IR 05000440/2010006

IR 05000440-10-006, on 06/14/2010 - 08/03/2010; Perry Nuclear Power Plant (Pnpp), Unit 1; Evaluations of Changes, Tests or Experiments and Permanent Plant Modifications

ML102420690
Person / Time
Site:	Perry
Issue date:	08/30/2010
From:	Robert Daley NRC/RGN-II/DRS/EB3
To:	Bezilla M FirstEnergy Nuclear Operating Co
References
IR-10-006
Download: ML102420690 (26)

Text

ust 30, 2010

SUBJECT:

PERRY NUCLEAR POWER PLANT EVALUATIONS OF CHANGES, TESTS, OR EXPERIMENTS AND PERMANENT PLANT MODIFICATIONS BASELINE INSPECTION REPORT 05000440/2010-006 (DRS)

Dear Mr. Bezilla:

On August 3, 2010, the U.S. Nuclear Regulatory Commission (NRC) completed an evaluation of changes, tests, or experiments and permanent plant modifications inspection at your Perry Nuclear Power Plant. The enclosed report documents the inspection findings, which were discussed on August 3, 2010, with Mr. John Grabnar and other members of your staff.

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

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

Based on the results of this inspection, one NRC-identified finding of very low safety significance was identified. The finding involved a violation of NRC requirements. However, because of its very low safety significance, and because the issue was entered into your corrective action program, the NRC is treating the issue as a Non-Cited Violation (NCV) in accordance with Section VI.A.1 of the NRC Enforcement Policy.

If you contest the subject or severity of a NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 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, DC 20555-0001; and the Resident Inspector Office at the Perry Nuclear Power Plant. In addition, if you disagree with the cross-cutting aspect assigned to any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region III, and the NRC Resident Inspector at the Perry Nuclear Power Plant. In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any), will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records System (PARS)

component of NRC's Agencywide Documents Access and Management System (ADAMS).

ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Robert C. Daley, Chief Engineering Branch 3 Division of Reactor Safety Docket No. 50-440 License No. NPF-58

Enclosure:

Inspection Report 05000440/2010-006 (DRS)

w/Attachment: Supplemental Information

REGION III==

Docket No: 50-440 License No: NPF 58 Report No: 05000440/2010-006(DRS)

Licensee: FirstEnergy Nuclear Operating Company (FENOC)

Facility: Perry Nuclear Power Plant (PNPP), Unit 1 Location: Perry, Ohio Dates: June 14, 2010, through August 3, 2010 Inspectors: George M. Hausman, Senior Reactor Inspector (Lead)

Zelig Falevits, Senior Reactor Inspector Larry J. Jones, Reactor Inspector Ronald A. Langstaff, Senior Reactor Inspector Approved by: Robert C. Daley, Chief Engineering Branch 3 Division of Reactor Safety Enclosure

SUMMARY OF FINDINGS

IR 05000440/2010-006; 06/14/2010 - 08/03/2010; Perry Nuclear Power Plant (PNPP), Unit 1;

Evaluations of Changes, Tests or Experiments and Permanent Plant Modifications This report covers a two-week announced baseline inspection on evaluations of changes, tests or experiments and permanent plant modifications. The inspection was conducted by Region III based engineering inspectors. One Green finding was identified by the inspectors. The finding was considered a Non-Cited Violation (NCV) of NRC regulations. 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 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: Mitigating Systems

Green.

The inspectors identified a finding of very low safety significance and associated NCV of Technical Specification 5.4.1.a for the licensees failure to maintain written procedures covering General Plant Operating Procedures, Procedures for Startup,

Operation and Shutdown of Safety-Related BWR [Boiling Water Reactor] Systems, and Procedures for Combating Emergencies and Other Significant Events, as required by the Technical Specifications. Specifically, the licensee failed to effectively manage, prioritize and disposition numerous long-standing design change requests (DCRs). The DCRs documented procedure changes to be incorporated into Operations procedures that were used during plant operation activities under normal, abnormal, emergency and shutdown conditions. The licensee entered this finding into their corrective action program (i.e., condition report (CR) 10-79187) and performed a cause analysis evaluation to identify the causes and determine potential impact on plant operations.

