IR 05000255/2007006

IR 05000255-07-006, on 07/01/2007 - 09/30/2007; Palisades Nuclear Plant, Integrated Inspection Report

ML073100888
Person / Time
Site:	Palisades
Issue date:	11/06/2007
From:	Christine Lipa Reactor Projects Region 3 Branch 4
To:	Schwartz C Entergy Nuclear Operations
References
IR-07-006
Download: ML073100888 (56)

Text

November 6, 2007

SUBJECT:

PALISADES NUCLEAR PLANT NRC INTEGRATED INSPECTION REPORT 05000255/2007006

Dear Mr. Schwarz:

On September 30, 2007, the U. S. Nuclear Regulatory Commission (NRC) completed an inspection at your Palisades Nuclear Plant. The enclosed report documents the inspection findings which were discussed on October 3, 2007, with you and 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.

In addition, the report documents four NRC-identified findings and one self-revealed finding of very low safety significance (Green). All five of these findings were determined to involve violations of NRC requirements. However, because the violations were of very low safety significance and because the issues have been entered into your corrective action program, the NRC is treating these findings as a non-cited violation (NCVs) consistent with Section VI.A.1 of the Enforcement Policy.

If you contest the subject or severity of an NCV, you should provide a response with a basis for your denial, within 30 days of the date of this inspection report, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C. 20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspector at the Palisades facility. 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 NRC's document system (ADAMS), accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/ Robert M. Lerch Acting For Christine A. Lipa, Chief Branch 4 Division of Reactor Projects Docket No. 50-255 License No. DPR-20 Enclosure:

Inspection Report 05000255/2007006 w/Attachment: Supplemental Information DISTRIBUTION See next page

SUMMARY OF FINDINGS

IR 05000255/2007006; 07/01/2007 - 09/30/2007; Palisades Nuclear Plant; Maintenance

Effectiveness; Maintenance Risk Assessments and Emergent Work Control; Temporary Plant Modifications; Identification and Resolution of Problems; Other Activities This report covers a three-month period of baseline inspections. The inspections were conducted by Region III inspectors and inspectors based in the NRC Region III office.

This report includes five Green findings, all which were non-cited violations (NCVs). The significance of most findings is indicated by their color (Green, White, Yellow, 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 Nuclear Regulatory Commission (NRC) management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 4, dated December 2006.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Initiating Events

Green.

A self-revealed finding and associated NCV of Technical Specification 5.4.1 was identified for failure by the licensee to follow procedural requirements. On May 13, 2007, the licensee failed to monitor for leakage across a Low Pressure Safety Injection (LPSI) check valve as required by procedure and a protective relief valve lifted.

Following lifting of the relief valve, the licensee seated the check valve to prevent further back leakage and entered the deficiency onto their corrective action program.

In accordance with IMC 0612, the inspectors concluded that the issue was more than minor because the failure to limit pressure in the LPSI piping until a protective device actuated increased the likelihood of an initiating event. After consultation with the Senior Risk Analyst (SRA), the inspectors concluded that the finding was of very low safety significance because of the extremely low frequency of the Interfacing System Loss of Coolant Accident initiating event. This finding included a cross-cutting aspect in the area of human performance in that human error prevention techniques (H.4(a)) were not effective in preventing lifting of the relief valve. (Section 4OA2)

Cornerstone: Mitigating Systems

Green.

The inspectors identified a Green NCV of 10 CFR 50.65(b)(2) because the licensee did not scope all plant radiation monitors used in site emergency operating procedures into the maintenance rule monitoring program. The licensee entered the item into their corrective action program and placed the radiation monitoring system in the a(1) status.

The finding was more than minor because it impacted the equipment performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. This finding was considered to have very low safety significance (Green) because the finding did not cause a loss of mitigation equipment functions and did not increase the likelihood of a fire or flooding event. (Section 1R12)

Green.

The inspectors identified a Green NCV of 10 CFR Part 50.65(a)(4), because the licensee did not adequately assess and manage online risk while performing a safety injection system actuation test. Specifically, prior to performance of the safety injection test, the inspectors identified that the test did not account for unavailability of a high pressure safety injection (HPSI) train. Accounting for the HPSI unavailability resulted in yellow risk. The licensee implemented appropriate risk mitigation actions prior to entering yellow risk. The licensee entered the item into their corrective action process and updated the risk assessment.

The finding was more than minor because it impacted the mitigating systems cornerstone objective to ensure availability of systems and the risk assessment failed to consider risk-significant systems, structures, components (i.e., high pressure safety injection pumps) which were unavailable during on-line maintenance. The inspectors concluded that the finding was of very low safety significance because the incremental core damage probability deficit was less than 1 x 10E-6 (green) in accordance with IMC 0609, Appendix K. The finding included a cross-cutting aspect in the area of human performance, work controls, in that the licensee failed to incorporate appropriate risk insights when coordinating work activities. (H.3.(a)) (Section 1R13)

• Severity Level IV. The inspectors identified a severity level (SL) IV NCV of 10 CFR 50.59, Changes, Tests, and Experiments for the licensees failure to perform a written evaluation prior to implementing a temporary modification to compensate for the absence of containment air cooler VHX-4. Specifically the modification adversely impacted the service water (SW) system and this was not evaluated in accordance with 10 CFR 50.59. The licensee entered the item into their corrective action process, added structural elements to minimize fouling of the service water system, evaluated the change in accordance with 10 CFR 50.59, and performed a written evaluation. The revised modification did not require prior NRC approval.

The inspectors concluded this finding was more than minor since it impacted the NRCs ability to perform its regulatory function and resulted in a condition which reduced the reliability of the SW system, a mitigating system. The inspectors concluded the original modification may have required prior NRC approval. The issue screened green in the phase 3 assessment for the equipment degradation and therefore was of very low safety significance, and therefore, SLIV. The finding has a cross-cutting aspect in the area of human performance in that the licensee failed to use conservative assumptions in decision making and failed to identify possible unintended consequences when implementing the augmented cooling for service water modification. (H.1.(b))

(Section 1R23)

Green.

The inspectors identified a Green non-cited violation NCV of 10 CFR 50,

Appendix B, Criteria III, Design Control for failing to adequately translate the design and licensing basis requirements into equipment specifications for the 8A and 8B Auxiliary Feedwater (AFW) pumps and controls. Specifically, the 8A and 8B pumps have a licensing basis to be operable during a High Energy Line Break (HELB) event in the turbine building; however, in some HELB scenarios the pumps would experience a harsh environment. The licensee did not qualify the pumps and associated equipment for a harsh environment. The licensee wrote a condition report and an operability recommendation (OPR) with compensatory actions to address the issue.

The finding was more than minor because it impacted the equipment performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of the AFW system to respond to initiating events. A phase 2 screening was required since the design qualification deficiency resulted in a loss of function for one train of AFW per Generic Letter 91-18. The SRA concluded in a phase 3 evaluation, which included external events, that the finding was of very low safety significance (Green). (Section 4OA5)

Licensee-Identified Violations

None

REPORT DETAILS

Summary of Plant Status

The plant began the inspection period at or near full rated thermal power. On or about September 1, the plant began coast down, and on September 9, 2007, the plant conducted a planned reactor shutdown to start refueling outage 19 (R19). The plant remained shut down for the remainder of the quarter.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and Emergency Preparedness

1R01 Adverse Weather Protection

.1 Adverse Weather Preparation

a. Inspection Scope

The inspectors completed one adverse weather site sample. The inspectors reviewed the sites procedure and readiness for high winds and strong thunderstorms on July 19, 2007. The inspectors reviewed the licensees procedures to determine if actions specified could be completed with expected plant staffing and to determine if areas identified would be accessible. In addition, the inspectors compared proceduralized actions with the Updated Final Safety Analysis Report (UFSAR) to determine if vulnerabilities existed. The inspection focused on actions needed due to a non-conformance that existed on the AFW pumps in the turbine building. Because the potential existed that the AFW pumps may not be available during a HELB, the inspectors also reviewed the compensatory actions needed for adverse weather related to non-conformances at the site.

b. Findings

No findings of significance were identified.

==1R04 Equipment Alignment

==

.1 Partial Walkdowns

a. Inspection Scope

The inspectors completed three equipment alignment inspection samples by performing partial walkdowns on the following risk-significant plant equipment:

• Instrument air system, compressors 2A and 2B with compressor 2C unavailable for maintenance

• Service water system during planned unavailability of the C SW pump

• Support train equipment with Motor Control Center 25 (MCC-25) out of service for planned maintenance During the walkdowns, the inspectors verified that power was available, accessible equipment and components were appropriately aligned, and no open work orders for known equipment deficiencies existed which would impact system availability.

The inspectors also reviewed selected condition reports (CRs) related to equipment alignment problems and verified that identified problems were entered into the corrective action program with the appropriate significance characterization and that planned and completed corrective actions were appropriate and implemented as scheduled. The documents reviewed during this inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

.2 Complete Walkdown

The inspectors completed one semiannual equipment alignment inspection sample by performing a complete walkdown of the component cooling water (CCW) system.

Utilizing piping and instrumentation diagrams and system checklists, the inspectors verified that accessible system components were correctly aligned. The inspectors also reviewed open maintenance work orders to verify that the equipments safety function was not adversely impacted by pending work. The inspectors reviewed operator work arounds (OWA) associated with the CCW system to verify the OWA did not adversely affect system operation.

The inspectors reviewed select condition reports associated with the CCW system to verify that identified problems were entered into the corrective action program with the appropriate significance characterization. The inspectors also verified that planned and completed corrective actions were appropriate.

