and 10 CFR 50.7 prohibit employers from discriminating against employees that raise safety concerns to the NRC or licensees.
The protection of "whistleblowers" is provided for in these statutes.
Thus, it is appropriate that licensee's have procedures and/or programs in place to address employee concern The licensee's current ECP program is provided by NDAP-AD-1510, Nuclear Safety Allegations and Concerns of Individuals.
This program was updated from an earlier program (NDI-9.2.1, Rev. 0, Handling of Nuclear Safety Allegations and Concerns of Individuals)
that was written in 1989 to provide a formal and consistent methodology for addressing employee concerns.
The original procedure was written after a number of discussions between NRC and PP&L in order to ensure a common approach to the resolution of safety concerns.
The licensee's ECP procedure (NDAP-QA-1510) defines an allegation as an issue raised by an individual that must satisfy three criteria:
1) involve nuclear safety, 2) involve a deviation from a standard or a requirement, and 3) bypass the normal chain of command.
A concern is defined as a nuclear safety issue that is processed by line management.
This procedure encourages employees to report their concerns directly to their immediate supervisor.
However, ifconcerned individuals are not satisfied with line management's resolution, they are encouraged to contact either a Designated Manager or a member of the Nuclear Safety Assessment (NSAG) Group.
Per the procedure, the NRC may be contacted at any time in the process.
The procedure does not address administrative, personnel, or non-safety-related allegations or concerns.
These are addressed by other internal policies and procedures.
The procedure may be used by either utility employees or contractors.
The ECP is administered by the Manager-NSAG who reports directly to the Senior Vice President - Nuclear.
The NSAG Supervisor assists, as necessary.
Resolution of allegations is assigned to line management with NSAG coordinating and validating the responses.
Designated managers may take independent action to resolve an allegation or may forward it to the manager - NSAG.
Confidentiality may be requested, and, ifso, precautions willbe taken to protect the alleger's identity throughout the resolution process.
Except for anonymous allegations, the Manager-NSAG is required to inform the alleger of the resolution of their allegation.
Per the procedure, resolutions of anonymous concerns are not published.
The licensee has tracked the status of allegation for a number of years.
There were a total of twelve allegations received during 1990, 1991, and 1992, all of which were closed.
There were five 1993 allegations, three of which are closed.
The licensee trends this information and discusses it during their Susquehanna Review Committee (SRC) meetings.
There are no internal audits of the program.
However, on their own initiative, the licensee contracted a
third party (Synergy, Inc.) to conduct a comprehensive evaluation of their ECP.
The third party audit began in July 1993 with a number of individuals (approximately 70 people) being interviewed.
On August 3, the results of these interviews were reviewed by 20 individuals selected to evaluate the results.
This group concluded that the basic program was sound, but certain improvements were needed.
These included, but were not limited to, recommendations for additional staffing and training requirements, procedure revisions, and the removal of natural and perceived communications barriers.
On October 15, the task team that generated these recommendations is scheduled to present them to both the Strategic Management Team (SMT) and the Operating Management Team (OMT). Final recommendations are expected to be in place by the end of the yea The inspector reviewed the licensee procedure for addressing employee concerns (NDAP-QA-1510) and discussed it in detail with cognizant licensee personnel.
In addition, the inspector reviewed the third party evaluation and the task team's report to assess their scope, findings, and recommendations.
Through this review, the inspector noted that the licensee expended significant discretionary resources to understand the effectiveness of their ECP.
Over the last several years, the inspector determined that corporate management has actively worked to foster an environment that is receptive to safety concerns.
The licensee has monitored and trended allegations since 1985 and has resolved them in a timely manner.
In 1991, the licensee hired an expert in alleger psychology to conduct training to the organization.
This training emphasized the importance of the initial contact with an alleger, and encouraged non-threatening and non-judgmental behaviors.
The recent third party audit concluded that the safety culture at PP8.L was very good.
However, the ECP was only considered adequate.
The task team also noted that ECP feedback was weak.