The finding was more than minor in accordance with IMC 0612, Appendix B because the finding was associated with the procedure quality attribute of the mitigating systems cornerstone and affected the cornerstones objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the licensees failure to maintain the Operations procedures up-to-date could have complicated and prolonged the operators response during plant operation activities under abnormal and emergency conditions, thereby delaying the mitigating systems availability to mitigate the consequences of a design basis accident. The finding was of very low safety significance based on a Phase 1 screening in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, Table 4a.

This finding had a cross cutting aspect in the area of human performance, resources because the licensee did not provide complete, accurate, and up-to-date Operations procedures to plant personnel. Specifically, the licensee failed to effectively manage, prioritize and disposition numerous long-standing DCRs. The DCRs documented procedure changes to be incorporated into Operations procedures that were used during plant operation activities under normal, abnormal, emergency and shutdown conditions. H.2(c) (Section 1R17.1b)

Licensee-Identified Violations

No violations of significance were identified.

REPORT DETAILS

1R17 Evaluations of Changes, Tests or Experiments and Permanent Plant

Modifications (71111.17) Evaluations of Changes, Tests or Experiments

a. Inspection Scope

From June 14, 2010, through August 3, 2010, the inspectors reviewed six safety evaluations performed pursuant to 10 CFR 50.59 to determine if the evaluations were adequate and that prior NRC approval was obtained as appropriate. The inspectors also reviewed 20 screenings where licensee personnel had determined that a 10 CFR 50.59 evaluation was not necessary. The inspectors reviewed these documents to determine if:

• the changes, tests or experiments performed were evaluated in accordance with 10 CFR 50.59 and that sufficient documentation existed to confirm that a license amendment was not required;

• the safety issue requiring the change, tests or experiment was resolved;

• the licensee conclusions for evaluations of changes, tests or experiments were correct and consistent with 10 CFR 50.59; and

• the design and licensing basis documentation was updated to reflect the change.

The inspectors used, in part, Nuclear Energy Institute (NEI) 96-07, Guidelines for 10 CFR 50.59 Implementation, Revision 1, to determine acceptability of the completed evaluations and screenings. The NEI document was endorsed by the NRC in Regulatory Guide 1.187, Guidance for Implementation of 10 CFR 50.59, Changes, Tests and Experiments, dated November 2000. The inspectors also consulted Part 9900 of the NRC Inspection Manual, 10 CFR Guidance for 10 CFR 50.59, Changes, Tests, and Experiments.

This inspection constituted six samples of evaluations and 20 samples of changes as defined in IP 71111.17-04

b. Findings

Failure to Effectively Manage, Prioritize and Disposition Numerous Operations Procedure Document Change Request Notifications

Introduction:

The inspectors identified a finding of very low safety significance and associated NCV of Technical Specification 5.4.1.a for the licensees failure to maintain written procedures covering General Plant Operating Procedures, Procedures for Startup, Operation and Shutdown of Safety Related BWR [Boiling Water Reactor]

Systems, and Procedures for Combating Emergencies and Other Significant Events, as required by the Technical Specifications. Specifically, the licensee failed to effectively manage, prioritize and disposition numerous long-standing design change requests (DCRs). The DCRs documented procedure changes to be incorporated into Operations procedures that were used during plant operation activities under normal, abnormal, emergency and shutdown conditions.

Description:

The inspectors reviewed 10 CFR 50.59, Regulatory Applicability Determination (RAD) and Screening Number 09-04248-00 dated October 12, 2009.

The RAD and screening was reviewed against the System Operating Instruction (SOI) -1R10 (LV), Plant Electrical System (Low Voltage), Revision 15. As a result of this review, the inspectors were informed that the proposed procedure changes, documented in Revision 15, had not been issued and that instead, another Revision 15, which addressed different changes to the procedure, was already issued. Since the revision to the SOI was not appropriately issued; the inspectors questioned the licensee concerning their DCR process and the number of outstanding SOI-IR10 (LV) DCRs.

The inspectors found that the licensees DCRs were maintained in the site priorities System Analysis and Program Development in Data Processing (SAP) Database, which tracked the DCRs initiation, review, priority, resolution, and closeout. The inspectors review of the licensees DCRs revealed that as of June 18, 2010, ten open DCRs were posted against SOI-IR10 (LV). The open DCRs documented procedure changes to be incorporated into the SOI that were used during plant operation activities. The DCRs were initiated between December 14, 2007, and April 5, 2009. All ten DCRs were classified as priority 6 or 600 (i.e., Steady-State/Routine). 1 However, the inspectors noted that the licensee treated all ten DCRs as normal work. The inspectors noted that several DCRs posted against SOI-IR10 (LV) were initiated to correct the following:

• Wrong attachment number and sequence of procedure steps (DCR600431054).

