IR 05000440/2010002

IR 05000440-10-002, on 01/01/2010 - 03/31/2010, Maintenance Risk Assessments and Emergent Work Control; Operability Evaluations

ML101240949
Person / Time
Site:	Perry
Issue date:	05/04/2010
From:	Jamnes Cameron NRC/RGN-III/DRP/B6
To:	Bezilla M FirstEnergy Nuclear Operating Co
References
IR-10-002
Download: ML101240949 (38)

Text

May 4, 2010

SUBJECT:

PERRY NUCLEAR POWER PLANT NRC INTEGRATED INSPECTION REPORT 05000440/2010002

Dear Mr. Bezilla:

On March 31, 2010, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Perry Nuclear Power Plant. The enclosed report documents the inspection findings which were discussed on April 7, 2010, 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.

Based on the results of this inspection, two NRC-identified findings of very low safety significance (Green) were identified. One of the findings was determined to involve a violation of NRC requirements, however, because the finding was of very low safety significance and because the issue was entered into your corrective action program, the NRC is treating the finding as a non-cited violation (NCV) consistent with Section VI.A.1 of the NRC Enforcement Policy.

If you contest the subject or severity of this NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, 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 characterization of 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 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/

Jamnes L. Cameron, Chief Branch 6 Division of Reactor Projects Docket No. 50-440 License No. NPF-58

Enclosure:

Inspection Report 05000440/2010002 w/Attachment: Supplemental Information

REGION III==

Docket No: 50-440 License No: NPF-58 Report No: 050000440/2010002 Licensee: FirstEnergy Nuclear Operating Company (FENOC)

Facility: Perry Nuclear Power Plant, Unit 1 Location: Perry, Ohio Dates: January 1, 2010, through March 31, 2010 Inspectors: M. Marshfield, Senior Resident Inspector T. Hartman, Resident Inspector R. Baker, Resident Inspector, Duane Arnold Energy Center D. Meléndez-Colón, Acting Project Engineer W. Slawinski, Senior Health Physicist P. Smagacz, Reactor Engineer Approved by: Jamnes L. Cameron, Chief Branch 6 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000440/2010002; 01/01/2010 - 03/31/2010; Maintenance Risk Assessments and

Emergent Work Control; Operability Evaluations.

The inspection was conducted by resident and regional inspectors. The inspection report (IR) covers a 3-month period of resident inspection. Two green findings, one of which was a non-cited violation (NCV) were identified. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609 Significance Determination Process (SDP). Cross-cutting aspects were determined using IMC 0310,

"Components Within The Cross-Cutting Areas." Findings for which the SDP does not apply may be "Green," or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 4, dated December 2006.

A. Inspector-Identified and Self-Revealed Findings

Cornerstone: Mitigating Systems

Green.

A finding of very low safety significance and associated NCV of 10 CFR 50.65(a)(4) was identified by the inspectors for the licensee's failure to accurately assess plant risk during maintenance activities. The inspectors determined that the licensee failed to correctly identify the plant risk condition when the Unit 1 Division 1 Emergency Diesel Generator (EDG) was out of service for maintenance. Specifically, there was a 5-hour period of time that the licensee restored plant risk to GREEN status while the EDG remained unavailable and plant risk was actually YELLOW. The licensee entered the issue associated with their failure to correctly assess the plant risk condition into their corrective action program (CAP).

The performance deficiency was determined to be more than minor because the finding was similar to IMC 0612, Appendix E, Example 7.e, and resulted in actual plant risk being in a higher licensee-established risk category than declared. The finding was of very low safety significance because the risk deficit, or incremental core damage probability deficit (ICDPD) was < 1E-6. This finding had a cross-cutting aspect in the area of Human Performance, Decision-Making per IMC 0310 (H.1(b)) because the licensee did not use conservative assumptions in decision making nor adopt a requirement to demonstrate that the proposed action is safe in order to proceed rather than a requirement to demonstrate that it is unsafe in order to disapprove the action.

Specifically, the licensee chose to minimize system unavailability time and as a result did not perform a complete post-maintenance test which would have verified the EDG system was fully functional and available to perform its mission at the end of the maintenance period. (Section 1R13)

Green.

A finding of very low safety significance was identified by the inspectors for the licensees failure to make an accurate immediate operability determination (IOD) based on the actual plant conditions and the available information to provide reasonable assurance of operability. Specifically, on February 15, 2010, through wall leakage was identified coming from a welded elbow connection of an instrument line associated with the 'B' Emergency Closed Cooling (ECC) system supply to the 'B' control complex chiller heat exchanger. This instrument line is an American Society of Mechanical Engineers (ASME)Section III, Class 3 piping system, and the licensees IOD declared the 'B' ECC system operable without the degradation mechanism being discernable from visual examination (such as external corrosion or wear) or having substantial operating experience (site specific) with the identified degradation mechanism in the affected system. No violation of regulatory requirements occurred, and the issue was entered into the licensees CAP.

The performance deficiency was determined to be more than minor because it is associated with the Mitigating Systems cornerstone attribute of Equipment Performance-Availability, Reliability, and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems to respond to initiating events to prevent undesirable consequences (i.e., core damage). The finding was of very low safety significance because a loss of system safety function, or the actual loss of safety function of a single train for greater than its TS-allowed outage time did not occur, and the finding does not screen as potentially risk-significant due to a seismic, flooding, or severe weather initiating event. This finding had a safety culture cross-cutting aspect in the area of Problem Identification and Resolution, related to the Operating Experience component for not implementing and institutionalizing operating experience through changes to station processes, procedures, equipment, and training programs per IMC 0310 (P.2(b)). Specifically, the requirement for the degradation mechanism of through wall leakage on ASME Section III, Class 2 and 3 piping, to be readily apparent from visual examination in order to support an operable IOD, was not completely understood by operations personnel. This finding did not involve a violation of regulatory requirements. (Section 1R15)

Licensee-Identified Violations

None.

