IR 05000331/2009002

IR 05000331-09-002, on 01/01/2009 - 03/31/2009, Duane Arnold Energy Center, Operability Evaluations and Follow-up of Events

ML091320075
Person / Time
Site:	Duane Arnold
Issue date:	05/12/2009
From:	Kenneth Riemer NRC/RGN-III/DRP/B2
To:	Richard Anderson Duane Arnold
References
FOIA/PA-2010-0209 IR-09-002
Download: ML091320075 (64)

Text

May 12, 2009

SUBJECT:

DUANE ARNOLD ENERGY CENTER NRC INTEGRATED INSPECTION REPORT 05000331/2009002

Dear Mr. Anderson:

On March 31, 2009, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Duane Arnold Energy Center. The enclosed report documents the inspection results, which were discussed on April 2, 2009, with you 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, two NRC-identified and one self-revealed finding of very low safety significance were identified, two of which involved violations of NRC requirements.

However, because of the very low safety significance, and because the issues were entered into your corrective action program, the NRC is treating these issues as non-cited violations (NCVs)

in accordance with Section VI.A.1 of the NRC Enforcement Policy. Additionally, a licensee identified violation is listed in Section 4OA7 of this report.

If you contest the subject or severity of these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the 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 Duane Arnold Energy Center. 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 Duane Arnold Energy Center. The information you provide will be considered in accordance with Inspection Manual Chapter 0305. 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). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Kenneth Riemer, Chief Branch 2 Division of Reactor Projects Docket No. 50-331 License No. DPR-49

Enclosure:

Inspection Report 05000331/2009002 w/Attachment: Supplemental Information cc w/encl:

M. Nazar, Senior Vice President and

Chief Nuclear Officer

M. Ross, Managing Attorney

A. Khanpour, Vice President, Nuclear Engineering

D. Curtland, Plant Manager

S. Catron, Manager, Regulatory Affairs

M. Mashhadi, Senior Attorney

T. Jones, Vice President, Nuclear Operations,

Midwest Region

P. Wells, Vice President, Nuclear Safety Assessment

R. Hughes, Director, Licensing and Performance Improvement

D. McGhee, Iowa Dept. of Public Health

Chairman, Linn County, Board of Supervisors

R. McCabe, Chairman, Regional Assistance Committee,

DHS/FEMA Region VII

M. Rasmusson, State Liaison Officer

SUMMARY OF FINDINGS

IR 05000331/2009002; 01/01/2009 - 03/31/2009; Duane Arnold Energy Center; Operability

Evaluations and Follow-up of Events.

This report covers a three-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. Two Green findings were identified by the inspectors and one Green finding was self-revealed. The inspector-identified findings were considered Non-Cited Violations (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: Initiating Events

Green.

A finding of very low safety significance was self-revealed when the operators exceeded the operational limit of the cooling tower riser by failing to secure one of the two running circulating water pumps prior to securing flow to the A cooling tower. The inspectors determined that the operators exceeding the operational limit of the B cooling tower west riser was contrary to the guidance for safe operation of plant equipment contained in Administrative Control Procedure (ACP) 110.1, Conduct of Operations, and therefore was a performance deficiency. No violation of regulatory requirements occurred. The licensee entered this issue into their corrective action program (CAP) as CAP 063426. The B cooling tower riser was repaired, structural support was added to all four cooling tower risers, and operating procedures were revised to preclude operators from operating two circulating water pumps with only one cooling tower in operation.

The finding was determined to be more than minor because the finding was associated with the Reactor Safety Cornerstone attribute of procedure quality and affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown. Specifically, operating the plant in an inappropriate configuration resulted in the loss of the normal plant heat sink, which required the operators to manually scram the reactor and rely on safety-related equipment to cool the plant down. The inspectors determined the finding was of very low safety significance (Green) because the finding only resulted in a reactor scram and did not contribute to the likelihood that mitigation equipment or functions would not be available. This finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Corrective Action, because the licensee did not take appropriate corrective actions to address safety issues and adverse trends in a timely manner.

Specifically, maintenance and operations personnel failed to adequately address a known deficiency with a plugged pressure transmitter, which resulted in the control room allowing throttling of the A cooling tower riser valves until they were fully shut, thus exceeding the operational limit of the cooling tower P.1(d). (Section 4OA3.1)

Cornerstone: Mitigating Systems

Green.