• Instruction step required operator to verify forced draft cooling fans on oil cooled transformers that did not have forced draft cooling fans (DCR600522487).

• No steps in Attachment 26 to de-energize/re-energize Bus EF-1-A, so that automatic isolation would not occur on various plant systems (DCR600524286).

• An incorrect reference to a motor control center functional location in 27, directed the operator to open a number of 120V disconnects (DCR600525979).

• Step 16 referred to the wrong checklist and the attachment did not include the requirement to open breaker EB1B10 (DCR600526277).

• Wrong unit designator (i.e., 1R71 verses 0R71) for emergency light units associated with breaker F1C08 (DCR600540792).

The inspectors reviewed procedure NOP-SS-8001, FENOC Activity Tracking, Revision 01, which provided the process methods and defined the responsibilities for Steady-State/Routine activities were defined as those activities necessary to maintain the plants current performance position. These activities are time and schedule discretionary. Work should be scheduled in a future Functional Equipment Group (FEG) week.

initiating and tracking activities that were contained in the SAP Database. The inspectors were informed that the site priority levels, as defined in procedure NOP-SS-8001, Attachment 1, could not be directly applied to assign priority classifications to the open DCRs and would not translate accurately to the DCR process.

As a result, the inspectors concluded that criteria and guidance were not established to assign priority to the DCRs.

On June 29, 2010, the inspectors reviewed a sample of the licensees backlog of 613 outstanding DCRs related to Operations procedures. The number of DCRs for each priority level is shown in Table 1 - Operations DCR Backlog Priority Listing. The backlog contained open DCRs that were initiated as early as 2005 (e.g., DCR600249977 was dated November 2, 2005). Based on this review, the inspectors conducted interviews with the licensees Operations Procedure Department (OPPD) personnel.

Through these discussions and further review of the DCRs follow-up actions with OPPD personnel, the inspectors observed that the DCR backlog contained numerous DCRs for which the assigned priority level was inconsistently applied. In addition, some of the DCRs priority levels were inappropriate and untimely to address the proposed changes commensurate with plant safety. Of the 613 open DCRs, the majority were assigned a priority level of 6 or 600 (i.e., normal work) with no clear or documented justification, 117 were more than three years old and no due dates were specified to complete the corrective actions required by the DCRs. Also, some of the open DCRs had already been incorporated into procedures and should have been closed and removed from the backlog list.

TABLE 1 - Operations DCR Backlog Priority Listing Priority Level Number of DCRs

13 479

82 Based on the inspectors questions concerning the Operations DCR backlog, the licensee initiated a corrective action plan with the issuance of CR10-79187, NRC ID 50.59: Prioritization of the Operations Procedure Backlog, dated July 1, 2010. On July 16, 2010, the following licensees corrective action plan activities were completed:

• A cause analysis evaluation initiated by CR10-79187 to:

1. Assess the potential for open DCRs to impact operator actions or response during abnormal or emergency conditions.

2. Determine the applicability and appropriate prioritization of the 613 open DCRs.

3. Establish an expected implementation date for each priority level and the periodic review of newly written DCRs.

4. Determine when to conduct periodic effectiveness reviews.

• The DCR backlog apparent causes (ACs) were identified as:

1. Clear defined criteria were not available to OPPD personnel to determine priorities with respect to DCRs (AC-1).

2. OPPD did not perform a review of either the DCR backlog or of the newly generated DCRs (AC-2).

• The 613 open DCRs contained in the Operations procedures backlog list were reevaluated utilizing the revised priority criteria developed by the OPPD. The reevaluation results are listed in Table 2 - Changes to Operations DCR Backlog Priority Levels Revised.

TABLE 2 - Changes to Operations DCR Backlog Priority Levels Revised Number of Previous DCR Revised DCR Affected DCRs Priority Level Priority Level 5 6 6 4 6 5 8 5 8 7 6 7 In addition, DCRs assigned level 4 or level 5 priorities were all previously treated as above normal work, without specific criteria. For example, the licensee defined priority level 4 (or 400) and priority level 5 (or 500) as Increased Attention 2 and Above Steady-State, 3 respectively.