==1R05 Fire Protection

==

.1 Fire Area Walkdowns

a. Inspection Scope

The inspectors completed six fire protection inspection samples by touring the following areas in which a fire could affect safety-related equipment:

• AFW pump room in turbine building (FA 24);

• SW intake structure (Room 136);

• Station batteries and cable spreading room (Room 224);

• Cableway north penetration room (Room 328);

• East safeguards room during R19 (Fire Area 10); and

• Containment during RF19 (Fire Area 14).

The inspectors verified that transient combustibles and ignition sources were appropriately controlled, and that the installed fire protection equipment in the fire areas corresponded with the equipment that was referenced in the UFSAR, Section 9.6, "Fire Protection." The inspectors also assessed the material condition of fire suppression systems, manual fire fighting equipment, smoke detection systems, fire barriers and emergency lighting units. For selected areas, the inspectors reviewed documentation for completed surveillances to verify that fire protection equipment and fire barriers were tested as required to ensure availability.

The inspectors reviewed selected CRs associated with fire protection to verify that identified problems were entered into the corrective action program with the appropriate significance characterization. The inspectors also verified that planned and completed corrective actions were appropriate. The documents reviewed during this inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R07 Heat Sink Performance

a. Inspection Scope

The inspectors completed one annual sample of heat sink performance. The inspectors visually inspected the internals of CCW heat exchanger E-54A and containment air cooler VHX-3 during planned maintenance of the heat exchangers. In addition, the inspectors reviewed licensee tube inspection results and associated CRs related to these heat exchangers. The inspectors concluded the licensee effectively maintained the availability of the heat exchangers.

b. Findings

No findings of significance were identified.

1R08 Inservice Inspection (ISI) Activities

.1 Piping Systems ISI

a. Inspection Scope

From September 10, 2007, through September 26, 2007, the inspectors conducted a review of the implementation of the licensees Risk-Informed Inservice Inspection Program (RI-ISI) program for monitoring degradation of the reactor coolant system boundary and the risk significant piping system boundaries. The inspectors selected the licensees RI-ISI program components and American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Section XI required examinations and Code components in order of risk priority as identified in Section 71111.08-03 of the inspection procedure, based upon the ISI activities available for review during the on-site inspection period.

The inspectors observed or performed a record review of the following two types of nondestructive examination (NDE) activities to evaluate compliance with the ASME Code Section XI and Section V requirements and to verify that indications and defects (if present) were dispositioned in accordance with the ASME Code Section XI requirements.

• Reviewed records and interviewed examiners for Ultrasonic Examination (UT) of pressurizer nozzle-to-safe end welds (PZR-006, weld 1; 007, weld 1; and 008, Weld 1)

• Observed Dye Penetrant (PT) Examination of an essential service water pipe lug (H722)

The inspector reviewed an examination completed during the previous outage with relevant/recordable conditions/indications that were accepted for continued service to verify that the licensees acceptance was in accordance with the Section XI of the ASME Code. Specifically, the inspector reviewed the following records:

• The inspectors reviewed radiographic examination records of a critical service water weld (NSW-010A Weld 23). During this examination, the licensee recorded porosity which was analyzed in accordance with ASME Code requirements prior to returning the Unit to service.

The inspectors reviewed pressure boundary welds for Class 1 or 2 Systems which were completed since the beginning of the previous refueling outage to determine if the welding acceptance and pre-service examinations (e.g., Visual Testing (VT), PT, and weld procedure qualification tensile tests) were performed in accordance with ASME Code Sections III, V, IX, and XI requirements. Specifically, the inspectors reviewed welds associated with the following work activities;

• Repair/replacement (welding) of ASME Class 2 safety injection refueling water tank recirculation pump (P-74)

• Repair/replacement (welding) of ASME Class 2 HPSI Pump P-66B Subcooling Valve (CV-3070)

The inspectors observed activities associated with the repair/replacement activities for control valve CV-0824 and associated piping. The repair work resulted from a small leak discovered in the critical service water header from containment to the makeup basin, approximately one foot downstream of CV-0824.

The activities described above counted as one inspection sample.

b. Findings

No findings of significance were identified.

.2 Pressurized Water Reactor Vessel Upper Head Penetration (RVUHP) Inspection

Activities

a. Inspection Scope

Since repairs were previously performed on control rod drive mechanism (CRDM)penetrations numbers 29 and 30, the Unit was considered to be in the high susceptibility ranking category and inspection activities were conducted in accordance with NRC Order EA-03-009. For each NDE activity performed by the licensee with regard to the RVUHPs, the inspectors performed the following either through direct observation or through record review:

• Verified that the activities were performed in accordance with the requirements of NRC Order EA-03-009; and

• Verified that indications and defects, if detected, were dispositioned in accordance with the ASME Code or an NRC approved alternative (e.g., approved relief request).

In keeping with the Order, both visual examination (VT-2) and non-visual examinations (eddy current testing (ET) and UT) were performed. The inspectors conducted a record review of the VT examination, and the licensees criteria for confirming visual examination quality to ensure minimum examination coverage.

The inspectors also observed a sample of the non-visual examinations performed. In particular, the inspectors observed UT testing of a minimum of 10 percent of the other 53 head penetrations, including a number of in-core instrumentation (ICI) penetrations and CRDM penetrations. The inspectors reviewed the NDE examination procedures and confirmed that the calibration requirements (essential variables) were consistent with those used in vendor mockup demonstrations. The inspectors also reviewed the examination records to verify extent of coverage of each penetration.

There were no examinations completed during the previous outage with relevant/recordable conditions/indications that were accepted for continued service.

There were no welding repairs on the upper head penetrations completed since the beginning of the previous refueling outage.

The reviews as discussed above counted as one inspection sample.

b. Findings

No findings of significance were identified.

.3 Boric Acid Corrosion Control (BACC) ISI

a. Inspection Scope

From September 9, 2007 through September 25, 2007, the inspectors reviewed the BACC inspection activities conducted pursuant to licensee commitments made in response to NRC Generic Letter 88-05 Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary.

The inspectors conducted a direct observation of BACC visual examination activities to evaluate compliance with licensee BACC program requirements and 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action requirements. Specifically;

• On September 9, 2007, following shutdown, the inspectors accompanied licensee personnel for portions of the post-shutdown normal operating pressure, normal operating temperature boric acid walkdown in containment.

The inspectors verified that the visible boric acid leaks were identified by the licensee and entered into their BACC program.

• The inspectors also reviewed the visual examination procedures and examination records for the BACC examination to determine if degraded or non-conforming conditions were properly identified in the licensee's corrective action system.

The inspectors reviewed the engineering evaluations performed for the following corrective action documents to ensure that ASME Code wall thickness requirements were maintained:

• CR-PLP-2006-04370, component CK-ES3339; HPSI pump min-flow check valve

• CR-PLP-2007-01654; component MV-ES3413 PI-0325; HPSI pump root valve

• The inspectors also reviewed a number of boric acid leak corrective actions to determine if they were consistent with the requirements of the ASME code and 10 CFR Part 50, Appendix B, Criterion XVI. The documents reviewed during this inspection are listed in the Attachment to this report.

The above counted as one inspection sample.

b. Findings

No findings of significance were identified.

.4 Steam Generator (SG) Tube Inspection Activities

a. Inspection Scope

From September 17, 2007 through September 25, 2007, the inspectors performed an on-site review of SG tube examination activities conducted pursuant to Technical Specification (TS) and the ASME Code Section XI requirements. The NRC inspectors observed acquisition of ET data, interviewed ET data analysts, and reviewed documents related to the SG ISI program to determine if:

• in-situ SG tube pressure testing screening criteria and the methodologies used to derive these criteria were consistent with the Electric Power Research Institute (EPRI) TR-107620, Steam Generator In-Situ Pressure Test Guidelines;

• the numbers and sizes of SG tube flaws/degradation identified was bound by the licensees previous outage Operational Assessment predictions;

• the SG tube ET examination scope and expansion criteria were sufficient to identify tube degradation based on site and industry operating experience by confirming that the ET scope completed was consistent with the licensees procedures, plant TS requirements and EPRI 1003138, Pressurized Water Reactor Steam Generator Examination Guidelines: Revision 6;

• the licensee identified new tube degradation mechanisms;

• the SG tube ET examination scope included tube areas which represent ET challenges such as the tubesheet regions, expansion transitions, and support plates;

• the licensee implemented repair methods which were consistent with the repair processes allowed in the plant TS requirements;

• the required repair criteria were being adhered to;

• the licensee primary-to-secondary leakage (e.g., SG tube leakage) was below the detection threshold during the previous operating cycle;

• the ET probes and equipment configurations used to acquire data from the SG tubes were qualified to detect the known/expected types of SG tube degradation in accordance with Appendix H, Performance Demonstration for Eddy Current Examination, of EPRI 1003138, Pressurized Water Reactor Steam Generator Examination Guidelines, Revision 6;

• retrieval attempts of foreign objects were made where practicable. For those objects that were unable to be retrieved, were evaluations performed for the potential detrimental effects of the objects and were appropriate repairs of the affected tubes planned/taken; and

• the licensee identified deviations from ET data acquisition or analysis procedures.

The documents reviewed during this inspection are listed in the Attachment to this report. The reviews as discussed above counted as one inspection sample.

b. Findings

No findings of significance were identified.

.5 Identification and Resolution of Problems

The inspectors performed a review of ISI/SG related problems that were identified by the licensee and entered into the corrective action program, conducted interviews with licensee staff and reviewed licensee corrective action records to determine if;

• the licensee had described the scope of any ISI/SG related problems;

• the licensee had established an appropriate threshold for identifying issues;

• the licensee had evaluated operating experience and industry generic issues related to ISI and pressure boundary integrity; and

• the licensee implemented appropriate corrective actions.