A finding of very low safety significance and associated NCV of Technical Specifications (TSs) was identified by the inspectors for the operators failing to perform required actions for existing limiting condition for operation (LCO) conditions, involving TS equipment declared inoperable, during in-vessel fuel movements. The inspectors determined that the failure to perform TS LCO required actions during in-vessel fuel movement was contrary to Refueling Operations TS required actions and therefore was a performance deficiency. The licensee entered this issue into their corrective action program as CAP 064489. The core alterations were suspended to comply with the TSs until the issue was resolved. Actions were taken to ensure that the control rods with the inoperable rod position indicators were fully inserted and to electrically disarm the control rod drives. Once the required actions were completed, the fuel shuffle was recommenced.

The performance deficiency was determined to be more than minor because the finding was associated with the Mitigating Systems Cornerstone attribute of human performance and adversely affected 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). Specifically, when changes to in-plant conditions affect previously performed required actions for equipment declared inoperable, the failure to perform the TS LCO required actions for the new plant conditions could lead to a more significant safety concern by unknowingly exceeding allowed outage times established for specific LCOs. This human error could, in turn, challenge mitigating systems availability, reliability, and capability to respond to initiating events. The inspectors determined that this finding only degraded the reactivity control function of the Mitigating Systems Cornerstone and only affected the safety of a reactor during refueling operations after the entry conditions had been met and shutdown cooling had been initiated. Using IMC 0609, Appendix G, Shutdown Operations SDP, and Checklist 7,

BWR Refueling Operation with RCS Level > 23, contained in Attachment 1, the inspectors determined that the finding did not require a quantitative assessment. Using Figure 1, this finding screened as very low safety significance (Green). The inspectors also determined that this finding has a cross-cutting aspect in the area of Human Performance, Decision Making, because the licensee did not adopt a requirement to demonstrate that the proposed action was safe in order to proceed rather than a requirement to demonstrate that it is unsafe in order to disapprove the action.

Specifically, the requirements of RFP-403 and IPOI-8 to verify readiness to commence in-vessel fuel movements did not adequately provide for a review of inoperable TS equipment completed LCO actions to ensure core alteration TSs for reactivity control were met during the fuel movements H.1(b). (Section 1R15.1.b)

Cornerstone: Barrier Integrity

Green.

A finding of very low safety significance and associated NCV of 10 CFR Part 50,

Appendix B, Criterion III, Design Control, was identified by the inspectors for the failure to verify the adequacy of the methodology and design inputs used to support licensee decisions to accept non-conforming systems, structures, and components for continued operation. The licensee entered this issue into its CAP and was able to demonstrate the Primary Containment system and piping subsystems attached to Drywell penetrations to be operable during design basis accident conditions.

The finding was determined to be more than minor because the omission of a design basis load in engineering evaluations used to justify continued operation resulted in a condition where there was reasonable doubt regarding the operability of the Primary Containment system and piping subsystems attached to Drywell penetrations during accident conditions. The inspectors determined the finding was of very low safety significance because it was a design deficiency that did not result in actual loss of safety function. This finding did not have a cross-cutting aspect. (Section 1R15.2.b)

Licensee-Identified Violations

A violation of very low safety significance that was identified by the licensee was reviewed by inspectors. Corrective actions planned or taken by the licensee have been entered into the licensees CAP. This violation and corrective action tracking numbers are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Duane Arnold Energy Center (DAEC) operated at full power for the entire assessment period except for brief down-power maneuvers to accomplish rod pattern adjustments and to conduct planned surveillance testing activities with the following exceptions:

• On January 18, 2009, fuel cycle coastdown began leading to a planned refueling outage, which began on February 1 following a reactor scram from approximately 45 percent power that occurred during plant shutdown. The refueling outage continued through March 3, with the generator connected to the grid on March 6.

Power ascension was completed on March 9, when the plant returned to full power.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

• A Standby Diesel Generator (SBDG) with the B SBDG Out-of-Service (OOS)for Planned Maintenance to Install Permanent Modifications;

• A Core Spray (CS) System with the B CS System OOS for Planned Preventive Maintenance; and

• A Standby Filter Unit with the B Standby Filter Unit OOS for Planned Corrective Maintenance.

