IR 05000219/2007005

IR 05000219-07-005; 10/01/07 - 12/31/2007; Amergen Energy Company, LLC, Oyster Creek Generating Station; Maintenance Effectiveness, Identification and Resolution of Problems, Event Followup

ML080250267
Person / Time
Site:	Oyster Creek
Issue date:	01/25/2008
From:	Bellamy R NRC/RGN-I/DRP/PB6
To:	Pardee C Exelon Generation Co
BELLAMY RR
References
IR-07-005
Download: ML080250267 (48)

Text

UNITED STATES ary 25, 2008

SUBJECT:

OYSTER CREEK GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 05000219/2007005

Dear Mr. Pardee:

On December 31, 2007, the US Nuclear Regulatory Commission (NRC) completed an inspection at your Oyster Creek Generating Station. The enclosed integrated inspection report documents the inspection findings, which were discussed on January 18, 2008, with Mr. T.

Rausch, Site Vice President, and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

The report documents one NRC-identified finding and three self revealing findings of very low safety significance (Green). Two of these findings were determined to involve violations of NRC requirements. However, because of the very low safety significance and because they were entered into your corrective action program, the NRC is treating these two findings as non-cited violations (NCVs) consistent with Section VI.A of the NRCs Enforcement Policy. If you contest these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at Oyster Creek.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs document system (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room). We appreciate your cooperation. Please contact me at (610) 337-5200 if you have any questions regarding this letter.

Sincerely,

/RA/

Ronald R. Bellamy, Ph.D., Chief Projects Branch 6 Division of Reactor Projects Docket No. 50-219 License No. DPR-16 Enclosure: Inspection Report 05000219/2007005 w/Attachment: Supplemental Information cc w/encl:

T. Rausch, Site Vice President, Oyster Creek Nuclear Generating Station, AmerGen J. Randich, Plant Manager, Oyster Creek Generating Station, AmerGen J. Kandasamy, Manager Regulatory Assurance, Oyster Creek Generating Station M. Pacilio, Chief Operating Officer, AmerGen R. DeGregorio, Senior Vice President - Mid Atlantic Operations, AmerGen S. Lendahl, Senior Vice President - Operations Support, AmerGen K. Jury, Vice President - Licensing and Regulatory Affairs, AmerGen P. Cowan, Director, Licensing and Regulatory Affairs, AmerGen D. Helker, Manager Licensing, AmerGen B. Fewell, Associate General Counsel, AmerGen Correspondence Control Desk, AmerGen P. Baldauf, Assistant Director, Radiation Protection and Release Prevention, State of NJ P. Mulligan, Chief, NJ Bureau of Nuclear Engineering, Dept of Environmental Protection Mayor of Lacey Township N. Cohen, Coordinator - Unplug Salem Campaign W. Costanzo, Technical Advisor - Jersey Shore Nuclear Watch E. Gbur, Chairwoman - Jersey Shore Nuclear Watch E. Zobian, Coordinator - Jersey Shore Anti Nuclear Alliance

SUMMARY OF FINDINGS

IR 05000219/2007005; 10/01/07 - 12/31/2007; AmerGen Energy Company, LLC, Oyster Creek

Generating Station; Maintenance Effectiveness, Identification and Resolution of Problems,

Event Followup.

The report covered a 3-month period of inspection by resident inspectors, a project engineer, regional reactor inspectors, and an announced inspection by a senior radiation specialist. Two Green non-cited violations (NCV) and two Green findings (FIN) were identified. The significance of most findings is indicated by their color (Green, White, Yellow, or Red) using Inspection Manual Chapter (IMC) 0609, "Significance Determination Process" (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 4, dated December 2006.

Cornerstone: Initiating Event

Green.

A self revealing finding occurred when the 1-1' service water pump motor failed on August 15, 2007 due to an inadequate motor refurbishment by a vendor. AmerGen previously noted a problem with the motor refurbishment process used by the vendor in July 2005, however they did not take actions to address this issue. This finding was determined not to be a violation of NRC requirements. AmerGen's corrective actions for this issue included replacing the motor and informing the vendor of the issue.

The finding is more than minor because it was associated with the equipment performance attribute of the initiating events cornerstone and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. In accordance with Inspection Manual Chapter (IMC) 0609, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations, the inspectors conducted a significance determination process (SDP) Phase 1 screening and determined that a detailed Phase 2 evaluation was required to assess the safety significance because the finding contributed to both the likelihood of a reactor trip and the likelihood that mitigation equipment would not be available. The finding was determined to be of very low safety significance (Green) based upon the Phase 2 evaluation. The performance deficiency had a cross-cutting aspect in the area of problem identification and resolution because AmerGen did not take appropriate corrective actions to address the issues identified with the quality of vendor practices P.1(d). (Section 1R12)

Cornerstone: Mitigating Systems

Green.

A self revealing finding occurred when AmerGen did not identify a degraded fuel oil condition on the 1-1' diesel driven fire pump in September 2007. This resulted in the pump being unable to maintain adequate discharge pressure on October 1, 2007 during testing due to restricted fuel flow caused by clogged fuel filters. The finding was determined not to be a violation of regulatory requirements. AmerGens corrective actions included removing the fuel oil sludge from the system; and proposed actions to revise the fuel oil tank cleaning procedure, providing administrative limits for particulate contamination in the chemistry procedure, and briefing chemistry personnel on the importance of properly trending data.

The finding was more than minor because it was associated with the equipment performance attribute of the mitigating systems cornerstone and affected the objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. In accordance with IMC 0609, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations, the inspectors conducted a SDP Phase I screening and determined that a detailed Phase 2 evaluation was required to assess the safety significance because the finding involved an actual loss of safety function of one or more non-technical specification trains of equipment designated as risk significant per 10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The finding was determined to be of very low safety significance (Green)based upon a Phase 2 evaluation. The performance deficiency had a cross-cutting aspect in the area of problem identification and resolution because AmerGen discovered an adverse condition in fuel oil particulate concentration, which impacted the safety function on the 1-1' diesel driven fire pump and did not enter this condition into the Corrective Action Program P.1(a). (Section 1R12)

Green.

The inspectors identified that AmerGen did not properly implement procedures during a reactor startup on July 20, 2007. Specifically, operations personnel withdrew source range monitors (SRM) from the core without first ensuring adequate overlap with the intermediate range monitors (IRM) as prescribed by procedures. The finding was determined to be an NCV of technical specification 6.8.1, Procedures and Programs.

AmerGens proposed corrective actions for this issue involve revising the operating procedure and providing training to operations personnel on this issue.

The finding is more than minor because it was associated with the human performance attribute (pre-event) of the mitigating systems cornerstone and affected the cornerstone objective to ensure the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors conducted a SDP Phase 1 screening in accordance with IMC 0609, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations. The finding was determined to be of very low safety significance (Green) because the finding was not a design or qualification deficiency, did not represent a loss of system safety function or loss of a single train for greater than its allowed technical specification time, and did not screen as potentially risk significant due to seismic, flooding, or severe weather initiating events. The performance deficiency had a cross-cutting aspect in the area of human performance because operations personnel did not follow procedures when they continued with the plant startup even though they did not meet the operating procedures requirements H.4(b). (Section 4OA2)

Green.

A self-revealing finding occurred when AmerGen operated in a condition prohibited by technical specifications on July 20, 2007. Specifically, AmerGen did not identify that intermediate range monitor (IRM)-16 was inoperable and ensure that the required number of IRM channels for the reactor protection system were available for a reactor startup. This finding was determined to be an NCV of Oyster Creek technical specification 3.1, Protective Instrumentation. AmerGen's corrective actions for this issue included replacing IRM 16 detector and developing lessons learned for reviewing operability of IRMs.

The finding is more than minor because it was associated with the equipment performance attribute of the mitigating systems cornerstone and affected the cornerstone objective to ensure the reliability and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors conducted a SDP Phase 1 screening in accordance with IMC 0609, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations. The finding was determined to be of very low safety significance (Green) because the finding was not a design or qualification deficiency, did not represent a loss of system safety function or loss of a single train for greater than its allowed technical specification time, and did not screen as potentially risk significant due to seismic, flooding, or severe weather initiating events. The performance deficiency had a cross-cutting aspect in the area of problem identification and resolution because AmerGen did not thoroughly evaluate the operability of IRM-16 prior to a reactor startup as requested P.1(c). (Section 4OA3)

Licensee-Identified Violations

None.

REPORT DETAILS

Summary of Plant Status

The Oyster Creek Generating Station (Oyster Creek) began the inspection period operating at full power.

On November 11, 2007, operators performed a planned downpower to 98% to support testing of a permanent modification involving installation of condensate prefilter vessels. After successful testing of the modification, the plant returned to full power the same day.

On November 24, 2007, operators performed an unplanned downpower to 97% and removed the C reactor recirculation pump from service after identifying an increase in the second stage seal pressure on the pump. Operators placed the pump in idle in accordance with technical specification 3.3.F, Recirculation Loop Operability, and engineering personnel investigated the cause of the issue. The plant returned to full power later that same day on November 24, 2007 with four reactor recirculation pumps in service and the C reactor recirculation loop in idle.

