IR 05000219/2006005

IR 05000219-06-005; 10/01/06 - 12/31/06; Amergen Energy Company, LLC, Oyster Creek Generating Station; Operability Evaluations, Refueling and Outage Activities, and Event Followup

ML070190461
Person / Time
Site:	Oyster Creek
Issue date:	01/18/2007
From:	Bellamy R NRC/RGN-I/DRP/PB7
To:	Crane C AmerGen Energy Co
Bellamy R Rgn-I/DRP/Br7/610-337-5200
References
IR-06-005
Download: ML070190461 (51)

Text

ary 18, 2007

SUBJECT:

OYSTER CREEK GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 05000219/2006005

Dear Mr. Crane:

On December 31, 2006, 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 9, 2007, 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 two self revealing findings of very low safety significance (Green). Two of these findings were determined to involve a violation of NRC requirements. Additionally, two licensee-identified violations which were determined to be of very low safety significance are listed in this report. However, because of the very low safety significance and because they were entered into your corrective action program, the NRC is treating these four 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).

Mr. Christopher 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 7 Division of Reactor Projects Docket No. 50-219 License No. DPR-16 Enclosure: Inspection Report 05000219/2006005 w/ Attachment 1: Confirmatory Measurements Comparison Criteria w/ Attachment 2: Oyster Creek Environmental Sample Data Comparison of Split Samples w/ Attachment 3: Supplemental Information cc w/encl:

Chief Operating Officer, AmerGen Site Vice President, Oyster Creek Nuclear Generating Station, AmerGen Plant Manager, Oyster Creek Generating Station, AmerGen Regulatory Assurance Manager, Oyster Creek, AmerGen Senior Vice President - Nuclear Services, AmerGen Vice President - Mid-Atlantic Operations, AmerGen Vice President - Operations Support, AmerGen Vice President - Licensing and Regulatory Affairs, AmerGen Director Licensing, AmerGen Manager Licensing - Oyster Creek, AmerGen Vice President, General Counsel and Secretary, AmerGen T. ONeill, Associate General Counsel, Exelon Generation Company J. Fewell, Assistant General Counsel, Exelon Nuclear Correspondence Control Desk, AmerGen J. Matthews, Esquire, Morgan, Lewis & Bockius LLP Mayor of Lacey Township K. Tosch, Chief, Bureau of Nuclear Engineering, NJ Dept of Environmental Protection R. Shadis, New England Coalition Staff N. Cohen, Coordinator - Unplug Salem Campaign E. Gbur, Chairwoman - Jersey Shore Nuclear Watch E. Zobian, Coordinator - Jersey Shore Anti Nuclear Alliance P. Baldauf, Assistant Director, Radiation Protection and Release Prevention, State of NJ

Mr. Christopher

SUMMARY OF FINDINGS

IR 05000219/2006005; 10/01/06 - 12/31/06; AmerGen Energy Company, LLC, Oyster Creek

Generating Station; Operability Evaluations, Refueling and Outage Activities, and Event Followup.

The report covered a 3-month period of inspection by resident inspectors, senior project engineer, project engineer, regional inspectors, and announced inspections by a senior radiation specialist and senior emergency preparedness inspector. Two Green non-cited violations (NCV) and one Green finding 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 3, dated July 2000.

Cornerstone: Initiating Events

Green.

A self-revealing finding was identified regarding inadequate procedure adherence when work activities on the 480 V 1A2' switchgear during 1R21 refueling outage resulted in a trip of a reactor building closed cooling water (RBCCW) and shutdown cooling (SDC) pump on October 22, 2006. Specifically, the steps in the clearance order were performed out of sequence. This finding was determined to be a non-cited violation of technical specification 6.8.1a, Procedures and Programs.

AmerGens corrective actions for this issue involved remediation training for the operators involved; and senior management lead training sessions with all operations personnel, which reviewed managements expectations for use of error prevention tools such as procedural compliance, peer checking, and questioning attitude.

The finding was more than minor because it was associated with the configuration control attribute of the initiating events cornerstone and affected the objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown operations. This finding was evaluated using IMC 0609, Appendix G,

Shutdown Operations Significance Determination Process , attachment 1, checklist 7 because it occurred during a refuel outage and reactor coolant system level in the reactor vessel was greater than 23 feet. The finding was of very low safety significance because the issue did not degrade AmerGens ability to recover decay heat removal once it was lost. The performance deficiency had a cross-cutting aspect in the area of human performance because operators did not follow procedures. (Section 1R20)

Cornerstone: Mitigating Systems

Green.

The inspectors identified that AmerGen did not perform an adequate operability determination to assure the A isolation condenser (IC) could meet its design bases requirements with elevated shell temperatures on October 6, 2006. This finding was determined not to involve a violation of regulatory requirements. AmerGens corrective iii actions included repairing the valve, performing operator training on operability determinations, and revising procedures and calculations.

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. This finding is also similar to more than minor example 3.I in NRC Inspection Manual Chapter 0612, Appendix E, Examples of Minor Issues, in that calculations had to be re-performed to assure design requirements were met. In accordance with IMC 0609, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations, the inspectors conducted a Phase I SDP screening and determined the finding to be of very low safety significance (Green). The finding was of very low safety significance because the issue was not a design or qualification deficiency that resulted in a loss of function, did not result in an actual loss of safety function for a single train of equipment for a period of time greater than allowed by technical specifications, did not result in an actual loss of safety function of non-technical specification equipment considered risk significant in the maintenance rule program for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, and was not screened as potentially risk significant from external events. This performance deficiency had a cross-cutting aspect in the area of problem identification and resolution because AmerGen did not thoroughly evaluate a problem for operability. (Section 1R15)

Green.

A self revealing finding was identified regarding inadequate procedure implementation when the B 125 volt (V) direct current (DC) battery main breaker was inadvertently operated and resulted in a loss of power to the B DC distribution center on October 10, 2006. This finding was determined to be a non-cited violation of technical specification 6.8.1.a, Procedures and Programs. AmerGens corrective actions included disqualifying and remediation training of the operators involved, re-communicating managements expectations that self and peer checks and other error prevention tools should be utilized, and revising the operating procedure.

The finding was more than minor because it was associated with the human performance attribute of the mitigating systems cornerstone and affected the objective to maintain the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. In accordance with Inspection Manual Chapter (IMC) 0609, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations, the inspectors conducted a Phase I SDP screening and determined the finding to be of very low safety significance (Green). The finding was of very low safety significance because the issue was not a design or qualification deficiency that resulted in a loss of function, did not result in an actual loss of safety function for a single train of equipment for greater than allowed by technical specifications, did not result in an actual loss of safety function of one or more non-technical specification trains of equipment considered risk significant in the maintenance rule program for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, and was not screened as potentially risk significant from external events. The performance deficiency had a cross-cutting aspect in the area of human performance because operations personnel did not properly utilize human error prevention techniques such as self and peer checking. (Section 4OA3)iv

Licensee-Identified Violations

Violations of very low safety significance, which were identified by AmerGen were reviewed by the inspectors. Corrective actions taken or planned by AmerGen have been entered into their corrective action program. The violations and corrective actions are listed in Section 4OA7 of this report.

v

REPORT DETAILS

Summary of Plant Status

The Oyster Creek Generating Station (Oyster Creek) began the inspection period operating at 93% power due to end-of-cycle coastdown as they prepared for an upcoming refueling outage.

On October 15, 2006, operators commenced a planned shutdown to begin the 1R21 refueling outage. The main turbine was removed from service, a planned manual reactor scram was performed, and Oyster Creek was placed in cold shutdown on October 16, 2006. The plant commenced a startup following the refueling outage on November 10, 2006 and declared the reactor critical on November 11, 2006. Operators synchronized the main turbine generator to the grid on November 12, 2006. The plant reached full power on November 14, 2006.

On November 28, 2006, operators performed an unplanned downpower to 97% and removed the C reactor recirculation pump from service in accordance with abnormal and operating procedures after identifying an increase in #2 seal pressure on the pump. Operators placed the pump in idle in accordance with technical specification 3.3.F, Recirculation Loop Operability.

The plant returned to full power later that same day on November 28, 2006.

On December 1, 2006, operators commenced an unplanned power reduction due to a high temperature reading on the A reactor recirculation pump motor winding in accordance with operating procedures. The power reduction was halted at 95% when it was determined by engineering personnel that the measured temperature was erroneous because only one of the two temperature indicators was reading higher then expected. Full power was restored several hours later on December 2, 2006.

On December 8, 2006, operators performed an unplanned power reduction to 93% after the D electromatic relief valve (EMRV) opened and reclosed after approximately one minute without operator action. When the EMRV closed, reactor pressure increased, resulting in a power level increase to approximately 102% for nine seconds. Operators reduced power in response to the power increase. Operators responded to this transient in accordance with abnormal and operating procedures. Operators identified that the D EMRV did not fully close after it had lifted based on acoustic output and tail pipe temperature indications.

On December 9, 2006, operators commenced a planned power reduction to 60% to perform a control rod for flow swap and to investigate and repair feedwater heater level control valve problems. Operators also manually reopened the D EMRV in accordance with operating procedures to get the valve to fully reseat. The D EMRV properly reseated and was confirmed by a reduction in EMRV tailpipe temperatures. Full power was restored on December 10, 2006.

On December 11, 2006, during performance of a technical specification surveillance test for anticipatory scram due to turbine stop valve closure, the #3 main turbine stop valve failed to close. AmerGen Energy Company, LLC (AmerGen) performed troubleshooting and identified a ground in the test circuit, and determined the ground could not be repaired online. AmeGen developed an alternate test method by installing a temporary test circuit to perform the test.

AmerGen also determined that when the test is being performed reactor power should be reduced to 80% to ensure adequate safety margins would be maintained if a problem occurred during testing using the alternate method. On December 27, 2006, operators reduced power to 80% to perform the required technical specification surveillance test. The test was successfully performed and full power was restored on December 28, 2006.

Oyster Creek operated at or near full 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 sample)

The inspectors reviewed AmerGens response to one adverse weather preparation. The inspectors completed an adverse weather preparation inspection for seasonal readiness (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 reviewed the fire diesels, emergency diesel generators, auxiliary boiler system, and the heat trace systems to assess their readiness for seasonal susceptibilities (extreme cold temperatures). The inspectors performed a walkdown of the auxiliary boiler and supporting systems, fire diesels, and emergency diesel. The inspectors also reviewed applicable corrective action program condition reports to assess the reliability and material condition of these systems. AmerGens cold weather preparation activities were also reviewed to assess their adequacy and to verify they were completed in accordance with procedure requirements. 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 (4 samples)

The inspectors performed four 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:

• B 125 Volt (V) direct current (DC) distribution system on October 11, 2006;

• 4160 V, 480 V and 125 VDC Division 1 electrical distribution system on October 25, 2006;

• A and B isolation condenser on November 11, 2006; and

• 1-1', 1-3', and 1-4' emergency service water (ESW) pump on December 5, 2006.