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 system, and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, Updated Final Safety Analysis Report (UFSAR), TS requirements, outstanding work orders, condition reports, 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 CAP with the appropriate significance characterization.

Documents reviewed are listed in the Attachment to this report.

These inspection activities constituted three partial system walkdown samples as defined in Inspection Procedure (IP) 71111.04-05.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

.1 Routine Resident Inspector Tours

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:

• Area Fire Plan (AFP) 20, Turbine Building Aux Boiler Room, Emergency Diesel Generator Rooms, and Generator Day Tank Rooms, Elevation 757 6;

• AFP 17, Turbine Building Condenser Bay, Heater Bay, and Steam Tunnel, Elevations 734 0 and 757 6;

• AFP 25, Control Building Cable Spreading Room, Elevation 772 6;

• AFP 18 & 19, North Turbine Building Ground Floor, Tube Pulling Area, 1A1 Switchgear Room, and South Turbine Building Ground Floor, Elevation 757 6; and

• AFP 8; Reactor Building Standby Gas Treatment System and MG Set Rooms, Elevation 786 0.

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 had 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 that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed, that 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 inspection activities constituted five quarterly fire protection inspection samples as defined in IP 71111.05-05.

b. Findings

No findings of significance were identified.

1R07 Annual Heat Sink Performance

a. Inspection Scope

The inspectors reviewed the licensees testing of the A Residual Heat Removal (RHR)

Heat Exchanger following planned maintenance for cleaning during the refueling outage.

The inspectors verified that the as-left conditions did not mask the licensees ability to detect degraded performance, or to identify any common cause issues that had the potential to increase risk, and that the licensee was adequately addressing problems that could result in initiating events that would cause an increase in risk. The inspectors reviewed the licensees observations as compared against acceptance criteria, the correlation of scheduled testing and the frequency of testing, and the impact of instrument inaccuracies on test results. Inspectors also verified that test acceptance criteria considered differences between test conditions, design conditions, and testing conditions.

This annual heat sink performance inspection constituted one sample as defined in IP 71111.07-05.

b. Findings

No findings of significance were identified.

1R08 Inservice Inspection Activities

From February 8, 2009, through February 11, 2009, the inspectors conducted a review of the implementation of the licensees Inservice Inspection (ISI) Program for monitoring degradation of the reactor coolant system, risk-significant piping and components and containment systems.

The inspections described in Sections 1R08.1 and 1R08.2 below constituted one inspection sample as defined in IP 71111.08-05.

.1 Piping Systems ISI

a. Inspection Scope

The inspectors observed the following nondestructive examinations mandated by the American Society of Mechanical Engineers (ASME)Section XI Code to evaluate compliance with the ASME Code Section XI and Section V requirements and if any indications were detected, to determine if these were dispositioned in accordance with the ASME Code or an NRC approved alternative requirement.

• Magnetic Particle and Visual Examination (VT-3) of Main Steam Line Pipe Support MSA-HA-1; and

• Visual Examination (VT-3) of Reactor Vessel Stabilizers VSW-0AZ and VSW-180AZ.

The inspectors observed the following nondestructive examination conducted as part of the licensees augmented inspection program for detection of stress corrosion cracking.

The inspectors observed this examination to determine if it was conducted in accordance with the licensees augmented inspection program basis document - Boiling Water Reactor Vessel Internals Program No. 75a BWR [Boiling Water Reactor] Vessel and Internals Project Technical Basis for Revisions to Generic Letter 88-01 Inspection Schedules and the associated nondestructive examination procedure. If any indications or flaws were detected during the examination, the inspectors confirmed that the indications were dispositioned in accordance with approved procedures and NRC requirements.

• Ultrasonic Examination of Reactor Recirculation Weld RRB-F002A.

The inspectors reviewed the following examinations completed during the previous outage with relevant/recordable conditions/indications accepted for continued service to determine if acceptance was in accordance with the ASME Code Section XI or an NRC approved alternative.

• Liquid Penetrant Examination Report PT-07-09, Pipe-to-Pipe Weld CSB-F004; and

• Ultrasonic Examination Report UT-07-033, Safe-End-to-Nozzle Weld FWA-J002.