The inspector concurred with this finding. Except for one recent allegation, the feedback to individuals has been very minimal and, in some cases, was insufficient to prove that their concerns were being taken seriously by the licensee.
In another case, feedback appeared to polarize the interaction between two individuals and the licensee.
The inspector noted that the licensee does not have a mechanism to respond to anonymous allegations nor are the bulletin boards used to indicate how concerns are resolved.
This item willbe addressed in the licensee's program revision scheduled to be completed by the end of the year.
The licensee plans to address the following concerns during their upcoming program revision.
Improve initial contact between concerned individuals and their supervisors and/or ECP staff for line management or independent safety concerns.
Focus on the issue and not the individual.
Ensure the initial contact is non-threatening and non-judgmental.
Consider periodic updates to concern'ed individuals.
Revise the current ECP posting to lower the point of contact from a senior vice president or corporate manager level to a working level or senior engineer level.
Consider removing the responsibilities of the Designated Manager from the ECP posting and from NDAP-QA-1510. This should minimize the potential intimidation of concerned individuals.
Improve feedback to concerned individuals for in-process concerns and allegations.
Consider using postings or the newsletter to publish the resolution of anonymous concerns.
The inspector reviewed the licensee's program improvement plan for these and other items and had no additional comments.
This TI is close.
MANAGEMENTAND EXIT MEETINGS 7e1 Resident Exit and Periodic Meetings The inspector discussed the findings of this inspection with station management throughout and at the conclusion of the inspection period.
Based on NRC Region I review of this report and discussions held with licensee representatives, it was determined that this report does not contain information subject to 10 CFR 2.790 restrictions.
7e2 Inspections Conducted By Region Based Inspectors Date 08/23 - 08/27/93 09/27 - 10/01/93
~Sub'ect Radiological Effluents Monitoring Status Control
~Ins ecti n
~Re ort N
.
93-16 93-18
~Re ortin
~ins ector J. Jang C. Sisco
ATTACHMENT 1 EMPL YEE C NCERNS PROGRAMS PLANT NAME: Susquehanna LICENSEE: PP&L DOCKET ¹:50-387, 50-388 NOTE:
Please circle yes or no ifapplicable and add comments in the space provided.
A.
PROGRAM:
1.
Does the licensee have an employee concerns program?
(Yes) NDAP-AD-1510, Nuclear Safety Allegations and Concerns of Individuals 2.
Has NRC inspected the program?
NO, however earlier resident inspections provided the genesis of the original safety concerns procedure in 1989.
B.
SCOPE: (Circle all that apply)
1 ~
Is it for:
a.
Technical? (Yes)
b.
Administrative? (No)
c.
Personnel issues?
(No)
2.
Does it cover safety as well as non-safety issues?
(No) The issues must involve nuclear safety or a deviation from a standard or requirement.
3, Is it designed for:
a.
Nuclear safety? (Yes)
b.
Personal safety? (No) Separate program pertains c.
Personnel issues - including union grievances?
(No) Separate program pertains
4.
Does the program apply to all licensee employees?
(Yes)
5.
Contractors?
(Yes)
6.
Does the licensee require its contractors and their subs to have a similar program?
(No)
7.
Does the licensee conduct an exit interview upon terminating employees asking ifthey have any safety concerns?
(Yes)
INDEPENDENCE:
1.
What is the title of the person in charge?
Manager, Nuclear Safety Assessment Group (NSAG)
2.
Who do they report to?
Senior Vice President-Nuclear 3.
Are they independent of line management?
4.
Does the ECP use third party consultants?
Yes, but only to provide assessment of the process.'hird party entities are not typically used to perform actual employee concern assessment How is a concern about a manager or vice president followed up?
Though not formally described by the procedure, the licensee indicates that such matters would be handled by referral to either the next higher level of management, the PP8cL Corporate Auditing Group, or the Board of Directors, depending on the level of management and nature of the assertion.
D.
RESOURCES:
What is the size of the staff devoted to this program?
There is no dedicated employee concerns staff.