REPORT DETAILS

Summary of Plant Status

The plant began the inspection period at 100 percent power. On March 28, 2010, reactor power was reduced to 75 percent and returned to full power on March 31, 2010, and remained at full power for the remainder of the inspection period. The power reduction occurred as an automatic system response to the operators tripping off the 'B' reactor feed pump turbine (RFPT) due to a small oil based fire in the RFPT room. The unit was at full power throughout the remainder of the inspection period, with the exception of planned power reductions for routine surveillance testing and rod pattern alignments.

REACTOR SAFETY

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

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdown

a. Inspection Scope

The inspectors performed partial system walkdowns of the following risk-significant systems:

• emergency closed cooling (ECC) train 'B' on January 7, 2010;

• Division 2 and 3 protected trains during Division 1 Emergency Diesel Generator (EDG) maintenance on January 29, 2010;

• 'A' flow control valve (FCV) hydraulic power unit (HPU) following repair and testing on March 9 and 10, 2010; and

• high-pressure core spray with the reactor core isolation cooling (RCIC)inoperable to replace the waterleg pump on March 18 and 19, 2010.

The inspectors selected these systems based on their risk significance relative to the reactor safety cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could impact the function of the systems, and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, Updated Safety Analysis Report (USAR), Technical Specification (TS) requirements, outstanding work orders (WOs), condition reports (CRs), and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also walked down accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the corrective action program (CAP) with the appropriate significance characterization.

Documents reviewed are listed in the Attachment.

These inspections constituted four partial system walkdown samples as defined in Inspection Procedure (IP) 71111.04-05.

b. Findings

No findings of significance were identified.

.2 Semi-Annual Complete System Walkdown

a. Inspection Scope

On March 12, 2010, the inspectors concluded a complete system alignment inspection of the Unit 1 and Unit 2 125-Volt direct current (Vdc) electrical distribution system to verify the functional capability of the system. This system was selected because it was considered both safety significant and risk significant in the licensees probabilistic risk assessment (PRA). The inspectors walked down the system to review mechanical and electrical equipment line ups, electrical power availability, system temperature indications, component labeling, component lubrication, component and equipment cooling, hangers and supports, operability of support systems, and to ensure that ancillary equipment or debris did not interfere with equipment operation. A review of a sample of past and outstanding WOs was performed to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the CAP database to ensure that system equipment alignment problems were being identified and appropriately resolved. Documents reviewed are listed in the

.

This inspection constituted one complete system walkdown sample as defined in IP 71111.04-05.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

a. Inspection Scope

The inspectors conducted fire protection walkdowns which were focused on availability, accessibility, and the condition of firefighting equipment in the following risk-significant plant areas:

• Fire Zones 1CC-3a and 3c; Divisions 1 and 2 4160 V and 480 V Switchgear Rooms;

• Fire Zones 1DG-1a and 1c; Division 1 and 2 EDG Rooms;

• Fire Zones 1AB-1a, 1b, 1f, 1g and 1AB-2; Auxiliary Building 574' and 599 elevations;

• Fire Zones 1CC-4a through 4e, 4h, 4i, and 2CC-4a through 4e, 4h, 4i; Unit 1 and Unit 2 Division 1 and 2 Cable Spreading Rooms, 125-Vdc Distribution Rooms, and Battery Rooms; and

• Fire Zones 1DG-1b and 1CC-3b; Division 3 EDG and Switchgear Rooms.

The inspectors reviewed areas to assess if the licensee had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant, effectively maintained fire detection and suppression capability, maintained passive fire protection features in good material condition, and implemented adequate compensatory measures for out-of-service, degraded or inoperable fire protection equipment, systems, or features in accordance with the licensees fire plan. The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to impact equipment which could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event. Using the documents listed in the Attachment, the inspectors verified the following:

• fire hoses and extinguishers were in their designated locations and available for immediate use;

• fire detectors and sprinklers were unobstructed;

• transient material loading was within the analyzed limits; and

• fire doors, dampers, and penetration seals appeared to be in satisfactory condition.

The inspectors also verified that minor issues identified during the inspection were entered into the licensees CAP. Documents reviewed are listed in the Attachment to this report.

These inspections constituted five quarterly fire protection inspection samples as defined in IP 71111.05-05.

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures - Underground Vaults

a. Inspection Scope

The inspectors selected underground bunkers/manholes subject to flooding that contained cables whose failure could disable risk-significant equipment. The inspectors determined that the cables were not submerged, that splices were intact, and that appropriate cable support structures were in place. In those areas where dewatering devices were used, such as a sump pump, the device was operable and level alarm circuits were set appropriately to ensure that the cables would not be submerged. In those areas without dewatering devices, the inspectors verified that drainage of the area was available, or that the cables were qualified for submergence conditions. The inspectors also reviewed the licensees corrective action documents with respect to past submerged cable issues identified in the CAP to verify the adequacy of the corrective actions. The inspectors performed a walkdown of the Division 3 cabling manholes 1 and 2 East vaults on January 20, 2010.

This inspection constituted one underground vaults sample as defined in IP 71111.06-05.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program

a. Inspection Scope

On February 8, and March 15, 2010, the inspectors observed two crews of licensed operators in the plants simulator during licensed operator requalification examinations to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

• licensed operator performance;

• crews clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of abnormal and emergency procedures;

• control board manipulations;

• oversight and direction from supervisors; and

• the ability to identify and implement appropriate TS actions and emergency plan actions and notifications.

The crews performance in these areas was compared to pre-established operator action expectations and successful critical task completion requirements. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one quarterly licensed operator requalification program sample as defined in IP 71111.11.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors evaluated degraded performance issues involving the following risk-significant systems:

• 125-Volt, direct current (Vdc) electrical systems; and

• reactor recirculation system.