On December 5, 2007, operators performed an unplanned downpower to 83% after identifying a salt water leak into the A condenser south waterbox. Maintenance personnel identified the leaking condenser tubes and performed repairs (plugged the damaged tubes). The plant returned to full power on December 6, 2007.

On December 15, 2007, operators performed an unplanned downpower to 35% due to degrading main condenser vacuum when both the 1-1' and 1-2' drain tank pumps in the steam jet air ejector (SJAE) system did not properly operate. Maintenance personnel performed repairs on both drain tank pumps. The plant returned to full power on December 16, 2007.

On December 19, 2007, operators performed a planned downpower to approximately 55% to support repairs on the A condenser north waterbox (plug condenser tubes) and perform maintenance on the A and E reactor recirculation pump motor generator (MG) sets. Shortly after reducing power to 55%, the plant experienced a loss of vacuum in the A condenser and a trip of the A reactor feedpump due to low suction pressure. Operators performed a manual reactor scram in accordance with abnormal operating procedures due to the plant conditions.

AmerGen reported this event to the NRC in Event Notification 43854, Manual Reactor Scram Due to Lowering Reactor Level. Additional information on this event is contained in section 4OA3 of this report. AmerGen completed repairs on the A condenser and performed an evaluation into the cause of the event. Operators commenced a reactor startup and established the reactor critical on December 20, 2007. Operators synchronized the main generator to the grid on December 21, 2007. Operators raised power to 55% to support the planned maintenance activities on the reactor recirculation pump MG sets.

On December 23, 2007, after completion of maintenance on the reactor recirculation MG sets, operations personnel began to raise reactor power. During these activities, operations personnel noted turbine control system (control valve) oscillations as they raised power from 93% to 95%. Operations personnel reduced reactor power to 92% to investigate the cause of the oscillations. On December 27, 2007, AmerGen determined that Oyster Creek would operate at reduced power for an extended period of time until troubleshooting and repairs to the turbine control system could be completed. Oyster Creek operated at 92% power for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

a. Inspection Scope

(1 seasonal sample)

The inspectors performed one adverse weather preparation inspection. The inspectors reviewed AmerGens activities associated with seasonal readiness for cold weather conditions. The inspectors reviewed the updated final safety analysis report (UFSAR)for Oyster Creek to identify risk significant systems that require protection from cold weather conditions. The inspectors assessed the readiness of the fire protection system, emergency diesel generators (EDG), service water system, emergency service water (ESW) system, and the heat trace systems to seasonal susceptibilities (extreme cold temperatures). The inspectors performed a walkdown of the service water system, ESW system, fire diesel driven pumps, and EDGs. The inspectors reviewed AmerGens cold weather preparation activities to assess their adequacy and to verify they were completed in accordance with procedural requirements. The inspectors also reviewed applicable corrective action program condition reports to assess the reliability and material condition of these systems.

Documents reviewed for this inspection activity are listed in the Supplemental Information attachment to this report.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

a. Inspection Scope

(71111.04Q-3 samples)

The inspectors performed three partial equipment alignment inspections. The partial equipment alignment inspections were completed during conditions when the equipment was of increased safety significance such as would occur when redundant equipment was unavailable during maintenance or adverse conditions, or after equipment was recently returned to service after maintenance. The inspectors performed a partial walkdown of the following systems, and when applicable, the associated electrical distribution components and control room panels, to verify the equipment was aligned to perform its intended safety functions:

• Containment spray/ESW system #1 on October 10, 2007;

• #1 EDG on October 23, 2007; and

• #2 EDG on November 1, 2007.

Documents reviewed for this inspection activity are listed in the Supplemental Information attachment to this report.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

a. Inspection Scope

(71111.05A- 1 sample; 71111.05Q 10 samples)

The inspectors performed a walkdown of ten plant areas to assess their vulnerability to fire and observed one plant fire drill. The inspectors observed an unannounced fire drill on October 30, 2007, to assess the readiness of AmerGens fire brigade to respond to fires within the plant. The drill scenario involved a simulated fire in the auxiliary clean-up pump breaker located in the B 480V room (fire area OB-FZ-6B B 480). The inspectors attended AmerGens drill critique to evaluate its adequacy in assessing personnel performance in responding to the postulated fire.

During plant walkdowns, the inspectors observed combustible material control, fire detection and suppression equipment availability, visible fire barrier configuration, and the adequacy of compensatory measures (when applicable). The inspectors reviewed Oyster Creeks Fire Hazards Analysis Report and Individual Plant Examination for External Events (IPEEE) for risk insights and design features credited in these areas.

Additionally, the inspectors reviewed corrective action program condition reports documenting fire protection deficiencies to verify that identified problems were being evaluated and corrected. Documents reviewed for this inspection activity are listed in the Supplemental Information attachment to this report. The following plant areas were inspected:

• C battery room on October 29, 2007;

• Station blackout transformer on October 30, 2007;

• C 4160V vault room roof on November 11, 2007;

• D 4160V vault room roof on November 11, 2007;

• D 4160V room on November 16, 2007;

• Shutdown cooling room on November 26, 2007;

• Turbine building lube oil bay on December 7, 2007;

• Upper cable spreading room on December 7, 2007;

• Fire brigade ready room on December 8, 2007; and

• Lower cable spreading room on December 21, 2007.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program

a. Inspection Scope

(71111.11Q 1 sample)

The inspectors observed one simulator training scenario on October 24, 2007, to assess operator performance and training effectiveness. The scenario involved a loss of coolant accident (LOCA) from an unknown location in the drywell and an anticipated transient without scram (ATWS). The inspectors assessed whether the simulator adequately reflected the expected plants response, operator performance met AmerGens procedural requirements, and the simulator instructors critique identified crew performance problems. Documents reviewed for this inspection activity are listed in the Supplemental Information attachment to this report.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

(3 samples)

The inspectors performed three maintenance effectiveness inspection activities. The inspectors reviewed the following degraded equipment issues in order to assess the effectiveness of maintenance by AmerGen:

• Bank 6 startup transformer voltage regulator (IR 649959) on July 13, 2007;

• 1-1' diesel driven fire pump (IR 678386) on October 1, 2007; and

• 1-1' service water pump motor failure (IR 660972) on November 16, 2007.

The inspectors also verified that the systems or components were being monitored in accordance with AmerGens maintenance rule program requirements. The inspectors compared documented functional failure determinations and unavailable hours to those being tracked by AmerGen. The inspectors reviewed completed maintenance work orders and procedures to determine if inadequate maintenance contributed to equipment performance issues. The inspectors also reviewed applicable work orders, corrective action program condition reports, operator narrative logs, and vendor manuals.

Documents reviewed for this inspection activity are listed in the Supplemental Information attachment to this report.

b. Findings

Degraded Fuel Oil in the 1-1 Fire Diesel Fuel Oil Storage Tank Not Identified

Introduction.

A self revealing finding occurred when AmerGen did not identify a degraded fuel oil condition on the 1-1' diesel driven fire pump in September 2007. This resulted in the pump being unable to maintain adequate discharge pressure on October 1, 2007 during testing due to restricted fuel flow caused by clogged fuel filters. The finding was determined to be of very low safety significance (Green) and not a violation of regulatory requirements.

Description.

On October 1, 2007, the 1-1' diesel driven fire pump was unable to maintain adequate discharge pressure during functional testing in accordance with procedure 645.4.018, Fire Pump Monitoring Test. Operations personnel noted that the pumps discharge pressure was less than the tests acceptance criteria of 156 psig.

They also noted that the longer the pump operated, the lower the discharge pressure became and that diesel engine speed could not be increased. Operations personnel shut down the pump and documented the issue in corrective action program condition report IR 678386. The diesel driven fire pumps provide fire protection water when the fire protection system demand exceeds the capacity of the electrical driven fire (pond)pumps. They can also provide a back-up water supply to the isolation condensers and core spray system.

Engineering and maintenance personnel initiated troubleshooting activities to determine the cause of the issue. Inspections of the diesel engine identified that its fuel filters were clogged which restricted fuel flow. This affected the ability of the pump to maintain adequate discharge pressure. AmerGen sent the fuel filters to a contracted laboratory for analysis. The analysis identified that the filters were clogged with a carbon-based sludge which is typical of the waxes and asphaltenes that settle out of fuel oil.

Maintenance personnel replaced the fuel filters and declared the 1-1' diesel driven fire pump operable after successfully performing testing on October 2, 2007. In addition, AmerGen sampled the 1-1' fuel oil tank and inspected the newly installed fuel oil filters to verify no additional clogging was present. These activities confirmed that the sludge was no longer present at a concentration to impact operation of the pump.