The inspectors reviewed records of the following pressure boundary welds completed for risk-significant systems during the outage to determine if the licensee applied the pre-service, nondestructive examinations and acceptance criteria required by the Construction Code. Additionally, the inspectors reviewed the welding procedure specification and supporting weld procedure qualification records to determine if the weld procedure was qualified in accordance with the requirements of Construction Code and the ASME Code Section IX.

• Welds W2, W3, W5 for replacement of Main Steam Drain Line Inboard Isolation Valve MO 4423; and

• Welds W1, W2, W3 for replacement of Main Steam Drain Line Outboard Isolation Valve MO 4424.

b. Findings

No findings of significance were identified.

.2 Identification and Resolution of Problems

a. Inspection Scope

The inspectors performed a review of ISI related problems entered into the licensees CAP and conducted interviews with licensee staff to determine if;

• the licensee had established an appropriate threshold for identifying ISI related problems;

• the licensee had performed a root cause (if applicable) and taken appropriate corrective actions; and

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

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

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review

a. Inspection Scope

On January 27, 2009, the inspectors observed a crew of licensed operators in the plants simulator during just-in-time training activities in preparation for shutdown of the reactor plant for a refueling outage. The inspectors observed the training activities 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

• 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. Documents reviewed are listed in the Attachment to this report.

This inspection activity 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

.1 Routine Quarterly Evaluations

a. Inspection Scope

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

• Condenser Heat Removal System; and

• Onsite 4160 volt AC Power System.

The inspectors reviewed events such as where ineffective equipment maintenance had resulted in unplanned plant transients 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 (SSCs)/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 inspection activities 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:

• RHR/Low Pressure Core Injection (LPCI) Planned Maintenance Work Activities during Work Week 9903;

• Review of Operational Decision Making Instructions (ODMI) for Recirculation Pump Issues;

• Electrical Bus 1B42 Outage Concurrent with Refuel Outage Fuel Shuffle during Work Week 9906;

• Main Turbine Bearing Number 9 Wiped during Startup Forces Plant Shutdown; and

• RHR Logic Functional Test Rescheduled during Work Week 9912.

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 activities constituted five samples as defined in IP 71111.13-05.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• A Emergency Service Water (ESW), A RHR Service Water (RHRSW) Loop, and A SBDG operability following a failure of the A ESW/RHRSW pump room ventilation supply fan, 1VSF056A;

• Required actions not performed for planned Control Rod Position Indication LCO conditions, prior to commencing in-vessel fuel movements, following replacements of the control rod position indication probes;

• B ESW system operability following discovery that sections of system piping were insulated, but by design should not be insulated; and

• A Standby Liquid Control (SBLC) Pump operability following discovery of a pump casing leak during performance of the pump operability surveillance test procedure (STP).

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 UFSAR 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 also 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 inspection activities constituted four samples as defined in IP 71111.15-05.

b. Findings

Introduction:

A finding of very low safety significance and associated NCV of TSs was identified by the inspectors for the operators failing to perform TS LCO required actions for existing LCO conditions involving TS equipment declared inoperable during in-vessel fuel movements.

Description:

On February 8, 2009, the first fuel shuffle of RFO 21, which involved the in-vessel fuel movements to support control rod drive (CRD) replacements and control rod blade shuffles, was completed. The next day the rod position indications for control rods 14-23 and 22-19 were declared inoperable to support replacement of the position indication probes. The associated TS 3.9.4 LCOs were entered for Condition A and the required actions were met by the control rods being verified fully inserted and electrically disarmed per the clearances and work orders to replace the probes. Additionally, on February 12, due to intermittent Full-In indication, which occurred during under-vessel work in the drywell, control rod 10-11 position indication was declared inoperable and TS 3.9.4 LCO Condition A was entered. The required actions were met by verifying that in-vessel fuel movement and control rod withdrawal were not being performed and all required control rods were fully inserted.

Following replacement of the position indication probes for control rods 14-23 and 22-19, the clearances were removed (controls rods no longer electrically disarmed), but since the required post-maintenance testing to verify that all positions and the Full-In and Full-Out lights operated properly was not scheduled to be performed until subsequent scram time testing was conducted, the rod position indication was not declared operable.

The required TS LCO actions were still met because in-vessel fuel movement and control rod withdrawal were not being performed and all required control rods were fully inserted. No further actions were documented. This TS inoperable equipment and the associated TS LCOs continued to be carried forward, tracked in the LCO Notebook, and discussed as shift turnover information.

