IR 05000352/1997006
| ML20210N995 | |
| Person / Time | |
|---|---|
| Site: | Limerick  |
| Issue date: | 08/13/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20210N984 | List: |
| References | |
| 50-352-97-06, 50-352-97-6, 50-353-97-06, 50-353-97-6, NUDOCS 9708260229 | |
| Download: ML20210N995 (46) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket No License No NPF 39 NPF 85 Report No Licensee: PECO Energy Facilities: Limerick Generating Station, Units 1 and 2 Location: Wayne, PA 19087 0195 Dates: May 28,1997 through July 21,1997 Inspectors: N. S. Perry, Senior Resident inspector F. P. Bonnett, Resident inspector L. M. Harrison, Reactor Engineer Approved by: Paul D._Swetland, Chief Projects Branch 4 9708260229 970813 PDR ADOCK 05000352
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TABLE OF CONTENTS Summary of Pla nt St at u s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1. O pe r a t io n s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-01 Condu ct of Ope r ations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 01.1 General Comments (71707) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 01.2 Electro Hydraulic Control System Malfunction Unit 2 . . . . . . . . . . . . . 2 01.3 Feedwater Heater Isolation Unit 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 01.4 Manual Shutdown to Replace Safety Reflef Valves Unit 1. . . . . . . . . . 4 02 Operational Status of Facilities and Equipment . . . . . . . . . . . . . . . . . . . . . . . . 6 02.1 Routine Plant Tours (71707) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 03 Operations Procedures and Documentation .......................... 6 03.1 - Reactor Core Isolation Cooling Isolation - Unit 2 . . . . . . . . . . . . . . . . . 6 07- Quality Assurance In Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 07.1 - Self Assessment Activities (71707) . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 08 Miscellaneous Operations issues (90712) ......,.................... 8 08.1 (Closed) LER, 2 97-005, Licensed Thermal Powsr Limit Exceeded Due to EHC Malfunction ..................................... 8 08.2 (Closed) LER 2 97-006, Closure of the Reactor Core isolation Cooling Containment bolation Valves Caused by Personnel Error . . . . . . . . . . . . 8 ll . M aint e n a n c e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 M1 Conduct of Maintenance ....................................... 9 M1.1 General Comments on Maintenance Activities (62707) . . . . . . . . . . . . . 9 M1.2 General Comments on Surveillance Activities (61726) ............. 9 M8 Miscellaneous Maintenance Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 M8.1 Impro.ner Demineralizer Assembly (62707,71750) .............. 10 lli. Engineering .................................................. 11 El Conduct of Engineering (37 551) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 E Emergency Service Water Pipe Repair - Unit 1 ..................-11 E1.2 Emergency Diesel Generator Test Failure . . . . . . . . . . . . . . . . . . . . . 12 E8 Miscellaneous Engineering issues (97012, 92903) . . . . . . . . . . . . . . . . . . . . 13 E (Closed) LER 1 97 005, & Revision 1, Reactor. Water Clean-up Isolations, Caused by Lifting of a Filter Demineralizer Pressure Safety Valve............................................... 13 il
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E8.2 (Closed) LER 2 97 003 Several Main Steam Syster.1 Seiety Relief Valves Having Setpoint Drift .................... ......... 13 E8.3 (Closed) VIO 50 353/97 01 01, Failure to Perform a 10 CFR 50.59 Review of a Modification to the Fuel Preparation Machine . . . . . . . . . . 13 l V. Pl a nt S u p p o r t . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 R1 Radiological Protection and Chemistry (RP&C) Controls . . . . . . . . . . . . . . . . . 14 R1.1 Chemistry RHR Heat Exchanger Potential Tube Leak . . . . . . . . . . . . . 14 R8 Miscella ne ou s i s sue s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 R8.1 (Closed) LER 2 97 004, Offgas System Grab Sample Obtained Late (90712) ............................................. 15 F8.1 (Closed) LER 196 015, URI 96 06 01 Failure to Maintain Equipment Needed for Operator Actions to Assure Fire Safe Shutdown Capability (90712, 92904) ....................................... 16 F8.2 -(Closed) eel 96 10 03, Fire Safe Shutdewn Analysis Error (92904) ......................................... 16 P5 Staf f Training and Qualification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 P Emergency Preparedness Drill (71750) ....................... 17 V. M a n agement Me eting s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17-X1 Exit Meeting Summ ary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 X2 Review of UFS AR Commitments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 X3- Pre-deelslonal Enforcement Conference . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 INSPECTION PROCEDURES USED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
. ITEMS OPENED, CLOSED,- AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 LIST O F ACRO NY M S U S E D . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
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EXECUTIVE SUMMARY Limerick Generating Station, Units 1 & 2 NRC Inspection Report 50 352/97 00, 50-353/97 06 This integrated inspection included aspects of PECO Energy operations, engineering, inalntenance, and plant support. The report covers an 8 week period of resident inspectio Ooorations
- Unit 2 underwent a reactor pressure transient and thermal power increase due to an unexplained transient in the electro hydraulic control (EHC) system. The thermal power transient resulted in the unit momei.tarily exceeding its licensed thermal power limit. Further, an undetermined ground in the balance of plant DC battery system occurred simultaneously. Engineering dernonstrated very good troubleshooting efforts in determining that the DC system ground was independent from the EHC system anomalies. Temporary monitoring equipment remained installed to provide additional troubleshooting data should a similar transient occu (Section 01.2)
- Operators responded well to a feedwater heater (FWH) isolation and transient, taking proper precautions by lowering power in the event of the further loss of FWHs, Troubleshooting revealed that the cause of the transient was a faulty drain valve positioner and the dump valvo controller needed recalibration (Section 01.3).
- The station staff demonstrated a conservative and safe approach to address increased leakage in a main steam line safety relief valve. The maintenance activities associated with the resultant forced outage were performed well and safely (Section 01.4).
- During a tag clearance restoration, a reactor operator failed to operate the reactor core isolation cooling system in accordance with the specified procedure. This resulted in an inadvertent engineered safety feature actuation and isolation of the system. Specific guidance for the use of approved procedures during tagging restoration was available in several Operations Department documents, but was not utilized in this case. (Section 03.1).