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 (8 samples)

The inspectors performed a walkdown of eight plant areas to assess their vulnerability to 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. The following plant areas were inspected:

C Condenser bay on October 26, 2006; C B and D core spray pump room on October 27, 2006; C Control rod drive (CRD) pump room on November 11, 2006; C Lower cable spreading room on November 11, 2006; C Main control room on November 11, 2006; C Upper cable spreading room on November 14, 2006; C Fire diesel pump house on November 15, 2006; and C Recirculation pump motor-generator set room on November 15, 2006.

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

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures

a. Inspection Scope

(1 sample)

The inspectors performed one internal flood protection inspection activity in the southeast corner room of the reactor building which contains the 1-3' and 1-4' containment spray pumps. The inspectors performed a walkdown of the flood barriers, floor drains, and floor sumps. The inspectors evaluated these items to determine if internal flood vulnerabilities existed, and assessed the physical condition of the equipment and components in the southeast corner room. The inspectors reviewed preventive maintenance activities associated with flood protection equipment. The inspectors also reviewed AmerGens procedures related to flooding of the southeast corner room. Documents associated with these reviews are listed in the Supplemental Information attachment to this report.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program

a. Inspection Scope

(1 sample)

The inspectors observed one simulator training scenario on November 20, 2006, to assess operator performance and training effectiveness. The scenario involved a small steam leak in the drywell with a loss of the C 4160 Volt (V) bus. The inspectors assessed whether the simulator adequately reflected the 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

(1 sample)

The inspectors performed one maintenance effectiveness inspection activity. The inspectors reviewed the following degraded equipment issue in order to assess the effectiveness of maintenance by Amergen:

• Alternate rod insertion (ARI) valve V-15-137 failed to open during testing on November 9, 2006.

The inspectors verified that the systems or components were 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 to evaluate the effectiveness of AmerGens condition monitoring activities and determine whether performance goals were being met. The inspectors reviewed completed maintenance work orders and procedures to determine if inadequate maintenance contributed to equipment performance issues. The inspectors reviewed applicable work orders, corrective action program condition reports, preventive maintenance tasks, vendor manuals, and system health reports. Documents reviewed for this inspection activity are listed in the Supplemental Information attachment to this report.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

(4 samples)

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

C A isolation condenser (IC) and containment spray system #1' unavailable due to planned maintenance on October 13, 2006; C B 125 V DC bus unplanned unavailability due to a human performance issue on October 10, 2006; C Division 2 electrical distribution, M1A and M1B main transformers, and #2' service water pump unavailable due to planned maintenance on October 27, 2006; and C D EMRV unplanned unavailability due to a failure to close following an inadvertent opening, and #2' service water pump unavailable due to planned maintenance on December 8, 2006.

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 procedure guidance.

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 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

(2 samples)

The inspectors reviewed two operability determinations for degraded or non-conforming conditions associated with:

C A IC elevated shell temperature on October 13, 2006 (IR 541029); and C Rod worth minimizer and reactor manual control timer issue during reactor startup on November 12, 2006 (IR 556142).

The inspectors reviewed the technical adequacy of the operability determinations to ensure the conclusions were technically justified. The inspectors also walked down accessible equipment to corroborate the adequacy of AmerGens operability determinations. Documents reviewed for this inspection activity are listed in the Supplemental Information attachment to this report.

b. Findings

Introduction.

The inspectors identified that AmerGen did not perform an adequate operability determination to assure the A IC could meet its design bases requirements with elevated shell temperatures on October 6, 2006. This finding was of very low safety significance (Green) and determined not to involve a violation of NRC requirements.

Description.

On October 4, 2006, maintenance personnel completed preventive maintenance on the A IC outboard condensate return valve (V-14-34) breaker. During performance of the maintenance activity, the valve was maintained opened versus a normally closed position. This allowed steam flow through a bypass valve and through the IC tubes which caused shell temperatures to rise to approximately 210 degrees F.

Prior to returning the IC to an operable status, operations personnel identified the temperature rise and documented the condition in corrective action program condition report IR 540059. In addition, operations personnel began monitoring temperatures and chemistry personnel took shell water samples in accordance with operating procedure 307, Isolation Condenser System.

Operations personnel with assistance from engineering determined that with the elevated shell temperatures the A IC was operable and the shell temperatures observed were expected. Engineering personnel concluded that the temperatures would last a few days and start to decrease once the tube bundles were filled with condensate and equilibrium was reached. Based on the information provided by engineering, operations personnel declared the A IC operable on October 4, 2006.

On October 6, 2006, the inspectors noted during plant status activities that the A IC shell temperatures had increased to 212 degrees F. In addition, the inspectors noted that operating procedure 307, Figure 307-6 contained guidance for operating the IC at elevated shell temperatures. When the inspectors identified the shell temperature at 212 degrees F, the A IC shell level was 7.5 ft. In accordance with the guidance in the procedure, it was unacceptable to operate the isolation condenser at that temperature and level. The inspectors also determined the bases for the chart that was contained in the operating procedure by reviewing calculation C-1302-211-5450-089, Evaluation of IC Shell Heatup. The calculation determined the operating conditions (i.e., shell temperature and level) that should be maintained to ensure the ICs design bases requirement per technical specification 3.8, Isolation Condenser, basis section could be met. The technical specification basis section stated that one condenser can operate for 45 minutes prior to requiring makeup to its shell after a scram. The inspectors informed operations personnel that they believed Oyster Creek was being operated outside of procedural guidance and that the design bases requirement could not be met with the elevated temperatures based on the information contained in the design bases calculation. Specifically, the elevated shell temperature would reduce the operating time of the condenser to less than forty-five minutes.

Operations personnel discussed the inspectors' concerns with Oyster Creek management, and shortly thereafter operations personnel declared the A IC inoperable per technical specification 3.8, Isolation Condenser. Oyster Creek management staffed the outage command center, initiated a quick human performance investigation, and requested engineering perform an evaluation of the condition.

Engineering personnel completed operability evaluation OC-OE-2006-006 and determined that from October 4 thru October 6 the 45 minute criterion was not met. The operability evaluation also determined that with shell temperatures at 212 degrees F, shell level greater than 7.5 ft and reactor power less than 1783 MWth the A IC could meet its design basis requirements. On October 7, 2006, operations declared the A IC operable based on the operability evaluation performed by engineering and reactor power being less than 1783 MWth due to end-of-cycle coastdown for an upcoming refueling outage.

On November 2, 2006, AmerGen completed calculation EXOC011-CALC-001, Isolation Condenser Heat Capacity, and work order (WO) A2069637, Tube Integrity for Shell Level Below Top of Bundle, to demonstrate the A IC was operable between October 4 and 6, 2006. The calculation and WO also demonstrated that the IC design bases requirements can be met with shell temperatures of 212 degrees F and level within the required operating procedure criteria of 7.3 to 7.7 feet. This can be accomplished because AmerGens evaluation determined it was acceptable to uncover a portion of the tubes in the IC while it is in service for a short period of time. The previous calculation of record did not consider operating the IC in this manner following a reactor scram.

Based on these results, AmerGen revised operating procedure 307 and removed the IC shell temperature limits.

During the refueling outage which began in October 2006, AmerGen inspected and repaired the condensate return valve under work order A2152013. The internal inspection identified that the valve was not seating properly and allowing steam to pass through the IC tubes.

Analysis.

The performance deficiency associated with this finding involved an inadequate operability determination with the A IC with elevated shell temperatures.

AmerGens initial technical bases for operability was not supported by the engineering calculation and operating procedure at the time which provided operating criteria (i.e.,

shell level and temperature) to ensure the IC design requirement would be met after a reactor scram. AmerGens corrective actions included repairing the valve, performing operator training on operability determinations, and revising procedures and calculations.

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. This finding is also similar to more than minor example 3.I in NRC Inspection Manual Chapter 0612, Appendix E, Examples of Minor Issues, in that calculations had to be re-performed to assure design requirements were met. In accordance with IMC 0609, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations, the inspectors conducted a Phase I SDP screening and determined the finding to be of very low safety significance (Green). The finding was of very low safety significance because the issue was not a design or qualification deficiency that resulted in a loss of function, did not result in an actual loss of safety function for a single train of equipment for a period of time greater than allowed by technical specifications, did not result in an actual loss of safety function of non-technical specification equipment considered risk significant in the maintenance rule program for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, and was not screened as potentially risk significant from external events.

This performance deficiency had a cross-cutting aspect in the area of problem identification and resolution because AmerGen did not thoroughly evaluate a problem for operability.

Enforcement.

No violation of regulatory requirements occurred. Nonetheless, because the finding was of very low safety significance (Green) and AmerGen has entered this finding into their corrective action program in condition report IR 540059, this is identified as a finding. (FIN 05000219/2006005-01, Inadequate Operability Determination Associated With Elevated Isolation Condenser Shell Temperatures)

1R19 Post-Maintenance Testing

a. Inspection Scope

(5 samples)

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

• M1A and M1B main transformer on October 26, 2006 (WO A2115378);

• #1' emergency diesel generator (EDG) on October 27, 2006 (WO A2153171);

• B outboard main steam isolation valve (MSIV) on October 30, 2006 (WO A2152500);

• B feedwater inboard containment isolation valve on November 1, 2006 (WO A2153098); and

• B feedwater pump motor on November 6, 2006 (WO A2146882).

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 one refueling activity.

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

On October 15, 2006, operators initiated a plant shutdown to support the 1R21 refueling outage. The inspectors observed portions of the shutdown from the control room, and reviewed plant logs to determine that technical specification requirements were met for placing the reactor in hot shutdown and cold 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 drywell (primary containment) on October 16, 2006; and the condenser bay and the main steam tunnel on October 17, 2006, 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. The inspectors confirmed on a sampling basis that tagged equipment was properly controlled and equipment configured to safely support maintenance work. 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 also verified that the decay heat removal function was maintained through monitoring shutdown cooling (SDC) parameters during plant status and performing a walkdown of the system on October 16 and 17, 2006. The inspectors observed Oyster Creeks plant onsite review committee (PORC) startup affirmations from November 6 through November 9, 2006.