AmerGen performed an evaluation (IR 678386) to determine the cause of the #1 diesel driven fire pumps degraded performance. AmerGen determined that maintenance performed on the diesels fuel oil tank on August 6, 2007 (work order R2068875) caused the fuel filters to clog. The work order involved draining the tank and performing interior inspections. AmerGen concluded that during refilling activities the remaining sludge and sediment in the tank was disturbed and mixed with the new fuel. The particulate matter was then pulled into the engine fuel filters during subsequent tests (August 10, August 23, and September 5, 2007) after the tank inspection activity. During the subsequent tests, the loading on the engine fuel filters increased and eventually impacted the ability of the fuel system to pass sufficient fuel to operate the engine when it was placed in service on October 1, 2007.

The evaluation also identified that the results of a fuel oil chemistry sample taken on August 22, 2007, contained elevated particulate contamination in the 1-1' diesel driven fire pumps fuel oil tank compared to previous samples taken. The fuel oil chemistry results for particulate contamination are summarized below:

Parameter Sample Date Particulate Particulate Contamination Contamination (0.8 µm filter) (3.0 µm filter)

February 23, 2007 0.4 mg/L 0.3 mg/L May 25, 2007 1.5 mg/L 0.2 mg/L August 22, 2007 25.8 mg/L 18.7 mg/L AmerGens procedure CY-OC-120-1107, Fuel Oil System Sample and Analysis Schedule, provides sampling and analysis requirements for fuel oil systems. The procedure does not provide an administrative limit for particulate contamination, but it does require that this parameter be trended. The evaluation (IR 678386) concluded that AmerGen personnel did not identify a potential adverse trend or enter this condition into the corrective action program to determine the cause of the elevated particulate contamination after receiving and reviewing the chemistry results on September 26, 2007.

The performance deficiency associated with this finding involves AmerGen not identifying a degraded condition with the 1-1' diesel driven fire pump fuel oil system, which impacted the capability and availability of the pump. Specifically, AmerGen personnel did not identify an adverse trend and enter the condition into their corrective action program for further evaluation. AmerGens corrective actions included removing the fuel oil sludge from the system, proposed actions to revise the fuel oil tank cleaning procedure, providing administrative limits for particulate contamination in the chemistry procedure, and briefing chemistry personnel on the importance of properly trending data.

Analysis.

The finding was more than minor because it was associated with the equipment performance attribute of the mitigating systems cornerstone and affected the objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. In accordance with IMC 0609, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations, the inspectors conducted a significance determination process (SDP) Phase I screening and determined that a detailed Phase 2 evaluation was required to assess the safety significance because the finding involved an actual loss of safety function of one or more non-technical specification trains of equipment designated as risk significant per 10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

The inspectors used the Risk Informed Inspection Notebook for Oyster Creek Nuclear Generating Station, Revision 2.01A, to conduct a Phase 2 evaluation. The inspectors made the following assumptions:

• The 1-1' diesel driven fire pump was unavailable, including the time for completing corrective maintenance, for a total of approximately 7 days (September 26 - October 2, 2007). Therefore, an exposure time of 3-30 days was used to identify the Initiating Event Likelihood per Table 1, Categories of Initiating Events for Oyster Creek Nuclear Generating Station, in the Risk-Informed Inspection Notebook for Oyster Creek Nuclear Generating Station.

• Full credit was given for available mitigation capability equipment.

• No operator recovery credit was given.

The inspectors determined that the finding was of very low safety significance (Green)using the pre-solved significance determination process (SDP) notebook for the Oyster Creek Nuclear Generating Station. This analysis conservatively estimated the increase in core damage frequency was less than 1 in 100,000,000 years (less than 1E-8). The dominant core damage sequences in each of the transients involved the need for isolation condenser makeup. The finding was determined to be of very low safety significance (Green).

The inspectors also reviewed this issue in accordance with IMC 0609, Appendix F, Fire Protection Significance Determination Process, to confirm the above results. The finding was determined to be of very low safety significance because it was assigned a low degradation rating due to other available fire protection pumps.

The performance deficiency had a cross-cutting aspect in the area of problem identification and resolution because AmerGen discovered an adverse condition in fuel oil particulate concentration, which impacted the safety function on the 1-1' diesel driven fire pump and did not enter this condition into the Corrective Action Program. P.1(a).

Enforcement.

No violation of regulatory requirements occurred because the diesel driven fire pumps are not safety related equipment. The finding was of very low safety significance (Green) and AmerGen has entered this finding into their corrective action program in condition report IR 678386. (FIN 05000219/2007005-01, Degraded Fuel Oil in the 1-1 Fire Diesel Fuel Oil Storage Tank Not Identified).

1-1 Service Water Pump Motor Failure Due to Inadequate Refurbishment Process

Introduction.

A self revealing finding occurred when the 1-1' service water pump motor failed on August 15, 2007 due to an inadequate motor refurbishment by a vendor.

AmerGen previously noted a problem with the motor refurbishment process used by the vendor in July 2005, however they did not take actions to address this problem. This finding was of very low safety significance and determined not to be a violation of NRC requirements.

\

Description.

On August 15, 2007, Oyster Creek experienced a trip of the 1-1 service water pump. Equipment operators responded to the intake area and observed a puff of smoke and an acrid odor near the 1-1' service water pump motor and reported these conditions to the control room. Operations personnel appropriately responded to the loss of a service water pump in accordance with alarm response and abnormal operating procedures. The service water system supplies cooling water flow to the turbine building and reactor building closed cooling water (TBCCW & RBCCW) systems. On August 16, 2007, maintenance personnel replaced the motor and pump (work order R2039464).

AmerGen performed an evaluation (IR 660972) to determine the cause of the motor failure. As part of their evaluation, the motor was disassembled and AmerGen identified a broken winding wire strand within the motor windings. AmerGen concluded that the wire strand broke due to coil movement that occurred because of a void space around the wire strand. AmerGen determined that the void space in the motor windings existed because it was not completely filled with resin during refurbishment and caused the motor to fail. AmerGen's corrective actions for this issue included replacing the motor and discussing with the vendor a process to prevent inadequate resin fill of windings for any future motor refurbishment.

In July 2005, Oyster Creek experienced a motor failure of the 1-1' service water pump and performed an evaluation (IR 355574) to determine the cause of the motor failure.

AmerGen concluded that the motor failure occurred due to excessive heat acting on the windings that was caused by not replacing the air inlet filter screens in a timely manner.

During disassembly of the motor, AmerGen also identified a broken winding wire strand and a lack of adequate resin fill, however, no corrective action was assigned to correct this identified deficiency.

AmerGens 2007 evaluation into the motor failure identified that the July 2005 and August 2007 motor failures were attributed to a less than adequate motor refurbishment process by the vendor. The inspectors noted that the 2005 evaluation identified void spaces in motor windings; however, corrective actions were not taken to address the problem with the vendors refurbishment process. The 2007 evaluation also determined that the currently installed service water pump motors are not susceptible to the problems previously experienced because refurbishment of the motors was performed by a different vendor.

The inspectors noted that Oyster Creeks procedure LS-AA-125-1003, revision 6, Apparent Cause Evaluation Manual, states in step 10, part A of attachment 6, that the quality of manufacturing for equipment failures will be reviewed. Additionally, in step 10, part D of attachment 6, states that if the quality of manufacturing is determined to be a contributing cause, a corrective action will be assigned to correct the deficiency.

Although the manufacturing deficiency to ensure adequate resin fill was identified during the July 2005 evaluation, a corrective action was not assigned in accordance with Oyster Creeks procedure LS-AA-125-1003.

The performance deficiency associated with this self revealing finding involved AmerGens failure to take actions to address a previously noted problem with the motor refurbishment process utilized by one of their vendors in July 2005, which resulted in a service water pump motor failure in August 2007. AmerGen's corrective actions for the August 2007 motor failure included replacing the motor and informing the vendor of the issue.

Analysis.

The finding is more than minor because it was associated with the equipment performance attribute of the initiating events cornerstone and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. In accordance with IMC 0609, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations, the inspectors conducted a SDP Phase 1 screening and determined that a detailed Phase 2 evaluation was required to assess the safety significance because the finding contributed to both the likelihood of a reactor trip and the likelihood that mitigation equipment would not be available. Specifically, the service water system is a support system to the RBCCW system; and a loss of RBCCW is an event initiator scenario in the Risk-Informed Inspection Notebook for Oyster Creek Nuclear Generating Station, Revision 2.01A. The service water system also supports the shutdown cooling system (mitigating system) in conjunction with the RBCCW system.

The inspectors used the Risk-Informed Inspection Notebook for Oyster Creek Nuclear Generating Station, Revision 2.01A, to conduct a Phase 2 evaluation. The inspectors made the following assumptions:

• The 1-1' service water pump was unavailable, including the time for completing corrective maintenance of approximately 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> (includes exposure period of one day prior to failure). Therefore, an exposure time of less than 3 days was used to identify the Initiating Event Likelihood per Table 1, Categories of Initiating Events for Oyster Creek Nuclear Generating Station in the Risk Informed Inspection Notebook for Oyster Creek Nuclear Generating Station.