Maintenance
- Observed maintenance activities were conducted well using approved procedures, and were completed with satisfactory results. Communications between the various work and support groups were good, and supervisor oversight was good (Section M1.1).
- Observed surveillance tests were conducted well using approved procedures, and were completed with satisfactory results. Communications between the various work and support groups were good, and supervisor oversight was good (Section M1.2),
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Enalneerina e Work activities to repair several pinhole leaks in the 1B emergency service water (ESW) system were performed well. The engineering evaluation, planning and implementation of the activities were very good (Section E1.1).
- Operations, maintenance and engineering personnel appropriately addressed a D21 cmergency diesel generator (EDG) test failure. The final root cause and corrective actions will be reviewed after the required special report is submitted. (Section E1.2)
Plant Suos.gn e There was inadequate evidence to conclude whether or not a residual heat removal heat exchanger (RHRHX) tube leak existed in late 1993. Therefore, na change to the UFSAR or other documents was required to be made. However, engineering performed an analysis,2 months after the occurrence, which indicated that minor leakage would be acceptable. Given the uncertainty of the existence of a leak, this review should have been perforrned earlier. (Section R1.1)
e in March 1993, plant management incorrectly concluded that a late chemistry compensatory grab sample was not reportable as a violation of technical specifications, as required by 10 CFR 60,73. Corrective actions for this event were subsequently deleted and another similar event occurred in March 1996. Had a licensee event report been submitted with more permer,ent corrective actions for the first event, the second occurrence would likely have been prevented. (Section R8.1)
- An instance was identified where plant personnel identified that certain equipment required to assure fire safe shutdown capability had not been in place since initial operation of Unit 2. Specifically, an electrical jumper cable, several battery powered lighting units, and a radio microphone were missing. This resulted in an apparent violation of License Condition 2.C.(3) (Section F8.1).
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Reoort Details Summarv of Plant stalua Unit 1 began the inspection period operating at 100 percent power. The unit remained at full power throughout the inspection period with the exception of power reductions for testing and the following events:-
o June 14 Operators reduced reactor power to 70 percent following a loss of feedwater heating caused by the isolation of the SA feedwater heater (FWH). Aftor correcting the fault, the unit returned to 100 percent power on June 1 o June 22 Operators manually shut down the unit to replace two safety relief valves (SRVs) that demonstrated indications of pilot seat leakag The unit remained in a forced outage until the operators made the reactor critical on June 26, and returned the unit to 100 percent power operations on June 2 Unit 2 began the inspection period operating at 100 percent power. The unit remained at full power throughout the inspection period with the following exceptions:
e June 5 Operators reduced reactor power to 23 percent following an unexpected perturbation in the electro hydraulic control (EHC) system that resulted in eight turbine bypass valves opening. Operators maintained power less then 25 percent while troubleshooting was performed, e June 7 Operators raised reactor power to 80 percent. The engineering staff determined that reactor power would not exceed any thermallimit at this power level should the EHC perturbation recu o June 10 Operators raised reactor power to 92 percent. Engineering continued to monitor EHC system performance then power was raised to 100 percent on June 1 o June 12 Operators manually reduced reactor power to 60 percent to perform a rod pattern adjustment, to perform rod scram t; ming, and for several maintenance activitie _ _ _ _ _ _ - _ _ _ _ _
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LQpaudinna 01 conduct of Operations'
01.1 General Comments (71707)
Using Inspection Procedure 71707, the ir.spectors conducted frequent reviews of ongoing plant operations. In general, PECO Energy's conduct of operations was professional and safety consciou .2 Electro Hvdraulle Control System Malfunction Unit 2
. Scope (71707)
On June 5, eight turbine bypass valves cycled open and then closed as a result of an unexpected control signal anomaly in the electro-hydraulic control (EHCl syste As a result, reactor power momentarily exceeded tte maximum licensed power level. Operators responded to stabilize the plant using Operation Transient Procedures OT 102, High Reactor Pressure, and OT 104, Reactivity Addition; then reduced reactor power to 23 percent and maintained power less than 25 percent while investigating the cause of the event. The inspector reviewed the event and observed portions of the operators' response and the engineering follow up
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activitie Observations and Findinas During the transient, reactor power (neutron flux) reached 108 percent as indicated on the average power range monitor (APRM) recorders and process compute Reactor engineers determined that the maximum heat flux in the core reached 102.4 percent of rated thermal power, exceeding the Unit 2 license limit of 102 percent. The system manager troubleshooting the event determined that in the EHC logic system, the turbine control valve (TCV) demand signal decreased to zero causing the TCVs to start closing. The EHC logic system opened the turbine bypass valves to compensate for the increasing reactor pressure caused by the TCV closure. The TCV demand signal returned to normal after approximately three seconds and the TCVs re-opene Control room operators noted that an intermittent balance of plant (BOP) battery ground alarm occurred coincident with the EHC anomaly. Site engineering conducted an extensive review of the Unit 2 non safeguards 125/250VDC system--
for possible causes for the evant. Plant technicians installed monitoring equipment
' Topical headings such as 01, M8, etc., are used in accordance with the NRC standardized reactor inspection report outline. Individual reports are not expected to address all outline topic _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