The inspectors determined whether offsite and electrical power sources were maintained in accordance with technical specification requirements and consistent with the outage risk assessment. Periodic walkdowns of portions of the onsite electrical buses and the EDGs were conducted during risk significant electrical configurations to confirm the equipment alignment met requirements. The inspectors verified through routine plant status activities whether decay heat removal safety function was maintained with appropriate redundancy as required by technical specifications and consistent with AmerGens outage risk assessment. The inspectors verified that flow paths, configurations, and alternative means for inventory control were consistent with the outage risk assessment.

The inspectors performed an inspection and walkdown of portions of the drywell prior to containment closure on November 9, 2006, to verify there was no evidence of leakage or visual damage to passive systems and to determine whether debris was left which could affect drywell suppression pool performance during postulated accident conditions. The inspectors monitored restart activities that began on November 10, 2006, 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 including the reactor going critical on November 11, 2006, as well as taking the mode switch to run and synchronization of the main turbine generator to the grid on November 12, 2006. The inspectors further verified that unidentified leakage and identified leakage rate values were within expected values and within technical specification requirements.

Inspectors performed followup inspections of AmerGens license renewal commitments related to the drywell shell and torus. In addition, the inspectors performed reviews of AmerGens evaluation of the discovery of water in the drywell concrete slab. Information on these items are contained in the NRC Preliminary Notification of Event or Unusual Occurrence Report PNO-1-06-012, dated November 9, 2006 (ADAMS Accession Number: ML063130424), and will be further detailed in NRC inspection report

===05000219/2006013 (to be issued).

b. Findings

Introduction.

A self-revealing finding was identified regarding inadequate procedure adherence when work activities on the 480 V 1A2' switchgear during 1R21 refueling outage resulted in a trip of a reactor building closed cooling water (RBCCW) and shutdown cooling (SDC) pump on October 22, 2006. Specifically, the steps in the clearance order were performed out of sequence. This finding was of very low safety significance (Green) and determined to be a non-cited violation of technical specification 6.8.1a, Procedures and Programs.

Description.

During 1R21 refueling outage, operators were in the process of hanging clearance 06501178 for work on the safety related 480 V 1A2' switchgear on October 22, 2006. The reactor cavity was flooded, and the mode switch was in refuel to support refueling operations. Reactor temperature was 88 degrees F, and the operators were maintaining temperature between 80 degrees F to 100 degrees F. The A and B SDC loops were in service, and the C loop was out of service for maintenance. The 1-1' and 1-2' RBCCW pump were in service supplying the fuel pool cooling heat exchangers. Plant risk was assessed as yellow due to high decay heat.

During the clearance activity, the A SDC pump and 1-1' RBCCW pump tripped.

Operators in the main control room received alarms for the pump trips, and implemented the annunciator response procedure and abnormal operating procedure associated with a loss of RBCCW and SDC. The trip of the pumps caused a reduction of SDC flow and reactor temperature rose 5 degrees F. Operators restored the A SDC and 1-1' RBCCW pumps to service within one hour after the event.

AmerGens investigation (IR 547452) identified that operations personnel applying the clearance did not implement the clearance in the order it was specified. Specifically, the operators performed steps ten through fourteen of the clearance (removing fuses)before steps two through nine (lifting leads) were completed. The clearance paperwork was located nearby, however it was not in hand and was not being marked and verified step by step as required by Oyster Creek procedure OP-MA-109-101, Clearance and Tagging.

The inspectors also noted that performing steps out of sequence is contrary to Oyster Creek procedure OP-MA-109-101, step 11.3.3.5 which states, Align and tag components in the sequence specified on the clearance. If a condition is encountered that requires the application of clearance tags to be performed out of sequence, then contact shift management.

Analysis.

The performance deficiency associated with this self-revealing finding involved inadequate procedure compliance. An operator performed the steps in a clearance activity out of sequence which is contrary to AmerGens procedure and resulted in a loss of one train of RBCCW and SDC and a 5 degree F rise in reactor temperature. AmerGens corrective actions for this issue involved remediation training of the operators involved; and senior management lead training sessions with all operations personnel which reviewed managements expectations for use of error prevention tools such as procedural compliance, peer checking, and questioning attitude.

The finding was more than minor because it was associated with the configuration control attribute of the initiating events cornerstone and affected the objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown operations. This finding was evaluated using IMC 0609, Appendix G, "Shutdown Operations Significance Determination Process," attachment 1, checklist 7 because it occurred during a refuel outage and reactor coolant system level in the reactor vessel was greater than 23 feet. The finding was of very low safety significance because the issue did not degrade the licensees ability to recover decay heat removal once it was lost.

The performance deficiency had a cross-cutting aspect in the area of human performance because operators did not follow procedures when they performed the clearance activity out of sequence.

Enforcement.

Technical specification 6.8.1a, requires, in part, that written procedures recommended in Appendix A of Regulatory Guide 1.33, Quality Assurance Requirements, shall be established, implemented, and maintained. Regulatory Guide 1.33 section 9e states that general procedures for the control of maintenance, repair, replacement, and modification work should be prepared. Contrary to the above, on October 22, 2006, AmerGen did not properly implement procedure OP-MA-109-101, Clearance and Tagging. Operators completed steps out of sequence for the safety related 480 V switchgear clearance activity, which resulted in a loss of one train of RBCCW and SDC during refuel operations. However, because the finding was of very low safety significance and has been entered into AmerGens corrective action program in condition report 547452, this violation is being treated as a non-cited violation, consistent with Section VI.A of the NRC Enforcement Policy. (NCV 05000219/2006005-02, Clearance Activity Performed Out of Sequence And Causes Trip of A Shutdown Cooling Pump)

=

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

• Scram discharge and instrument volume functional test on October 16, 2006;

• Primary containment isolation functional test on October 16, 2006;

• MSIV local leak rate test on October 17, 2006;

• Reactor Lo-Lo level functional test on October 17, 2006;

• Reactor coolant system unidentified leak rate integrator test on November 21, 2006; and

• Condensate transfer pump operability and in-service test on November 22, 2006.

The inspectors evaluated the test procedures to verify that applicable system requirements for operability were adequately incorporated into the procedures and that test acceptance criteria were consistent with Oyster Creeks technical specification requirements and the UFSAR. The inspectors also verified that test data was complete, verified, and met procedural requirements to demonstrate that systems and components were capable of performing their intended function. The inspectors also reviewed corrective action program condition reports that documented deficiencies identified during 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

(14 Samples)

The inspectors reviewed selected activities and associated documentation, in the area of access control to radiologically significant areas. The evaluation of Amergens performance was against criteria contained in 10 CFR 20 (Standards for Protection Against Radiation), applicable technical specifications, and AmerGens procedures.

The inspectors identified exposure significant work areas during station tours and walked down selected radiological controlled areas and performed independent radiation surveys. The inspectors reviewed housekeeping, material conditions, postings, barricades, and access controls to determine if radiological controls were acceptable. The inspectors determined if prescribed radiation work permits (RWP),procedures, and engineering controls were in place. The inspectors attended job briefings for selected work activities. The inspectors evaluated use of respiratory protective equipment. The inspectors conducted independent radiation surveys with a survey instrument to evaluate ambient conditions and adequacy of applied radiological controls in selected areas.

The inspectors toured outage work areas and reviewed ongoing radiologically significant work activities in the drywell, reactor building, turbine building, and refueling floor. The inspectors observed ongoing underwater diving activities within the torus. The inspectors conducted direct observation and review of ongoing outage work activities, including control rod drive replacement, and inboard and outboard main steam line valve maintenance. The inspectors also reviewed refueling outage work activities involving main turbine component sand blasting, control and stop valve maintenance, reactor disassembly, and resin transfer activities. The inspectors reviewed implementation of technical specification high radiation area controls, reviewed the adequacy of electronic dosimeter setpoints, and verified worker knowledge concerning actions required upon receiving an alarm. The inspectors evaluated the adequacy of personnel monitoring in areas of potential dose rate gradients. The review included evaluation of the adequacy of applied radiological controls including radiation work permits, procedure adherence, radiological surveys, job coverage, system breach surveys, airborne radioactivity sampling, contamination controls, barrier integrity and associated engineering control performance. The inspectors reviewed the use of electronic personnel dosimetry (EPDs) and inter-comparison of EPD results with thermoluminescent dosimetry results.

The inspectors reviewed internal dose assessments for 2006 (as of the time of the inspection), to identify apparent occupational internal doses greater than 50 millirem committed effective dose equivalent (CEDE). The review also included the adequacy of evaluation of selected dose assessments, as appropriate, and included a review of the program for evaluating potential intakes associated with hard-to-detect radionuclides (e.g., transuranics).

The inspectors reviewed physical and programmatic controls for highly activated or contaminated (non-fuel) material stored within spent fuel or other storage pools, as applicable.

The inspectors also conducted a post-outage walk-down of selected radiological controlled areas at Oyster Creek to evaluate post-outage housekeeping, material conditions, postings, barricades, and access controls, as appropriate.

The inspectors discussed procedure changes for high radiation area access controls since the last inspection with the radiation protection manager and supervisors to determine if these changes had resulted in a reduction in the effectiveness and level of radiological protection for workers. During walkdowns, the inspectors reviewed implementation of high and very high radiation area controls and discussed high radiation area controls with the in-field, lead radiological controls personnel. Postings, barricades, and locking of high radiation areas were reviewed. The inspectors discussed controls in place for special areas that had the potential to become very high radiation areas, when applicable.

During plant walkdowns, the inspectors observed radiation worker performance with respect to stated radiation protection work requirements. The inspectors questioned workers to determine if they were aware of the significant radiological conditions in their workplace, the RWP controls/limits that were in place, and if their performance took into consideration the level of radiological hazards present.

The inspectors observed radiation protection technician performance with respect to radiation protection work requirements to determine if they were aware of the radiological conditions in their workplace and the RWP controls/limits which were in place, and if their performance was consistent with expectations for potential radiological hazards present. The inspectors reviewed corrective action program condition reports to determine if issues existed with radiation protection technician performance.

The inspectors reviewed self-assessments and audits since the previous inspection to determine if identified problems were entered into the corrective action program for resolution. The inspectors evaluated the database for repetitive deficiencies or significant individual deficiencies to determine if self-assessment activities were identifying and addressing the deficiencies. The review also included an evaluation to determine if radiological issues had occurred which impacted NRC performance indicators (PI).

The inspection also included a review of corrective action condition reports since the last inspection which involved potential radiation worker or radiation protection personnel errors to determine if there was an observable pattern traceable to a similar cause. The review included an evaluation of corrective actions. In addition, the inspectors reviewed outage radiological oversight activities.

b. Findings

No findings of significance were identified.