• Using Table 1 in the Risk Informed Inspection Notebook for Oyster Creek Nuclear Generating Station, the specified initiating event likelihood of four

(4) was increased by one order of magnitude to three (3), because the finding directly affects the likelihood of an initiating event (per usage rule 1.2 in IMC 0609, Attachment 2, Appendix A)

• Full credit was given for available mitigation capability equipment.

• No operator recovery credit was given.

The inspectors determined that the finding was of very low safety significance (Green)using Table 2, Initiators and Dependency Table for Oyster Creek Nuclear Generating Station, and Table 3.9, SDP Worksheet for Oyster Creek Nuclear Generating Station -

Loss of Reactor Building Closed Cooling Water (RBCCW), in the Risk Informed Inspection Notebook for Oyster Creek Nuclear Generating Station. The analysis conservatively estimated the increase in core damage frequency at approximately 1 in 15,000,000 years (approximately 7 E-8). The dominant core damage sequence involved the loss of service water leading to a loss of RBCCW; failure of operators to trip the reactor recirculation pumps leading to a total seal failure LOCA; and either the failure to depressurize or the failure to use low pressure injection following successful depressurization.

The performance deficiency had a cross-cutting aspect in the area of problem identification and resolution because AmerGen did not take appropriate corrective actions to address the issues identified with the quality of vendor practices P.1(d).

Enforcement.

The 1-1' service water pump is not a safety-related component, and therefore no violation of regulatory requirements occurred. Nonetheless, because the finding was of very low safety significance and AmerGen entered this issue into their corrective action program in condition report IR 660972 and IR 718793, this is identified as a finding. (FIN 05000219/2007005-02, 1-1 Service Water Pump Motor Failure Due to Inadequate Refurbishment Process)

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

(2 samples)

The inspectors reviewed two on-line risk management evaluations through direct observation and document reviews for the following plant configurations:

• 1-2' ESW pump and Z52' offsite power source (express feeder) unavailable due to planned maintenance on October 17, 2007; and

• Bank 5 startup transformer unavailable due to unplanned maintenance on October 21, 2007.

The inspectors reviewed the applicable risk evaluations, work schedules, and control room logs for these configurations to verify the risk was assessed correctly and reassessed for emergent conditions in accordance with AmerGens procedures.

AmerGens actions to manage risk from maintenance and testing were reviewed during shift turnover meetings, control room tours, and plant walkdowns. The inspectors also used AmerGens on-line risk monitor (Paragon) to gain insights into the risk associated with these plant configurations. Additionally, the inspectors reviewed corrective action program condition reports documenting problems associated with risk assessments and emergent work evaluations. Documents reviewed for this inspection activity are listed in the Supplemental Information attachment to this report.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

a. Inspection Scope

(6 samples)

The inspectors reviewed six operability evaluations for degraded or non-conforming conditions associated with:

• B isolation condenser steam inlet isolation valve (V-14-30) exceeded stroke time acceptance criteria during surveillance test on October 2, 2007 (IR 679066);

• #1 EDG circulating oil pump low discharge pressure on October 24, 2007 (IR

===688558);

• Bank 6 startup transformer footing support degraded (IR 695539) on November 8, 2007;

• #1 EDG low lube oil on November 26, 2007 (IR 703406);

• C battery cell #56 degraded with interior casing crack on December 1, 2007 (IR 706122); and

• Drywell sump unidentified leak rate integrated flow indication degraded on December 4, 2007 (IR 706834).

The inspectors reviewed the technical adequacy of the operability evaluations to ensure the conclusions were technically justified. The inspectors also walked down accessible portions of equipment to corroborate the adequacy of AmerGens operability evaluations.

Documents reviewed for this inspection activity are listed in the Supplemental Information attachment to this report.

b. Findings

No findings of significance were identified.

=

The inspectors observed portions of and/or reviewed the results of four post-maintenance tests for the following equipment:

• 1-1' diesel driven fire pump on October 2, 2007 (WO A2177130);

• 1-4' ESW pump on October 11, 2007 (WO A2146495);

• #2 EDG on October 26, 2007 (WO A2116551); and

• Drywell sump flow integrator on December 11, 2007 (WO A2183148).

The inspectors verified that the post-maintenance tests conducted were adequate for the scope of the maintenance performed and that they ensured component functional capability. Documents reviewed for this inspection activity are listed in the Supplemental Information attachment to this report.

b. Findings

No findings of significance were identified.

1R20 Refueling and Other Outage Activities

a. Inspection Scope

(1 sample)

The inspectors monitored AmerGens activities associated with the outage activities described below. Documents reviewed for this inspection activity are listed in the Supplemental Information attachment to this report.

On December 19, 2007, operators initiated and completed a plant shutdown to support a forced maintenance outage due to a manual reactor scram. Additional information on the cause for the plant shutdown is contained in section 4OA3 of this report. The inspectors observed portions of the shutdown from the control room, and reviewed plant logs to ensure that technical specification requirements were met for placing the reactor in hot shutdown. The inspectors also monitored AmerGens controls over outage activities to determine whether they were in accordance with procedures and applicable technical specification requirements.

The inspectors verified that cooldown rates during the plant shutdown were within technical specification requirements. The inspectors performed a walkdown of portions of the turbine building and reactor building to verify there was no evidence of leakage or visual damage to passive systems contained in these areas. The inspectors verified that AmerGen assessed and managed the outage risk. During control room tours, the inspectors verified that operators maintained reactor vessel level and temperature within the procedurally required ranges for the operating condition. The inspectors observed Oyster Creeks plant onsite review committee (PORC) startup meeting on December 20, 2007, which discussed the cause of the reactor scram and the plant response to the transient.

The inspectors monitored restart activities that began on December 20, 2007, to ensure that required equipment was available for operational condition changes, including verifying technical specification requirements, license conditions, and procedural requirements. Portions of the startup activities were observed from the control room to assess operator performance. The inspectors further verified that unidentified leakage and identified leakage rate values were within expected values and within technical specification requirements.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

a. Inspection Scope

(3 IST samples and 2 Routine Surveillance samples)

The inspectors observed portions of and/or reviewed the results of five surveillance tests:

• A standby liquid control pump operability and in-service test (IST) on October 2, 2007;

• Containment spray/ESW system #2 operability and comprehensive IST on October 10, 2007;

• Local shutdown panel LSP-1B3 functional test on October 14, 2007;

• Drywell equipment and floor drain sump isolation valve operability and IST on October 18, 2007; and

• 1-1' diesel driven fire pump on December 3, 2007.

The inspectors verified that test data was complete and met procedural requirements to demonstrate the systems and components were capable of performing their intended function. The inspectors also reviewed corrective action program condition reports that documented deficiencies identified during these surveillance tests. Documents reviewed for this inspection activity are listed in the Supplemental Information attachment to this report.

b. Findings

No findings of significance were identified.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

2OS1 Access Control to Radiologically Significant Areas (71121.01)

a. Inspection Scope

(7 samples)

The inspectors reviewed activities and associated documentation in the area of access control to radiological significant areas.

The inspectors walked down radiological controlled areas at Oyster Creek and verified that radiological controls (posting, barricading, and access controls) were acceptable.

During walk downs, the inspectors conducted independent radiation surveys to evaluate the adequacy of radiological controls.

The inspectors evaluated the adequacy and effectiveness of radiological controls utilized during two radiologically significant work activities conducted in 2007. The work activities involved A and C reactor recirculation pump seal replacement and spent fuel pool work. The inspectors reviewed AmerGens implementation of technical specification high radiation area controls and the adequacy of electronic dosimeter setpoints. The review included evaluation of the adequacy of applied radiological controls (for areas of potential dose rate gradients) including radiation work permits, procedure adherence, radiological surveys, job coverage, system breach surveys, airborne radioactivity sampling, contamination controls, and barrier integrity and associated engineering control performance. The inspectors also reviewed the use of electronic personnel dosimetry (EPDs) by Oyster Creek personnel. The inspectors observed workers signing into the radiological controlled areas and validating dose and dose rate alarms.

The inspectors reviewed internal dose assessments for 2007 (as of the time of the inspection), to identify apparent occupational internal doses greater than 50 millirem committed effective dose equivalent (CEDE). The review involved an evaluation of dose assessments performed by AmerGen. The inspectors reviewed the program which monitors potential intakes associated with hard-to-detect radionuclides (e.g.,

transuranics). The inspectors also reviewed external dose results to determine if any anomalus results existed.

The inspectors reviewed procedure changes which impacted high radiation area access controls to determine if the changes resulted in a reduction in the effectiveness and level of worker protection. During plant walkdowns, the inspectors reviewed implementation of high and very high radiation area controls and discussed how these controls (posting, barricading, and locking of high radiation areas) were implemented with radiological protection personnel. The inspectors also reviewed control and issuance of locked high radiation area keys. The inspectors observed locking and controls for materials stored within the spent fuel pool.

The inspectors observed radiation worker performance with respect to radiation protection work requirements during plant walkdowns. The inspectors also assessed radiation protection technician proficiency by reviewing corrective action program condition reports associated with radiation protection technician performance.