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to record any subsequent BOP DC system grounds or EHC system anomalies. The system manager was not able to determine the cause of the perturbations on the DC bus, but concluded that the battery and EHC problems were mdependent since no further EHC transients recurred during subsequent battery ground EHC troubleshooting revealed no card or relay problems. The system manager installed, via a temporary plant alteration (TPA), a recorder to monitor the EHC logic card and relay performance for anomalies. No further problems were experience The temporary monitoring equipment remained installed to provide data if a similar translent occurs. A troubleshooting and diagnostic plan will be developed based on the information obtained. The plant operators raised the unit to 80 percent power while troubleshooting activities continued. This provided additional margin to technical specification (TS) and scram limits and assured that the 102 percent power limit would not be exceeded should the transient recur. Operators eventually raised power to 100 percen The inspector determined that the EHC transient caused a reactor pressure spike that resulted in the unit exceeding the thermal power limit specified by the Facility License Condition 2.C.1. -This violation resulted from circumstances not within licensee control, (e.g. the equipment failure could not have been avoided or detected by reasonable licensee quality assurance or management control measures), and therefore is not being cited, consistent with section VI.A. of the NRC Enforcement Policy, Conclusions
Unit 2 underwent a reactor pressure transient and thermal power increase due to an unexplained transient in the EHC system. The thermal power transient resulted in the unit momentarily exceeding its licensed thermal power limit. Further, an undetermined ground in the BOP DC battery system occurred simultaneousl Engineering demonstrated very good troubleshooting efforts in determining that the DC system ground was independent from the EHC system anomalles. Temporary monitoring equipment remained installed to provide additional troubleshooting data should a similar transient occu .3 Feedwater Heater isolation - Unit 1 Scooe (71707)
The Unit 1 SA feedwater heater (FWH) isolated on June 14, due to a faulty drain valve positioner. The FWH isolation caused a loss of feedwater heating and positive reactivity addition transient. The control room operators entered OT 104, Reactivity Addition, and reduced reactor power to 70 percent in accordance with the Reactor Maneuvering Shutdown Instruction (RMSI). The inspector reviewed the event, operators actions, and corrective actions implemented to prevent recurrence, i
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4 Observations and Findings The operators initially reduced reactor power to 95 percent, but further reduced power to 70 percent in anticipation of having to remove a low pressure FWH string from service. The operators performed this evolution in a controlled manner using the appropriate procedures. Shift management called engineering to provide troubleshonting assistanc The SA FWH isolated due to a high high level condition caused by the drain valve, LV C 004109A, not fully opening and the FWH dump valve not opening fast enough to compensate for the FWH levelincrease. Troubleshooting revealed that the positioner for the drain valve was faulty, which prevented the drain valve from fully opening. Technicians found that the drain valve operated satisfactorily when the positioner was placed in the bypass mode of operation, which sends the controller signal directly to the valve actuato Due to the drain valvt; being located in a high radiation area, the drain valve positioner was left in the bypass mode and was scheduled to be replaced during the refueling outogo in the Spring 1998. The dump valve controller had drifted to its calibration tolerance lirnit, it was recalibrated to respond more quickly during a high level conditio Conclusion The operators responded well to the FWH isolation transient, taking proper precautions by lowering power in the event of the further loss of FWHs, Troubleshooting revealed that the cause of the transient was a faulty drain valve-positioner, and the dump valve controller needed retalibratio .4 Manual Shutdown to Replace Safety Relief Valves - Unit 1 Scone (717071 On June 22, control room operators manually shut down Unit 1 to replace a safety relief valve (SRV) that demonstrated indications of pilot seat leakage. The inspectors followed the activit!es of the forced outage, and observed portions of the work activities in the control room and in the plant, Observations and Findinas On June 16, the "J" SRV tailpipe temperature increased from 212 degrees F to about 230 degrees F. The control room staff quickly entered the appropriate procedures to continuously monitor and trend the SRV temperature. The engineering staff evaluated the data collected and determined that there was a small pilot seat leak. The leak was small as evidenced by the small suppression pool heat up rate and did not demand immediate corrective actions. The SRV tailpipe temperature stabilized at about 230 degrees F for several days, after which the j
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temperature ir. creased to 238 degrees F on June 20. The engineering staff re-
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evaluated the situation and recommended that the unit be shut down to replace the SRV. Senior msnagement accepted the recommendation and initiated plans to begin a forced outage on June 2 '
The operators performed the shutdown well,in a controlled and professional manner. Following the manual scram frorr 25 percent power, the operators attempted to reset the scram and found that the B2 side of the reactor protection system (RPS) would not recet. Technicians troubleshooting the problem found that the K14F scram relay was not operating properly. A piece of bakelite insulation surrounding the relay contacts had fractured and fouled the contact mechanis The relay was replaced, response time tested, and the system was returned to an operable condition. Technicians visually inspected the other scram relays to
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determine signs of wear, degradation and cracking, and other potential generic concerns. No further problems were identified. The failed relay was sent to a laboratory for additional test!ng 1:, identify the root cause of the failur Operators also identified that the position Indication for control rod 22 39 did not indicate fullin following the scram. All other control rods indicated full-in, l&C ,
- technicians determined that the position Indication probe (PIP) had faile Replacement of the PIP assembly required undervessel work. Technicians replaced the PIP for this control rod and for control rod 1014, which also had pre existing magnetic reed switch problems. The work was performed well, observing propur radiological practices. The maintenance technicians replaced the "J" SRV without any problems. The "A" SRV was also replaced because of a higher than nominal-temperature indication monitored on its tailpip The inspector. determined that the outage work was well planned and implemente Station personnel performed work activities carefully and in accordance with approved work procedures arid work orders. The outage was completed ahead of schedule and the reactor was taken critical on June 2 Concluslos The station staff demonstrated a conservative and safe approach to address increased leakage in a main steam line safety relief valve. The maintenance activities associated with the resultant forced outage were performed well and safel . .