2OS2 ALARA Planning and Controls (71121.02)

a. Inspection Scope

(5 Samples)

The inspectors reviewed activities and associated documentation in the planning and controls designed to maintain personnel occupational exposure as low as reasonably achievable (ALARA). The inspectors evaluated Amergens performance against criteria contained in 10 CFR 20 (Standards for Protection Against Radiation), applicable industry standards, and AmerGens procedures.

The inspectors reviewed pertinent information regarding station collective dose history, current exposure trends, and ongoing or planned activities in order to assess current performance and exposure challenges.

The inspectors reviewed 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 determined Oyster Creeks three-year rolling average collective exposure. The inspectors reviewed Oyster Creek procedures associated with maintaining occupational exposures ALARA. The inspectors also reviewed the processes used to estimate and track activity specific exposures.

The inspectors reviewed AmerGens planning and preparation for the 1R21 refueling outage to determine if AmerGen had established procedures, engineering and work controls, based on sound radiation protection principles, to achieve occupational exposures that were ALARA.

For planning purposes, the inspectors selected work activities likely to result in the highest personnel collective exposures and reviewed the planning and preparation for those work activities to determine if ALARA requirements were integrated into work procedure and RWP documents. The work activities reviewed included: under vessel work/control rod drive change-out; in-service inspection; scaffolding activities; various valve work activities; refueling activities; and radiological controls coverage.

The inspectors evaluated interfaces between operations, radiation protection, and other work groups, particularly in the area of source term controls. The use of shielding and other techniques (e.g., decontamination) to reduce exposures was reviewed.

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 for selected work activities conducted during the fall 2006 outage. The inspectors reviewed implementation of program requirements for re-evaluation of dose estimates including re-review of work plans by the station ALARA committee. The inspectors also reviewed exposure tracking for ongoing outage activities.

The inspectors observed workers to determine if they were utilizing low dose waiting areas and to determine if workers received appropriate on-the-job supervision to ensure the ALARA requirements were met. The inspectors also reviewed job supervisor oversight to ensure the work activities were conducted in a dose efficient manner (e.g., work crew size minimized, workers properly trained, proper tools and equipment).

The inspectors attended worker briefings to evaluate adequacy of radiological controls briefings. The inspectors also reviewed radiological exposure reports of individuals from selected work groups.

The inspectors reviewed AmerGens evaluations and efforts in the area of source term controls. Areas reviewed included: source term, chemical controls, shutdown methodology, and clean-up strategies. The inspectors reviewed primary system piping radiation measurements, including trends and current status. The inspectors also discussed longer term source term reduction plans and efforts.

The inspectors observed radiation worker and radiation protection technician performance during work activities being performed in radiation areas, airborne radioactivity areas, or high radiation areas. The inspector reviewed activities that presented the greatest radiological risk to workers (e.g., under vessel work, reactor refueling pool work). The inspectors determined if workers demonstrated the ALARA philosophy in practice (e.g., were workers familiar with the work activity scope and tools to be used, were workers utilizing ALARA low dose waiting areas) and whether there were any procedure compliance issues (e.g., were work activity controls being complied with). Also, the inspectors observed worker and technician performance to determine if it was consistent with expectations considering potential radiological hazards and the work involved.

The inspectors reviewed the exposure and monitoring controls employed by AmerGen for declared pregnant workers with respect to 10 CFR 20 requirements.

The inspectors reviewed overall ALARA performance for 2006, including the refueling outage. The inspectors compared accrued occupational dose, for various work tasks, relative to initial task estimates, including under vessel work/control rod drive change-out, in-service inspection, scaffolding activities, shielding activities, various valve work activities, and various refueling activities including reactor disassembly and reassembly.

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 reviewed methods used to adjust exposure estimates (e.g., work-in-progress reviews), when unexpected changes in scope or emergent work was encountered. The inspectors also reviewed the level of tracking detail, exposure report timeliness, and exposure report distribution.

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 reviewed dose significant post-job (work activity) reviews and post-outage ALARA report critiques of exposure performance to determine if identified problems were properly characterized, prioritized, and resolved.

b. Findings

No findings of significance were identified.

2OS3 Radiation Monitoring Instrumentation (71121.03)

a. Inspection Scope

(1 sample)

The inspectors reviewed activities and documentation in the area of radiation monitoring instrumentation and protective equipment. The inspectors evaluated AmerGens performance against criteria contained in 10 CFR 20, applicable technical specifications, and AmerGen procedures.

The inspectors reviewed the radiological source term at Oyster Creek, based on 10 CFR Part 61 (Licensing Requirements for Land Disposal of Radioactive Waste) data, to identify potential changes in radiation types and energies that could impact calibrations and/or analyses. The inspectors reviewed calibration and operability determination for selected instruments used for job coverage.

The inspectors reviewed audits and self-assessments in the area of radiation monitoring equipment and protective equipment to determine if identified issues in this area were entered into the corrective action program. The inspectors reviewed corrective action program condition reports to evaluate AmerGens threshold for identifying, evaluating, and resolving problems in this area.

b. Findings

No findings of significance were identified.

4OA1 Performance Indicator (PI) Verification

a. Inspection Scope

(5 samples)

The inspectors reviewed AmerGens program to gather, evaluate, and report information on five performance indicators (PIs) associated with the emergency preparedness, occupational radiation safety, and public radiation safety cornerstones. The inspectors used the guidance provided in Nuclear Energy Institute (NEI) 99-02, Revision 4, Regulatory Assessment Performance Indicator Guideline, to assess the accuracy of AmerGens collection and reporting of PI data. The inspectors reviewed licensee event reports (LERs), AmerGens monthly operating reports, NRC inspection reports, documentation from drills and tests, projected monthly and quarterly dose assessment results due to radioactive liquid and gaseous effluent releases, 2005 Annual Effluent Release Report and corrective action program condition reports.

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

• Emergency Response Organization Drill/Exercise Performance between October 1, 2005 through September 30, 2006;

• Emergency Response Organization (ERO) Participation between October 1, 2005 through September 30, 2006;

• Alert and Notification System (ANS) Reliability between October 1, 2005 through September 30, 2006;

• Occupational Exposure Control Effectiveness between October 1, 2005 through September 30, 2006; and

• RETS/ODCM Radiological Effluent Indicator between October 1, 2005 through September 30, 2006.

The inspectors noted that NRC inspection report 05000219/2006003, dated July 13, 2006, contained a typographical error in section 4OA1 of the report. Specifically, the inspectors verified the accuracy and completeness of data between the periods of January 1, 2005 through March 31, 2006 for the Safety System Function Failure (SSFF)

PI.

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, and/or accessing AmerGens computerized database.

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 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, nuclear oversight reports, and Oyster Creek monthly management reports.

The review considered a six-month period of July through December 2006.

Assessment and Observations The inspectors did not identify trends that could indicate the existence of a more significant safety issue. A substantive cross-cutting issue in the area of human performance at Oyster Creek was identified in the NRCs mid-cycle assessment letter, dated August 31, 2006. Specifically, weaknesses in the human performance cross-cutting aspect of procedure adherence were identified. During the past six months, Oyster Creek has implemented corrective actions and an excellence plan to improve plant performance in this area. As of the end of this inspection period, all training on procedure use and adherence had been completed except for portions of the maintenance department. Training is expected to be completed during the first quarter of 2007. The inspectors have noted a positive change in the understanding and knowledge by Oyster Creek personnel concerning managements expectations on procedure use and adherence. Mixed performance improvement has been achieved to date as demonstrated by a recent inspection finding in the fourth quarter of 2006 concerning procedure adherence during work on the 480 V switchgear (see Section

1R20 ), observations identified by inspectors during inspection activities, and self

assessments performed by AmerGen during the past six months.

The inspectors also noted that AmerGen identified a potential adverse trend in the area of work practices, specifically effective use of human error prevention techniques by Oyster Creek personnel. AmerGen was in the process of evaluating this potential issue and determining appropriate corrective actions in corrective action program condition report IR 577111.

In NRC inspection report 05000219/2006003, dated July 13, 2006, the inspectors noted that AmerGen had identified an extensive backlog (approximately 500 condition reports)of corrective action program condition reports that had not been assigned trend codes.

AmerGen management took effective corrective action to reduce the backlog and maintain the backlog below site goals. As of the end of the inspection period their were approximately 70 condition reports in the backlog that had not been assigned trend codes verses a goal of 100 condition reports.

.3 Annual Sample Review

a. Inspection Scope

(2 samples)

The inspectors reviewed AmerGens evaluation and corrective actions associated with the following two issues:

Inoperable Start-up Transformer due to A Phase Voltage Regulator (VR) Failure. The inspectors reviewed evaluations and recommendations from corrective action program condition reports IR 360859, 500493, and 516160 associated with issues on the Bank 5 startup transformer A phase voltage regulator. The Bank 5 and Bank 6 startup transformers (each with three single phase voltage regulators) supply off-site power to the 4160V switchgear during plant startup and shutdown. The Bank 5 startup transformer also supplies power to the dilution pumps. Normally two of three dilution pumps are running to maintain the mixed water temperature at the canal bridge below 97 degrees F.

On August 3, 2006, the Bank 5 startup transformer A phase voltage regulator failed, due to severe arcing of internal electrical components. The licensee placed the VR into the neutral position, declared Bank 5 startup transformer inoperable, and entered a seven-day LCO in accordance with technical specification 3.7.B.1, Auxiliary Electrical Power. On August 6, 2006, operations personnel reduced power from 100% to 50% to lower the discharge temperature, and installed temporary power (from a rented diesel)to keep one dilution pump running in order to replace the failed A phase voltage regulator with a spare (with new controller).

The A phase voltage regulator had also experienced equipment problems in May and June 2006. Specifically, on May 18, 2006, abnormalities were observed in the A phase voltage regulator controller-firmware that required replacement of the affected controller with a newer version of controller-firmware (IR 360859). On June 15, 2006, the A phase voltage regulator experienced a failure in its controller external to the voltage regulator housing (IR 500493). The controller was subsequently replaced and AmerGen was in the process of evaluating this issue when the failure on August 3, 2006, occurred.

The inspectors completed a detailed review of AmerGens evaluations and corrective actions for all three events to determine whether they were appropriate. The inspectors also reviewed the Doble test results (conducted in November 5, 2004), work orders for installing the new voltage regulator and its post installation testing to determine their adequacy, and walked down all six voltage regulators and controllers to detect any abnormal conditions.