The inspectors performed these reviews to ensure compliance with 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements. The corrective action documents reviewed by the inspectors are listed in the attachment to this report.

1R11 Licensed Operator Requalification

a. Inspection Scope

The inspectors completed one inspection sample of licensed operator requalification training by observing a crew of licensed operators during simulator training on August 30, 2007. The inspectors assessed the operators response to the simulated events which included a steam generator tube rupture with a loss of the C 4160 Volt Bus.

The inspectors verified that the operators were able to effectively mitigate the events through accurate and timely implementation of applicable alarm response procedures, Off-Normal Procedures and Emergency Operating Procedures. The inspectors also observed the post-training critique to assess the licensee evaluators and the crews ability to self-identify performance deficiencies.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors completed two inspection samples pertaining to maintenance effectiveness by reviewing maintenance rule implementation activities for the following systems and components:

• Neutron monitoring and nuclear instruments; and

• Radiation monitoring system.

The inspectors reviewed the licensee's implementation of the maintenance rule requirements to verify that component and equipment failures were evaluated and appropriately dispositioned. The inspectors also verified that the selected systems and components were scoped into the maintenance rule and properly categorized as (a)(1) or (a)(2) in accordance with 10 CFR 50.65.

b. Findings

Introduction:

The inspectors identified a Green Non-Cited Violation (NCV) of 10 CFR 50.65 (b)(2) due to a failure by the licensee to scope all plant radiation monitors used in site emergency operating procedures into the maintenance rule monitoring program.

Description:

The inspectors reviewed the licensees maintenance effectiveness implementation for plant radiation monitors including system scoping. Specifically, the inspectors reviewed EGAD-EP-10, Maintenance Rule Scoping Document, Revision 4.

The inspectors noted that the scoping document for the plant radiation monitoring system omitted several instruments from the scope of the maintenance rule program.

Specifically, several site emergency operating procedures (EOPs) including EOP-4, Loss-of-Coolant Accident Recovery Procedure, Revision 17, and EOP-5, Steam Generator Tube Rupture Recovery Procedure, Revision 14, require operators to classify an event per EI-1, yet some of the radiation monitors used to classify an event per EI-1 were not in the scope the maintenance rule. In response to the inspectors questioning, the maintenance rule system engineer examined the basis for excluding RIA-0833 and RIA-5211 from the monitoring program. During this review, the licensee identified that the radiation monitors in question, RIA-0833 and RIA-5211, were explicitly used in several EOPs. The extent of condition review identified additional radiation monitors that were not in the maintenance rule.

On August 22, 2007, the licensee convened a maintenance rule expert panel to address scoping questions regarding plant radiation monitors. The panel reviewed the EOP steps referencing RIA-0833, RIA-5211, RIA-2311, RIA-1809 and RIA-5711. The panel noted that industry guidance recommends only system functions and components providing a significant contribution to the mitigation function of the EOP be included in the scope of the maintenance rule. However, the expert panel reviewed Regulatory Guide 1.160, Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, Revision 2, which states the NRC staff position that System, Structure or Components (SSCs) used directly to address the accident or transient or are explicitly used in EOPs are to be included in the scope of maintenance rule. Based on the panels review of Regulatory Guide 1.160, RIA-0833, RIA-5211, RIA-2311, RIA-1809 and RIA-5711 were placed in scope due to their specific reference in site EOPs. As a result of the expert panels decision to scope additional plant radiation monitors, the radiation monitoring system accrued additional failures and was placed in Maintenance Rule (a)(1) category.

Analysis:

The failure to scope sections of the plant radiation monitoring system into the Maintenance Rule Program was a performance deficiency in that it was a violation of paragraph (b)(2)(I) of 10 CFR 50.65. The finding was more than minor because it had greater significance than similar issues described in NRC Manual Chapter 0612, Appendix E, Examples of Minor Issues, Example 7(d). Specifically, once the licensee added the radiation monitors to the scope of the maintenance rule, the licensee could no longer demonstrate effective maintenance of the radiation monitoring system. The inspectors determined the finding to have very low safety significance (Green) using the NRCs SDP for Reactor Inspection Findings for At-Power situations because the finding did not contribute to a loss of mitigation equipment functions and did not increase the likelihood of a fire or flooding event. Since the radiation monitors were added to the scope of the EOPs in 1994 and 1998, the inspectors concluded that the finding did not represent current performance; therefore, the inspectors determined that no cross cutting aspect existed.

Enforcement:

Paragraph (b)(2)(I) of 10 CFR 50.65 requires that the scope of the Maintenance Rule program include nonsafety-related structures, systems or components that are relied upon to mitigate accidents or transients or are used in the EOPs. Contrary to the above, the licensee did not include all plant radiation monitors used in the EOPs in the scope of the Maintenance Rule program. Because this finding was of very low safety significance and it was entered into the sites corrective action program as CR-PLP-2007-03152, this finding is being treated as a NCV, consistent with Section VI.A of the NRC Enforcement Policy: (NCV 05000255/2007006-01, Plant Radiation Monitors Not Fully Scoped into the Maintenance Rule.)

1R13 Maintenance Risk Assessments and Emergent Work Evaluation

a. Inspection Scope

The inspectors completed four inspection samples. The inspectors reviewed the following activities to verify that the appropriate risk assessments were performed prior to removing equipment for work. The inspectors verified that risk assessments were performed as required by 10 CFR 50.65(a)(4), and were accurate and complete. When emergent work was performed, the inspectors verified that the plant risk was promptly reassessed and managed. The inspectors verified the appropriate use of the licensees risk assessment tool and risk categories in accordance with Administrative Procedure 4.02, Control of Equipment, Revision 40, and Fleet Procedure FP-OP-RSK-01, Risk Monitoring and Risk Management, Revision 0.

Documents reviewed are listed in the Attachment.

• Maintenance risk associated with work week 0728 and 1-2 emergency diesel generator (EDG);

• Maintenance risk associated with QO-1, safety injection system;

• Shutdown outage risk, planned Orange path for mid loop, September 13; and

• Shutdown outage risk, planned Orange path for C 4160 Volt bus outage, September 21.

The inspectors also verified that CRs related to emergent equipment problems were entered into the corrective action program with the appropriate significance characterization. Select CRs related to risk management during maintenance activities were reviewed to verify that planned corrective actions were appropriate and had been implemented as scheduled.

b. Findings

Introduction:

The inspectors identified a Green NCV of 10 CFR Part 50.65(a)(4),because the licensee failed to recognize that a safety injection system actuation test rendered the system unavailable and resulted in an increase in plant risk.

Description:

On July 27, 2007, the licensee performed TS Surveillance Procedure QO-1, Safety Injection System, Revision 55, to demonstrate the operability of the safety injection system initiation circuitry through use of its internal testing capability. During the performance of the test, the licensee simulates a safety injection actuation signal which results in starting the associated HPSI Pump. Previous test performances revealed the potential to unseat primary coolant system check valves following the test due to thermal expansion of water.

Consequently, the licensee revised Procedure QO-1 on July 10, 2007 to require shutting valve MV-ES3178, P-66B HPSI Pump Discharge and MV-ES3187, P-66A HPSI Pump Discharge to prevent check valve unseating. The licensee failed to recognize that this change rendered the affected HPSI train unavailable.

The inspectors noted that prior to the performance of the procedure, the licensee calculated the online Risk Achievement Worth to be green, or low risk. When questioned about the status of HPSI with the valves closed, the licensee recalculated plant risk and determined that the change placed the plant in yellow or medium risk.

Further review indicated that the recent revision to the procedure had inserted a step to close the HPSI pump discharge valves. Procedure FP-G-DOC-04, Procedure Processing, Revision 4, provided no provision for the sites probabilistic safety assessment group to review procedure changes for impacts on plant risk modeling; therefore, the risk model was not updated. Prior to rendering HPSI unavailable, the licensee entered yellow risk and took mitigation actions consistent with procedural requirements.

Analysis:

The inspectors determined that the licensees failure to adequately assess and manage online maintenance activities associated with QO-1, Safety Injection Actuation Test, was a performance deficiency. The inspectors determined that the finding impacted the Mitigating Systems Cornerstone. The finding was more than minor because the risk assessment failed to consider risk-significant systems, structures, components, and support systems that were unavailable during on-line maintenance. When properly considered, risk increased from Green to Yellow.

Specifically, the unavailability of high pressure safety injection pumps was not included in the on-line risk assessment for July 27, 2007. The inspectors assessed the finding using Manual Chapter 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process, Flowchart 1, Assessment of Risk Deficit, and determined the finding to be of very low safety significance because the incremental core damage probability deficit was less than 1 x 10E-6. The finding included a cross-cutting aspect in the area of human performance work controls in that the licensee failed to incorporate appropriate risk insights when coordinating work activities. (H.3.(a))

Enforcement:

10 CFR Part 50.65(a)(4), requires, in part, that licensees assess and manage the increase in risk that may result from proposed maintenance activities.

Contrary to the above, on July 27, 2007, the licensee failed to adequately assess and manage the increased risk of operating with the HPSI pump unavailable during Surveillance Procedure QO-1, Safety Injection System. Because this issue was of very low safety significance and was entered into the corrective action program as CR-PLP-2007-03078, this violation is being treated as an NCV consistent with Section VI.A.1 of the NRC Enforcement Policy: (NCV 05000255/2007006-02, Inadequate Risk Assessment for Safety Injection Actuation Test).