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O2 Operational Status of Facilities and Equipment 02.1 Routine Plant Tours (71707)
The inspectors used Procedure 71707 to perform routine tours of the facility and also to walk down accessible portions of engineered safety feature (ESF) systems:
o Reactor Core isolation Cooling (RCIC) System Unit 2 e Emergency Diesel Generators (EDG) Unit 1 and 2 Equipment operability, material condition, and housekeeping were acceptable in all cases. Several minor discrepancies were brought to management's attention and were corrected. The inspectors identified no substantive concerns as a result of these walkdown Operations Procedures and Documentation 03.1 Reactor Core Isolation Coolina Isolation Unit 2 Scone (71707, 93702)
On June 11, while realigning the Unit 2 reactor core isolation cooling (RCIC) system to an automatic standby condition, the reactor operator (RO) inadvertently caused an automatic isolation of the RCIC system. The inspector reviewed the event and discussed the event with various representatives of the operations staff, Observations and Findinos The RO was in the process of removing blocking tags to restore the RCIC system following a scheduled maintenance outage. The RO missed a handwritten step in the clearance, to perform System Procedure S49.1.A, Normal RCIC System Lineup for Normal System Operation, prior to removing the blocking tag from the outboard steam supply isolation valve. The RO removed the tag from the isolation valve and opened the valve without warming the steam line first. The resultant high steamline flow condition resulted in an unplanned engineered safety feature (ESF) isolation of the syste The isolation system functioned normally with both inboard and outboard isolation valves shutting on the isolation signal. Operators performed a walkdown of tha RCIC steam piping and identified no abnormalities. The RCIC system steam piping was then properly warmed and unisolated using S49.1.B, Recovery From RCIC Steamline Isolation, without further problem Several causal f actors contributed to this event:
o The RCIC systram was not restored in accordance with an approved procedure.. The RO did not follow the guidance to align the RCIC system to an automatic standby condition in accordance with S49.1.A. The inspector
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noted that the use of approved procedures in the restoration of a clearance is emphasized and directed in the Clearance and Tagging Manual, Section 15, Clearance Restoration; in the Operations Manual, OM C 10.6, Equipment Return to Service; and is a check off step in Exhibit OM C 10.5:1, Equipment Return to Service Checklist. The inspector also noted through discussions with the Operations staff that these documents were not used or referred to on a routine basis, e The RO was not a part of the restoration brief and became too focused on the release of the clearance. He fo!! owed the clearance restoration sequence by removing the tag and then repositioning the valve to align the component to the recommended Inservice Position as specified on the clearanc Further, the control room supervisor (CRS) was involved with another activity so that he was not available for oversight of the system restoratio * -The clearance did not consider appropriate human factors. The step to use procedure S49.1.A was not clearly written In The recommended inservice-Position was based on the system being returned to an operable condition and not aligning the system to a condition such that procedure S49. could have been entered. Further, the inspector noted that the restorstion process combined tag removal and procedure use together. This was confusing because it appeared that the clearance had the same or more authority than the procedure, e <The clearance was not prepared adequately. Originally, th clearance did not recommend the use of any procedure to restore the RCir system. The CRS identified the deficiency during the final clearance review prior to clearance removal. Therefore, the CRS review barrier was challenged to identify the-
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deficiency and the correction of the deficiency was unsuccessfu Additional corrective actions for the event included: The RO was counseled on the need for a thorough brief and procedure review prior to performing a critical system restoration; all operators were informed of potential similar problems and the lessons learned; clearance and tagging guidance would be clarified regarding the restoration of closed Primary Containment Isolation Valves (PCIVs); and online system restorations processes would be reviewed for improvements. Additionally, operations management recognized the opportunity to clarify and reinforce guidance associated with clearance restoration with regards to use of checkoff lists, operating procedures, and clearance restoration sequences; this was expected to be accomplished through continuing training methods including core training, shift training bulletins, or briefing sheet The inspector determined that the failure of the operations staff to properly implement the clearance, using procedure S49.1.A, Normal RCIC System Lineup for Normal System Operation, when restoring the RCIC system to an automatic standby condition is a violation. This licensee-identified and corrected violation is being treated as a non cited violation, consistent with Section Vll.B.1 of the NRC Enforcement Polic .
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8 Conclunica During a tag clearance restoration, a reactor operator failed to operate the RCIC system in accordance with the specified procedure. This resulted in an inadvertent ESF actuation and isolation ol the system. Specific guidance for the use of approved procedures during tagging restoration was available in several Operations Department documents, but was not utilized in this cas Quellty Assurance in Operations 07.1 Self Assessment Activities (717011 During the inspection period, the inspectors reviewed or attended multiple self-assessment activities, including:
e The quarterly Nuclear Review Board (NRB) meeting on June 19; e various Plant Operations Review Committee (PORC) meetings and meeting minutes; e various quality verification (QV) and independent safety engineering group ,
(ISEG) report The NRB and PORC reviewed several activities related to safe station operatio The members of NRB and PORC actively participated in the meetings with open discussions on the plant issues while maintaining a focus on safety, in particular, the NRB focused on the causes for several Unit 2 transients that occurred due to turbine vibration problems in the March / April time frame. The inspector concluded that PECO provided an effective self assessment of recent plant activitie Miscellaneous Operations issues (P0712)
08.1 (Closed) LER, 2 97 005. Licensed Thermal Power Limit Exceeded Due to EHC Malfunction This event is reviewed in section 01.2 of this inspection report. The Licensee Event Report (LER) met the requirements of 10 CFR 50.73, and the inspectors had no further questions regarding the even .2 (Closed) LER 2 97 006, Closure of the Reactor Core Isolation Coolina Containment isolation Valves Caused by Personnel Error This event is reviewed in section 03.1 of this inspection report. The LER met the requirements of 10 CFR 50.73, and the laspectors had no further questions regarding the event.