The inspectors reviewed problems reports to identify issues associated with access control to radiological significant areas. The inspectors reviewed self-assessments and audits related to access control to radiological areas to determine if problems were being entered into the corrective action program for resolution. The inspectors reviewed corrective action program condition reports to determine if repetitive issues were occurring that could lead to more significant problems. The review also included evaluation of data to determine if any problems involved performance indicator (PI)events with dose rates greater that 25 R/hr at 30 centimeters, greater than 500 R/hr at 1 meter or unintended exposures greater than 100 millirem total effective dose equivalent (TEDE), 5 rem shallow dose equivalent (SDE), or 1.5 rem lens dose equivalent (LDE).

Documents reviewed for this inspection activity are listed in the Supplemental Information attachment to this report.

b. Findings

No findings of significance were identified.

2OS2 ALARA Planning and Controls (71121.02) a.

Inspection Scope (4 samples)

The inspectors reviewed activities and documentation associated with radiological planning and controls to determine if AmerGen was implementing operational, engineering, and administrative controls to maintain personnel occupational radiation exposure as low as is reasonably achievable (ALARA). The inspectors evaluated AmerGens performance against criteria contained in 10 CFR 20, Standards For Protection Against Radiation, AmerGen procedures, and applicable industry standards.

The inspectors, as part of their inspection planning, reviewed information regarding Oyster Creeks collective dose history, current exposure trends, and ongoing or planned activities to assess current performance and exposure challenges. The inspectors also reviewed Oyster Creeks Five Year Exposure Reduction Plan. The inspectors evaluated Oyster Creeks collective exposures (using NUREG-0713 and plant historical data) and source-term (average contact dose rate with reactor coolant piping)measurements. The inspectors also evaluated Oyster Creeks three-year rolling average collective exposure. The inspectors reviewed site specific procedures associated with maintaining occupational exposures ALARA; and the processes used to estimate and track activity specific exposures.

The inspectors reviewed procedures and engineering and work controls used by AmerGen personnel during radiologically risk significant work activities conducted in 2007 to assess AmerGens ability to achieve occupational exposures that were ALARA.

Specifically, the inspectors reviewed AmerGens activities associated with the spent fuel pool and reactor recirculation pump. The inspectors compared the results achieved (dose and dose rate reductions, person-rem expended) with the estimated occupational doses established in the initial ALARA plans.

The inspectors evaluated AmerGens source term controls at Oyster Creek. The review included source term, chemical controls, shutdown methodology, and clean-up strategies. The inspectors also reviewed implementation of radiological controls and dose results for declared pregnant workers.

The inspectors reviewed Oyster Creeks ALARA performance as of November 2007 and compared accrued occupational dose for various work tasks to initial task estimates.

The inspector also reviewed work-in-progress reports to ascertain bases for emergent dose. The inspectors evaluated assumptions and bases for current annual collective exposure estimates and reviewed the dose rate and person-hour estimates (versus actual sustained) for accuracy.

The inspectors also reviewed methods used by AmerGen to adjust exposure estimates (e.g., work-in-progress reviews), or re-planning work, when unexpected changes in scope or emergent work were encountered. The inspectors reviewed daily and monthly dose tracking and emergent work dose control reports utilized by AmerGen.

The inspectors reviewed self-assessments, audits, and special reports related to the ALARA program to determine if identified problems were entered into the corrective action program for resolution. The inspectors also reviewed dose significant post-job (work activity) reviews and post-outage ALARA report critiques involving exposure performance to determine if identified problems were properly characterized, prioritized, and resolved in the corrective action program.

Documents reviewed for this inspection activity are listed in the Supplemental Information attachment to this report.

b. Findings

No findings of significance were identified.

2OS3 Radiation Monitoring Instrumentation and Protective Equipment (71121.03)

a. Inspection Scope

(2 samples)

The inspectors reviewed activities and associated documentation in the area of radiation monitoring instrumentation and protective equipment.

The inspectors reviewed radiological source term data based on 10 CFR Part 61, Licensing Requirements for Land Disposal of Radioactive Waste, in order to identify potential changes in radiation types and energies, that could impact calibrations or analyses. The inspectors reviewed calibration records on the Fast Scan whole body counter and the following radiological survey instrumentation (including control charts):

• Beta counter 700488 and 25301;

• Alpha counter 700509 and 700487; and

• Underwater meter 73525 and 73526.

The inspectors reviewed audits and self-assessments related to radiation monitoring equipment and protective equipment to determine if identified problems were being entered into the corrective action program for resolution. The inspectors also reviewed corrective action program condition reports to determine if identified problems were being properly characterized, evaluated, and resolved in the corrective action program.

Documents reviewed for this inspection activity are listed in the Supplemental Information attachment to this report.

b. Findings

No findings of significance were identified.

Cornerstone: Public Radiation Safety

2PS1 Radioactive Gaseous and Liquid Effluent Treatment and Monitoring Systems 71122.01)

a. Inspection Scope

(2 samples)

The inspectors reviewed activities and associated documentation in the area of radioactive gaseous and liquid effluent treatment and monitoring. Specifically, the inspectors reviewed technical specification required testing (auto-start, flow, and heater)on the standby gas treatment systems. The inspectors also reviewed operability of the stack monitoring system and initiation of compensatory sampling when required.

Documents reviewed for this inspection activity are listed in the Supplemental Information attachment to this report.

b. Findings

No findings of significance were identified.

2PS3 Radiological Environmental Monitoring Program (REMP) and Radioactive Material

===Control Program (71122.03)

a. Inspection Scope

(2 samples)===

The inspectors reviewed activities and documentation associated with the radiological environmental monitoring program (REMP) at Oyster Creek. The inspectors reviewed the results of meteorological evaluations and the placement of environmental air sampling stations relative to Oyster Creeks Offsite Dose Calculation Manual (ODCM)requirements. The inspectors also reviewed AmerGens evaluation and assessment of environmental dosimetry results for 2005, 2006, and 2007. Documents reviewed for this inspection activity are listed in the Supplemental Information attachment to this report.

b. Findings

No findings of significance were identified.

4OA1 Performance Indicator Verification

a. Inspection Scope

(10 samples)

The inspectors reviewed AmerGens program to gather, evaluate, and report information on ten performance indicators (PIs) associated with the mitigating systems, physical protection, occupational radiation safety, and public radiation safety cornerstones. The inspectors used the guidance provided in Nuclear Energy Institute (NEI) 99-02, Revision 5, Regulatory Assessment Performance Indicator Guideline to assess the accuracy of AmerGens collection and reporting of PI data. Documents reviewed for this inspection activity are listed in the Supplemental Information attachment to this report.

The inspectors verified the accuracy and completeness of the reported data for the following mitigating systems PIs:

• Mitigating Systems Performance Index (MSPI), High Pressure Injection Systems between April 1, 2006 and September 30, 2007;

• MSPI, Isolation Condensers between April 1, 2006 and September 30,2007;

• MSPI, Emergency AC Power Systems between April 1, 2006 and September 30, 2007;

• MSPI, Residual Heat Removal System between April 1, 2006 and September 30, 2007; and

• MSPI, Cooling Water Systems between April 1, 2006 and September 30, 2007.

The inspectors reviewed operating logs and corrective action program condition reports.

The inspectors verified the accuracy and completeness of the reported data for the following physical protection PIs:

• Protected Area Security Performance Index between October 1, 2006 and June 30, 2007;

• Personnel Screening Program between October 1, 2006 and June 30, 2007; and

• Fitness-for-Duty/Personnel Reliability between October 1, 2006 and June 30, 2007.

Security PIs were inspected during the annual security baseline inspection and the documentation was inadvertently omitted from the security baseline inspection report issued on September 12, 2007. The inspectors reviewed AmerGens corrective action program condition reports and security event reports; and interviewed security personnel.

The inspectors also verified the accuracy and completeness of the reported data for the following occupational and public radiation safety PI:

• Occupational Exposure Control Effectiveness between October 1, 2006 and September 30, 2007; and

• RETS/ODCM Radiological Effluent between October 1, 2006 and September 30, 2007.

The inspectors reviewed corrective action program condition reports, radiation work permits, monthly and quarterly dose assessment results due to radioactive liquid and gaseous effluent releases, and the 2006 Annual Effluent Release Report.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Review of Items Entered Into the Corrective Action Program

The inspectors performed a daily screening of items entered into AmerGens corrective action program to identify repetitive equipment failures or specific human performance issues for follow-up. This was accomplished by reviewing hard copies of each condition report, attending daily screening meetings, or accessing AmerGens computerized database.

.2 Semi-Annual Review to Identify Trends

a. Inspection Scope

(1 sample)

The inspectors performed one semi-annual trend review. The inspectors reviewed AmerGens corrective action program documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors also performed a walkdown of equipment important to safety to ensure issues were being properly identified and corrected in the corrective action program. The inspectors review was focused on repetitive equipment problems, human performance issues, and program implementation issues. The results of the trend review by the inspectors were compared with the results of normal baseline inspections. The review included issues documented outside the normal corrective action system, such as in system health reports and Oyster Creek monthly management reports. The review considered a six-month period of July through December 2007.

b. Assessment and Observations No findings of significance were identified.