The inspectors reviewed events where ineffective equipment maintenance had resulted in valid or invalid automatic actuations of engineered safeguards systems and independently verified the licensee's actions to address system performance or condition problems in terms of the following:

• implementing appropriate work practices;

• identifying and addressing common cause failures;

• scoping of systems in accordance with 10 CFR 50.65(b) of the maintenance rule;

• characterizing system reliability issues for performance;

• charging unavailability for performance;

• trending key parameters for condition monitoring;

• ensuring 10 CFR 50.65(a)(1) or (a)(2) classification or re-classification; and

• verifying appropriate performance criteria for structures, systems, and components/functions classified as (a)(2) or appropriate and adequate goals and corrective actions for systems classified as (a)(1).

The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the system. In addition, the inspectors verified maintenance effectiveness issues were entered into the CAP with the appropriate significance characterization. Documents reviewed are listed in the Attachment to this report.

These inspections constituted two quarterly maintenance effectiveness samples as defined in IP 71111.12-05.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed the licensee's evaluation and management of plant risk for the maintenance and emergent work activities affecting risk-significant and safety-related equipment listed below to verify that the appropriate risk assessments were performed prior to removing equipment for work:

• emergency service water intake/suction line silt removal (including diving activities) on January 21, 2010;

• reactor feed booster pump 'A' maintenance on January 27, 2010;

• Division 1 EDG extended maintenance outage on January 28, 2010;

• ECC 'A' planned maintenance while the 'A' FCV HPU was shut down for emergent repairs on March 10, 2010;

• RCIC system waterleg pump replacement on March 18, 2010; and

• 'B' RFPT emergent repairs and testing March 29 through 31, 2010.

These activities were selected based on their potential risk significance relative to the reactor safety cornerstones. As applicable for each activity, 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 reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed TS requirements and walked down portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met.

These maintenance risk assessments and emergent work control evaluations constituted six samples as defined in IP 71111.13-05.

b. Findings

Introduction:

The inspectors identified a finding of very low safety significance (Green)and an associated NCV of 10 CFR 50.65(a)(4) for the failure to accurately assess plant risk, considering the actual equipment conditions, during post-maintenance activities conducted on the Division 1 EDG.

Description:

During the period of January 26, 2010, through February 3, 2010, the licensee performed planned maintenance on the Division 1 EDG, 1R43C00001A.

Following completion of the mechanical maintenance activities on the diesel engine, the EDG and support systems were placed in standby, and the licensee declared the Division 1 EDG available. This declaration of availability allowed the plant online PRA indicator to change from yellow to the lower risk indication of green, at 1659 hours0.0192 days <br />0.461 hours <br />0.00274 weeks <br />6.312495e-4 months <br /> on February 2, 2010. Approximately 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> later, at 10:00 p.m. on February 2, 2010, while the licensee was performing pre-start activities for the maintenance run of the Division 1 EDG, the operators discovered all of the petcock vents on the EDG piston cylinders in the open position. These petcocks are opened when the diesel is rolled with starting air, are closed following completion of the activity, and are required to be closed when the EDG is placed in standby. The System Operating Instruction (SOI) for EDGs, SOI-R43, contains provisions which allow operator actions for restoration to maintain availability of the EDG. Using this guidance, the licensee continued with the required pre-start activities and subsequent maintenance run and testing activities.

At 3:59 a.m. on February 3, 2010, when the DIESEL GENERATOR control switch in the control room was placed in STOP at completion of the post-maintenance test run, an unexpected overspeed trip annunciator was received. The licensee determined that the cause of the alarm was a fault in the overspeed pneumatic logic and not due to an actual overspeed condition or mechanical trip of the engine. At 5:02 a.m. the licensee declared the EDG unavailable to support further testing. Subsequent discussions between the responsible system engineer and operations personnel determined that the logic fault would preclude the EDG responding to a demand/start signal, and therefore the EDG would have been unavailable from the time the overspeed alarm was received. At 6:03 that morning, the licensee documented this change in Division 1 EDG availability and recorded that plant online PRA status should have been yellow between 3:59 and 5:02 a.m. on February 3, 2010.

Later that morning at approximately 7:30 a.m., following the shift turnover meeting, the inspectors requested the results of the licensees evaluation of the open petcocks with respect to availability of the EDG. The licensee concluded the Division 1 EDG was rendered unavailable with the petcocks open and in the standby lineup. At 4:04 p.m. on February 3, 2010, the licensee again updated the Division 1 EDG status as unavailable from 4:59 p.m. on February 2, 2010, with the petcocks open, until 10:00 p.m. on February 2, 2010. Operability after 10:00 p.m. was through the provisions of SOI-R43 which allow for available with restoration operator actions to shut the petcocks during the startup phase of the test run. The inspectors determined that the licensee had not promptly considered EDG availability with the petcocks open. The required online PRA indicator and site risk management responses for the Division 1 EDG being unavailable should have been yellow until 10:00 p.m. The inspectors noted that, although the online PRA risk category was lowered to green, the risk mitigation strategies implemented for the yellow risk category remained in place since the licensees procedures for allowed outage time maintenance requires them to remain in place until post-maintenance testing is completed.

Analysis:

The inspectors determined that the licensees failure to accurately assess the risk associated with maintenance activities on the Division 1 EDG was a performance deficiency. The performance deficiency was determined to be more than minor because it was similar to Inspection Manual Chapter (IMC) 0612, Appendix E, Example 7.e and resulted in actual online PRA risk crossing the threshold into a higher licensee-established risk category. The performance deficiency is associated with the Mitigating Systems cornerstone attribute of Equipment Performance - Availability, and adversely impacted the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage).

The inspectors determined that this 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. Using IMC 0609, Appendix K Maintenance Risk Assessment and Risk Management Significance Determination Process, as referenced from Table 3b, the SDP Phase 1 Screening Worksheet for the Mitigating Systems Cornerstone, the inspectors determined that the finding was of very low safety significance (Green) since the ICDPD was < 1E-6.