1R15 Operability Evaluations

a. Inspection Scope

The inspectors completed one inspection sample. For the OPR listed below, the inspectors evaluated the technical adequacy of the evaluation to ensure that TS operability was properly justified and the subject components remained available such that no unrecognized increase in risk occurred. The inspectors reviewed the UFSAR to verify that the components remained available to perform the intended functions. In addition, the inspectors reviewed compensatory measures implemented to verify that they worked as stated; and that the measures were adequately controlled. In addition, the inspectors verified that the CRs generated for equipment operability issues were entered into the licensees corrective action program with the appropriate significance characterization. Documents reviewed are listed in the Attachment.

• OPR for AFW pump 8B and 8A during postulated high energy line breaks

b. Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors completed six inspection sample(s) pertaining to post maintenance testing by assessing testing activities that were conducted for the following maintenance activities:

• Power Supply -0751C, channel C power supply to reactor protection equipment;

• Augmented cooling for SW modification following redesign of discharge piping;

• EDG 1-1 following replacement of air start motor and solenoid replacement;

• Circuit for transfer following disabling fast transfer;

• Polar crane upper limit switch following replacement; and

• SW pump 7B following pump replacement.

The inspectors observed portions of the post maintenance testing and/or reviewed documentation to verify that the tests were performed as prescribed by the work orders and test procedures; that applicable testing prerequisites were met prior to the start of the tests; and, that the effect of testing on plant conditions was adequately addressed by the control room operators. The inspectors reviewed documentation to verify that the test criteria and acceptance criteria were appropriate for the scope of work performed; reviewed test procedures to verify that the tests adequately verified system operability; and reviewed documented test data to verify that the data was complete, and that the equipment met the prescribed acceptance criteria. Further, the inspectors reviewed CRs to verify that post maintenance testing problems were entered into the corrective action program with the appropriate significance characterization. For select CRs, the inspectors verified that the corrective actions were appropriate and implemented as scheduled.

b. Findings

No findings of significance were identified.

1R20 Refueling and Other Outage Activities

a. Inspection Scope

This inspection does not constitute an inspection sample because the licensee did not complete the outage during the inspection period. The inspectors observed and assessed licensees performance during a planned refueling outage (R19). The outage began on September 9 with planned completion in October, 2007. Additional activities will be documented in the fourth quarter report. Prior to the outage, the inspectors reviewed the outage risk profile to ensure the licensee performed a detailed and accurate assessment of plant risk. During the outage the inspectors, the inspectors performed the following activities:

• Observed operations performance during shutdown and cooldown to verify the licensee performed plant operations in accordance with TS and plant procedures;

• Observed operations performance during drain to midloop (planned orange risk activity) to install nozzle dams. The inspectors also ensured the licensee complied with committed actions for reduced inventory;

• Observed plant controls and verified system alignments for the reactor vessel; head lift and verified items required in the head drop calculation were established prior to the lift;

• Verified decay heat removal systems were aligned per TS;

• Verified electrical equipment alignments;

• Verified spent fuel decay heat removal systems;

• Verified reactor coolant system instrumentation;

• Verified reactivity control system;

• Verified inventory control systems;

• Verified risk assessment aligned with plant clearance activities;

• Accompanied licensee personnel during containment initial entry to look for evidence of boric acid leakage;

• Observed refueling and fuel handling to verify conformance with TS and plant procedures.

b. Findings

No findings of significance were identified

1R22 Surveillance Testing

a. Inspection Scope

The inspectors completed seven surveillance test samples by observing test performance and/or reviewing test data. One sample was an inservice test. Two samples were containment isolation valves. The inspectors assessed, as appropriate, whether the SSCs met the requirements of the TS; the UFSAR; Palisades Administrative Procedure 9.20; TS Surveillance and Special Testing Program; Engineering Manual EM-09-02 and EM-09-04, Inservice Testing of Plant Valves and Inservice Testing of Selected Safety-Related Pumps. The inspectors also determined whether the testing effectively demonstrated that the SSCs were operationally ready and capable of performing their intended safety functions. Further, the inspectors reviewed selected CRs regarding surveillance testing activities. The inspectors verified that the identified problems were entered into the licensees corrective action program with the appropriate significance characterization and that the planned and completed corrective actions were appropriate.

C QO-1 safety injection system actuation test; C

Auxiliary feedwater class 2 and 3 system Functional/Inservice test; C

Comprehensive pump test Procedure AFW pump P-8B; C

Left train engineered safeguards system test RT-8C; C

Containment isolation valve testing for penetration MZ-26; C

Containment isolation valve testing for valve CK-N2/465; and C

Inspection of reactor vessel for foreign material and weld integrity.

b. Findings

No findings of significance were identified.

1R23 Temporary Modifications

a. Inspection Scope

The inspectors completed two baseline inspection samples by reviewing the following temporary modifications:

C Temporary Modification EC-10617, "Augmented Cooling for Service Water System to Compensate for Absence of Containment Air Cooler VHX-4";

C Temporary Modification EC-10749, Temporary Service Water Discharge Pipe Installation.

The inspectors reviewed the design documents and 10 CFR 50.59 screening document to verify that the temporary modification did not affect the operability of the related systems and other interfacing systems. The inspectors reviewed documentation to verify that the modification was implemented as designed. Post modification testing results were reviewed to verify that the system functioned as intended after the modification was implemented.

b. Findings

Introduction:

The inspectors identified a Severity Level IV NCV of 10 CFR 50.59, Changes, Tests, and Experiments for the licensees failure to perform a written 10 CFR 50.59 evaluation prior to implementing a temporary modification intended to compensate for the absence of containment air cooler VHX-4.

Description:

In March 2007, the licensee isolated containment air cooler VHX-4 because of several through wall piping leaks of service water within the unit. In order to ensure that adequate cooling remained available during summer months, the licensee initiated a temporary modification for augmented cooling to the service water inlet under Engineering Change (EC) 10617. The licensee developed a modification that would withdraw, cool, then return water from the intake structure. The licensee did not identify any adverse impacts associated with the use of the temporary modification in a 10 CFR 50.59 screening document and concluded a 10 CFR 50.59 evaluation was not required.

The licensee tested the augmented cooling for the service water modification on June 29, 2007. Since the licensee did not identify any potential for an adverse impact, the licensee did not develop a test procedure to use the temporary modification. The licensee conducted the test by ramping up augmented cooling water flow in 500 gallon per minute (gpm) increments to the maximum flow rate of 4500 gpm. Shortly after reaching the maximum system flow rate, the licensee experienced debris intrusion into the P-7C and P-7A Service Water Pump basket strainers (P-7B was not in service).

Over approximately seven minutes, a maximum differential pressure of 7.5 pounds per square inch differential (psid) and 6 psid was observed on local gauges for the P-7C and P-7A basket strainers, respectively. The pre-job brief conducted prior to the test evolution on June 29, 2007, discussed the possibility for sand intrusion into the service water basket strainers and established a threshold of 6 psid across any basket strainer as a termination criteria. While this requirement was not in a procedure, the licensee suspended testing of the modification as discussed in the pre-job brief. The inspectors noted that despite receiving unexpected results of rapid fouling of service water pump basket strainers during testing on June 29, 2007, the licensee failed to enter the condition into the sites corrective action program.

Following the debris intrusion experienced during the June 29, 2007 testing, the licensee removed from service and cleaned the affected service water basket strainers per SOP-15, Service Water System, Revision 42. The cleaning evolution revealed the presence of corrosion products in addition to sand and silt entrained in the strainers.

The licensee hypothesized that corrosion products were introduced from non-structural metallic components within the intake structure. In order to maximize the cooling benefit, the design of the system directed the discharge flow to the base of the service water pump columns at a flow velocity of approximately 14.5 feet/sec. Subsequent review by the licensee determined this flow velocity was sufficient to dislodge and suspend sand, silt and corrosion products within the intake structure inner bay. These suspended products were then transported to the suction of the service water pumps causing the service water pump basket strainers to become fouled. The licensee re-evaluated the design of the augmented cooling water system and modified the discharge piping to include the use of a diffuser to limit the flow velocity of water exiting the discharge piping. Although the licensee now had demonstrated an adverse effect on the SW system from the temporary modification, no revision or review of the 10 CFR 50.59 screening document occurred. The licensee planned to run the test again on July 2, but put the test on hold based on the inspectors concerns on the adequacy of the 10 CFR 50.59 evaluation and the failure to enter the unexpected testing results into the corrective action program. Following discussions with the inspectors, the licensee revised the 50.59 screening document, concluded that an evaluation was required, and performed a 10CFR 50.59 evaluation. With the addition of structural enhancements and material assessments to preclude loss of the diffuser, the licensee determined that the modification could be performed without prior NRC approval.

Analysis:

The inspectors determined that the licensees failure to perform a 10 CFR 50.59 evaluation for the augmented cooling to service water modification was a performance deficiency. Because this is a violation of 10 CFR 50.59, it is considered to be a violation which potentially impedes or impacts the regulatory process. Therefore, such violations are dispositioned using traditional enforcement process instead of the Significance Determination Process. In this case, the licensee failed to perform an evaluation in accordance with 10 CFR 50.59 for changes made by a temporary modification to augment service water cooling and this modification adversely affected the function and operation of the service water system. To determine the significance of the violation, the inspectors determined the risk of the underlying technical issue. The inspectors completed a Significance Determination Review using IMC 0609, Appendix A, Significance Determination of Reactor Inspection Findings for At Power Situations. Because the finding contributed to the likelihood of a loss of service water initiating event and the likelihood that mitigation equipment or functions would not be available, the finding required an SDP Phase 2 analysis.