The inspectors reviewed the corrective action program condition reports for twelve high risk maintenance rule systems (core spray, standby liquid control, shutdown cooling, service water, TBCCW, 4160V AC power, 125V station DC power, EDG, station blackout combustion turbine, reactor ventilation, service air, and instrument air) and did not identify any adverse trends. The inspectors also reviewed corrective action program condition reports associated with human performance issues and program implementation and did not identify any significant adverse trends. The inspectors noted that AmerGen recently identified (IR 671623) that Oyster Creek personnel were not effectively utilizing their formal trending process and were relying on cognitive recognition to determine if an adverse trend existed.

.3 Annual Sample Review

a. Inspection Scope

(1 Operator Work Around and 2 Annual samples)

The inspectors reviewed AmerGens evaluation and corrective actions associated with the following three issues. Documents reviewed for this inspection activity are listed in the Supplemental Information attachment to this report.

Operator Work-Arounds (Cumulative Review). The inspectors reviewed equipment issues that were identified as operator work-arounds (OWAs) and operator challenges by AmerGen. The inspectors verified that the OWAs were being properly controlled as specified by OP-AA-102-103, Operator Work-Around Program. The inspectors assessed the cumulative impact of the identified OWAs, operator challenges, and control room deficiencies by performing a detailed document review and interviewing operations personnel during the week of October 9, 2007. In addition, the inspectors conducted a walkdown of the main control room and risk significant plant areas to determine if these deficiencies adversely affected the ability of operations personnel to implement emergency operating procedures or respond to plant transients.

Motor Control Center Auxiliary Contactor Binding. The inspectors reviewed AmerGens evaluation and corrective actions associated with several instances of non-safety related motor control center (MCC) auxiliary contactor binding (IR 488539, 494633, and

===498149). The inspectors reviewed relevant corrective action program condition reports to ensure that the full extent of the issue was identified, appropriate evaluations were performed, and corrective actions were specified and prioritized. The inspectors discussed this issue with engineering personnel and reviewed work orders and maintenance procedures. The inspectors reviewed AmerGens response to internal and external operating experience related to white residue on MCC auxiliary switches to ensure that the issue was understood and addressed appropriately.

Intermediate Range Monitor-16 Unresponsive During Startup. The inspectors reviewed AmerGens evaluation and corrective actions associated with troubleshooting of a failed detector on intermediate range monitor (IRM)-16 that occurred during a reactor startup on July 20, 2007 (IR 652257). The inspectors reviewed relevant corrective action program condition reports to ensure that the full extent of the issue was identified, appropriate evaluations were performed, and corrective actions were specified and prioritized. The inspectors discussed this issue with engineering, operations, and maintenance personnel; and reviewed work orders, trouble shooting action plans, and procedures used to repair and replace the failed detector. The inspectors also reviewed operator logs and process plant computer data to better understand AmerGens response to the failed detector prior to and during the reactor startup.

b. Findings and Observations

Operator Work-Arounds (Cumulative Review). The inspectors verified that OWAs were being identified at an appropriate threshold, entered into the corrective action program, tracked for resolution, and the cumulative effects of OWAs for mitigating systems were evaluated to determine the overall impact on the affected systems. No findings of significance were identified.

Motor Control Center Auxiliary Contactor Binding. The cause of and potential consequences of white residue on MCC auxiliary switches was fully understood and all susceptible MCCs were evaluated by AmerGen. The inspectors noted that AmerGen has removed the AeroShell #7 lubricant from use in accordance with operating experience to prevent white residue from forming. The MCC maintenance procedure was updated to be more explicit about inspecting for white residue and includes corrective actions if a white residue is discovered in the future. The inspectors determined that the overall short term and proposed longer term corrective actions associated with the MCC auxiliary switches were reasonable and adequately prioritized.

No findings of significance were identified.

Intermediate Range Monitor-16 Unresponsive During Startup. AmerGens evaluation adequately determined the cause and extent of condition for the failed detector. The evaluation identified that a degraded seal for the detector allowed the argon gas in the detector to leak out. On July 20, 2007, during a plant startup from a forced outage, operations personnel noted that IRM-16 was not responding to an increase in reactor power (with IRM-17 already inoperable). IRM-16 was declared inoperable with the mode switch in startup, maintenance and engineering personnel commenced troubleshooting but did not identify any issues with the cables, connectors, instrumentation power supplies, or IRM circuitry. The pre-amp for the IRM was replaced, a post maintenance test was completed, and IRM-16 was declared operable. A second reactor startup was commenced, but after reaching IRM range 1 power level, IRM-16 again did not respond to increasing power level. IRM-16 was declared inoperable, the reactor was shutdown, and a drywell entry was made to further troubleshoot IRM-16. On July 21, 2007, after the detectors for both IRMs were replaced and declared operable, a reactor startup was commenced, and all eight IRMs responded as expected. AmerGen evaluation also determined that engineering personnel were not fully knowledgeable on the limitations associated with nuclear instrument testing.

AmerGen reported this event in license event report (LER) 2007-002-00, dated September 18, 2007. Additional information on the LER is contained in Section 4OA3 of this report. During review of this issue the inspectors identified the following finding:

Operations Personnel Did Not Appropriately Implement Reactor Startup Procedure

Introduction.

The inspectors identified that AmerGen did not properly implement procedures during a reactor startup that occurred on July 20, 2007. Specifically, operations personnel withdrew source range monitors (SRM) from the core without first ensuring adequate overlap with the intermediate range monitors (IRM) as prescribed by procedures. The finding was of very low safety significance and determined to be an NCV of technical specification 6.8.1, Procedures and Programs.

Description.

On July 20, 2007, after a forced outage following an automatic reactor scram, operations personnel commenced a reactor startup. IRM-17 was inoperable due to a previously identified failed detector that was discovered during a startup in April 2007, and was bypassed for the startup on July 20, 2007. During the startup, once the IRMs came on scale, operations personnel discovered that IRM-16 was not responding as power increased. Thus, it was declared inoperable. Oyster Creeks operating procedure 201, Plant Startup, states in step 5.31.2, when at least three IRMs in each reactor protection system (RPS) are reading approximately 50 percent on scale of Range 1, then withdraw the SRM detectors in accordance with procedure 401.2, Nuclear Instrumentation SRM Channels Operating During Startup. Each RPS trip system has four IRM detectors, and both IRM-16 and IRM-17 provide inputs to RPS-2 trip system. After review of the operator logs and procedures, the inspectors determined that the conditions required to carry out step 5.31.2 of operating procedure 201 could not be met.

The inspectors reviewed the Process Plant Computer (PPC) data and digital recorder data for the IRM channels during the startup and noted there was no visible meter deflection observed for both IRM-16 and IRM-17 during the entire startup evolution.

While Oyster Creek technical specifications allows 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> before the reactor must be shutdown when in a condition where there are less than three operable IRM channels in each RPS trip system, operating procedure 201 does not allow the operators to continue with the startup. The inspectors confirmed that operators continued with the reactor startup through reviews of operator logs, PPC data, operating procedures, and discussions with operations personnel. Therefore, the inspectors determined that the conditions required to complete step 5.31.2 of operating procedure 201 could not be met and that the reactor startup should not have continued.

The performance deficiency associated with this inspector identified finding involved AmerGen not properly implementing procedures during a reactor startup. AmerGens proposed corrective actions involve revising the operating procedure and providing training to operations personnel on this issue.

Analysis.

The finding is more than minor because it was associated with the human performance attribute (pre-event) of the mitigating systems cornerstone and affected the cornerstone objective to ensure the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors conducted a SDP Phase 1 screening in accordance with IMC 0609, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations.

The finding was determined to be of very low safety significance (Green) because the finding was not a design or qualification deficiency, did not represent a loss of system safety function or loss of a single train for greater than its allowed technical specification time, and did not screen as potentially risk significant due to seismic, flooding, or severe weather initiating events.

The performance deficiency had a cross-cutting aspect in the area of human performance because operations personnel did not follow procedures when they continued with the plant startup even though they did not meet the operating procedures requirements H.4(b).

Enforcement.

Oyster Creeks technical specification 6.8.1, Procedures and Program, states in part that applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Quality Assurance Program Requirements (Operation), Revision 2, will be established and implemented. Regulatory Guide 1.33, Appendix A, section 3.t(2),requires that procedures for nuclear instrumentation systems be written and implemented. Oyster Creek Operating Procedure 201 Plant Startup directs the operation of intermediate range nuclear instrumentation during Reactor Startup and Power Ascension. Contrary to the above, on January 20, 2007, AmerGen did not properly implement operating procedure 201, Plant Startup. Therefore, Oyster Creek allowed operation of the plant in a condition not allowed by procedures. However, because the finding was of very low safety significance and has been entered in to the corrective action program in condition report IR 718763, this violation is being treated as an NCV, consistent with section IV.A of the NRC Enforcement Policy. (NCV 05000219/2007005-03, Operations Personnel Did Not Appropriately Implement Reactor Startup Procedure)

=

The inspectors performed five event followup inspection activities. Documents reviewed for this inspection activity are listed in the Supplemental Information attached to this report.