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lI. Maintenanta M1 Conduct of Maintenance M1.1 General Comments on Maintenance Activities (62707)
The inspectors observed selected maintenance activities to determine whether approved procedures were in use, details were adequate, technical specifications were satisfied, maintenance was performed by knowledgeable personnel, and post-maintenance testing was appropriately complete The inspectors observed portions of the following work activities:
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EDG D21 troubleshoot!ng for governor problems (high frequency), on July U 1, B Core Spray (CS) outage work (cooler cleaning and reassembly), on July 1 Observed maintenance activities were conducted well using approved procedures, and were completed with satisfactory results. Communications between the various work and support groups were good, and supervisor oversight was goo M1.2 General Comments on Surveillance Activities (6172Q1 The inspectors observed selected surveillance tests to determine whether approved procedures were in use, details were adequate, test instrumentation was properly calibrated and used, technical specifications were satisfled, testing was performed-by knowledgeable personnel, and test results satisfied acceptance criteria or wore properly dispositione The inspectors observed portions of the following surveillance activities:
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EDG D13 monthly, on June 1 EDG D14 monthly, on July Safe shutdown equipment, on July Unit 1 high pressure coolant injection (HPCI) quarterly, on July EDG D21 monthly, on July EDG D21 weekly, on July 1 Unit 1 *B" CS pump, valve and flow test, on July 1 EDG D21 weekly, on July 1 Observed surveillance tests were conducted well using approved procedures, and were completed with satisfactory results. Communications between the various work and support groups were good, and supervisor oversight was goo . _ _ _ _ _ -
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M8 Miscellaneous Maintenance issues M8.1 imoroner Dominerallier Assemblv (62707, 71750)
The inspector reviewed an instance whero improper assembly of a filter domineralizer resulted in a reactor chemistry excursion. An independent Safety Engineering Group (ISEG) report dated August 30,1991, reviewed the events involving resin injection and reactor water conductivity spikes due to problems associated with the ID condensato filter domineralizer. The report stated that the primary cause for the event was a less than adequate station management policy for maintenance activities under time constraints. Further, the report concluded that had the maintenance organization been more attentive to an INPO SOER (82-13), the problem may have been prevented er minimize The report included two recommendations for clarifying the maintenance procedural requirements. These included aligning filter domineralizer reassembly practices with the recommendations of the vendor, and the use of the proper adapter sealant (loctite or RTV). The inspector verified that these recommendations were implemented with a revision to the maintenance proceduro. The prosent maintenance procedure has been changed further to reflect the new style filter demineralizer being used. The procedure revisions that were implemented were adequat However, the major theme of the report was the perception by maintenance management and personnel that it was station management's desire to return domineralizers to service as quickly as possible. The schedule pressure contributed to the maintenance errors. However, the ISEG report did not make any recommendation for implementing corrective action for this concer The inspector determined that the licenseo concluded that a rer.in injection resulted from the improper reassembly of the 1D condensate filter domint:ralizer. Adcquate corrective actions to revise the maintenance procedures were implemented, but the scheduler pressure issue was not addressed. Notwithstanding, the inspector has noted over the past few years, that the PECO Nuclear organization at Limerick and Peach Bottom has actively focused and addressed initiatives toward reducing schedule pressure and emphasizing doing the job right the firt,t time. The inspector had no further questions in this issu _ _ _ _ _ _ _ _ _ _
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111. Enaineerino E1 Conduct of Engineering (37651)
E Ernernency Service Water Pine Renair Unit 1 Scoce (375511 Two pinhole leaks were identified and repaired on June 19,in the 10 emergency service water (ESW) loop at Unit 1. Or.e leak was in the eight inch return header from the control room chiller (OBK112) at a butt weld located above the reactor enclosure cooling water (RECW) heat exchanger. The other leak was in a four inch tee fitting at the 1D residual heat removal (RHR) unit cooler. The inspector observed portions of the work activities and reviewed the engineering change requests and safety evaluations, Observations and Findinas Both pinhole leaks were in ASME Ill class 3, schedule 40 piping. Each leak emitted a fine spray which resulted in a very smallloss in water inventory, and did not affect the respective components' operability since the leaks were on the outlet side. Engineering determined the minimum wall thickness by ultrasonic testing and justified the measurements by a minimum wall computation, comparing the results with a calculation performed for a similar leak. Ultrasonic testing of the section indicated that the flaws were localized with a wall thickness of .140 inches at the flaw. The nominal wall thickness for the B inch pipe is .322 inches, and .237 inches for the 4 inch pipe. Pipe stresses at the leak were within the ASME Code requirements and the structuralintegrity of the piping was not compromised. The pipe section was replaced and inspected per the non destructive examination procedure MAG CG 409, Determination of Measurement Areas for the Detection of Corrosion in Raw Water Piping System The work activities were planned and implemented well. The welding technicians were qualified and performed the repair in a professional manner. Shift management placed the unit in a 72 hout TS LCO due to the removal of the eight-inch ESW header. The inspector noted that the eight inch pipo repair was considered a priority by the craft and was replaced expeditiously allowing the unit to quickly exit the LCO. The removed sections of piping were sent to the corporate leboratory for Nrther evaluatio Conclusiong Work activities to repair two pinhole leaks in the 1B ESW system were performed well. The engineering evaluation, planning and implementation of the activities were very good, f
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E1.2 Emeraeriev Diesel Generator Test Failure insoection Scone (61726,37551)
On July 3, during a monthly surveillance test run of the D21 emergency diesel generator (EDG), the surveillance requirement for frequency was not met. The inspector observed the frequency response of the EDG, observed initial troubleshooting efforts, and discussed the cause and corrective actions, with encineering personnel. The inspector noted that a previous failure on the D21 EDG occurred in January 1997; similarities and differences were discussed with engineering personne Observations and Findinas During the normal monthly surveillance test of the D21 EDG, after the EDG was started, the EDG frequency stabilized at approximately 62 Hz. Since the required range for frequency was 58.8 61.2 Hz, the EDG was shut down to investigate the event. After some troubleshooting efforts, the F.DG was restarted and successfully tested. At the end of the inspection period, engineering personnel had not completed their root cause determination; however, the system manager believed that, since the initial troubleshooting had identified that the governor motor operated potentiometer (MOP) was not in t.ie normal setting while the engine was running at 62 Hz, the most probable root cause was dirt or oxidation on the MOP causing it to hang up. Additionally, no further problems have been observed on three subsequent EDG tests, Indicating that the cleaned MOP is operating correctl The system manager indicated that corrective actions were being evaluated, including replacement of the MOP, evaluating the preventive maintenance program for the MOP, and revising the surveillance procedures to exercise the MOP a the end of an EDG test. These actions will be finalized in a special report to be sent to the NRC within thirty days, as required by Technical Specification 4.8.1. Since this was the second valid D21 EDG test failure in the last twenty attempts, the frequency for testing D21 was increased to weekly, as required by technical specifications. The previous test failure was on January 1,1997, and was due to a loose wire associated with the governor. The system manager did not believe that the root causes for the two failures were the same, but he was evaluating it since both involved higher frequency than allowed, Conclusigna The inspector concluded that operations, maintenance and engineering personnel appropriately addressed a D21 EDG test failure. The final root cause and corrective actions will be reviewed by NRC after the required special report is submitted.