Additionally, the inspectors determined that this finding had a cross-cutting aspect in the area of Human Performance, Decision-Making per IMC 0310 (H.1(b)) because the licensee did not use conservative assumptions in decision making and adopt a requirement to demonstrate that the proposed action is safe in order to proceed rather than a requirement to demonstrate that it is unsafe in order to disapprove the action.

Specifically, the licensees administrative process to declare the EDG available following completion of the maintenance activities paperwork, without actually demonstrating that the EDG would start and reach required voltage and frequency, allowed the EDG to be considered available to perform designed safety functions when actual equipment conditions prohibited operation.

Enforcement:

The requirements of 10 CFR 50.65(a)(4) state, in part, that the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities. Contrary to this requirement, for approximately 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> on February 2, 2010, the licensees risk assessment did not accurately reflect the increase in online PRA risk associated with the Division 1 EDG being unavailable.

Since the licensees risk mitigation actions remained in place during this period and an actual demand for the EDG did not occur, no actual safety consequences resulted.

The licensee restored the EDG to a standby condition by closing the petcocks on the EDG. Because this violation was of very low safety significance and because the issue was entered into the licensees CAP as CR 10-71049, this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy.

(NCV 05000440/2010002-01, Failure to Correctly Assess Risk During Post-Maintenance Activities.)

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• 3DMONICORE non-conservative calculation impact with oscillating power range monitors;

• through wall leakage from a welded joint on the 'B' ECC system;

• M23/24 control complex chilled water cooling valve not controlling temperature; and

• offsite power low/degraded voltage concerns.

The inspectors selected these potential operability issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TS and USAR to the licensees evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. Documents reviewed are listed in the to this report.

These inspections constituted four samples as defined in IP 71111.15-05.

b. Findings

Introduction:

A finding of very low safety significance (Green) was identified by the inspectors for the licensees failure to make an accurate immediate operability determination (IOD) based on the actual plant conditions and the available information to provide reasonable assurance of operability. Specifically, on February 15, 2010, through wall leakage was identified coming from an apparent welded connection of an instrument line associated with the 'B' ECC system supply to the B control complex chiller heat exchanger. This instrument line is an American Society of Mechanical Engineers (ASME)Section III, Class 3 piping system, and the licensees IOD declared the 'B' ECC system operable without the degradation mechanism being discernable from visual examination (such as external corrosion or wear) or having substantial operating experience (site specific) with the identified degradation mechanism in the affected system.

Description:

During plant equipment rounds, on February 15, 2010, at approximately 9:30 p.m., a small water leak was noted coming from the overhead in the vicinity of the

'B' control complex chiller. The auxiliary operator informed the control room, and a more detailed investigation was performed. The leak was traced to a small crack where a 1/2-inch flow instrument line is welded to a 10-inch ECC piping flange. Licensee CR 10-71622 was generated, together with notification 600597496, to document the issue.

The shift manager on the evening shift documented an operable IOD for the 'B' ECC system based upon the leakage being minor (approximately 2 drops per minute) and a belief that the leakage would not challenge equipment mission time. Plant management was informed on a duty call at approximately 5:15 a.m. on February 16, 2010, and a prompt operability determination (POD) was requested to be completed by 5:00 a.m. on February 17, 2010 (approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> from the IOD).

The day-shift shift manager took the watch on February 16, 2010, with knowledge that the engineering department was actively working on a prompt operability determination (POD.) Plans were made to isolate and repair the affected 'B' ECC piping. While the degraded/nonconforming condition of the piping was being isolated per the SOIs, the shift manager was informed by phone that it was unlikely they would be able to characterize the flaw with visual observation and the POD they were working on would not support operability. With this knowledge, the shift manager immediately declared the

'B' ECC system inoperable and entered the required TS limiting condition for operation (LCO) action statement, TS 3.7.10 Condition A, to declare the supported systems inoperable and take the required actions of applicable LCOs.

In accordance with TS 3.7.10, once the degraded/nonconforming condition is isolated, by declaring the 'B' Control Complex Chiller inoperable and isolating the 'B' ECC system piping to the chiller, the remaining portion of the 'B' ECC system is declared operable and the requisite LCO conditions are exited. The POD request was cancelled since the component of concern was declared inoperable and planned to be restored using ASME code repairs.

Information provided by the engineering department on the inability to characterize the through wall flaw in the 'B' ECC piping, documented the existing requirements and information which was available to the shift manager for determining operability of ASME Section III, Class 1, 2, and 3 piping with identified through wall leakage. Guidance for Class 2 and 3 piping provides that the degradation mechanism must be readily apparent (discernable from visual examination, or there must be substantial operating experience with the identified degradation mechanism in the affected system) to determine the component is operable for the purpose of making an IOD. This criteria was not correctly applied when the initial IOD bases for reasonable assurance of operability was determined and documented. Additionally, the shift manager believed that the system could remain operable until the POD characterized the flaw associated with the through wall leakage. The inspectors discussions with both operations and engineering department personnel determined that the knowledge deficiency associated with understanding the requirements for operability related to piping through wall leakage was not limited to any one individual.

Analysis:

The inspectors determined that the licensees failure to make an accurate IOD based on the actual plant conditions and the available information to assess operability requirements was a performance deficiency warranting further review. The performance deficiency was compared to, and was not similar to any of the examples in IMC 0612, Appendix E, Examples of Minor Issues. The performance deficiency was then evaluated in accordance with to IMC 0612 Appendix B, Issue Screening, and was characterized as more than minor because it was associated with the Mitigating Systems cornerstone attribute of Equipment Performance-Availability, Reliability, and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems to respond to initiating events to prevent undesirable consequences (i.e., core damage).

The inspectors determined that this finding could be evaluated in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings. As referenced in Table 2, the inspectors determined that long term core decay heat removal was degraded. Using Table 4a, Characterization Worksheet for IE, MS, and BI Cornerstones, the inspectors assessed the finding as having very low safety significance (Green) because a loss of system safety function, or the actual loss of safety function of a single train for greater than its TS-allowed outage time did not occur, and the finding does not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event.