2006 Nuclear Safety Culture Survey & Self Assessment. The inspectors reviewed Oyster Creeks focused area self assessment (FASA) report, Nuclear Safety Culture Survey (AT# 489001-03) and the associated responses to the safety culture survey questionnaire. In addition, the inspectors reviewed the methods used to collect and analyze the data to support the FASAs conclusions. The inspectors reviewed the survey to ensure it was adequate to assess the safety culture at Oyster Creek, the data was properly collected and analyzed, and the FASAs conclusions agreed with the data collected. The inspectors also reviewed corrective action program condition reports to ensure that the findings, observations, and recommendations of the FASA were captured in the corrective action program and corrective actions were developed as appropriate.

b. Findings and Observations

No findings of significance were identified.

Inoperable Start-up Transformer due to A Phase Voltage Regulator Failure. The inspectors considered AmerGens analyses and corrective actions reasonable as there were no specific maintenance requirements for this non-safety related equipment. In addition to replacing the A phase voltage regulator and its controller, AmerGen also changed the oil of the other five unaffected voltage regulators, and replaced their controllers with new ones which contained the new version of controller-firmware during the refueling outage in October 2006. The inspectors noted that all voltage regulators (except A phase voltage regulator which was replaced in August 2006) were 10 years old with only limited inspection and testing. Specifically, Amergen performed a daily tour and log of certain parameters of the controllers, oil samples were taken every six months, and one Doble test (required by the insurance company). The oil sample analysis did not include dissolved gas analysis, and there were no inspections to observe the condition of the moving mechanism inside the voltage regulator. The inspectors noted that this limits AmerGens ability to detect precursors of a moving part failure similar to the failure that occurred on August 3, 2006.

AmerGen plans to improve their maintenance and performance of the voltage regulators by: 1) installing a new oil sample valve in each VR which enables better samples to be obtained and will include dissolved gas analysis and trending of samples; 2) pursue replacing the other five voltage regulators with new ones during upcoming refueling outages and develop a preventive maintenance activity to replace the voltage regulators at predetermined time intervals; and 3) modify the power supply source to the dilution pumps from the Bank 5 startup transformer to a 4160 V source from the switch yard so that the operation of the dilution pumps would not be affected by maintenance on the Bank 5 voltage regulators.

2006 Nuclear Safety Culture Survey & Self Assessment. The inspectors determined that the survey was well designed and was a good tool to assess the safety culture at Oyster Creek. Approximately 60% of the surveys distributed were returned and analyzed. The data collection and analysis techniques were sound and supported the FASAs conclusions. The FASA did identify several areas for improvement in the safety culture environment and made recommendations to address these weaknesses.

The inspectors concurred with the overall conclusions of the FASA. However, the inspectors noted that the FASA failed to identify that the radiation protection/chemistry department scored the lowest among the Oyster Creek departments. Specifically, the radiation protection/chemistry department had statistically significant deviations from the other departments on ten of forty-eight questions. The FASA report did not document this or recommend corrective actions.

4OA3 Event Followup

(5 samples)

.1 Loss of B 125 V DC Power

a. Inspection Scope

On October 10, 2006, operators were in the process of swapping the B 125V DC battery chargers when the B battery output breaker was inadvertently opened and caused a loss of power to the bus. The inspectors responded to the site and observed operators returning the B bus to service after the event. The inspectors reviewed the control room logs and discussed the event with AmerGen management and operations personnel to gain an understanding of the conditions leading up to the event and actions taken immediately following to assess operator performance. The inspectors performed a walkdown of the electrical distribution system after restoration in accordance with NRC inspection procedure 71111.04, Equipment Alignment, to ensure the system was properly restored to an operable condition. The inspectors reviewed AmerGens evaluation (IR 542375) to assess the contributing causes of the event and proposed corrective actions. The inspectors also reviewed 10 CFR 50.72, Immediate Notification Requirements for Operating Nuclear Power Reactors, to determine if this condition was reportable.

b. Findings

Introduction.

A self-revealing finding was identified regarding inadequate procedure implementation when the B 125 V DC battery main breaker was inadvertently operated and resulted in a loss of power to the B DC distribution center on October 10, 2006.

This finding was of very low safety significance (green) and determined to be a non-cited violation of technical specification 6.8.1.a, Procedures and Programs.

AmerGens corrective actions included disqualifying and remediation training of the operators involved, re-communicating managements expectations that self and peer checks and other error prevention tools should be utilized, and revising the operating procedure.

Description.

On October 10, 2006 operators declared the safety related 125 V DC distribution center unavailable and inoperable in accordance with technical specification 3.7.A.1.e, "Auxiliary Electrical Power," when it lost power. When power was lost, operators were swapping battery chargers from the motor generator (MG) charger to the static charger in accordance with operating procedure 340.1, 125 V DC Distribution Systems A & B. During this activity the B battery main output breaker was opened instead of the MG set charger breaker, which caused a loss of power to the B DC distribution center. The loss of power to the distribution center caused a loss of control power and automatic trip functions for pumps and valves powered from the 'B'/'D' 4160 V and B 480 V switchgear. This condition did not cause equipment associated with the 4160 V or 480 V switchgear to become unavailable. In addition, operators assessed plant risk as red due to this condition.

Operators entered abnormal procedure ABN-54, DC Bus B and Panel/MCC Failures, and stationed operators to locally operate supply and load breakers on the 'B'/'D' 4160 V and B 480 V breakers. Operators returned the B 125 V DC distribution center to its normal alignment and power was restored in accordance with operating procedure 340.1 approximately three hours after power was lost.

AmerGen performed a prompt investigation (IR 542375) to determine the cause of this human performance event. AmerGen determined that the two operators assigned to the activity both identified the wrong component to operate. The evaluation also identified that the wording in the procedure was different than used on the labels for equipment in the field. AmerGens investigation determined that this event occurred due to a lack of adequate self and peer checks, lack of questioning attitude, inadequate use of error prevention tools such as flagging, lack of supervisor engagement in overseeing the evolution, and inadequate procedure quality.

Analysis.

The performance deficiency associated with this self-revealing finding involved inadequate procedure implementation. The procedure for swapping battery chargers was not properly implemented and resulted in a loss of power to the B 125 V DC distribution center. AmerGens corrective actions for this issue included disqualifying and remediation training of the operators involved, re-communicating managements expectations that self and peer checks and other error prevention tools should be utilized, and revising the operating procedure.

The finding was more than minor because it was associated with the human performance attribute of the mitigating systems cornerstone and affected the objective to maintain the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. In accordance with Inspection Manual Chapter (IMC) 0609, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations, the inspectors conducted a Phase I SDP screening and determined the finding to be of very low safety significance (Green). The finding was of very low safety significance because the issue was not a design or qualification deficiency that resulted in a loss of function, did not result in an actual loss of safety function for a single train of equipment for greater than allowed by technical specifications, did not result in an actual loss of safety function of one or more non-technical specification trains of equipment considered risk significant in the maintenance rule program for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, and was not screened as potentially risk significant from external events.

The performance deficiency had a cross-cutting aspect in the area of human performance because operations personnel did not properly utilize human error prevention techniques such as self and peer checking, such that the incorrect breaker was operated and safety related equipment was impacted.

Enforcement.

Technical specification 6.8.1, Procedures and Programs, requires, in part, that written procedures recommended in Appendix A of Regulatory Guide 1.33, Quality Assurance Requirements, shall be established, implemented, and maintained.

Regulatory Guide 1.33 section 4 states that instructions for energizing, filling, venting, draining, startup, shutdown, and changing modes of operation should be prepared for emergency power sources. Contrary to the above, on October 10, 2006, AmerGen did not properly implement operating procedure 340.1, 125 V DC Distribution System A &

B, and resulted in a loss of power to the B 125 V DC distribution center. However, because the finding was of very low safety significance (Green) and has been entered in the corrective action program in condition report IR 542375, this violation is being treated as an NCV, consistent with section IV.A of the NRC Enforcement Policy.

(NCV 05000219/2006005-03, Inadequate Procedure Implementation Results in Loss of Power to the B 125V DC Distribution Center)

.2 C Reactor Recirculation Pump #1 Seal Degraded

a. Inspection Scope

On November 28, 2006, operators noted that the C reactor recirculation pump #2' seal pressure was at 800 psig. The seal pressure had been increasing for several weeks and operations personnel were monitoring reactor recirculation pump seal performance on a daily bases. Oyster Creek ABN - 2, Recirculation System Failure, states that if the #2' seal pressure rises to 800 psig then the pump should be removed from service because the #1' seal is considered degraded. In accordance with ABN-2 and operating procedures, operators reduced power and removed the C reactor recirculation pump from service and placed the pump in idle.

The inspectors responded to the control room after hearing the site announcement that the C reactor recirculation pump was being removed from service. The inspectors observed the response of AmerGen personnel, including operator action in the control room. The inspectors verified that operators responded in accordance with procedures and equipment responded as intended. The removal of the C reactor recirculation pump from service was described and evaluated in corrective action program condition report IR 561679.

b. Findings

No findings of significance were identified.

.3 Inadvertent Actuation of the D EMRV

a. Inspection Scope

On December 8, 2006, operators performed an unplanned power reduction to 93% after the D EMRV opened and reclosed after approximately one minute without operator action. Operators confirmed the D EMRV had lifted based on acoustic output, tailpipe temperature, main control room indications, and a decrease in reactor pressure and power. When the EMRV reclosed, reactor pressure increased which resulted in a power level increase to approximately 102% for nine seconds. Operators reduced power, and responded to this transient in accordance with abnormal and operating procedures.

Operators identified that the D EMRV did not fully reseat after it had lifted based on acoustic output and tail pipe temperature indications.

On December 9, 2006, operators manually opened and closed the D EMRV in accordance with operating procedure 602.4.003, Electromatic Relief Valve Operability Test and were able to get the valve to properly reseat. The lifting and subsequent closing of the D EMRV is documented in corrective action program condition report IR 567038.

The inspectors responded to the control room after hearing the site announcement that the D EMRV had lifted. The inspectors observed the response of AmerGen personnel, including operator action in the control room. The inspectors verified that operators responded in accordance with procedures and equipment responded as intended by reviewing control room logs and discussing the event with AmerGen management and operations personnel to gain an understanding of the conditions leading up to the event and actions taken. The inspectors also observed operators manually open and close the D EMRV from the control room and confirmed the EMRV properly reseated on December 9, 2006.

b. Findings

A URI was identified to review AmerGens corrective action program evaluation (IR 567038) regarding the inadvertent actuation of the D EMRV on December 8, 2006.

The inspectors will review this evaluation after it is completed.