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E8 Miscellaneous Engineering IssL:s (97012,92903)
E (Closed) LER 1 97 005, & Revision 1 Reactor Water Clean-uo Isolations Caused by Liftino of a Filter Demireralizer Pressure Safetv Valv Two separate primary containment and reactor vesselisolation control system actuations occurred on March 11,1997, causing reactor water clean up (RWCU)
system isolations. The isolations were caused by a high differential flow condition due to the liftmg of the prossure safety valve (PSV) for the "B" filter domineralize The PSV was roplaced and sent to the corporate laboratory for analysis. There were no adverse consequances and no radioactive rnatorial was released. Revision 1 to the LER incorporated the commitment to monitor the RWCU filter domineralizer PSVs to determine if a ger erir, concern exists and to establish a frequency to replace them when necessor'/. The inspector reviewed the corrective actions and found them to be adequat E8.2 (Closed) LER 2 97 003 Several Main Steam System Safety Relief Valves Havino Setooint Drift This LER concerned an instance where eleven of the fourteen Unit 2 main steam safety relief valves (SRV) did not meet the one percent setpoint tolerance of Technical Specification 3.4.2. This resulted in a condition where a common cause resulted in more than two independent trains becoming inoperable in a single safety system. The NRC has concluded that the current concerns with SRV setpoint drift are being adequately addressed by PECO Energy and the BWR Owners Group, and that there is neargin in BWR designs which can accommodate the setpoint drift that hes been experienced at most operating plants. This licensee identified and corrected violation is being treated as a non-cited violation, consistent with Section Vll B.1 of the NRC Enforcement Polic E8.3 (Closed) VIO 50 353/97 01-01. Failure to Perform a 10 CFR 50.59 Review of a Modification to the Fuel Preoaration Machine This violation concerned an instanc. ,nere PECO Energy provided inadequate oversight and review of a vendor activity that resulted in operation of a refueling activity outside that assumed and reviewed in the Updated Final Safety Analysis Report (UFS AR). Specifically, a modification was made to the Unit 2 fuel preparation machines which result' J in the raising of two spent fuel assemblies closer to the surface of the spent fuel pool than allowed by the UFSAR. Corrective actions to avoid future violations included: a 10 CFR 50.59 review was completed for the modification; a continuing training lesson will be incorporated into Engineering Support Personnel Continuing Training Prouram to ensure appropriate engineering personnel are aware of the processes by which a design change or a temporary modif':ation can be reviewed and evaluated; revisions to the procedures for set-up and use of the fuel preparation machine to ensure that chain stop setting 1 will maintain 7 feet of water coverage over irradiated fuel assemblies; requisition and work order planning procedures will be reviewed and revised as necessary to ensure adequate methods are established for review and oversight of vendor
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activities; training will be conducted concerning the design and precautions for use of fuelinspection fixtures; and the incident and lessons learned will be included in the next cycle of licensed operator training. The inspector reviewed the corrective actions taken and planned, discussed them with appropriate plant personnel, and had no further questions or concern IV. Plant Support R1 Radiological Protection and Chemistry (RP&C) Controls R1.1 Chemistry RHR Heat Exchanoer Potential Tube Leak .nsoection Scone (71750)
The inspectors reviewed the situation, which existed in the Fall of 1993, where plant personnel identified potential tube leakage in the Unit 1 rer.idual heat removtl heat exchangers (RHRHX). Such leakage could have been in noncompliance with the UFSAR requirements with respect to tube leakage. Documentation, including chemistry and operations records were reviewed to determine if leakage existed, -
and plant management conclusions were reviewed to determine if the actions taken were reasonable, Observations and Findinos In the Fall of 1993, the licensee suspected that there may be leakago in the 1B RHRHX; this was due to an alarming RHR service water (SW) radiation monitor on October 1,1993, and again on October 5,1993. Plant management had extensive monitoring performed on the heat exchanger, mostly performed by chemistry, but with significant engineering support. They ultimately concluded that there was not sufficient technical data to conclude that any tube leakage existed. This was based on the following:
- the lack of Co 60 and Zn-65 in the RHR Service Water (RHRSW),
commensurate with that present in the RHR syste the measured activity in the RHRSW did not increase as predicted by a leak rate model; in fact, at times the activity in the RHRSW decreasso instead of increasing with the RHR and RHRSW systems isolated for periods of tim the RHRHX had previously been contaminated by connection to the Ultimate Cooling inter tie pipin Stone and Webster performed an independent review uf the heat exchanger contamination, and concluded that the station approach and conclusions were reasonabl ~
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NRC review of the technical data did not confirm the existence of a leak. However, the elternative thecry regarding the leeching of radioactivity from prior contamination events was also inconclusiv Review of the UFSAR from October 1993, Section 5.4.7, Residual Heat Removal System, did not reveal any explicit statements regarding RHRHX tube leakag Review of UFSAR Section 9.2.3, RHR Service Water System, revealed that the RHRSW system is designed to limit the possibility of any radioactive material releases to the environment. Additionally, radiation monitors are provided which cause an alarm and automatically initiate the isolation of the RHRHX due to a high activity leve Plant personnel indicated that the RHRSW system was designed as a " clean" system, so that no leakage into it is acceptable. Af ter potential leakage was identified in October 1993, an evaluation (10 CFR 50.59) was completed on December 21,1993, to determine what leakage would be acceptable so that no offsite dose limits would be exceeded. The review was performed because a leak in the RHRHX could result in a radiological release to the environment through the ultimate heat sink spray pond. This potential leakage pathway had not been evaluated in the UFSAR. The 50.59 review evaluated continued operation with an RHRHX leak of 5 cc/ minute maximum, in one of the two RHRHXs on Unit Becarse no leak had been confirrned, this analysis was not incorporated as a change to the UFSAR or the Offsite Dose Calculation Manual (ODCM). After the potentially degraded 1B RHRHX was identified, operations personnel were instructed to minimize its use until both Unit 1 RHRHXs were replaced during the refueling outage in February 199 Conclusions There was inedequate evidence to conclude whether or not an RHRHX tube leak existed in late 1993. Therefore, no change to the UFSAR or other documents was required to be made. However, engineering performed an analysis two months after the occurrence, which indicated that minor leakage would be acceptable. Given the uncertainty of the existence of a leak, this review should have been performed earlier. No noncompliances were identified, h8 Miscellaneous issues R8.1 (Closed) LER 2 97-004. Offoes System Grab Samole Obtained Late (90712)
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The inspector identified, on June 5,1997, that a conditiun prohibited by Technical Specifications (TSs) was not reported under 10 CFR 50.73(a)(2)(i)(B), as required, Reportability Evaluation / Event Investigation Form (RE/EIF) 93-03 22 was initiated on March 16,1993, because a chemistry technician obtained a compensatory grab sample, for hydrogen on the Unit 2 offgas system,34 minutes past the four hour time interval required by TS. The corrective action for this problem was to increase the frequency of the compensatory grab samples to provide a grace period to the TS interval. The RE/EIF concluded that the event was not reportable because the r
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i 16 j sample was obtained using a surveillance test, for which they believed a 25 percent grace period defined in TS 4.0.2 should apply. However, the inspector pointed out that the grab sample was required per a TS limiting condition for operation (LCO)
and that the 25 percent grace period did not apply.