As part of the licensees corrective action plan, the OPPD revised the existing eight priority level definitions for determining DCR priority level. For example, a priority level 4 was re-defined as having the potential to impact operator actions or response during alarm conditions, abnormal conditions, and emergency conditions (e.g., would affect ARI, ONI, EOP and other transient response procedures). As a result, the OPPD Operations DCRs backlog was changed from 613 to 507 open DCRs. The final results of the licensees corrective actions are shown in Table 3 - Operations DCR Backlog Priority Listing (Revised).

Increased Attention is defined as Activities procedurally or administratively time-dependent and necessary to maintain and sustain industry standards, plant reliability, regulatory expectations, continued operations including significant operations concerns or burdens, business requirements, or management-established performance criteria. Work is expected to be completed in less than 90 calendar days for most processes.

Above Steady-State is defined as Approved work above steady state to incrementally improve the plants current performance position. These activities are time and schedule aligned with approved process milestones.

TABLE 3 - Operations DCR Backlog Priority Listing (Revised)

Priority Level Number of DCRs

38 338

64 Although the priority level definitions were addressed, the inspectors were concerned with the licensees implementation of their revised corrective action plan (i.e., the interpretation of priority level definitions). Specifically, the licensees conclusion that delayed operator actions or response for the eight DCRs that were upgraded from priority level 6 to priority level 4 4 would have little to no impact on the recovery from abnormal or emergency conditions. The inspectors concern was based on another of the licensees conclusion that due to existing typographical errors, wrong functional locations, and disparity between some procedure sections in EOPs, ONIs, FPI and SVI operating procedures, that a delayed operator action or error could be experienced. As a result, a reactor operator performing the activity would have to stop and work through the process with a senior reactor operator to disposition the discrepancy during procedure performance. The length of the delayed operator actions or response would be dependent on the operators level of experience and could have an adverse affect on plant recovery.

The inspectors observed previous examples related to adequacy of Operations procedures. For example, on March 19, 2008, the licensee closed as complete Top Priority Actions to improve operations performance, including Action Items 510200 and 510211. These efforts were initiated to address the lack of management oversight and engagement in addressing open DCRs. Similar concerns related to adequacy of Operations procedures were documented by the NRC in the Perry IR 05000440/2009007-01 (DRS). In response, the licensee revised CR10-79187 to address this concern.

Analysis:

The inspectors determined that the licensees failure to maintain 5 written procedures covering General Plant Operating Procedures, Procedures for Startup, Operation, and Shutdown of Safety-Related BWR Systems, and Procedures for Combating Emergencies and Other Significant Events, was contrary to TS Section 5.4.1.a, and was a performance deficiency.

The finding was determined to be more than minor because the finding was associated with the mitigating systems cornerstone attribute of procedure quality and affected the i.e., having the potential to impact operator actions or response during abnormal or emergency conditions i.e., properly manage, prioritize and disposition/incorporate numerous long-standing DCR notifications into Operations procedures cornerstones objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the inspectors were concerned that the licensees failure to maintain the Operations procedures up-to-date could have complicated and prolonged the operators response during plant operation activities under abnormal and emergency conditions, thereby delaying the mitigating systems availability to mitigate the consequences of a design basis accident. To resolve the inspectors concern, the licensee entered this finding into their corrective action program as CR10-79187 and performed a cause analysis evaluation to identify the causes and determine the potential impact on plant operations.

The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 -

Initial Screening and Characterization of Findings, Table 4a for the mitigating systems cornerstone. The basis for selecting the mitigating systems cornerstone was that failure to maintain Operations procedures up-to-date could have complicated and prolonged the operators response during plant operation activities under abnormal and emergency conditions, thereby delaying the mitigating systems availability to mitigate the consequences of a design basis accident. The finding screened as Green because it was a procedure quality deficiency that did not result in actual loss of safety function.

This finding has a cross-cutting aspect in the area of human performance, resources because the licensee did not provide complete, accurate, and up-to-date Operations procedures to plant personnel. Specifically, the licensee failed to effectively manage, prioritize and disposition numerous long-standing DCRs. The DCRs documented procedure changes to be incorporated into Operations procedures that were used during plant operation activities under normal, abnormal, emergency and shutdown conditions. H.2(c)

Enforcement:

Technical Specification Section 5.4.1.a, states, in part, that Written procedures shall be established, implemented, and maintained covering the following activities. The applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Paragraphs 2, 4, and 6, of this Regulatory Guide states, in part, that procedures related to General Plant Operating Procedures, Procedures for Startup, Operation and Shutdown of Safety-Related BWR Systems, and Procedures for Combating Emergencies and Other Significant Events, respectively, shall be prepared and activities shall be performed in accordance with these procedures. The licensee established NOP-SS-8001, FENOC Activity Tracking, Revision 1, as the implementing procedure for initiating and tracking the DCRs for these procedures. The DCRs were maintained in the site priorities SAP Database, which tracked notification initiation, review, priority and resolution, and closeout.