IMC 0609, Appendix A, states that if the Phase 2 SDP pre-solved tables/worksheets do not clearly address the inspection finding then a Phase 3 analysis should be performed to characterize the significance of the finding. In this case, the RIII senior reactor analyst determined that the Phase 2 SDP tools do not adequately address the finding since input assumptions were overly conservative. For example, the exposure time for this finding was no more than one hour. The shortest duration in the Phase 2 significance determination process addresses findings from one to three days duration.

Therefore the senior reactor analyst (SRA) performed the analysis using the Phase 3 SDP tools.

The SRA performed the risk evaluation using the Palisades Standardized Plant Analysis Risk (SPAR) Model, Level 1, Revision 3P, Change 3.31, created October 2005. The analyst also used the NRC's Risk Assessment Standardization Project (RASP) manual.

To represent the assumed common cause failure of all three SW pumps, the SRA set the basic events representing failure of all three SW pumps to start and run to "True." A cutset truncation of 1.0E-12 was used. Average test and maintenance were assumed.

The delta-core damage frequency (CDF) adjusted for the one-hour exposure was 4.6E-7 dominated by a loss of offsite power, common cause failure of the SW pumps (leading to station blackout due to loss of EDG cooling water), failure to recover emergency and offsite power in four hours, and failure to maintain reactor subcooling.

The SRA determined that this dominant sequence did not result in a contribution to Large Early Release Frequency (LERF) because of the short exposure time of the condition. Similarly, for external initiating events, the risk contribution was not significant enough to increase the total delta-CDF above 1E-6. The SRA concluded the finding was, therefore, of very low safety significance (green). The finding has a cross-cutting aspect in the area of human performance in that the licensee failed to use conservative assumptions in decision making and failed to identify possible unintended consequences when implementing the augmented cooling for service water modification. (H.1.(b))

Enforcement:

10 CFR 50.59(d)(1) requires, in part, that licensees maintain records of changes in the facility, of changes in procedures, and of tests and experiments. These records must include a written evaluation which provides the basis for determination that the change, test, or experiment does not require a license amendment. Contrary to the above, the licensee approved a plant modification that adversely affected the service water system designed safety function and failed to perform an adequate evaluation in accordance with 10 CFR 50.59. However, because this violation was of very low safety significance, because the finding was entered into the licensees corrective action program as CR-PLP-2007-02732, and the licensee took immediate actions, this violation is being treated as a Severity Level IV NCV consistent with Section VI.A.1 of the NRC Enforcement Policy: (NCV 05000255/2007006-03, Failure to Perform a 10 CFR 50.59 Evaluation for a Temporary Modification for Augmented Cooling of SW).

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

20S1 Access Control to Radiologically Significant Areas (71121.01)

.1 Review of Licensee Performance Indicators for the Occupational Exposure Cornerstone

a. Inspection Scope

The inspectors reviewed licensees event reports, corrective action documents, electronic dosimetry transaction data for radiologically controlled area egress, internal dose assessment summary information, and data reported on the NRCs web site relative to the licensees occupational exposure control performance indicator.

The inspectors confirmed that the conditions surrounding any actual or potential performance indicator (PI) occurrences had been evaluated, and identified problems had been entered into the corrective action program for resolution. These reviews represented one inspection sample.

b. Findings

No findings of significance were identified.

.2 Plant Walkdowns, Boundary Verifications, and Internal Dose Calculations

a. Inspection Scope

With a survey instrument, the inspectors walked down and surveyed selected radiation areas, high and locked high radiation area boundaries in the auxiliary building to determine if the prescribed radiological access controls were in place, if licensee postings were complete and accurate, and if physical barricades/barriers were adequate. During the walkdowns, the inspectors challenged access control boundaries to determine if high radiation area (HRA) and locked high radiation area (LHRA) access was controlled in compliance with the licensees procedures, Technical Specifications, and the requirements of 10 CFR 20.1601 and were consistent with Regulatory Guide 8.38, Control of Access to High and Very High Radiation Areas in Nuclear Power Plants.

The adequacy of the licensees internal dose assessment process for internal exposures exceeding 50 millirem committed effective dose equivalent was assessed to determine if affected personnel were properly monitored utilizing calibrated equipment and if the data was analyzed and internal exposures were properly assessed in accordance with licensee procedures.

The inspectors reviewed the licensees physical and administrative controls for the storage of highly activated and/or contaminated materials (non-fuel) within the spent fuel pool. In particular, the radiological control for non-fuel materials stored in these pools was evaluated to ensure that adequate barriers were in-place to reduce the potential for the inadvertent movement of these materials and to assess compliance with the licensees procedures and for consistency with NRC regulatory guidance.

These reviews represented three inspection samples.

b. Findings

No findings of significance were identified.

.3 Problem Identification and Resolution

a. Inspection Scope

The inspectors reviewed the corrective action database along with individual Action Requests (ARs) related to the radiological access control program to determine if identified problems were entered into the corrective action program for resolution.

In particular, the inspectors reviewed radiological issues which occurred over approximately the 15-month period that preceded the inspection including the review of any HRA radiological incidents (non-PI occurrences identified by the licensee in high and locked high radiation areas) to determine if follow-up activities were conducted in an effective and timely manner commensurate with their importance to safety and risk based on the following:

• Initial problem identification, characterization, and tracking;

• Disposition of operability/reportability issues;

• Evaluation of safety significance/risk and priority for resolution;

• Identification of repetitive problems;

• Identification of contributing causes;

• Identification and implementation of effective corrective actions;

• Resolution of NCVs tracked in the corrective action system; and

• Implementation/consideration of risk significant operational experience feedback.

The inspectors evaluated the licensees process for problem identification, characterization, and prioritization and determined if problems were entered into the corrective action program and were being resolved in a timely manner. For potential repetitive deficiencies or possible trends, the inspectors determined if the licensees self-assessment activities were capable of identifying and addressing these deficiencies as applicable.

The inspectors reviewed the licensees documentation for all potential PI events occurring since the NRCs last review of these areas in April 2006 to determine if any of these events involved dose rates greater than 25 Rem/hour at 30 centimeters or greater than 500 Rem/hour at 1 meter or involved unintended exposures greater than 100 millirem total effective dose equivalent (or greater than 5 Rem shallow dose equivalent or greater than 1.5 Rem lens dose equivalent). None were identified.

These reviews represented four inspection samples.

b. Findings

No findings of significance were identified.

.4 High Risk Significant, LHRA and Very High Radiation Area (VHRA) Access Controls

a. Inspection Scope

The inspectors reviewed the licensees procedures and Radiation Protection (RP)job standards and evaluated RP practices for the control of access to radiologically significant areas (high, locked high, and very high radiation areas). The inspectors discussed locked high and very high radiation area controls with the RP staff to assess compliance with the licensees TSs, procedures and the requirements of 10 CFR Part 20 and for consistency with the guidance contained in Regulatory Guide 8.38.

In particular, the inspectors evaluated the RP staffs control of keys to LHRAs and VHRAs, the use of access control guards during work in these areas, and methods and practices for independently verifying proper closure and locking of access doors upon area egress. The inspectors selectively reviewed key issuance/return, door lock verification records, and key accountability logs for selected periods to determine the adequacy of accountability practices and documentation.

The inspectors discussed with RP staff the controls that were in place for areas that had the potential to become high radiation areas during radwaste operations to determine if these activities required communication before-hand with the RP group, so as to allow corresponding timely actions to properly post and control the radiation hazards.

The inspectors conducted plant walkdowns to verify the posting and locking of entrances to numerous LHRAs throughout the plant.

These reviews represented three inspection samples.

b. Findings

No findings of significance were identified.

.5 Radiation Worker Performance

a. Inspection Scope

The inspectors reviewed radiological problem reports, which showed the cause of the event was due to radiation worker errors; and to determine if there was an observable pattern traceable to a similar cause and if this matched the corrective action approach taken by the licensee to resolve the identified problems. These reviews represented one inspection sample.

During job performance observations, the inspectors evaluated radiation worker performance with respect to stated radiation protection work requirements and evaluated whether workers were aware of the significant radiological conditions in their workplace, the Radiation Work Permit (RWP) controls and limits in place, and that their performance had accounted for the level of radiological hazards present.

These reviews represented one inspection sample

b. Findings

No findings of significant were identified.

.6 Radiation Protection Technician Proficiency

a. Inspection Scope

The inspectors reviewed selected radiological problem reports generated between April 2006 and June 2007 to determine the extent of any specific problems or trends that may have been caused by deficiencies with Radiation Protection Technician work control and to determine if the corrective action approach taken by the licensee to resolve the reported problems, if applicable, was adequate. These reviews represented one inspection sample.

During job performance observations, the inspectors evaluated Radiation Protection Technician performance with respect to radiation protection work requirements and evaluated whether they were aware of the radiological conditions in their workplace, the RWP controls and limits in place, and if their performance was consistent with their training and qualifications with respect to the radiological hazards and work activities. These reviews represented one inspection sample.

b. Findings

No findings of significance were identified.

7. Plant Walkdowns and Radiation Work Permit Reviews

a. Inspection Scope

The inspectors reviewed licensee controls and surveys in the following three radiologically significant work areas; within radiation areas, high radiation areas and airborne radioactivity areas in the plant; and reviewed work packages which included associated licensee controls and surveys of these areas to evaluate whether radiological controls including surveys, postings and barricades were acceptable:

• ICI shielding in the reactor cavity;

• Tilt pit activities; and

• Decon/disassembly/clean/reassemble and test CRDM seal housings.