The inspectors determined this finding had a safety culture cross-cutting aspect in the area of Problem Identification and Resolution, related to the Operating Experience component, for the licensee's failure to implement and institutionalize operating experience through changes to station processes, procedures, equipment, and training programs per IMC 0310 (P.2(b)). Specifically, the requirement for the degradation mechanism of through wall leakage on ASME Section III, Class 2 and 3 piping, to be readily apparent from visual examination in order to support an operable IOD, was not completely understood by operations personnel.

Enforcement:

The licensee entered this issue into the CAP as CR 10-71622.

Enforcement action does not apply because the performance deficiency did not involve a violation of a regulatory requirement. Because this finding does not involve a violation of regulatory requirements, and has very low safety significance, it is identified as Finding (FIN)05000440/2010002-02, Failure to Make an Accurate Immediate Operability Determination.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed the following post-maintenance activities to verify that procedures and test activities were adequate to ensure system operability and functional capability:

• Division 1 EDG extended maintenance outage and PM testing maintenance run during the weeks of January 25 and February 1, 2010;

• Division 1 EDG pneumatic trip logic troubleshooting and PM testing during the week of February 1, 2010;

• Unit 1 Division 1 125-Vdc battery replacement during the week of February 16, 2010;

• 'A' FCV HPU repair and testing during the week of March 8, 2010;

• RCIC waterleg pump replacement during the week of March 15, 2010; and

• 'B' RFPT oil system repair and post-maintenance testing during the week of March 29, 2010.

These activities were selected based upon the structure, system, or component's (SSCs)ability to impact risk. The inspectors evaluated these activities for the following (as applicable): the effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed; acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate; tests were performed as written in accordance with properly reviewed and approved procedures; equipment was returned to its operational status following testing (temporary modifications or jumpers required for test performance were properly removed after test completion); and test documentation was properly evaluated. The inspectors evaluated the activities against TS, the USAR, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with PM tests to determine whether the licensee was identifying problems and entering them in the CAP and that the problems were being corrected commensurate with their importance to safety. Documents reviewed are listed in the Attachment to this report.

These inspections constituted six post-maintenance testing samples as defined in IP 71111.19-05.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the test results for the following activities to determine whether risk-significant systems and equipment were capable of performing their intended safety function and to verify testing was conducted in accordance with applicable procedural and TS requirements:

• standby liquid control 'A' pump and valve operability in-service testing on January 5, 2010;

• Division 2 DG start and load routine testing on January 12, 2010;

• ECC system loop 'B' flow balance routine testing on January 14, 2010;

• control rod maximum scram insertion time routine testing on February 6, 2010;

• drywell floor drain sump flow functional reactor coolant system (RCS) leakage testing on March 9, 2010;

• annulus exhaust gas treatment system 'B' routine testing on March 24, 2010.

The inspectors observed in-plant activities and reviewed procedures and associated records to determine the following:

• did preconditioning occur;

• were the effects of the testing adequately addressed by control room personnel or engineers prior to the commencement of the testing;

• were acceptance criteria clearly stated, demonstrate operational readiness, and consistent with the system design basis;

• plant equipment calibration was correct, accurate, and properly documented;

• as-left setpoints were within required ranges;

• calibration frequency were in accordance with TS, the USAR, procedures, and applicable commitments;

• measuring and test equipment calibration was current;

• test equipment was used within the required range and accuracy;

• applicable prerequisites described in the test procedures were satisfied;

• test frequencies met TS requirements to demonstrate operability and reliability;

• tests were performed in accordance with the test procedures and other applicable procedures;

• jumpers and lifted leads were controlled and restored where used;

• test data and results were accurate, complete, within limits, and valid;

• test equipment was removed after testing;

• where applicable for in-service testing activities, testing was performed in accordance with the applicable version of Section XI, ASME code, and reference values were consistent with the system design basis;

• where applicable, test results not meeting acceptance criteria were addressed with an adequate operability evaluation or the system or component was declared inoperable;

• where applicable for safety-related instrument control surveillance tests, reference setting data were accurately incorporated in the test procedure;

• where applicable, actual conditions encountering high resistance electrical contacts were such that the intended safety function could still be accomplished;

• prior procedure changes had not provided an opportunity to identify problems encountered during the performance of the surveillance or calibration test;

• equipment was returned to a position or status required to support the performance of its safety functions; and

• all problems identified during the testing were appropriately documented and dispositioned in the CAP.

Documents reviewed are listed in the Attachment to this report.

These inspections constituted four routine surveillance testing samples; one in-service testing sample; and one RCS leak detection inspection sample as defined in IP 71111.22, Sections -02 and -05.

b. Findings

No findings of significance were identified.

1EP6 Emergency Preparedness Drill Evaluation Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine licensee emergency drill on March 2, 2010, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the control room (simulator) and technical support center to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the licensee's drill critique to compare any inspector-observed weakness with those identified by the licensee's staff in order to evaluate the critique and to verify whether the licensee's staff was properly identifying weaknesses and entering them into the CAP. As part of the inspection, the inspectors reviewed the drill package and other documents listed in the Attachment to this report.

This emergency preparedness drill inspection constituted one sample as defined in IP 71114.06-05.

b. Findings

No findings of significance were identified.

2RS8 Radioactive Solid Waste Processing and Radioactive Material Handling, Storage and

Transportation (71124.08)

This inspection constituted a partial sample as defined in IP 71124.08.

Shipment Preparation (02.05)

a. Inspection Scope

The inspectors reviewed an incident that occurred on February 3, 2010, that involved a radioactive waste shipment readiness problem, as documented in CR 10-71097.

Specifically, as a radioactive resin waste shipment was slowly being moved through the site's protected area for transport offsite, the tractor's fifth wheel locking assembly disengaged from the cask shipment trailer. As a result, the trailer disconnected from the tractor, dropping the trailer to the pavement adjacent to the plant access facility.