Contrary to the above, from November 2, 2005, to June 28, 2010, the licensee failed to maintain written procedures covering General Plant Operating Procedures, Procedures for Startup, Operation, and Shutdown of Safety-Related BWR Systems, and Procedures for Combating Emergencies and Other Significant Events, as required by Technical Specification, Section 5.4.1.a. Specifically, the licensee failed to effectively manage, prioritize and disposition numerous long-standing DCRs. The DCRs documented procedure changes to be incorporated into Operations procedures that were used during plant operation activities under normal, abnormal, emergency and shutdown conditions. Because this violation was of very low safety significance and it was entered into the licensees corrective action program as CR10-78998 and CR10-79187, this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy (NCV 05000440/2010006-01 (DRS), Failure to Effectively Manage, Prioritize and Disposition Numerous Operations Procedure Document Change Request Notifications).

Permanent Plant Modifications

a. Inspection Scope

From June 14, 2010, through August 3, 2010, the inspectors reviewed 11 permanent plant modifications that had been installed in the plant during the last three years. This review included in-plant walkdowns of safety and non-safety-related systems and/or components. The modifications were selected based upon risk-significance, safety significance, and complexity. The inspectors reviewed the modifications selected to determine if:

• the supporting design and licensing basis documentation was updated;

• the changes were in accordance with the specified design requirements;

• the procedures and training plans affected by the modification have been adequately updated;

• the test documentation as required by the applicable test programs has been updated; and

• post-modification testing adequately verified system operability and/or functionality.

The inspectors also used applicable industry standards to evaluate acceptability of the modifications. The list of modifications and other documents reviewed by the inspectors is included as an Attachment to this report.

This inspection constituted 11 permanent plant modification samples as defined in IP 71111.17-04.

b. Findings

Diesel Generator Rooms Fire Protection System Concern

Introduction:

The inspectors identified an unresolved item (URI) associated with the licensees Division 1, 2 and 3 diesel generator (DG) rooms carbon dioxide (CO2) fire suppression system. Specifically, the licensed CO2 fire suppression systems actuation logic was redesigned from single heat detector logic to cross-zoned (e.g., multiple) heat detector logic without prior approval from the NRC (i.e., the authority having jurisdiction).

In addition, the setpoint for the heat detectors was raised substantially. The heat detector actuation logic was used to generate the CO2 fire suppression actuation signal, which discharges the DG rooms CO2 fire suppression system.

Description:

The inspectors reviewed Engineering Change Package (ECP) 05-0229-01, Division 1, 2, and 3 Diesel Generator Room Carbon Dioxide (CO2) Fire Suppression System Upgrade. The results of that review showed that the licensee modified the DG rooms CO2 fire suppression system to utilize a cross-zoned heat detector layout. The DG rooms cross-zoned heat detector layout changed the actuation logic that discharges the DG rooms CO2 fire suppression system. The systems actuation logic was modified from requiring a single heat detector output that generated the CO2 suppression actuation signal to cross-zoned (e.g., multiple) heat detectors located in different heat detector circuits which required a heat detector output from each circuit to generate a CO2 suppression actuation signal. The CO2 suppression actuation signal is used to discharge the DG rooms CO2 fire suppression system. In addition, the setpoint for the heat detectors was changed from 190 degrees (°) Fahrenheit (F) to 275°F.

The inspectors reviewed the plants license bases and amendment documents to determine the as built configuration for the Division 1, 2 and 3 DG rooms CO2 fire suppression system. The inspectors review concluded that the cross-zoned heat detector installation was redesigned from the original heat detector installation that was reviewed and approved by the NRC (i.e., the authority having jurisdiction).