These reviews represented one inspection sample.

The identified radiologically significant work areas were walked down and surveyed to evaluate whether the prescribed RWP, procedures and engineering controls were in place, licensee surveys and postings were complete and accurate, and air samplers were properly located. This review represented one sample.

The inspectors reviewed selected RWPs and associated radiological controls used to access these and other radiologically significant areas and evaluated the work control instructions and control barriers that were specified in order to evaluate whether the controls and requirements provided adequate worker protection. Site TS requirements for high radiation areas (HRAs) and locked high radiation areas were used as standards for the necessary barriers. Electronic dosimeter alarm set points for both integrated dose and dose rate were evaluated for conformity with survey indications and plant policy. The inspectors attended pre-job briefings to assess whether instructions to workers emphasized the actions required when their electronic dosimeters noticeably malfunctioned or alarmed. This review represented one sample.

The adequacy of the licensees internal dose assessment process for internal exposures

>50 millirem committed effective dose equivalent was assessed to determine if affected personnel were properly monitored utilizing calibrated equipment and that the data was analyzed and internal exposures were properly assessed in accordance with licensee procedures. This review represented one sample.

b. Findings

No findings of significance were identified. However, there was an event that occurred during the refueling outage where an individuals respiratory protection equipment failed during the removal of the reactor head o-ring. This event resulted in an intake of radioactive material. However, the internal dose assessment was not complete because the event occurred within an area where it was difficult to detect which radionuclides were present. In accordance with plant procedures, samples (i.e., area contamination and in vitro bioassay) were collected and sent to a contracted off-site facility to perform analysis for those difficult to detect radionuclides. The results from this analysis were not available during the inspection. Additionally, the cause(s) for the respiratory equipment failure was still under evaluation during the inspection. Therefore, this issue remains under review by the NRC and is categorized as an Unresolved Item (URI 05000255/2007006-04, Internal Dose Assessment for O-ring work).

8. Job-In-Progress Reviews

a. Inspection Scope

The inspectors observed the following three jobs that were being performed in radiation areas and high radiation areas for observation of work activities that presented the greatest radiological risk to workers:

• ICI shielding in the reactor cavity;

• Tilt pit activities; and

• Decon/disassembly/clean/reassemble, and test CRDM seal housings The inspectors reviewed radiological job requirements for these activities, including RWP requirements and work procedure requirements, and attended As-Low-As-Reasonably-Achievable (ALARA) job briefings. These reviews represented one inspection sample.

Job performance was observed with respect to these requirements to assess whether radiological conditions in the work area were adequately communicated to workers through pre-job briefings and postings. The inspectors also evaluated the adequacy of radiological controls including required radiation, contamination, and airborne surveys for system breaches; radiation protection job coverage which included audio and visual surveillance for remote job coverage; and contamination controls. These reviews represented one inspection sample.

The inspectors reviewed the adequacy of radiological controls, radiation protection job coverage (including audio and visual surveillance for remote job coverage), and contamination controls during these job performance observations. This review represented one sample.

The inspectors reviewed the application of dosimetry to effectively monitor exposure to personnel for high radiation work areas with significant dose rate gradients (factor of five or more). This review represented one sample.

b. Findings

No findings of significance were identified. However, events occurred during the refueling outage that created airborne radioactivity areas within the containment building. Increased levels of noble gas were identified after the pressurizer manway was removed and increased again after the steam generator manways were removed, as part of the work that was scheduled during the refueling outage. Increased levels of iodine-131 were identified after the reactor head was lifted to support the refueling outage. The increased airborne radioactivity levels caused small, but measurable, intakes of iodine-131 to several hundred workers during the refueling outage. At the time of the inspection, the events were still under review with respect to the causes of the events, the extent of the personnel intakes, the adequacy of pre-job planning, and the adequacy of contingency actions to mitigate the conditions before allowing work to continue in the affected areas. Therefore, this issue remains under review by the NRC and is categorized as an URI, (URI 05000255/2007006-05, Increased airborne radioactivity in containment).

20S2 ALARA Planning and Controls (71121.02)

.1 Radiological Work Planning.

a. Inspection Scope

The interfaces between operations, RP, maintenance, maintenance planning, scheduling, and engineering groups were evaluated to identify interface problems or missing program elements. This review represented one sample.

The integration of ALARA requirements into work procedures and RWP documents was evaluated to assess whether the licensees radiological job planning would reduce dose.

This review represented one sample.

Shielding requests from the radiation protection group were evaluated with respect to dose rate reduction and reduced worker exposure. This review represented one sample.

The inspectors reviewed work activity planning to determine if there was consideration of the benefits of dose rate reduction activities such as shielding provided by water filled components and piping, job scheduling, along with shielding and scaffolding installation and removal activities. This review represented one sample.

b. Findings

No findings of significance were identified.

.2 Source-Term Reduction and Control

a. Inspection Scope

The inspectors discussed with the licensee its plans to perform a comprehensive source term evaluation including the input mechanisms in order to reduce the source term.

The licensee indicated that the evaluation would prescribe a new source term control strategy that may include a process for evaluating radionuclide distribution plus a shutdown and operating chemistry plan which can minimize the source-term external to the core. Other methods used by the licensee to control the source-term, including component/system decontamination, hotspot flushing and the use of shielding, were evaluated. This review represented one sample.

The licensees process for identification of specific sources was reviewed, along with exposure reduction actions and the priorities the licensee had established for implementation of those actions. Results achieved against these priorities since the last refueling cycle were reviewed. For the current assessment period, source-term reduction evaluations were reviewed, and actions taken to reduce the overall source-term were compared to the previous year. This review represented one sample.

b. Findings

No findings of significance were identified.

4OA1 Performance Indicator (PI) Verification

Cornerstone: Mitigating Systems

a. Inspection Scope

The inspectors completed two inspection samples. The inspectors reviewed the licensees records associated with the mitigating system PIs listed below. The inspectors verified that the licensee accurately reported these indicators in accordance with relevant procedures and Nuclear Energy Institute guidance endorsed by NRC.

Specifically, the inspectors reviewed licensee records associated with PI data reported to the NRC for the period July 2006 through June 2007. The inspectors reviewed records for Mitigating System Performance Index (MSPI), control room logs, and CRs related to the selected systems. The following PIs were reviewed:

C MSPI, Emergency AC Power System and

• MSPI, Residual Heat Removal

b. Findings

No findings of significance were identified.

.2 Radiation Safety Strategic Area

a. Inspection Scope

The inspectors sampled the licensees submittals for the PIs listed below for the period indicated. The inspectors used PI definitions and guidance contained in the Nuclear Energy Institute guidance document to verify the accuracy of the PI data. The following PIs were reviewed:

• Radiological Effluent TS/Offsite Dose Calculation Manual Radiological Effluent Occurrence The inspectors reviewed the licensees corrective action database and selected individual reports generated since this indicator was last reviewed through April 2006, to identify any potential occurrences such as unmonitored, uncontrolled, or improperly calculated effluent releases that may have impacted offsite dose. The inspectors reviewed gaseous effluent summary data and the results of associated offsite dose calculations for selected dates between April 2006 and July 2007 to determine if indicator results were accurately reported. The inspectors also reviewed the licensees methods for quantifying gaseous and liquid effluents and determining effluent dose.

This review represented one inspection sample.

Cornerstone: Occupational Radiation Safety

• Occupational Exposure Control Effectiveness The inspectors reviewed the licensees assessment of the PI for occupational radiation safety to determine if indicator related data was adequately assessed and reported during the previous four quarters. The inspectors compared the licensees PI data with the corrective action report database, reviewed radiological restricted area exit electronic dosimetry transaction records and discussed data collection and analysis methods for PIs with licensee representatives. This review represented one inspection sample.

Cornerstone: Barrier Integrity

• Reactor Coolant System Specific Activity The inspectors reviewed Chemistry Department records including isotopic analyses for selected dates between April 2006 through July 2007 to determine if the greatest dose equivalent iodine (DEI) values determined during steady state operations corresponded to the values reported to the NRC. The inspectors also reviewed selected DEI calculations including the application of dose conversion factors as specified in plant TSs. Additionally, the inspectors accompanied a chemistry technician and observed the collection and preparation of reactor coolant system samples to evaluate compliance with the licensees sampling procedures. Further, sample analyses and calculation methods were discussed with chemistry staff to determine their adequacy relative to TSs, licensee procedures and industry guidelines. This review represented one inspection sample.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Routine Review of Identification and Resolution of Problems

a. Inspection Scope

As discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that CRs were being generated and entered into the corrective action program (CAP) with the appropriate significance characterization. For select CRs, the inspectors also verified that identified corrective actions were appropriate and had been implemented or were scheduled to be implemented in a timely manner commensurate with the significance of the identified problem.

b. Findings

No findings of significance were identified.

.2 Annual In-depth Sample:

Review of Open NRC Issues

a. Inspection Scope

The inspectors reviewed licensee responses to various NRC questions related to condition reports and operating experience. Specific items reviewed that the inspectors concluded were resolved included:

• Vibrations on the P-7C service water pump

• Bearing vents on ECCS pumps

• Fire door gaps The inspectors reviewed the licensees analysis of the above issues and determined that the licensee had adequately supported operability of the affected systems and determined appropriate corrective actions.

In addition, the inspectors reviewed the licensee evaluation of operating experience related to treatment of atmospheric dump valves in TSs. Review of the licensing documents identified that the submittals approved by the NRC clearly identified that TSs would require one operable ADV per steam generator. However, the calculations and UFSAR accident analysis were not clear on the number of ADVs per steam generator that were used in the analysis. The licensee will evaluate the analysis to validate that the TS remain conservative.