One NSAG manager, and one NSAG supervisor are used to coordinate activities; others are assigned as necessary depending on the nature and volume of concerns.
2.
What are ECP staff qualifications (technical training, interviewing training, investigator training, other)?
Again, there is no ECP staff.
The NSAG manager has 35 years of nuclear operating, management, and technical experience; and is degreed in engineering.
The NSAG supervisor nuclear operating, management, and technical experience; and is degreed in engineering.
No specific qualifications relative to ECP are currently required.
However, the individuals have been trained in the resolution of Engineering Deficiency Reports, which could involve employee concern as the basis of the EDR.
E.
REFERRALS:
1.
Who has followup on concerns (ECP staff, line management, other)?
Line management has the responsibility for actual review; NSAG coordinates the process, tracks resolution of the concern, and reports result F.
CONFIDENTIALITY:
1.
Are the reports confidential?
Confidentiality is maintained, but not strictly. The status of allegations is periodically discussed in'the Susquehanna Review Committee ( the Off-site Safety Review Committee).
However, the identity of the alleger is not revealed in these discussions and is not normally released.
2.
Who is the identity of the alleger made known to (senior management, ECP staff, line management, other)?
Disclosure of identity is intentionally limited by the NSAG.
Senior management may be informed of the identity, but line management would not normally be informed.
Identity is normally restricted to a need-to-know basis.
3.
Can employees be:
a.
Anonymous? (Yes)
b.
Report by phone? (Yes)
G.
FEEDBACK:
1.
Is feedback given to the alleger upon completion of the followup?
(Yes)
Either verbal or written feedback (or both) is provided.
2.
3.
Does the program reward good ideas?
NO Who, or at what level, makes the final decision of resolution?
Usually, the NSAG manager.
However, though not usual, the final decision may be modified by the Susquehanna Review Committee in some cases.
4.
Are the resolutions of anonymous concerns disseminated?
NO
5.
Are resolutions of valid concerns publicized (newsletter, bulletin board, all hands meeting, other)?
NO H.
EFFECTIVENESS:
1.
How does the licensee measure the effectiveness of the program?
Statistical analysis, Susquehanna Review Committee assessments, third party assessments 2.
Are concerns:
a.
Trended?
(Yes)
b.
Used? (Yes)
3.
In the last three years how many concerns were raised?
Of the concerns raised, how many were closed?
What percentage were substantiated?
YEAR RCV'D BY PPEcL UNSUBSTANTIATED NO SAFETY SIGNIFICANCE VALIDATED CLOSED 1990 1992 TOTAL
2
21 4.
How are followup techniques used to measure effectiveness (random survey, interviews, other)?
Random surveys, external reviews, third party assessment of effectiveness are accomplished.
Results and recommendations are factored into the progra.
How frequently are internal audits of the ECP conducted and by whom?
There are no prescribed audits of the process.
Only periodic self-assessment efforts have been performed.
About four such efforts have been accomplished to date.
I.
ADMINISTRATION/TRAINING:
1.
Is ECP prescribed by a procedure?
(Yes) NDAP-AD-1510, Nuclear Safety Allegations and Concerns of Individuals.
The procedure (and predecessor procedures)
has been in effect for the last four years.
2.
How are employees, as well as contractors, made aware of this program (training, newsletter, bulletin board, other)?
Bulletin Board postings (Nuclear Safety Concerns)
and the PP&L Newsletter (Nuclear Notes)
ADDITIONALC MiVIKNT:
(Including characteristics which make the program especially effective, ifany.)
Details are included in the Inspection Report on this subject.
The licensee is currently re-evaluating the policy and process.
Consideration is being given to the development on a dedicated ECP staff to act as advocates for raised concerns and assure objective resolution.
Additionally, specific development of special skills and ECP training is being considered to enhance the effectiveness of the existing program.
NAME: Scott Barber (John White) TITLE: Senior Resident Inspector (Section Chief)
PHONE ¹: 717-542-2134 (215-337-5114)
DATE COMPLETED: September 9, 1993