Based on the inspectors review of the licensees fire protection codes of record, the National Fire Protection Association (NFPA) 12, Standard on Carbon Dioxide Extinguishing Systems, Revision 1974 and NFPA 72, National Fire Alarm and Signaling Code, Revision 1974), the inspectors determined that the NFPA codes of record provided no information regarding the use of cross-zoned heat detectors. The definition of Cross-zoning is the application of two detectors/sensors where one would usually suffice - in other words, the detection area of each smoke detector is degraded by 50 percent. In this application both detectors must discern a legitimate fire/smoke signature in order to set the system into alarm [/ actuation]. 6 The inspectors were concerned that the redesigned cross-zoned heat detector layout and subsequent CO2 fire suppression systems actuation logic change did not meet the licensees codes of record for detector spacing requirements and introduced design changes that required the NRCs review and approval prior to installation. This was based on the following inspectors concerns:

• The inspectors questioned the licensees detector spacing adherence to NFPA 72E - 1974, in that the NFPA codes spacing requirement for smooth ceilings read:

All points on the ceiling shall have a detector within a distance equal to or less than 0.7 times the listed spacing (0.7S).

With the redesigned cross-zoned heat detector layout and subsequent CO2 fire suppression systems actuation logic change, the cross-zoned heat detector layout required two heat detectors to take the place of one heat detector. Since the two heat detectors, which were located in different detector circuits, were required to take the place of one heat detector, not all points on the ceiling were covered by the two heat detectors (e.g., the inspectors initial interpretation of the licensees code of record indicated that there was a 30 percent reduction in the ceiling area coverage based on the heat detector spacing requirements specified by the NFPA code).

Colombo, A. False Alarm Fighting, Security Sales and Integration, November 2009

• The cross-zoned heat detector layout and subsequent CO2 fire suppression systems actuation logic change introduced an inherent heat detector time delay through the cross-zoned method that was not formally evaluated by the licensee.

The licensee used engineering judgment in preference to appropriate fire modeling. The licensee did not believe that there was a significant delay introduced through the redesign cross-zoned heat detectors.

• The licensees design review did not include considerations for ceiling heights of 26 feet.

• The licensee did not evaluate the impact of higher temperature setpoints upon actuation of the heat detectors. The inspectors performed calculations to determine what size of fire would be required to activate the heat detectors for CO2 activation based on a floor fire located three feet from an east-west wall. The inspectors used the formula for Alperts correlation of ceiling jet temperatures 7 to calculate the impact using the higher temperature setpoints. The inspectors calculations also accounted for the additional distance required to actuate a second detector due to the cross-zoning. The inspectors determined that an approximate 2 megawatt (MW) fire was required to actuate the CO2 system under the original design. A 2 MW fire is roughly equivalent to a diesel fuel oil fire with an area of 12 square feet. With the revised design incorporating cross-zoning and higher detector setpoint temperatures, an approximate 10 MW fire was required to actuate the system. A 10 MW fire is roughly equivalent to a diesel fuel oil fire with an area of 54 square feet. Based on these calculations, the inspectors concluded that the redesign would require a fire that was five times larger than the licensed design to actuate the DG rooms CO2 fire suppression system. As a result, the inspectors were concerned that the cross-zoned heat detector redesign, with the higher temperature setpoint change, created an adverse affect on the DG rooms CO2 fire suppression systems actuation time and would have a potential adverse impact on the licensees fire protection program and/or post-fire safe shutdown analysis.

• The acceptance testing of the current system designed did not account for the actuation of the system. The inspectors questioned whether the testing approach used for the dual zone installation actually tested the system as-installed. The licensee currently puts a false alarm in for one of the detectors and then used a heat source to actuate another detector in the other zone. The inspectors felt that this was not an adequate means of verifying that the system would detect the heat produced across the zones of influence.

• The licensee did not obtain, for the redesigned cross-zoned heat detectors and the substantially raised setpoint, the approval of the authority having jurisdiction. as required by the NFPA code of record for Approval of Installations, which read:

The completed system shall be tested by qualified personnel to meet the approval of the authority having jurisdiction. These tests shall be adequate to determine that the system has been properly installed and will function as intended. Only listed or approved equipment and devices shall be used in the systems.