Finally, the inspectors reviewed the licensees analysis of the cause of a LPSI relief valve lift during a plant heat-up. The initial review of the licensees analysis identified that the scope of the review focused too narrowly on the effects on equipment from the event. While the inspectors concurred that the relief valve lifted as designed and protected LPSI piping, the evaluation lacked an analysis of why the valve lifted. A revised evaluation identified that plant operators failed to properly seat check valves in the system and monitor LPSI header pressure.

b. Findings

Introduction:

A self-revealed violation of TS 5.4.1 occurred on May 13, 2007 during heat up following a forced outage. During the heat up, licensee personnel failed to follow procedural requirements for control and monitoring of LPSI check valve leakage, thus leading to lifting of the LPSI relief valve. The licensee determined that operators had failed to aggressively seat Primary Coolant System (PCS) loop check valves and failed to monitor LPSI header pressure.

Discussion: On May 13, 2007, while in mode 3 conducting plant heat up, relief valve 3162 on the LPSI injection header lifted. The relief valve, located upstream of two check valves, provides overpressure protection for the LPSI line that could result from primary system back leakage or HPSI pump discharge back leakage. Procedurally, during heat up operators monitor LPSI discharge pressure and back seat the check valve to minimize check valve leakage. SOP-3 required verification of LPSI check valve back leakage prior to entry to mode 2 but following seating of PCS check valves.

During plant heat up on May 13, the licensee back seated the LPSI check valves prior to Mode 2 but before seating PCS check valves. Following this evolution, the procedure required monitoring for continued back leakage and notification of the duty station manager and engineering if back leakage continued. In addition, a note in this section of the procedure required monitoring of header pressure to ensure that the relief valve does not lift. However, operators failed to effectively monitor for back leakage and maintain header pressure below the relief valves setpoint. As a result, the relief valve lifted. After the relief valve reseated, the licensee again seated the LPSI check valve and seated the PCS loop injection check valves.

Analysis:

The inspectors concluded that the failure to ensure LSPI checks valves had seated represented a performance deficiency that warranted a safety significance determination. The inspectors assessed this finding using the SDP. The inspectors reviewed the samples of minor issues in IMC 0612, "Power Reactor Inspection Reports,"

Appendix E, "Examples of Minor Issues," and determined that there were no examples similar to this issue. The inspectors concluded that the issue was more than minor because the finding was associated with the configuration control attribute in the initiating events cornerstone and affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations.

The inspectors performed a Phase 1 SDP review of this finding using the guidance provided in IMC 0609, Appendix A, "Significance Determination of Reactor Inspection Findings for At-Power Situations. This finding affected LOCA initiators in the IE cornerstone. Assuming worst case degradation, back leakage through the LPSI check valves would not have resulted in exceeding the TS limit for identified RCS leakage.

However, the finding could have rendered the LPSI function inoperable since the relief valve is in a common discharge header. Therefore the Regional SRA performed a more refined SDP Phase 2 risk analysis to estimate the risk impact of this performance deficiency.

The class of accidents impacted by this performance deficiency are interfacing LOCAs.

The interfaces shown to be risk significant for Palisades are listed in the SDP Phase 2 Risk-Informed Inspection Notebook for Palisades, Revision 2.01. The exposure time assumed in this analysis is less than three days. The initiating event likelihood for the three day exposure time is stated as 1E-8. Based on this information the SRA determined that the finding was of very low safety significance (Green). This finding included a cross-cutting aspect in the area of human performance in that human error prevention techniques (H.4(a)) were not effective in preventing lifting of the relief valve.

Enforcement:

Technical Specification 5.4.1., requires, in part, that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Appendix A of Regulatory Guide 1.33. Appendix A, Item 2.a., states that general operating procedures for cold shutdown to hot standby should be covered by written procedures. Contrary to the requirements of Procedures GOP-3, and SOP-1C for taking the plant from cold shutdown to hot standby, the operators failed to ensure the LPSI check valve had seated. However, because this violation was of very low safety significance and because the issue was entered into the licensee's corrective action program (CR-PLP-2007-02364) this violation is being treated as an NCV, consistent with Section VI.A.1 of the Enforcement Policy (NCV 05000255/2007006-06, LPSI Check Valve Unseated) The licensee's initial corrective action included seating the LPSI and PCS injection check valves.

4OA3 Event Follow-up

.1 (Closed) Licensee Event Report (LER) 05000255/2007005-00:

Reactor Protection System and Auxiliary Feedwater System Actuation On May 8, 2007, while performing maintenance on a main feedwater regulating valve position indicator, a technician disconnected the power to the valve controller instead of the valve position indicator. The power loss caused the closure of the B feed regulating valve which led to a reactor trip on steam generator low feedwater level. In addition to the reactor trip signal which actuated as designed, the AFW system actuated as designed. The evaluation of the trip and trip response was conducted in 4OA3 of inspection report 2007004. The inspectors identified one finding, which was not a violation of NRC requirements, which was documented in Inspection Report (IR)2007004 as FIN 05000255/2007004-04, Reactor Trip Caused by Human Performance Error. No additional findings were identified. This LER is closed.

.2 (Closed) LER 05000255/2007006-00:

Emergency Diesel Generator (EDG) Inoperable in Excess of TS Requirements On July 25, 2007, the licensee completed a past operability assessment which concluded that, for 23 days in the fourth quarter of 2005, the 1-2 EDG would have been unable to perform its design function and thus was inoperable. The time of inoperability exceeded the LCO time of seven days. The reason for the inoperability was the presence of 2 defective snubber valves on cylinders 5R and 5L. While the failure of one snubber valve did not make the 1-2 EDG inoperable, the failure of two snubber valves resulted in the 1-2 EDG inoperability. The first snubber failure occurred November 20, 2005 and was documented in IR 2006013 as NCV 05000255/2006013-04. The second snubber failure occurred on February 22, 2007 and was documented in IR 2007004 as NCV 05000255/2007004-06. Both failures constituted a violation of 10 CFR 50, Appendix B, Criterion VIII. No additional findings were identified. This LER is closed.

.3 (Closed) LER 05000255/2007003-00:

Potential for Reduced Component Cooling Water Flow On February 25, the licensee determined that heat damaged electrical cabling in the CCW room could experience a hot short and render component cooling water inoperable and result in less than 100 percent of the required cooling flow. The licensee reported this condition as an LER 05000255/2007003. After repair of the cabling, the licensee tested the damaged cabling to determine the effects of the damage on the serviced components. Because the testing did not identify a hot short, the licensee retracted the LER on September 14, 2007. The inspectors reviewed the retraction and underlying test results. Based on the test data, the inspectors concluded that the licensee had reasonably demonstrated that no loss of safety function occurred. The inspectors had previously reviewed the degraded cables in Inspection Report 05000255/2007002. No additional findings were identified. This LER is closed.

4OA5 Other Activities

a.

(Closed) URI 05000255/2006013-03: Review of Barrier Controls for High Energy Line Breaks (HELB)

As part of an annual problem identification and resolution inspection sample for the fourth quarter of 2006, the inspectors reviewed the sites barrier control processes as they related to a postulated HELB. During baseline inspection activities, the inspectors questioned licensee HELB controls. In particular the inspectors noted the site did not have any HELB barriers designed to isolate turbine building HELBs from safety-related equipment. The inspectors reviewed the sites processes for control of HELBs and the licensing basis for HELB barrier control. In addition, the inspectors reviewed ARs related to HELB control including review of external operating experience. The inspectors identified an issue associated with two AFW pumps (8A and 8B) which are located in the turbine building. Specifically, the AFW pumps 8A and 8B are located in a room which is not protected from a harsh environment and the components are not rated for a harsh environment.

b. Findings

Introduction:

The inspectors identified a Green Non-Cited violation (NCV) of 10 CFR 50, Appendix B, Criteria III, Design Control for failing to adequately translate the design and licensing basis requirements into equipment specifications for the 8A and 8B AFW pump and controls. Specifically, the 8A and 8B pumps were expected to be operable during a HELB event, but upon review are susceptible to a harsh environment and would not function in that environment.

Description:

During a review of work activities associated with an AFW pump, the inspectors noted the watertight door to the AFW room was allowed to remain open during maintenance while the equipment in the room remained operable. The AFW room houses two of the three AFW pumps and resides in the turbine building. The third pump, 8C, is housed in the Auxiliary Building. The inspectors also noted that the exhaust duct for the room ventilation system is open to the turbine building interior with no HELB barrier. Finally, the non-safety ventilation system has damper alignments which can take a suction on the turbine building interior and discharge to the AFW room.