The inspectors reviewed the shipment/vehicle readiness inspection protocol and associated checklists, the cask radiological survey completed before and after the incident, and the licensee's radioactive material/waste shipment procedure to determine whether the licensee properly characterized the problem. Corrective action documents including the licensee's cause analysis were also reviewed to determine if the licensee's corrective actions were sufficient to prevent recurrence.

b. Findings

No findings of significance were identified.

4OA1 Performance Indicator Verification

.1 Unplanned Scrams per 7000 Critical Hours

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Scrams per 7000 Critical Hours Performance Indicator (PI) for the period from the first quarter 2009 through the fourth quarter 2009. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the Nuclear Energy Institute (NEI)

Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports, and NRC Inspection Reports (IRs) for the period of first quarter 2009 through the fourth quarter 2009 to validate the accuracy of the submittals.

The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.

This inspection activity constituted one unplanned scrams per 7000 critical hours sample as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

.2 Unplanned Scrams with Complications (Scrams with Loss of Normal Heat Removal)

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Scrams with Complications PI for the period from first quarter 2009 through the fourth quarter 2009.

To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports and NRC Integrated IRs for the period of first quarter 2009 through the fourth quarter 2009 to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.

This inspection activity constituted one unplanned scrams with complications sample as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

.3 Unplanned Transients per 7000 Critical Hours

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Transients per 7000 Critical Hours PI for the period from the first quarter 2009 through the fourth quarter 2009. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, maintenance rule records, event reports, and NRC Integrated IRs for the period of first quarter 2009 through the fourth quarter 2009 to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified.

Documents reviewed are listed in the Attachment to this report.

This inspection activity constituted one unplanned transients per 7000 critical hours sample as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

.4 Barrier Integrity - Reactor Coolant System Specific Activity (02.01)

a. Inspection Scope

The inspectors sampled licensee submittals for the RCS Specific Activity PI for the period from the fourth quarter 2009 through February 2010. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, were used. The inspectors reviewed chemistry records and calculational methods (including isotopic analyses) to determine if the greatest dose equivalent iodine values obtained during steady state operations corresponded to the values reported.

The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. In addition to record reviews, the inspectors observed a chemistry technician obtain and analyze a RCS sample. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one RCS specific activity sample as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

4OA2 Problem Identification and Resolution

Cornerstone: Initiating Events, Mitigating Systems, Barrier Integrity, and

Emergency Preparedness

.1 Routine Review of Items Entered Into the CAP

a. Inspection Scope

As part of the various baseline IPs discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that they were being entered into the licensees CAP at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. Attributes reviewed included: the complete and accurate identification of the problem; that timeliness was commensurate with the safety significance; that evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent-of-condition reviews, and previous occurrence reviews were proper and adequate; and that the classification, prioritization, focus, and timeliness of corrective actions were commensurate with safety and sufficient to prevent recurrence of the issue.

These routine reviews for the identification and resolution of problems did not constitute any additional inspection samples. Instead, by procedure they were considered an integral part of the inspections performed during the quarter and documented in Section 1 of this report.

b. Findings

No findings of significance were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensees CAP. This review was accomplished through inspection of the stations daily CR packages.

These daily reviews were performed by procedure as part of the inspectors daily plant status monitoring activities and, as such, did not constitute any separate inspection samples.

b. Findings

No findings of significance were identified.

.3 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a review of the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screening discussed in Section 4OA2.2 above, licensee trending efforts, and licensee human performance results. The inspectors review nominally considered the 6-month period of July 2009 through December 2009, although some examples expanded beyond those dates where the scope of the trend warranted.

The reviews also included issues documented outside of the normal CAP in major equipment problem lists, repetitive and/or rework maintenance lists, departmental problem/challenges lists, system health reports, quality assurance audit/surveillance reports, self-assessment reports, and maintenance rule assessments. The inspectors compared and contrasted their results with the results contained in the licensees CAP trending reports. Corrective actions associated with a sample of the issues identified in the licensees trending reports were reviewed for adequacy.

This review constituted a single semi-annual trend inspection sample as defined in IP 71152-05.

b. Findings

No findings of significance were identified.

.4 Annual Follow-Up of Selected Issues Sample: Operability Determinations Process

a. Inspection Scope

The inspectors performed an annual follow-up of selected issues sample of the licensees process for performing and documenting operability determinations. The inspectors reviewed documentation in both the licensees CAP and official narrative operating logs, for compliance with site-specific administrative and operational procedures, specifically to assess for proper documentation of the bases for reasonable assurance of operability; and proper documentation and evaluation of degraded and/or non-conforming conditions when appropriate for specific operability determinations. The inspectors also assessed how the safety significance of the affected components or the identified degraded or non-conforming condition influenced determinations of the time period allowed to perform PODs in support of continued operability. Documents reviewed are listed in the Attachment to this report.

This review constituted one in-depth problem identification and resolution sample as defined in IP 71152-05.

b. Observations and Assessments The site procedures provide clear requirements for implementing IMC Part 9900 Technical Guidance when documenting sufficient details for both IODs and PODs.

Adequate detail is required so that another technically knowledgeable individual should reach the same conclusion as the original determination. The licensee's current challenge though is reconstructing the sequence and timing of updates to CAP documents with entries from the narrative logs, predominately for IODs. The PODs are stand-alone products, once completed. One example which is inconsistent with the site Nuclear Operating Procedure (NOP)-OP-1009 was noted. The procedure requires a new CR to be written if a SSC is declared inoperable as a result of POD efforts. For the recent determination associated with the 'B' ECC system, an update was simply added to the existing CR.

The inspectors noted that site procedures clearly implement the IMC Part 9900 Technical Guidance regarding timeliness requirements for performing a POD, most of which can usually be completed within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, unless it is appropriate to make a POD within a few hours for a safety-significant SSC. Currently, POD due dates are routinely established at 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> from the time the IOD is complete, unless a more safety-significant issue based upon a shorter duration LCO action statement applies.