(URI 05000219/2006005-04, Inadvertent Actuation of D EMRV)

.4 Identification of Cesium-137 on AmerGens Owner Controlled Property

a. Inspection Scope

On December 6, 2006, AmerGen received the results on environmental samples which were collected in August and September 2006 on portions of the owner controlled area east of the Oyster Creek facility. The results indicated detectable levels of Cesium (Cs)-137 in both the soil and tree leaf samples that were analyzed. The gamma spectroscopy analysis did not identify other radionuclides in the samples taken. These samples were taken at locations not normally sampled as part of the radiological environmental monitoring program (REMP), since AmerGen was not able to collect samples from its normal location, a vegetable garden, because the garden crop was eaten by wildlife in the area in August 2006. No immediate reporting requirements were reached. AmerGen established an investigation team to evaluate potential public dose consequences, likely causes of the results, and coordinate additional sampling as needed to support the investigation.

The inspectors reviewed available data onsite associated with the issue on December 7, 2006, including AmerGens corrective action program condition report IR 566146. The inspectors reviewed the circumstances surrounding the identification of the samples, the reporting of information, and conformance with Oyster Creeks technical specifications and associated offsite dose calculation manual. The inspectors reviewed 10 CFR 50.72, Immediate Notification Requirements for Operating Nuclear Power Reactors, and determined this condition was not reportable.

The inspectors performed a walkdown of the area and made independent radiation level measurements on December 7, 2006. On December 13, 2006, in conjunction with personnel from the State of New Jerseys Bureau of Nuclear Engineering (BNE), the inspectors and NJ State personnel conducted additional radiation surveys and observed collection of split samples for independent analysis by AmerGen, NRC, and the State of New Jersey. The split samples were re-samples of the areas of highest indicated radioactivity (based on initial sample results) for independent laboratory analysis and included random and biased selected samples.

The inspectors reviewed the sample results obtained and also reviewed 2006 REMP sampling program results available to date. The data reviewed included effluent release data, monthly and quarterly projected public dose calculations, thermoluminescent dosimeter (TLD) data, and environmental particulate and iodine sampling results.

b. Findings

AmerGens preliminary dose assessments did not identify any significant credible public or occupational doses associated with the identification of detectable levels of Cs-137 within the owner controlled area. AmerGen performed conservative projected public doses calculations and the results were below 10 CFR 50 Appendix I and ODCM ALARA dose guidelines assuming a continuous occupancy scenario. No immediate reporting criterion was identified. The NRCs independent sampling and analysis results, for gamma emitting radionuclides, compared favorably with those of AmerGen.

At the conclusion of the inspection period, AmerGen was implementing its sampling and evaluation plan to identify potential causes, including validating expected Cs-137 background levels associated with previous weapons testing. Attachment 1, Confirmatory Measurements Comparison Criteria, provides a description of the sample comparison methodology. Attachment 2, Oyster Creek Environmental Sample Data Comparison of Split Samples, provides a comparison of AmerGens and NRCs sample analysis results from the split samples collected on December 13 and 14, 2006.

The inspectors noted that recent environmental TLD results from stations near the area did not show abnormal ambient radiation levels. AmerGens primary effluent release control and public dose analysis programs did not identify any significant public dose projections as a result of effluent release projections. In addition, established REMP sampling stations, in areas of expected maximum projected public dose, based on meteorology, did not identify any apparent significant recent effluent releases to the areas involved.

Notwithstanding the above, AmerGen was continuing to implement its investigation plan at the end of this inspection period. AmerGen was collecting additional sample results and conducting evaluations as to the probable cause for the presence of Cs-137. The inspectors will conduct additional follow-up on this issue to review the results of AmerGens evaluation when it is completed. (URI 05000219/2006005-05, Identification of Cesium-137 on AmerGens Owner Controlled Property)

.5 (Closed) LER 05000219/2006-003-00, Local Leak Rate Test Results in Excess of

Technical Specifications On October 16, 2006, AmerGen identified that inboard MSIV NS03B did not meet as-found local leak rate test (LLRT) acceptance criteria in accordance with technical specification 4.5.D.2, Containment Systems. At the time of discovery Oyster Creek was in cold shutdown for a refueling outage. An as-found local leak rate value could not be obtained on the MSIV because an adequate test pressure could not be maintained.

AmerGen determined the apparent cause to be an oxide layer build up on the valve poppet seat and in-body seat ring, which potentially caused the valve not to properly reseat and allowed a leakage pathway. On October 22, 2006, the inboard MSIV was successfully tested after troubleshooting. The safety significance of this event is considered minimal. The leakage past the inboard MSIV would have been limited by the leak rate of the outboard MSIV (NS04B) in the same main steam header which met the LLRT acceptance criteria when tested during the refueling outage. The inspectors reviewed this LER and no findings were identified. This LER is closed.

4OA5 Other

.1 (Closed) NRC Temporary Instruction (TI) 2515/169 Mitigating Systems Performance

Index Verification

a. Inspection Scope

The objective of TI 2515/169, Mitigating Systems Performance Index (MSPI), was to verify that licensees have correctly implemented the MSPI guidance for reporting unavailability and unreliability of monitored safety systems. The inspectors, on a sampling basis, selected key aspects of the MSPI to ensure that AmerGen followed the MSPI guidelines. The inspectors validated the unavailability and unreliability input data and verified the accuracy of the first reported results which occurred in the second quarter of 2006. The inspectors performed the following activities:

• Reviewed Oyster Creeks MSPI basis document and compared the listed systems against the guidance contained in NEI 99-02, Rev. 4, "Regulatory Assessment Performance Indicator Guidance," to verify that AmerGen was monitoring the correct systems;

• Reviewed surveillance test procedures to confirm that equipment was rendered unavailable only for a short duration, or can be rapidly restored to service using instructions provided in the procedures;

• Reviewed unavailability data for the MSPI target systems which was previously reported under the Safety System Unavailability PI for the period of 2002 through 2004. This review was performed to verify that the data was properly incorporated into the planned unavailability for MSPI;

• Reviewed a listing of work orders and corrective action condition reports for the period of January 2005 through October 2006, to verify planned and unplanned unavailability periods for the MSPI systems; and

• Reviewed Oyster Creek LERs and a list of corrective action condition reports for the period of January 2005 through October 2006, to identify failures of MSPI monitored components.

b. Findings and Observations

No findings of significance was identified.

The inspectors identified that the baseline planned unavailability hours for the MSPI systems were accurately documented. The inspectors determined that the actual unavailability hours were accurately documented. The inspectors determined that the actual unreliability was correctly documented for the samples selected. The inspectors did not identify any significant errors in the data used to calculate the MSPI value. The inspectors did not identify any significant discrepancies in the MSPI basis document.

.2 Institute of Nuclear Power Operations (INPO) Plant Assessment Report Review

a. Inspection Scope

The inspectors reviewed the final report for the INPO plant assessment of Oyster Creek conducted in January 2006. The inspectors reviewed the report to ensure that issues identified were consistent with NRCs perspectives of AmerGens performance and to verify if any significant safety issues were identified that required further NRC follow-up.

b. Findings

No findings of significance were identified.

4OA6 Meetings, Including Exit

Deputy Regional Administrator Site Visit. On October 20, 2006, a site visit was conducted by Mr. Marc Dapas, Deputy Regional Administrator, for the Region 1 office.

During Mr. Dapas visit, he toured the plant and met with AmerGen managers.

Resident Inspector Exit Meeting. On January 9, 2007, the inspectors presented their overall findings to members of AmerGens management led by Mr. T. Rausch, who acknowledged the findings. The inspectors confirmed that any proprietary information reviewed during the inspection period was returned to AmerGen.

4OA7 Licensee-Identified Violations

The following violation of very low safety significance (Green) were identified by AmerGen and are violations of NRC requirements which meet the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as an NCV.

• Oyster Creek License Condition 2.C(3), Fire Protection, requires that AmerGen will implement and maintain all provisions of the approved fire protection program as described in the UFSAR. Oyster Creek Procedure101.2, Oyster Creek Site Fire Protection Program, section 4.9, Fire Watch, states, in part, that if a fire protection system becomes inoperable, a fire watch will be established. Contrary to this, on October 26, 2006, AmerGen identified that a fire watch was secured and removed from the safety related 4160 V switchgear rooms when the fire damper and fire water sprinkler system were defeated and inoperable for over four hours. Contractors responsible for work in the area had closed out a separate work activity in the same area and then removed both fire watches in the area; however they did not recognize that one of the fire watches was for a different work activity. When the error was discovered, a fire watch was immediately dispatched to the area.

The violation was of very low safety significance (Green) because although the fire watch was not stationed as required by procedure, the duration of his absence was short, and the likelihood of a fire in the 4160 V switchgear room was considered low. This issue is described in corrective action program condition report IR 549199.

• Technical Specification 6.13.2, High Radiation Area, requires that locked doors be provided to prevent unauthorized entry to areas with a deep dose equivalent of 1000 millirem/hour at 30 cm from a source of radioactivity and that the keys to these areas be under the administrative control of operations and/or radiation protection supervision on duty. Contrary to this, on October 3, 2006, AmerGen identified that an HR-59 key, which provided access to a High Radiation Area greater than 1000 mR/hr at 30 cm, via the condenser bay southwest entrance, was not under the required administrative controls for an undetermined period of time.

The violation was of very low safety significance (Green) because AmerGen did not identify evidence of unauthorized entry. AmerGen also reviewed personnel exposure history and did not identify anomalus individual dose results associated with this area. This issue is described in corrective action program condition report IR 539585.

ATTACHMENT 1: Confirmatory Measurements Comparison Criteria ATTACHMENT 2: Oyster Creek Environmental Sample Data Comparison of Split Samples ATTACHMENT 3: Supplemental Information ATTACHMENT 1 Confirmatory Measurements Comparison Criteria The NRC applied the comparison criteria contained in NRC Inspection Procedure (IP)84750, Radioactive Waste Treatment, and Effluent and Environmental Monitoring, dated March 15, 1994, to determine if AmerGens measured results were in agreement with the NRCs measured results. For the purposes of this comparison, the NRCs results are divided by its associated uncertainty to obtain the resolution. Please note that for purposes of this process, the uncertainty is defined as the relative standard deviation, one sigma, of the NRCs contract laboratorys analysis. AmerGens results are then divided by the corresponding results from the NRCs tests to obtain the ratio (AmerGens results/NRCs results). AmerGens measurements are in agreement if the value of the ratio falls within the limits shown in the following table for the corresponding resolution.