The licensee did not consider the AFW pump room to be susceptible to a harsh environment. The original licensing basis document from Bechtel noted there was a large volume turbine building and therefore it is not likely to impact the AFW pump room. The report also noted at 0.5 psi some building portions would give way to limit pressure. The inspectors, using some basic calculations of heat transfer, demonstrated that, assuming an entire SG emptied into the turbine building, temperatures could exceed 200F. The inspectors calculations were rudimentary and did not consider Main Steam Line isolation or single failures; however, there are no other quantitative assessments of room temperature or humidity. The inspectors reviewed NRC Information Notice 2000-20, "Potential Loss of Redundant Safety-related Equipment Because of a Lack of High Energy Line Break Barriers." This Information Notice is related to the impact on safety-related equipment due to failures of non safety-related high energy line piping. Although there are no barriers for the ventilation system for the 8A and 8B pumps, the potential impact is limited to those two pumps since the third pump is protected in the auxiliary building. Although there is no existing common failure mode, there was a reasonable basis to determine that a performance deficiency existed; namely, that two AFW pumps are not protected from a harsh environment. Detailed Gothic models and an assessment by the licensee were completed and reviewed by the NRC as part of CAP 01068459. The licensee determined, in cases where turbine doors to the outside environment were closed, that the environmental condition of pressure would change from a mild environment to a harsh environment. This change means that a pressure gradient exists in the building that would be great enough to drive moisture and steam into equipment internals. Since the AFW equipment in the turbine building is not Environmental Qualification (EQ) qualified, it is reasonable to assume the equipment would fail prematurely; that is, be inoperable. Since the turbine doors could, and have been closed in cold winter months or during significant storms, the licensee wrote OPR-1, CR-PLP-2007-02860, Revision 0, to establish the compensatory actions to control the appropriate doors open (which would ensure the turbine building would not pressurize to an unacceptable value); and ensure operability of pumps 8A and 8 B. The licensee is evaluating long term plans to establish blowout panels in the turbine building and/or upgrade the AFW room to EQ standards. The NRC concluded the licensee failed to adequately assess the impact of a HELB in the turbine building on the AFW room equipment. The NRC concluded the current actions in the OPR were reasonable as reviewed in Section 1R15.

Analysis:

The inspectors determined that the licensees failure to ensure the AFW design and licensing basis requirements for the 8A and 8B pumps were properly incorporated in the design to withstand a harsh environment was a performance deficiency that warranted a significance evaluation in accordance with Inspection Manual Chapter (IMC) 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening. The finding is more than minor, was associated with the equipment performance attribute of the Mitigating Systems Cornerstone, and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using IMC 0609, Appendix A, Determining the Significance of Reactor Inspection Findings for At-Power Situations, Attachment 1, SDP Phase 1 Screening Worksheet for the mitigating systems cornerstone, the inspectors determined this finding was a design qualification deficiency resulting in a loss of function per Generic Letter 91-18, and did represent an actual loss of safety function of a system or train of equipment. The inspectors conducted a phase 2 screening using greater than one month exposure time which would include winter months and used the initiating events of a major steam leak. The screening yielded a very low safety significance (Green, 1E-7), but required a phase 3 to refine the results and include external events which may cause HELBs (seismic and tornado). The Region III SRA performed a Phase 3 analysis to estimate the increase in risk due to external initiators. The only external event initiators which could result in a HELB were related to tornados and seismic events. The analyst used references listed in the reference section of this report to assess the risk.

For tornados, the analyst conservatively assumed that any category F3 (Fujita Scale)tornado or higher would result in a turbine building HELB. Category F3 tornados produce wind speeds of approximately 160 to 200 mph. NUREG/CR-4461 stated that the frequency of these tornados striking Palisades were 1E-5/yr. Alternatively, the analyst reviewed data from the National Climatic Data Center and noted that there were only three F3 tornados in the last 57 or so years in Van Buren County: two on April 3, 1956, and one on May 13, 1980. There were no F4 or greater tornados. Considering the land area of the county is about 611 square miles, the analyst estimated the frequency of F3 tornados or greater striking Palisades based on this data to be about 8.6E-5/yr. This was the value used.

The analyst performed an external initiating events assessment using the SPAR model and set the frequency of transients to 1.0. The analyst assumed that P8A and P8B failed to start and run after the transient. The analyst also assumed that the main steam isolation valves would close or be closed during the transient. The results were a conditional core damage probability of 2.7E-3. Factoring in the tornado frequency of 8.6E-5/yr, and considering the exposure time of about four months, the estimated delta-CDF tornado was calculated at 7.8E-8. The analyst concluded that the risk increase due to tornados was inconsequential for this finding.

For seismic events, the analyst used data from the NRC RASP Handbook and the licensee<s Individual Plant Examination of External Events (IPEEE) report. The IPEEE stated that the mean fragility (capacity) of the plant is 0.488g peak ground acceleration and the high confidence of a low probability failure is 0.217g pga. The Palisades safe shutdown earthquake design basis was listed at 0.20g pga. The RASP Handbook listed the mean frequency for a 0.15g earthquake at Palisades to be 6.870E five/yr. The analyst assumed that any 0.15g or greater earthquake would guarantee to result in a turbine building HELB. Using the same method as described above for the external initiating events assessment, factoring in a seismic frequency of 6.9E-5/yr, considering the exposure time of about four months, the estimated delta-CDF seismic was calculated at 6.2E-8. The analyst concluded that the risk increase due to seismic events was inconsequential for this finding.

In summary, the SRA concluded that the risk contribution due to tornados and seismic events on this finding was inconsequential. The combined risk due to internal events, external events, and LERF did not result in a risk increase of greater than 1E-6; therefore the risk was of very low safety significance, green. This issue had no cross-cutting aspects as the deficiency was introduced over 20 years ago and was not indicative of current performance.

Enforcement:

Title 10 CFR 50 Appendix B, Criterion III, states, in part, that measures shall be established to assure that the applicable regulatory requirements and the design basis for components, to which Appendix B applies, are translated into specifications. Contrary to this, the licensee failed to design the 8A and 8B AFW pump to function during a high energy line break in the turbine building. Because the finding was entered into the licensees corrective action program as CR-PLP-2007-02860 and the licensee took immediate compensatory actions, this violation is being treated as an NCV consistent with Section VI.A.1 of the NRC Enforcement Policy:

(NCV 05000255/2007006-07, AFW Pumps Inoperable Due to High Energy Line Breaks in the Turbine Building).

4OA6 Meetings

.1 Exit Meeting

The inspectors presented the inspection results to Mr. C. Schwarz and other members of licensee management on October 3, 2007. Licensee personnel acknowledged the findings presented. The inspectors asked licensee personnel whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

.2 Interim Exit Meetings

Interim exit meetings were conducted for:

• An interim exit meeting was conducted with Mr. C. Schwarz and other licensee staff on July 27, 2007, for occupational radiation safety access control to radiologically significant areas and PI verification.

• An interim exit meeting was held to discuss results of baseline Procedure 71111.08 with Mr. C. Schwarz and other members of licensee management on September 26, 2007. The inspectors returned proprietary information reviewed during the inspection and the licensee confirmed that none of the potential report input discussed was considered proprietary.

• An interim exit meeting was conducted for Access Control to Radiologically Significant Areas with Mr. Chris Schwarz on September 14, 2007, and September 21, 2007. Subsequently, an interim exit meeting was conducted for Access Control to Radiologically Significant Areas with Ms. Barbra Dotson on October 25, 2007.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

C. Schwarz, Site Vice President

G. Baustian, Training Manager

S. Bell, Health Physicist

D. Bemis, Entergy/ISI Program Owner

A. Blind, Design Engineering Manager

L. Blocker, Operations Manager

J. Broschak, Engineering Director

N. Brott, Emergency Preparedness Coordinator

J. Burnett, RETS-REMP Analyst

T. Davis, Operations Training Supervisor

B. Dotson, Regulatory Compliance

D. Farrell, Acting Radiation Protection manager

J. Fontaine, Emergency Preparedness Coordinator

J. Ford, Emergency Preparedness Manager

J. Hager, Entergy/Steam Generator Program Owner

G. Hettel, Plant Manager

G. Higgs, Maintenance Manager

K. Housh, Appendix R Engineer

P. Johnson, Safety Manager

L. Lahti, Licensing Manager

A. Lyon, Design Engineer

D. Malone, Regulatory Affairs

D. Nestle, Acting Chemistry and Radiation Protection Manager

B. Nixon, Assistant Operations Manager

D. Nestle, Radiation Protection Manager, Acting

J. Plumb, Corrective Action Coordinator

M. Richey, Acting Plant General Manager

G. Sleeper, Assistant Operations Manager

K. Smith, Quality Assurance Manager

J. Smith, Mechanical Design Supervisor

B. Smoot, Radiation Protection Supervisor

T. Stell, Operations Training

T. Swiecicki, Appendix R Engineer

R. Van Wagner, Entergy/Engineering Programs Supervisor

P. Williams, Sr. RP Technician - Outage ALARA Planner

Nuclear Regulatory Commission

M. Chawla, Project Manager, NRR

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000255/2007006-01 NCV Plant Radiation Monitors Not Fully Scoped into the Maintenance Rule (Section 1R12)

05000255/2007006-02 NCV Inadequate Risk Assessment for Safety Injection Actuation Test (Section 1R13)

05000255/2007006-03 NCV Failure to Perform a 10 CFR 50.59 Evaluation for a Temporary Modification for Augmented Cooling of SW (Section 1R23)

05000255/2007006-06 NCV LPSI Check Valve Unseated (4OA2)

05000255/2007006-07 NCV AFW Pumps Inoperable Due to High Energy Line Breaks in the Turbine Building (Section 4OA5)

Closed

05000255/2007005-00 LER Reactor Protection System and Auxiliary Feedwater System Actuation (Section 4OA3)

05000255/2007006-00 LER Emergency Diesel Generator Inoperable in Excess of TS Requirements (Section 4OA3)

05000255/2006013-03 URI Potential Impact on AFW Pumps from High Energy Line Breaks in the Turbine Building (Section 4OA5)

05000255/2007003-00 LER Potential for Reduced Component Cooling Water Flow (Section 4OA3)

Opened

05000255/2007006-04 URI Internal Dose Assessment for O-ring work (Section 2OS1.7)

05000255/2007006-05 URI Increased Airborne Radioactivity in Containment (Section 2OS1.8)