The normal process at Perry is that an update is provided at the 24-hour point, followed by a request for an extension, as opposed to establishing a reasonable due date, taking into account the safety significance of the condition/issue, when the POD is requested.

Each POD should have a due date established which is based upon the safety significance of the identified condition, and is consistent with the bases for reasonable assurance in the initial IOD.

One minor discrepancy was identified in the site procedure, NOP-OP-1009, with regard to IMC Part 9900 Technical Guidance. Part 9900 Technical Guidance for Operability Determinations requires, in part, that A senior licensed operator on the operating shift crew with responsibility for plant operations makes the declaration of operability, i.e.,

makes the call on whether an SSC described in TS is operable or inoperable. In NOP-OP-1009, a NOTE listed above Section 4.1.11, the section which defines the responsibilities for the Shift Manager, states that when the outage control center is staffed, the Outage Control Center (OCC) Operations SRO may perform the duties of the Shift Manager with parallel comms to the Control Room Shift Manager. Having an OCC SRO make an operability determination is in conflict with the Part 9900 guidance.

c. Findings

No findings of significance were identified.

4OA3 Follow-up of Events and Notices of Enforcement Discretion

.1 (Closed) Licensee Event Report 05000440/2010-001-01: Invalid Isolation Signal Results

in Shutdown Cooling Interruption

a. Inspection Scope

During the spring 2009 refueling outage, while the reactor was in Mode 4, a safety system function failure occurred when a maintenance error resulted in a loss of all residual heat removal system capabilities. The licensee initially classified the event as reportable and made the phone report on April 28, 2009. The licensee later determined that it was not reportable and retracted the initial report on June 25, 2009. The licensee initiated a corrective action to investigate the decision to retract the event report. The licensees investigation, using additional guidance and enforcement history related to safety system functional failure reporting criteria, determined that the April 27, 2009, event does meet the reporting criteria for Any event that could have prevented the fulfillment of the safety function of structures or systems that are needed to remove residual heat. The licensee provided an update to the original Event Notification 45025 on March 10, 2010, and submitted Licensee Event Report (LER) 05000440/2010-001-01, Invalid Isolation Signal Results in Shutdown Cooling Interruption, on March 25, 2010. The inspectors reviewed the original performance deficiency which was reviewed under previous inspection activities and was documented as a self-revealed finding of very low safety significance (Green) with an associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, (NCV 05000440/2009003-09; Loss of Shutdown Cooling Water Flow to Reactor Vessel).

The licensee documented their failure to report the safety system functional failure in CR 10-71293. The LER and final evaluation were reviewed by the inspectors and no additional findings or violations of NRC requirements were identified. Documents reviewed are listed in the Attachment. This LER is closed.

This event follow-up review constituted one sample as defined in IP 71153-05.

.2 Fire in the 'B' Reactor Feed Pump Turbine Area

a. Inspection Scope

The inspectors reviewed the licensee's personnel performance in response to an oil fire which occurred the evening of March 28, 2010, on the 'B' RFPT area in the Unit 1 Heater Bay Building. The control room was notified by an in-plant operator at 6:18 p.m.

and the control room operators manually tripped the 'B' RFPT to allow removal of the turbine lube oil system from service. All plant equipment responded as expected and reactor power was stabilized at approximately 75 percent. The Perry Township Fire Department was notified for assistance, and responded to the site. The fire was reported out at 10:12 p.m. and an initial Event Notification (Event Number 45795),4-hour non-emergency report, was made due to notification of offsite state and local authorities.

The inspectors reviewed the licensees actions to investigate, repair, and restore the

'B' RFPT and associated support systems to service, and did not identify any significant issues with the activities. The licensee will conduct a root cause investigation to identify factors leading to the event, and the inspectors will review the results once the evaluation is completed. Documents reviewed associated with the event response and restoration activities are listed in the Attachment.

This event follow-up review constituted one sample as defined in IP 71153-05.

b. Findings

No findings of significance were identified.

4OA5 Other Activities

.1 (Closed) Unresolved Item 05000440/2009005-03: Potential Missed Reporting

Requirement for Loss of Residual Heat Removal During Shutdown

a. Inspection Scope

This Unresolved Item (URI) is associated with the licensees potential failure to report a safety system function failure caused by a maintenance error which occurred during the spring 2009 refueling outage, while the reactor was in Mode 4, and resulting in a loss of all residual heat removal system capabilities. The licensee initially classified the event as reportable and made a phone report on April 28, 2009. The licensee later determined that it was not reportable and retracted their initial report on June 25, 2009.

The licensee initiated a corrective action to investigate the decision to retract the event report. The licensees investigation, using additional guidance and enforcement history related to safety system functional failure reporting criteria, determined that the April 27, 2009, event does meet the reporting criteria for Any event that could have prevented the fulfillment of the safety function of structures or systems that are needed to remove residual heat. The licensee provided an update to the original event notification, Event Number 45025, on March 10, 2010, and submitted LER 05000440/2010-001-01, Invalid Isolation Signal Results in Shutdown Cooling Interruption, on March 25, 2010.

The inspectors reviewed the results from the licensees final investigation, as documented in CR 10-71293, did not identify any findings or violations, and have assessed the actions to submit the LER as adequate. This URI is closed and no further actions are required.

.2 (Closed) NRC Temporary Instruction 2515/173 Review of the Implementation of the

Industry Ground Water Protection Voluntary Initiative

a. Inspection Scope

An NRC assessment was performed of the licensees implementation of the Nuclear Energy Institute - Ground Water Protection Initiative (NEI-GPI) dated August 2007 (ML072610036) at the Perry Nuclear Power Station. Under the voluntary initiative, each site was to develop an effective, technically sound ground water protection program that aligned with the NEI initiative by August 2008.