Resolution Acceptance Range (AmerGens Results/NRCs Results)

<4 No comparison 4-7 0.5-2.0 8-15 0.6-1.66 16-50 0.75-1.33 51-200 0.80-1.25

>200 0.85-1.18 A-1-1 Attachment

ATTACHMENT 2 Oyster Creek Environmental Sample Data Comparison of Split Samples Environmental Sample Data Results (results in pCi/kg Cs-137)

December 13 -14, 2006 Samples Sample ID AmerGens NRCs Resolution Ratio Agreement Results Results based on

(+/-2 sigma) (+/-2 sigma) 1 sigma 12-4 489 +/-45 710 +/-60 24 0.68 disagree (0-5cm)12-4 137 +/-22 150 +/-20 15 0.91 agree (5-30cm)

BNE-01 572 +/-42 690 +/-60 23 0.82 agree (0-5 Cm)

BNE-01 199 +/-30 240 +/-30 16 0.82 agree (5-30 cm)13-9 516 +/-43 700 +/-60 23 0.74 disagree (0-5cm)13-9 115 +/-20 130 +/-20 13 0.88 agree (5-30cm)906-SAS 876 +/-63 1160 +/-80 29 0.75 agree (0-5cm)906-SAS 393 +/-32 470 +/-40 24 0.83 agree (5-30cm)

Hallock East 103 +/-25 90 +/-30 6 1.1 agree (0-5cm)

Hallock East 59 +/-25 80 +/-30 5 0.7 agree (5-30cm)

Hallock West 89 +/-25 90 +/-20 9 0.98 agree (0-5cm)

Hallock West 107 +/-24 110 +/-40 6 1.0 agree (5-30 cm)

A-2-1 Attachment

ATTACHMENT 3 Supplemental Information KEY POINTS OF CONTACT Licensee Personnel:

K. Barnes, Senior Reg. Assurance Engineer M. Button, Director Work Management J. Dostal, Shift Operations, Superintendent M. Godknecht, Programs Engineer S. Hutchins, Senior Manager Design Engineering T. Keenan, Manager Security D. Kettering, Director Engineering J. Kandasamy, Manager, Regulatory Assurance J. Magee, Director, Maintenance J. Makar, Senior Manager System Engineering D. Peiffer, Manager Nuclear Oversight J. Randich, Plant Manager J. Renda, Manager Radiation Protection T. Rausch, Site Vice President T. Schuster, Manager Environmental/Chemistry Manager S. Schwartz, System Engineer T. Sexsmith, Manager Corrective Action Program J. Vaccaro, Director Training R. Zacholski, Director Operations Others:

P. Schwartz, State of New Jersey, Bureau of Nuclear Engineering LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED Opened:

05000219/2006005-04 URI Inadvertent Actuation of D EMRV (Section 4OA3)05000219/2006005-05 URI Identification of Cesium-137 on AmerGens Owner Controlled Property Opened/Closed:

05000219/2006005-01 FIN Inadequate Operability Determination Associated With Elevated Isolation Condenser Shell Temperatures (Section 1R15)05000219/2006005-02 NCV Clearance Activity Performed Out of Sequence And Causes Trip of A Shutdown Cooling Pump (Section 1R20)

A-3-1 Attachment

05000219/2006005-03 NCV Inadequate Procedure Implementation Results in Loss of Power to the B 125V DC Distribution Center (Section 4OA3)05000219/2006-003-00 LER Local Leak Rate Test Results in Excess of Technical Specifications (Section 4OA3)

Closed:

05000219, 999/2515/169 TI Mitigating Systems Performance Index Verification LIST OF

DOCUMENTS REVIEWED

In addition to the documents identified in the body of this report, the inspectors reviewed the

following documents and records:

Section 1R01: Adverse Weather Protection

Procedures

OP-AA-108-111-1001, Severe Weather and Natural Disaster Guidelines

WC-AA-107, Seasonal Readiness

OP-OC-108-1001, Preparation for Severe Weather T&RN for Oyster Creek

OP-OC-108-109-1002, Cold Weather Freeze Inspection

OP-OC-108-109-1003, Winter Readiness

29, Reactor Building, Heating, Cooling, and Ventilation System

Condition Reports (IR)

570779

Other Documents

System Engineering System Readiness Review for Isolation Condensers

System Engineering System Readiness Review for Core Spray/ADS

System Engineering System Readiness Review for Containment Spray

System Engineering System Readiness Review for ESW

System Engineering System Readiness Review for 230 KV distribution

System Engineering System Readiness Review for 34.5 KV distribution

System Engineering System Readiness Review for Emergency Diesel Generator

System Engineering System Readiness Review for 125 Volt Station DC

System Engineering System Readiness Review for 24/48 Volt Instrumentation DC

System Engineering System Readiness Review for 480 Volt distribution

System Engineering System Readiness Review for Fire Diesel system

Section 1R04: Equipment Alignment

Procedures

307, "Isolation Condenser System"

337, 4160 Volt Electrical System

340.1, 125 V DC Distribution Systems A & B

310, Containment Spray System Operation

A-3-2 Attachment

Condition Reports (IR)

555244, 555673, 556394, 556557, 556631

Work Orders (AR)

C2012801, R2062448, C2011956

Other Documents

OE18031, "Additional Experience With Trico Opto-Matic oilers

Clearance # 6501069

Section 1R05: Fire Protection

Procedures

ABN-29, "Plant Fires,"

333, "Plant Fire Protection System,"

101.2, Oyster Creek Fire Protection Plan

OP-OC-210-008, "Oyster Creek Fire Plans,"

645.6.033, "Fire Detection System Alarm Circuitry Test for Control Room and Upper and Lower

Cable Spreading Room"

645.6.034, "Fire Detection System Alarm Circuitry Tests for 480V Switchgear Rooms, A/B

Battery Rooms and MG Set Room"

645.6.035, "Fire Detection System Alarm Circuitry Test for Office Building, Service Area, Old

Radwaste, Boiler House, Diesel Generator, and Fire Pump House"

Condition Reports (IR)

555682, 555825

Drawings

GU 3D-911-02-002, "Fire Area Layout Turbine Building Basement Floor

GU 3D-911-02-008, "Fire Area Layout Turbine Building Section C-C & D-D

GU 3D-911-02-001, "Fire Area Layout Turbine Building Basement Floor Plan

GU 3D-911-02-030, "Fire Area Layout Reactor Building Plan Floor Elevation

GU 3D-911-02-006, "Fire Area Layout Turbine Building Operating Floor

GU 3D-911-02-004, "Fire Area Layout Turbine Building Mezzanine Floor

GU 3D-911-02-020, "Fire Area Layout Reactor Building Section B-B

GU 3D-911-02-008, "Fire Area Layout Turbine Building Section C-C & D-D"

GU 3D-911-02-014, "Fire Area Layout Reactor Building Plan Floor Elevation 23'-6" "

GU 3D-911-02-030, "Fire Area Layout Fresh Water Pumphouse & Redundant Fire Protection

Pumphouse & Tank"

Other Documents

OC Fire Risk Analysis - Compartment Fire Scenario Development Report (R0467050033.04)

Oyster Creek Nuclear Generating Station Fire Hazard Analysis Report (990-1746)

Doc #990-1746, "Oyster Creek Nuclear Generating Station Fire Hazard Analysis Report,"

"Oyster Creek Individual Plant Examination for External Events," dated December 1995

Section 1R06: Flood Protection

Drawings

JC 147434, Sumps and Waste Collection System

A-3-3 Attachment

DWG 2184, Floor & Equipment Drains Plans & Details Reactor Building

Condition Report (IR)

436134, 503440, 541679, 564541, 521908

Work Order (AR)

R2049885, R2059894, R0806420, R0806421, R2066710, R2090296

Other Documents

FSAR 9.3.3.2.2, Reactor Building Floor & Equipment Drains

TDR 779, Evaluation of Possible Internal Flooding of OC Nuclear Generating Station Power

Plant Buildings

C-1302-822-E610-076, Flooding Due to HELBS Outside Containment

NRC Information Notice 2005-11, Internal Flooding/Spray Down of Safety Related Equipment

Due to Unsealed Equipment Hatch floor Plugs and/or Blocked Floor Drains

NRC Information Notice 200530, Safe Shutdown Potentially Challenged by Unanalyzed

Internal Flooding Events and Inadequate Design

NRC Information Notice 83-44, Potential Damage to Redundant Safety Equipment as a Result

of Backflow Through the Equipment and Floor Drain System

(a)(1) Action Plan - 1-6 and 1-7 Sump Isolation Valves V-24-35, 36, 37, and 38

System Manager Walkdown Report - 2nd Quarter 2006

System Manager Walkdown Report - 3rd Quarter 2006

Section 1R11: Licensed Operator Requalification Program

Procedures

330, Standby Gas Treatment System

RAP B4g, Safety Valve/EMRV not closed

RAP C3f, Drywell Pressure Hi/Lo

413, Operation of the Safety Valve/EMRV Acoustic Monitoring System

ABN-1, Reactor Scram

2000 EMG 3200.01A, Reactor Pressure Vessel Control With No ATWS

2000 EMG 3200.01B, Reactor Pressure Vessel Control With ATWS

Other Documents

EOP Users Guide (2000-BAS-3200.02)

Section 1R12: Maintenance Implementation

Procedures

ER-AA-310, Implementation of Maintenance Rule

ER-AA-310-1005, Maintenance Rule - Disposition Between (a)(1) and (a)(2)

619.3.001, SDIV Digital Level Cal and Test

Drawings

GE 197E871, SDIV flow diagram

GE 237E566, Elementary diagram Reactor Protection System

Condition Reports (IR)

555972, 560908, O2005-1946

A-3-4 Attachment

Work Orders (AR)

C2013709, A2114350, R2063782

Other Documents

NEI 93-01, Industry Guideline for monitoring the Effectiveness of Maintenance at Nuclear

Power Plants

Technical Specification 4.2, Reactor Control

Section 1R13: Maintenance Risk Assessments and Emergent Work Control

Procedures

ER-AA-600-1042, On-line Risk Management

WC-OC-101-1001, On-line Risk Management and Assessment

2.3.004, EMRV Pressure Sensor Cal and Test

619.3.006, Rx Triple Low Water Level Test and Calibration

Drawings

BR 3001, Electrical Distribution System

BR 3013, AC Vital One Line Diagram

Condition Report (IR)

567038, 539466

Other

Clearance # 6501089

OC-2006-OE-0008, Operability Evaluation for D EMRV

Section 1R15: Operability Evaluations

Procedures

LS-AA-105, Operability Determination

307, Isolation Condenser System

MA-AA-716-026, Station Housekeeping/Material Condition Program

119.5, Loose Equipment Storage

RAP-N3d, Alarm Response Procedure - Feedwater Heaters 1A)

Drawings

GE 148F262, Emergency Condenser Flow Diagram

Condition Reports (IR)