Alpert, R. L., Equation (3), Chapter 2, Ceiling Jet Flows, Section 2, Fire Dynamics, The SFPE Handbook of Fire Protection Engineering, Third Edition, 2002 As a result of the redesigned cross-zoned logic, the lack of time delay evaluation, the substantial heat detector temperature increase and the adequacy of acceptance testing, the inspectors were concerned that the DG rooms CO2 fire detection and suppression systems modification (i.e., ECP 05-0229-01) created a potential adverse impact on the licensees fire protection program and/or post-fire safe shutdown analysis. Therefore, prior approval from the NRC as the authority having jurisdiction may be required. In response to the inspectors concerns, the licensee initiated CR 10-79208, NRC ID 50.59: Submittal of the DG Room Detector Changes to NRC for Review, dated July 1, 2010, and CR 10-79210, NRC ID 50.59. Cross-Zone Heat Detector Layout, dated July 1, 2010.

This issue will be considered a URI to obtain a more thorough review of the suppression system design and the plants license basis to determine if prior NRC approval was necessary for installation of this system (URI 05000440/2010-006-02(DRS), Diesel Generator Rooms Fire Protection System Concern).

4OA2 Identification and Resolution of Problems

Routine Review of Condition Reports

a. Inspection Scope

From June 14, 2010 through August 3, 2010, the inspectors reviewed corrective action process documents that identified or were related to 10 CFR 50.59 evaluations and permanent plant modifications. The inspectors reviewed these documents to evaluate the effectiveness of corrective actions related to permanent pant modifications and evaluations for changes, tests, or experiments issues. In addition, corrective action documents written on issues identified during the inspection were reviewed to verify adequate problem identification and incorporation of the problems into the corrective action system. The specific corrective action documents that were sampled and reviewed by the inspectors are listed in the Attachment to this report.

b. Findings

No findings of significance were identified.

4OA6 Meetings

.1 Exit Meeting Summary

On August 3, 2010, the inspectors presented the inspection results to Mr. John Grabnar and other members of the licensee staff. The licensee personnel acknowledged the inspection results presented and did not identify any proprietary content. The inspectors confirmed that all proprietary material reviewed during the inspection was returned to the licensee staff.

.2 Interim Exit Meeting

An interim exit meeting was conducted on July 2, 2010.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

B. Allison, Engineer - Fire Protection/Electrical

K. Baird, Engineer - System Engineering (Fire Protection)

S. Benedict, Superintendent Operations Services - Operations

M. Bezilla, Vice President - PNPP

R. Briggs, Engineer - Electrical and Instrumentation and Control

R. Coad, Manager - Regulatory Compliance

E. Condo, Shift Manager - Work Management

R. Dame, Performance Assessor - Fleet Oversight

C. Elberfeld, Supervisor - Nuclear Compliance

D. Evans, Director - Work and Outage Management

M. Garnett, Operations Procedure Writer - Operations

J. Grabnar, Director - Site Engineering

H. Hanson, Director - Performance Improvement

H. Hegrat, Fleet Program Manager - 50.59 Programs

T. Hilston, Manager - Design

B. Huck, Supervisor - Electrical and Instrumentation and Control

T. Jardine, Manager - Operations

D. Jondle, Supervisor - Engineering Analysis

M. Koberling, Manager - Plant and Equipment Reliability

K. Krueger, Plant General Manager - PNPP

M. Makar, Engineer - Fire Protection

A. Mueller, Jr. Manager - Training

K. Nelson, Supervisor - System Engineering

T. Rood, Nuclear Specialist Procedure Writer - Operations

P. Roney, Supervisor - Mechanical/Structural/Civil

R. Stadel, Staff Nuclear Engineer - Procurement Engineering

M. Stevens, Director - Maintenance

J. Tuffs, Manager - Chemistry

J. Pelcic, Engineer - Nuclear Compliance

A. Watkins, Program Owner - Perry 50.59 Program

K. Zaharewicz, Engineer - System Engineering

L. Zerr, Engineer - Nuclear Compliance

Nuclear Regulatory Commission

T. Hartman, Resident Inspector

M. Marshfield, Senior Resident Inspector

Attachment

LIST OF ITEMS

Opened

Failure to Effectively Manage, Prioritize and Disposition

05000440/2010006(DRS)-01 NCV Numerous Operations Procedure DCR Notifications (Section 1R17.1b)

Diesel Generator Rooms Fire Protection System

05000440/2010006(DRS)-02 URI Concern (Section 1R17.2b)

Closed

Failure to Effectively Manage, Prioritize and Disposition

05000440/2010006(DRS)-01 NCV Numerous Operations Procedure DCR Notifications (Section 1R17.1b)

Discussed

None Attachment