The inspectors assessed whether the licensee evaluated work practices that could lead to leaks and spills and performed an evaluation of SSCs that contain licensed radioactive material to determine potential leak or spill mechanisms.

The inspectors assessed whether the licensee completed a site characterization of geology and hydrology to determine the predominant ground water gradients and potential pathways for ground water migration from on-site locations to off-site locations.

The inspectors also verified that an on-site ground water monitoring program had been implemented to monitor for potential licensed radioactive leakage into ground water and that the licensee had provisions for the reporting of its ground water monitoring results.

(See http://www.nrc.gov/reactors/operating/ops-experience/tritium/plant-info.html)

The inspectors reviewed the licensees procedures for the decision making process for potential remediation of leaks and spills, including consideration of the long term decommissioning impacts. The inspectors also assessed whether records of leaks and spills were being recorded in the licensees decommissioning files in accordance with 10 CFR 50.75(g).

The inspectors reviewed the licensees notification protocols to determine whether they were consistent with the GPI and/or State of Ohio statutes, as applicable. The inspectors determined whether the licensee identified the appropriate local and state officials and conducted briefings on the licensees ground water protection initiative.

The inspectors also evaluated whether protocols were established for notification of the applicable local and state officials regarding detection of leaks and spills.

b. Findings

No findings of significance were identified; however, as specified in Section 2515/173-05 of the Temporary Instruction (TI), the inspectors identified the following deviations from NEI-GPI protocols that were either not fully developed or had not yet been fully implemented at Perry Nuclear Power Plant.

(1) GPI Objective 1.1e - Site Hydrology and Geology Perform a site characterization of the geology and hydrology that provides an understanding of the predominant ground water gradients based upon current site conditions. Revise the Final Safety Analysis Report (FSAR) to include changes to the characterization of hydrology and/or geology, as appropriate.

A site characterization of the geology and hydrology was completed in 2006, which provides an understanding of the predominant ground water gradients based upon current conditions. However, the licensee had not completed its review of the FSAR to ensure alignment with the current site characterization study.

(2) GPI Objective 1.2b - Site Risk-Assessment Identify SSCs that involve or could reasonably be expected to involve licensed material for which there is a credible mechanism for licensed material to reach ground water. Identify leak detection methods for each SSC for which there is a credible mechanism for licensed material to reach ground water.

A leak detection program was developed for SSCs that reside outside the radiologically controlled area while development continues for SSCs located within the power block.

The program is expected to be fully developed in 2011. Integrity assessments of SSCs that contain or could contain licensed material are targeted for completion in mid-2013, consistent with industry expectations.

(3) GPI Objective 1.3f - Onsite Ground Water Monitoring Establish an onsite ground water monitoring program to ensure timely detection of inadvertent radiological releases to ground water including a long-term program for preventative maintenance of ground water wells.

The licensee had not established a long-term maintenance program for its monitoring wells. While well heads were visually inspected by licensee or contractor staff periodically, the integrity of the well casing, confirmation of well depth consistency, silt buildup, and other preventative maintenance activities as provided in industry standards had not yet been developed.

(4) GPI Objective 1.4b - Remediation Process Evaluate the potential for detectible levels of licensed material resulting from planned releases of liquids and/or airborne materials.

The licensee had not performed an evaluation of the potential for detectible levels of licensed material from planned releases of liquids and/or airborne materials (e.g.,

rain-out and condensation). An evaluation protocol was being developed by the licensee for future implementation.

(5) GPI Objective 2.2a - Voluntary Communications Develop guidance for voluntary communication to satisfy the thresholds provided in the NEI Initiative or state/local agreements.

The licensee established ground water monitoring communication protocols in written procedures that do not fully align with the industry initiative and the licensee's radiological environmental monitoring program. Although the licensee understands the expected reporting thresholds, portions of the licensees written procedures are inconsistent with industry guidance.

4OA6 Meetings

.1 Exit Meeting

The inspectors initially presented the inspection results to the Site Vice President, Mr. Mark Bezilla, and other members of licensee management on April 7, 2010.

An additional exit meeting was held on April 20, 2010, with the Plant General Manager, Mr. Kurt Krueger, and other members of licensee management, to update the proposed findings and associated cross-cutting aspects from those previously briefed on April 7, 2010.

The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. Proprietary information was reviewed during this period but none of the material is included in this report.

.2 Interim Exit Meetings

An interim exit meeting was conducted for ground water protection voluntary initiative and RCS specific activity PI verification with Mr. T. Jardine and other licensee staff on March 12, 2010.

The inspectors confirmed that none of the potential report input discussed was considered proprietary. Proprietary material received during the inspection was returned to the licensee.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

M. Bezilla, Vice President Nuclear

K. Krueger, Plant General Manager

T. Jardine, Operations Manager

P. McNulty, Radiation Protection Manager

J. Oelbracht, Chemistry Supervisor

J. Tufts, Chemistry Manager

LIST OF ITEMS

OPENED, CLOSED, DISCUSSED

Opened and Closed

05000440/2010002-01 NCV Failure to Correctly Assess Risk During Post-Maintenance Activities (Section 1R13)

05000440/2010002-02 FIN Failure to Make an Accurate Immediate Operability Determination (Section 1R15)

Closed

05000440/2010-001-01 LER Invalid Isolation Signal Results in Shutdown Cooling Interruption (4OA3)

05000440/2009005-03 URI Potential Missed Reporting Requirement for Loss of Residual Heat Removal During Shutdown (Section 4OA5.1)

2515/173 TI Review of the Implementation of the Industry Ground Water Protection Voluntary Initiative (Section 4OA5.2)

Discussed

05000440/2009003-09 NCV Loss of Shutdown Cooling Water Flow to Reactor Vessel (Section 4OA5.1)

05000440/2010-001-01 LER Invalid Isolation Signal Results in Shutdown Cooling Interruption (4OA5.1)

Attachment