. A similar late compensatory sample event occurred c,n February 11,1996, that .
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resulted in LER 1 96-005. The corrective actions from the 1993 occurrence had
- been deleted, thus allowing this event to recur. The issues associated with the 1996 occurrences were previously dispositioned in NRC Inspection Report 50-l 352/96 03. The corrective actions committed in LER 1 96-005 are sufficient to prevent recurrence of both the March 1993 and February 1996 events. The new actions cannot be deleted without a formal review of the impact on future compliance with the grab sample requirements. The inspector determined that had !
an LER been submitted with permanent corrective actions for the first event, the !
- second occurrence would likely have been prevented. The failure to submit an LER required by 10 CFR 50.73 is being citsd as a violation. (VIO 50 353/97 06-01)
F (Closed) LER 196 016, URI 96-06-01 Failure to Maintain Eauloment Needed for Operator Actions to Assure Fire Safe Shutdown Caoabilltv (90712. 92904)
This unresolved item concerned an instance where plant personnel identified that
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certain equipment required to assure fire safe shutdown capability had not been in place since initial operation of Unit 2. Specifically, an electrical jumper cable, several battery powered lighting units, and a radio microphona were not pre staged -
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as required. Such pre staged equipment is routinely verified by periodic inventory procedures. However, those procedures did not list these components for verification. Plant personnel concluded that failure to maintain this equipment was a violation of License Condition 2.C.(3), which requires PECO Energy to implement and maintain in effect all provisions of the approved Fire Protection Program as described in the UFSAR. This event was initially reviewed in NRC Integrated Inspection Report 50 352/96-06, 50 353/96-06, and subsequently in NRC Integrated Inspection Report 50 352/97 01,50 353/97 01. The safety significance
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and corrective actions were reviewed and documented in those reports. NRC concluded that the failure to properly implement and maintain in effect all provisions of the approved Fire Protection Program is an apparent violation of License Condition 2.C.(3), (eel 50 352,353/97 06-02)
F8.2 (Closed) eel 98 10-03. Fire Safe Shutdown Analvsis Error (92904)
This Apparent Violation concerned an instance where normal system leakage in the primary containment instrument gas (PCIG) system was not accounted for, which
, resulted in a condition where the plants were operating in non-compliance with the licenses. Enforcement discretion exercised in this instance was described in a June 2,1997, NRC letter to the license j
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P5 Staff Training and Qualification P Emeroency Preoaredness Drill (71750) '
On June 3, plant personnel conducted a practice emergency drill. This drill was a site wide practice in preparation for the blannual emergency exercise. The inspector i observed portions of the drill throughout the plant, and attended the post drill !
critique in the Technical Support Center (TSC). The inspector concluded that the drill adequately met the goal of providing plant personnel with training for the annual exercise and potential plant events. In particular, the inspector noted that the critique was comprehensive with good comments and recommendations from players and observers.
l V. foanaaement Meetinas
i X1 Exit Meeting Summary
The inspector presented the inspection results to members of plant management at the conclusion of the inspection on July 21,1997. The plant manager acknowledged tha -
inspectors' findings. The inspectors asked whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.
j X2 Review of UFSAR Corrmitments
% recent discovery of a licensee operating their facility in a manner contrary to the UFSAR
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oescription highlighted the need for a special focused review that compares plant practices,
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procedures and/or parameters to the UFSAR description. While performing the inspections
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consistent with the observed plant practices, procedure and/or parameter X3 Pre-deciolonal Enforcement Conference !
'On June 2,1997, a pre decisional enforcement conference was held at the NRC Region 1
office to discuss potential enforcement issues regarding the falsification of surveillance test j results at the Limerick Generating Station. The handouts from the meeting are attached to this inspection report.