.1 C Reactor Recirculation Pump #1 Seal Degraded

a. Inspection Scope

On November 24, 2007, operators noted that the C reactor recirculation pump second stage seal pressure was at 940 psig. Operations personnel were monitoring reactor recirculation pump seal performance on a daily basis due to indications of decreasing and increasing seal pressure starting in June 2007. Oyster Creeks abnormal operating procedure ABN-2, Recirculation System Failure, states that the first stage seal is considered failed if the second stage seal pressure increases to 950 psig; and the pump should be removed from service if the second stage seal pressure rises to 800 psig. In accordance with ABN-2 and operating procedure 301.2, Reactor Recirculation System, operators reduced reactor power and removed the C reactor recirculation pump from service and placed the pump in idle.

The inspectors verified that operations personnel responded in accordance with procedures and equipment responded as intended by reviewing the completed procedures, control room narrative logs, corrective action program condition reports, and through interviews of operation personnel. The inspectors also reviewed technical specification requirements to ensure that Oyster Creek was operated in accordance with its operating license. The inspectors performed a walkdown of the main control room panels and indications to verify equipment status and plant parameters. The removal of the C reactor recirculation pump from service is described and evaluated in corrective action program condition report IR 703097.

The inspectors reviewed AmerGens technical decision to restart the C reactor recirculation pump. The inspectors attended the PORC which approved the activity and observed the restart of the pump from the control room on December 5, 2007. Shortly after the attempt to restart the pump, the second stage seal pressure rose to approximately 900 psig and operations personnel removed the pump from service and placed the pump in an idle condition. The C reactor recirculation pump remained in idle for the remainder of the year; and no degradation of the second stage seal was noted by operations personnel who continued to monitor the performance of the seal.

b. Findings

No findings of significance were identified.

.2 Downpower to 35% Due to SJAE Drain Tank Pump Issues

a. Inspection Scope

On December 15, 2007, operations personnel in the control room responded to a failure of the 1-2' steam jet air ejector (SJAE) drain tank pump. Operators attempted to start the back-up 1-1' SJAE drain tank pump but it failed to start. Shortly after the loss of both drain tank pumps, vacuum in all three condensers began to degrade. Operators entered ABN-14, "Loss of Condenser Vacuum," and began to lower power to 35% in order to stabilize and maintain condenser vacuum. Maintenance personnel determined that the 1-1' drain tank pump did not start due to contactors inside its Motor Control Center. The contactors were replaced and the pump was restarted in approximately thirty minutes from the time it tripped. This enabled operators to restore condenser vacuum to normal levels and raise reactor power. Operations personnel returned the plant to full power on December 16, 2007. Maintenance personnel performed troubleshooting on the 1-2' SJAE drain tank pump and determined the pump tripped due to a failed motor. The motor was replaced on December 16, 2007, and the system returned to its normal configuration.

The inspectors arrived on site after being informed of the event on December 15, 2007.

The inspectors performed a walkdown of the control room and discussed the issue with AmerGen personnel in order to understand the extent of the issues with the SJAE system. The inspectors also reviewed operator logs, PPC data, and system drawings to understand the plants response and to determine if a common mode failure existed between the drain tank pump failures. The inspectors observed portions of the power ascension and ensured no additional issues were observed with the SJAE system.

b. Findings

No findings of significance were identified.

.3 Loss of A Condenser Vacuum and Trip of A Feedwater Pump Results in a Reactor

Scram

a. Inspection Scope

On December 19, 2007, a reactor power reduction to approximately 50% was commenced to perform planned maintenance on the reactor recirculation pump MG sets and to find and repair condenser tube leaks in the A north water box. Shortly after reducing power to 55%, the plant experienced a loss of vacuum in the A condenser and a trip of the A reactor feedpump due to low suction pressure. Operations personnel responded in accordance with abnormal operating procedures ABN-14,Loss of Condenser Vacuum, and ABN-17, Feedwater System Abnormal Conditions; and performed a manual reactor scram (shutdown) due to the plant conditions. Specifically, the B reactor feedwater pump was removed from service during the power reduction per operating procedures; and with only the C reactor feedwater pump in service, operators performed a manual scram per abnormal operating procedure ABN-17 guidance. Operators mitigated the reactor scram and stabilized the plant in accordance with abnormal operating procedure ABN-1, Reactor Scram and emergency operating procedure (EOP) EMG-3200.01A, RPV Control - No ATWS. Operations personnel and equipment responded as expected during the event. The plant was maintained in hot shutdown while investigation into the cause of the event was determined.

At the time of the event, Oyster Creek was operating with two of its four circulating water pumps in-service. In accordance with AmerGens environmental plan and work management schedule for the downpower, the circulating water system was reduced to two pump operation to maximize discharge water temperatures and to minimize the thermal shock impact to aquatic life in the discharge canal during winter conditions.

AmerGens preliminary investigation (IR 713652) into the cause of the event determined that two circulating water pump operation, combined with draining of the A north water box, resulted in degraded condenser vacuum, reduced performance of the A condensate pump, and the subsequent trip of the A reactor feedwater pump on low suction pressure. AmerGen reported this event to the NRC in Event Notification 43854, Manual Reactor Scram Due to Lowering Reactor Level.

The inspectors responded to the control room following site announcement of a loss of condenser vacuum and observed the response of AmerGen personnel to the event, including operator actions in the control room. At the time of the event, the inspectors verified that conditions did not meet the entry criteria for an emergency action level (EAL) as described in the Oyster Creek EAL matrix. In addition, the inspectors reviewed 10 CFR 50.72, Immediate Notification Requirements for Operating Nuclear Power Reactors, to verify that AmerGen properly notified the NRC during the event. The inspectors also reviewed technical specification requirements to ensure that Oyster Creek operated in accordance with its operating license. This also included a review of Oyster Creeks environmental technical specifications and AmerGens environmental discharge permit NJ0005550 (issued by New Jersey Department of Environmental Protection) due to the impact on the aquatic life (fish) due to the unplanned shutdown.

The inspectors reviewed PPC data, control room logs, and discussed the event with AmerGen personnel to gain an understanding of how operations personnel and plant equipment responded during the event. The inspectors evaluated AmerGens program and process associated with event response to ensure they adequately implemented station procedures OP-AA-108-114, Post Transient Review and OP-AA-106-101-1001, Event Response Guidelines.

The inspectors also observed the PORC meeting prior to plant startup to evaluate whether AmerGen understood the cause of the event and appropriately resolved issues identified during the event. The inspectors reviewed AmerGens post-trip review report (IR 713652) to gain additional information pertaining to the event, and ensure that human performance and equipment issues were properly evaluated and understood prior to plant startup.

b. Findings

No findings of significance were identified. An unresolved item (URI) was identified to review AmerGens corrective action program root cause evaluation (IR 714203)regarding the manual reactor scram on December 19, 2007. The inspectors plan to review this evaluation after it is completed, which had not occurred by the end of this inspection period. (URI 05000219/2007005-04, Loss of A Condenser Vacuum and Trip of A Feedwater Pump Results in a Reactor Scram)

.4 (Closed) LER 05000219/2007-002-00, Intermediate range monitor (IRM) 16 inoperable

during startup.

a. Inspection Scope

This LER discussed operation of Oyster Creek in the startup mode without the minimum number of required channels per RPS trip system, contrary to technical specification requirements. Specifically, Oyster Creek was in the startup mode with two inoperable IRMs in the same RPS trip system which is a condition prohibited by technical specification 3.1, Protective Instrumentation. The inspectors reviewed this LER and no new issues were identified. This LER is closed.

b. Findings

Introduction.

A self-revealing finding occurred when AmerGen operated in a condition prohibited by technical specifications on July 20, 2007. Specifically, AmerGen did not identify that intermediate range monitor (IRM)-16 was inoperable and ensure that the required number of IRM channels for the RPS were available for a reactor startup. This finding was of very low safety significance and determined to be an NCV of Oyster Creek technical specification 3.1, Protective Instrumentation.

Description.

On July 17, 2007, Oyster Creek experienced a reactor scram after a loss of the C reactor feed pump. Additional information on this event is contained in NRC inspection report 05000219/2007004, dated October 29, 2007 (ADAMS Accession Number: ML07030013).

On July 20, 2007, AmerGen commenced a reactor startup with IRM-17 inoperable due to a previously identified failed detector that was discovered in April 2007. During the startup, once the IRMs came on scale, it was discovered that IRM-16 was not responding as power increased, and operations personnel declared IRM-16 inoperable (IR 652257). Oyster Creeks technical specifications require that three of four IRMs in each of the two RPS trip systems be operable in the startup mode. Since IRM-16 and IRM-17 are in the same trip system (RPS-2), operators did not meet the technical specification requirement for startup. AmerGen performed troubleshooting (work order C2015553). Initial troubleshooting did not identify any problems with components associated with IRM-16 that was located outside the drywell. Operations personnel performed a reactor shutdown and maintenance personnel replaced the IRM detector that was located in the drywell. Operations personnel performed a reactor startup on July 21, 2007, after completion of repairs (work order C2015553).