O2003-1110, 556073, 556142, 540059, 541029, 541777, 564370, 560470, 557679, 559878,

2464

Work Order (AR)

A2069637

Other Documents

Operator Logs for October 3-7, 2006

Operator Logs for November 10-11, 2006

A-3-5 Attachment

Operator Logs for November 14-19, 2006

Operability Eval: OC-OE-2006-0006, A Isolation Condenser

C-1302-211-5450-089, Evaluation of IC Shell Heatup April 19-26, 1995"

C-1302-211-5450-090, Isolation Condenser Shell Heat Capacity

Tube Integrity For Shell Level Below Top of Bundle (A2069637)

EXOC011-CALC-001, Isolation Condenser Heat Capacity

Section 1R19: Post-Maintenance Testing

Procedures

MA-AA-716-012, Post Maintenance Testing

636.4.001, Diesel Generator #1 Automatic Actuation Test

665.5.003, Main Steam Isolation Valve Leak Rate Test

24.4.001, Main Steam Valve Position Indication & IST Test

2.4.002, MSIV Closure & IST Test

665.5.004, Feedwater Isolation Valve Leak Rate Test

OP-MA-109-101, Clearance and Tagging

2400-SMM-3900.04, System Pressure Test Procedure (ASME XI)

Condition Report (IR)

548643, 549679, 549394, 549383, 544994, 556890

Work Order (AR)

C2012636, C2012632, A2115378, A2153171

Drawings

EM 839039, Emergency Diesel Generator #1 Electrical Elementary Wiring Diagram

BR 3000, Electrical Power System Key One Line Diagram

GE 237E566, Reactor Protection System Electrical Elementary Diagram

GE 237E726, Drywell & Suppression System Flow Diagram

BR 2003, Condensate and Feedwater Flow Diagram

Other

Clearance # 6501089

Section 1R20: Refueling and Outage Activities

Procedures

ABN-3, Loss of Shutdown Cooling

201, "Plant Startup"

203, Plant Shutdown

205.0, Reactor Refueling

205.1, Receiving and Processing New Fuel

303, Reactor Cleanup Demineralizer System

305, Shutdown Cooling System Operation

NF-AB-715, "Critical Predictions With Powerplex III"

1001.27, "Shutdown Margin Measurement Test "

OP-AA-108-108, Unit Restart Review

A-3-6 Attachment

Condition Report (IR)

556015, 556021, 556157, 556199, 556233, 556247, 556461, 556555, 556569, 556575,

556583, 554544, 556631, 552802, 552346, 553600, 553597, 553423, 553341, 553339,

553627, 557142, 556639, 554461, 554473, 553354, 553170, 554455, 551246, 548438

Other Documents

1R21 Refueling Outage Shutdown Safety Evaluation

"Oyster Creek Cycle 21 Estimated Critical Prediction for 1R21 Startup," dated November 10,

2006

Clearance # 06501827

Procedure 201, Attachment 201-9, "Reactor Coolant Temperature Heatup/Cooldown Plot,"

dated November 11, 2006

"Cycle 21 Core Operating Limits Report (COLR) - Oyster Creek,"

OP-AA-108-108, "Unit Restart Review," dated November 10, 2006

Section 1R22: Surveillance Testing

Procedures

LS-AA-104-1001, Exelon 50.59 Review Coversheet Form

665.5.003, Main Steam Isolation Valve Leak Rate Test

665.5.020, Integrated Local Leak Rate Test Summary

610.3.010, Rx Lo-Lo Level Test

619.3.004, Primary Containment Isolation Functional Test

619.4.022, Scram Discharge Volume Vent and Drain Valve Functional Test

644.4.002, Condensate Transfer Pump Operability and In-Service Test

205.94.0, RPV Floodup Using Core Spray

2.1, Control Rod Drive Hydraulic System

2.2, Control Rod Drive Manual Control System

316.1, Condensate Transfer System

RAP-H3E, Rx Level Lo-Lo I

RAP-H4E, Rx Level Lo-Lo II

Drawings

20451-H, 24 inch Globe Body Main Steam Isolation Valve - with Cylinder Operation

GE 885D781, Core Spray System

Condition Reports (IR)

544944, 545756, 544958, 544964, 544977, 544535, 548568,547723, 549369, 551222, 545835,

548883, 555946, 554342

Work Order (AR)

R2091030, A2148848

Other Documents

Technical Specification 4.2, Reactivity Control

NRC Regulatory Guide 1.163, Performance-Based Containment Leak-Test Program

Equipment Apparent Cause Evaluation for Failure of MSIV to pass initial LLRT

LER 2004-006, LLRT results in excess of Technical Specifications

Oyster Creek white paper, Chronological Listing of V-1-8 LLRT Tests

A-3-7 Attachment

1R20 and 1R19 MSIV LLRT data

50.59 review for RPV floodup using Core Spray

Section 2OS1: Access Control to Radiologically Significant Areas

Condition Report (IR)

551045, 550802, 550285, 549717, 548604, 547433, 547627

2OS2: ALARA Planning and Controls

Condition Report (IR)

54755, 547331, 546540, 546609, 546701, 549803,

2OS3 Radiation Monitoring Instrumentation and Protective Equipment

Condition Report (IR)

547627, 551302, 551306, 551329

Section 4OA2: Identification and Resolution of Problems

Other Documents

Oyster Creek Generating Station Business Plan Performance Report, November 2006

Oyster Creek SHIP System Summary Report

IR Trend Code Backlog Report, December 26, 2006

Station Focus Area Trend Report, December 26, 2006

Section 4OA1: Performance Indicator (PI) Verification

Procedures

LS-AA-2001, Performance Indicator Procedure

Other

NEI 99-02, Revision 4, Regulatory Assessment Performance Indicator Guidelines

Drill and Exercise Performance PI Data, October 2005 - September 2006

ERO Drill Participation PI Data, October 2005 - September 2006

Alert and Notification System Reliability PI Data, October 2005 - September 2006

Section 4OA3: Event Followup

Procedures

ABN-2, Recirculation System Failures

ABN-54, DC Bus B and Panel/MCC Failures

340.1, 125 VDC Distribution Systems A & B

2.43.003, Electromatic Relief Valve Operability Test

619.3.006, Rx Triple Low Water Level Test and Calibration

RAP-B3g, EMRV Open

ABN-40, Stuck Open EMRV

Drawings

GE 112C819, Reactor Plant Instrumentation Piping/Tubing

GE 112C2827, Spec Control Rack (RK03 Recirc Pump, Reactor Prot and NSS system

GE 729E182, Auto Depressurization System Electrical Elementary Drawing

Condition Reports (IR)

A-3-8 Attachment

561679, 542375, 567038

Work Orders (AR)

AR 2156939

Other Documents

NUREG-1022, Event Reporting Guidelines 10 CFR 50.72 and 50.73"

NEI 99-02, Rev 3, Regulatory Assessment Performance Indicator Guideline

Adverse Condition Monitoring Plan, #2 Seal Pressure for C Recirc pump

Control Room Logs October 10-11, 2006

Licensee Event Report 2006-003-00, Local Leak Rate Test Results in Excess of Technical

Specifications

OC-2006-OE-0008, Oyster Creek Operational Evaluation for D EMRV

Primary Plant Computer data on December 8, 2006 for reactor pressure, reactor power, reactor

water level, and recirculation pump flow

Technical Specification 4.5, Containment

Section 4OA5: Other

Procedures

607.4.004, Containment Spray and ESW System 1 Pump Operability and

Comprehensive/Preservice/Post-Maintenance IST

607.4.005, Containment Spray and ESW System 2 Pump Operability and

Comprehensive/Preservice/Post- Maintenance IST

607.4.007, Containment Spray and ESW System 1 Pump Operability Test

607.4.008, Containment Spray and ESW System 2 Pump Operability Test

607.4.014, Containment Spray and ESW System 1 Pump Operability, IST and Containment

Spray Pumps Trip

607.4.015, Containment Spray and ESW System 2 Pump Operability, IST and Containment

Spray Pumps Trip

607.4.016, Containment Spray and ESW System 1 Pump Operability and Quarterly IST

607.4.017, Containment Spray and ESW System 2 Pump Operability and Quarterly IST

609.4.001,Isolation Condenser Valve Operability and IST

610.4.003, Core Spray Valve Operability and IST

610.4.002, Core Spray Pump Operability Test

610.4.021, Core Spray System 1 Pump Operability and Quarterly IST

610.4.022, Core Spray System 1 Pump Operability and Quarterly IST

Other Documents

NRC Regulatory Issue Summary 2006-07, Changes to the Safety System Unavailability

Performance Indicators

NEI 99-02, Rev. 4, Regulatory Assessment Performance Indicator Guideline

OC-2006-001, Rev. 0, OCGS MSPI Basis Document

A-3-9 Attachment

LIST OF ACRONYMS

ABN Abnormal Operating Procedure

ADAMS Agency-wide Documents Access and Management System

ALARA As Low As Is Reasonably Achievable

AmerGen AmerGen Energy Company, LLC

ANS Alert and Notification System

ARI Alternate Rod Insertion

BNE Bureau of Nuclear Engineering

CEDE Committed Effective Dose Equivalent

CFR Code of Federal Regulations

COLR Core Operating Limits Report

CRD Control Rod Drive

CS Cesium

DC Direct Current

EDP Electronic Personnel Dosimetry

EDG Emergency Diesel Generator

EMRV Electromatic Relief Valve

ERO Emergency Response Organization

ESW Emergency Service Water

F Fahrenheit

FASA Focused Area Self Assessment

HRA High Radiation Area

IMC Inspection Manual Chapter

INPO Institute of Nuclear Power Operations

IPEEE Individual Plant Examination for External Events

IR Condition Report

LCO Limiting Conditions for Operation

LER License Event Report

LHRA Locked High Radiation Area

LLRT Local Leak Rate Test

MSPI Mitigating Systems Performance Index

NCV Non-Cited Violation

NEI Nuclear Energy Institute

NRC Nuclear Regulatory Commission

Oyster Creek Oyster Creek Generating Station

PARS Publicly Available Records

PI Performance Indicator

PORC Plant Onsite Review Committee

RAP Annunciator Response Procedure

RBCCW Reactor Building Closed Cooling Water

RCA Radiologically Controlled Area

REMP Radiological Environmental Monitoring Program

RWP Radiation Work Permit

SDC Shutdown cooling

SDP Significance Determination Process

SSFF Safety System Functional Failure

TLD Thermoluminescent Dosimetry

TI Temporary Instruction

UFSAR Updated Final Safety Analysis Report

A-3-10 Attachment

URI Unresolved Item

V Volt

WO Work Order

A-3-11 Attachment