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INSPECTION PROCEDURES USED IP 37551: Onsite Engineering IP 61726: Surveillance Observation IP 62707: Maintenance Observation IP 71707: Plant Operations IP 71750: Plant Support Activities IP 90712: In office Review of Written Reports IP 90713: Review of Periodic and Special Reports IP 92903: Followup - Engineering IP 92904: Followup Plant Support IP 93702: Prompt Onsite Response to Events at Operating Power Reactors ITEMS OPENED, CLOSED, AND DISCUSSED Ooened 353/97-06-01 VIO - Offgas System Grab Sample Obtained Late (R8.1)
352,353/97 06 02 eel Failure to Maintain Fire Safe Shutdown Equipment (F8.1)
Closed 353/2 97 005 LER Facility Operating License Thermal Pownr' Limit Exceeded Due to EHC Malfunction (08.1)
353/2 97 006- LER Automatic Closures of the Reactor Core Isolation Cooling Steam Supply Primary Containment isolation Valves, and ESF, Caused by Personnel Error During Restoration of a Clearance (08.2)
352/1 97 005 LER ' Two Separate Reactor Water Clean up Isolations, Engineered Safety Features, Caused by Lifting of a Filter Domineralizer Pressure Safety Valve (E8.1)
353/2 97 003 LER- Corrosion Induced Bonding Results in Several Main Steam System Safety Relief Valves Having Setpoint Drift (E8.2)
353/97 01 01 VIO Failure to Perform a 10 CFR 50.59 Review of a Modification to the Fuel Preparation Machine (E8.3)
353/2 97 004 LER Offgas System Grab Sample Obtained Late (R8.1)
353/97 06 01 VIO Offgas System Grab Sample Obtained Late (R8.1)
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352,353/196 015 LER - Failure to Maintain Equipment Needed for Operator Actions to Assure Fire Safe Shutdown Capability (F8.1)
352,353/96 06 01- URI Failure to Maintain Equipment Needed for Operator Actions to Assure Fire Safe Shutdown Capability (F8.1)
352,353/9610 03 eel Fire Safe Shutdown Analysis Error (F8.2)
- Discussed None o
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LIST OF ACRONYMS USED APRM Average Power Range Monitor CFR Code of Federal Regulations CRS Control Room Supervisor F 73 Emergency Diesel Generator
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il u '. - Electro hydraulic Control eel Escalated Enforcement Issue
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EO Equipment Operator
. ESF- Engineered Safety Feature ESW Emergency Service Water l! F Fire Protection i FWH Feedwater Heuter HPCI High Pressure Coolant injection IFl Inspection Follow up Item IRM Industrial Risk Management ISEG Independent Safety Engineering Group i l&C Instrumentation and Control l LCO Limiting Condition For Operation
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LER Licensee Event Report '
NCV Non-Cited Violation i
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NOA Nuclear Quality Assurance
. NRB Nuclear Review Board 4 NRC Nuclear Regulatory Commission ODCM Offsite Dose Calculation Manual i PClG Primary Containment Instrument Gas
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PCIV . Primary Containment isolation Valve PEP Performance Enhancement Process PORC Plant Operations Review Committee PSV Pressure Safety Valve OA Quality Assurance OV Quality Verification
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RCIC Reactor Core Isolation Cooling RECW Reactor Enclosure Cooling Water RHR Residual Heat Removal RHRHX RHR Heat Exchanger
RHRSW RHR Service Water RMSI Roo Maneuvering Shutdown instructions
. RO Reactor Operator RP&C Radiological Protection and Chemistry RP Radiation Protection RPS Reactor Protection System RWCU Reactor Water Clean-up 4 SRV; Safety Relief Valve TCV Turbine Control Valve
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TPA Temporary Plant Alteration TRM Technical Requirements Manual TS Technical Specification TSC Technical Support Center UFSAR Updated Final Safety Analysis Report URI Unresolved item VIO Violation
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Limerick Generating Station Predecisional Enforcement
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Conference
L~SNRC Region I June 2,1997
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AGENDA Introduction W. MacFarland Chemistry Event R. Boyce
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Fire Protection Event D. LeQuia Site-Wide Actions R. Boyce l
Limerick Culture W. MacFarland Enforcement Policy W. MacFarland Considerations Conclusions G. Rainey
.J Chemistry Event Description Chem Tech realized RECW sample not taken
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Chem Tech openly notified co-workers and then the Primary Chemistry Manager RECW sample taken late and analyzed Experience Assessment Coordinator notified of a change to the sample time
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Immediate Actions XQA/ Corporate Security investigation initiated
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Chem Tech access temporarily suspended Primary Chemistry Manager removed from immediate supervisory duties l Chemistry line management review initiated
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Investigation Results XQA/ Corporate Security investigation
- Three individuals involved
- RECW sample documentation falsified
- Coercion by Primary Chemistry Manager
- Collusion involving a Chemist
Chemistry line management review
- Two other discrepancies identified l
- A different individualinvolved
- No conclusion on willful intent to falsify
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Immediate Follow-up Actions ,
No plant safety consequences confirmed Primary Chemistry Manager and Chemist unescorted access suspended Primary Chemistry Manager and Chemist suspended - subsequently resigned l Chem Tech counseled - access reinstated
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Independent task force on integrity of Chemistry function convened by VP
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Task Force Results
- Positive recognition of core values
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Opportunities for: Chemistry organization improvements identified regarding:
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- Process and procedures
- Team building ;
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- Communications
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Actions to Prevent Recurrence
- Chemistry all-hands meeting conducted
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Expectations on personal integrity reinforced with Chemistry Supervision l
- Read and Sign on personal integrity issued to Chemistry personnel
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Site Directors briefed on the issue
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Personnel teamwork interviews conducted Potential surveillance discrepancy identified
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Fire Protection line management review conducted Discrepancy substantiated
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I Immediate Actions NQA/ Corporate Security investigation initiated
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Individual's unescorted access suspended
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Investigation Results XQA/ Corporate Security investigation
- One individual involved
- Six surveillances falsified
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- Acted on own accord Investigation expanded within FP Group
- Two other discrepancies identified
- Two other individuals involved
- Concluded no intent to falsify records
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Immediate Follow-up Actions
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- Individual's employment suspended
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No plant safety consequences confirmed
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Expectations reinforced within FP Group
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Actions to Prevent Recurrence Expectations reinforced withir. Site Support Division
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Letter from Vice President issued to all site personnel
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.e e Site-Wide Actions
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Limerick Culture
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History of openness
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Various methods of self-identification
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PECO Energy Advantage
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Considerations Plant Safety Significance Identification Credit
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Corrective Action Credit
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Plant Safety Significance
- Affected RECW sample not contaminated
- All affected FP equipment operable
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Identification Credit
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comprehensive to prevent recurrence
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Conclusions No plant safety consequences Licensee-identified issues
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Prompt and comprehensive corrective actions Investigation and corrective actions appropriately expanded Independent incidents No generic willingness to misrepresent
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