Prior to the reactor startup, AmerGen requested that engineering personnel determine the acceptability and challenges of a reactor startup with IRM-17 inoperable.

Engineering personnel concluded that it was acceptable to start up because the remaining seven IRMs were operable. Based on interviews with engineering and operations personnel, the inspectors determined that the conclusions were based on a review of IRM performance data (IV curves and TDR traces) taken during a refueling outage in October 2006 and a planned maintenance outage in May 2007. The inspectors noted that the review did not include data from the PPC of the IRM channels following the reactor scram. A review of this data would have shown that approximately eight hours following the reactor scram, IRM-16 failed downscale while the remaining operable IRM channels trended downward as would be expected after a reactor scram.

The inspectors noted that Oyster Creek procedure ER-AA-2030, Conduct of Plant Engineering Manual, states in step 4.5.2, that systems engineering personnel should monitor and trend on a regular basis parameters and components to identify abnormal trends or degrading component performance. The procedure further states that system engineering personnel are expected to trend system parameters and component failures to identify adverse trends or failures using information contained in PPC and other data sources. Engineering personnel did not effectively utilize readily available information in the PPC to monitor and analyze IRM performance after the reactor scram.

The performance deficiency associated with this self-revealing finding involved AmerGen not identifying that IRM-16 was inoperable and that the required number of IRM channels for RPS was not available for a reactor startup. AmerGen's corrective actions for this issue included replacing the IRM-16 detector and developing lessons learned for reviewing operability of IRMs.

Analysis.

The finding is more than minor because it was associated with the equipment performance attribute of the mitigating systems cornerstone and affected the cornerstone objective to ensure the reliability and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors conducted a SDP Phase 1 screening in accordance with IMC 0609, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations. The finding was determined to be of very low safety significance (Green) because the finding was not a design or qualification deficiency, did not represent a loss of system safety function or loss of a single train for greater than its allowed technical specification time, and did not screen as potentially risk significant due to seismic, flooding, or severe weather initiating events.

The performance deficiency had a cross-cutting aspect in the area of problem identification and resolution because AmerGen did not thoroughly evaluate the operability of IRM-16 prior to a reactor startup as requested P.1(c).

Enforcement.

Oyster Creeks technical specification 3.1, Protective Instrumentation, states, in part, that prior to changing position of the mode switch from shutdown to startup, there are at least three operable instrument channels in each of the RPS trip systems. Contrary to the above, on July 20, 2007, AmerGen did not have at least three operable instrument channels in one of the RPS (RPS-2) trip systems prior to changing the mode switch to startup. Therefore, Oyster Creek allowed a mode change from shutdown to startup in a condition prohibited by technical specifications. However, because the finding was of very low safety significance (Green) and has been entered in to the corrective action program in condition report IR 652257 and IR 718792, this violation is being treated as an NCV, consistent with section IV.A of the NRC Enforcement Policy. (NCV 05000219/2007005-05, Inadequate Evaluation of IRM Channels Prior to Reactor Startup)

.5 (Closed) LER 05000219/2004-002-01, Change in Methodology Used by General Electric

(GE) and Global Nuclear Fuel to Demonstrate Compliance with Emergency Cooling System Performance Requirements.

This LER was a supplement to LER 2004-002-00 and details the results of GEs evaluation of this issue. LER 2004-002-00 described a concern identified by AmerGens fuel vendor involving a postulated new heat source that affected the calculation of the peak clad temperature and maximum local cladding oxidation required by 10 CFR 50, Appendix K, Emergency Core Cooling Systems Evaluation Models, and 10 CFR 50.46(b)(2), Acceptance Criteria for Emergency Core Cooling Systems for Light Water Nuclear Power Reactors. The postulated heat source is the recombination of hydrogen and oxygen within the fuel bundles during core heatup in a LOCA event. The issue had not been addressed by the analysis models used by the fuel vendor for the condition when reactor power is greater than 25% and the primary containment is not inerted.

LER 2004-002-00 was previously reviewed in NRC inspection report 5000219/2004004, dated November 10, 2004. Based on GEs analysis of this issue, LER 2004-002-01 concluded that sufficient conservatism in the Appendix K analysis exists to adequately account for the peak clad temperature and maximum local cladding oxidation, and therefore the original SAFER/CORCL application methodology for conformance with the Appendix K analysis and 10 CFR 50.46 limits remain applicable for normal inerted containment conditions. Based on the results, Oyster Creek will maintain the corrective actions in place when containment is allowed to be de-inerted above 25% power. The inspectors reviewed this LER and no new issues were identified. This LER is closed.

4OA5 Other

.1 (Closed) URI 05000219/2007004-01, C Reactor Feedwater Pump Motor Failure

a. Inspection Scope

On July 17, 2007, Oyster Creek experienced an automatic reactor scram due to a low reactor water level following a trip of the C reactor feedwater pump. The NRC initially reviewed and discussed this issue in NRC inspection report 05000219/2007004, dated October 29, 2007 (ADAMS Ascension No. ML073030013).

The C reactor feedwater pump tripped due to an electrical ground fault in the pumps motor. AmerGen determined that the ground fault was identified as an age related internal winding problem that developed after thirty years of service. The inspectors noted that the motor was scheduled to be replaced in the next refueling outage.

AmerGen conducted an evaluation (IR 650654) to identify and understand why the motor did not get replaced prior to the age related failure. The inspectors performed a review of AmerGens evaluation associated with the failure of the C reactor feedwater pump.

b. Findings

No findings of significance were identified.

AmerGens investigation concluded that AmerGen did not adequately implement a preventive maintenance program to refurbish/replace the motors on a ten-year frequency. Specifically, in 2005 AmerGen recognized that the feedwater pump motors had not been replaced in over thirty years and developed plans to replace each of the feedwater pump motors over a six year period of time. AmerGen selected the B feedwater pump motor to be replaced in October 2006 during a refueling outage with the other pumps being replaced during subsequent refueling outages. The B feedwater pump was selected to be replaced first because it showed indications of accelerated wear and degradation. The C feedwater pump motor showed no signs of wear or degradation until its failure on July 17, 2007. Therefore, the inspectors concluded that a performance deficiency did not exist because it was not reasonable for AmerGen to have prevented this motor failure. This URI is closed.

4OA6 Meetings, Including Exit

Resident Inspector Exit Meeting. On January 18, 2007, the inspectors presented their overall findings to members of AmerGens management led by Mr. T. Rausch, Site Vice President, and other members of his staff who acknowledged the findings. The inspectors confirmed that proprietary information reviewed during the inspection period was returned to AmerGen.

4OA7 Licensee-Identified Violations

None.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

K. Cellars, Director, Maintenance

J. Dent, Director, Work Management

J. Dostal, Shift Operations, Superintendent

S. Dupont, Regulatory Assurance Specialist

S. Hutchins, Senior Manager Design Engineering

T. Keenan, Manager Security

D. Kettering, Director, Engineering

J. Kandasamy, Manager, Regulatory Assurance

G. Ludlam, Director, Training

J. Makar, Senior Manager System Engineering

P. Orphanos, Director, Operations

D. Peiffer, Manager Nuclear Oversight

J. Randich, Plant Manager

T. Rausch, Site Vice President

H. Ray, Manager, Engineering Programs

J. Renda, Manager Radiation Protection

T. Schuster, Manager Environmental/Chemistry Manager

T. Sexsmith, Manager Corrective Action Program

Others:

P. Schwartz, State of New Jersey, Bureau of Nuclear Engineering

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000219/2007005-04 URI Loss of A Condenser Vacuum and Trip of A Feedwater Pump Results in a Reactor Scram (Section 4OA3)

Opened/Closed

05000219/2007005-01 FIN Degraded Fuel Oil in the 1-1 Fire Diesel Fuel Oil Storage Tank Not Identified (Section 1R12)

05000219/2007005-02 FIN Service Water Pump Motor Failure Due to Inadequate Refurbishment Process (Section 1R12)

05000219/2007005-03 NCV Operations Personnel Did Not Appropriately Implement Reactor Startup Procedure (Section 4OA2)

05000219/2007005-05 NCV Inadequate Evaluation of IRM Channels Prior to Reactor Startup (Section 4OA3)

Closed

05000219/2007-002-00 LER Intermediate Range Monitor 16 Inoperable (Section 4OA3)

05000219/2004-002-01 LER Change in Methodology Used by General Electric (GE) and Global Nuclear Fuel to Demonstrate Complaince with Emergency Cooling System Performance Requirements (Section 4OA3)

05000219/2007004-01 URI C Reactor Feedwater Pump Motor Failure (Section 4OA5)