On February 15, the requirements of Refueling Procedure 403 and IPOI-8 were verified complete and the second fuel shuffle was commenced. Subsequently, during a control room observation on February 17, the inspectors, noting that the TS LCOs for rod position indication of the three control rods was still in effect, asked how the required actions were being met during in-vessel fuel movements. The core alterations were suspended to comply with the TSs until the issue was resolved. The licensee initiated actions to verify the control rods with the inoperable rod position indicators were fully inserted and to electrically disarm the CRDs. Once the required actions were completed, the fuel shuffle was recommenced.

Analysis:

The inspectors determined that the failure to perform the required TS LCO actions during in-vessel fuel movements, for TS equipment declared inoperable, was contrary to the TS section for Refueling Operations, was reasonably within the licensees ability to foresee, correct, and prevent, and was therefore a performance deficiency.

This performance deficiency did not meet any of the conditions requiring traditional enforcement, was not similar to any of the minor examples of IMC 0612 Appendix E, and was therefore compared to the questions in IMC 0612 Appendix B, Issue Screening.

The inspectors determined the performance deficiency to be more than minor because the finding was associated with the Mitigating Systems Cornerstone attribute of human performance and adversely affected 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). Specifically, when changes to in-plant conditions affect previously performed required actions for equipment declared inoperable, the failure to perform the TS LCO required actions for the new plant conditions could lead to a more significant safety concern by unknowingly exceeding allowed outage times established for specific LCOs. This human error could, in turn, challenge mitigating systems availability, reliability, and capability to respond to initiating events.

Using Attachment 4 of IMC 0609, Significance Determination Process, the inspectors determined that the finding only degraded the reactivity control function of the Mitigating Systems Cornerstone and only affected the safety of a reactor during refueling operations after the entry conditions had been met and shutdown cooling had been initiated. Hence, the finding could be evaluated in accordance with IMC 0609, Appendix G, Shutdown Operations SDP. The inspectors used Checklist 7, BWR Refueling Operation with RCS Level > 23, contained in Attachment 1 and determined that the guidelines for reactivity control, which specifically assumes existing core alteration TSs are being met, was adversely affected. However, the finding did not require a phase 2 or phase 3 analysis because the plant had appropriately met the safety function guidelines for core heat removal and inventory control and the finding did not involve a loss of control associated with inadvertent RCS pressurization or inadvertent loss of 2 of RCS inventory. Using Figure 1, this finding does not require a quantitative assessment and therefore screened as very low safety significance (Green).

The inspectors determined that this finding has a cross-cutting aspect in the area of human performance for decision making because the licensee did not adopt a requirement to demonstrate that the proposed action was safe in order to proceed rather than a requirement to demonstrate that it is unsafe in order to disapprove the action.

Specifically, the requirements of RFP-403 and IPOI-8 to verify readiness to commence in-vessel fuel movements did not adequately provide for a review of inoperable TS equipment completed LCO actions to ensure core alteration TSs for reactivity control were met during the fuel movements. H.1(b)

Enforcement:

Technical Specification Section 3.9, Refueling Operations, LCO 3.9.4, Control Rod Position Indication, requires that during Mode 5, The control rod full-in position indication for each control rod shall be Operable. Condition A states that for One or more required control rod position indications inoperable, the licensee will Immediately, (A.1.1) Suspend in-vessel fuel movement; AND (A.1.2) Suspend control rod withdrawal. AND (A.1.3) Initiate action to fully insert all insertable control rods in core cells containing one or more fuel assemblies; OR (A.2.1) Initiate action to fully insert the control rod associated with the inoperable position indicator; AND (A.2.2) Initiate action to disarm the control rod drive associated with the fully inserted control rod.

Contrary to the above, between February 15, and February 17, core alterations were conducted without performing the TS 3.9.4 LCO Condition A required actions for three control rod position indications declared inoperable. Specifically, while in-vessel fuel movements were suspended during CRD exchanges and Control Rod Blade shuffles, the required actions for LCOs entered for control rods 10-11, 14-23, and 22-19 were complete. However, once in-vessel fuel movements were recommenced, without completing actions A.2.1 & A.2.2, the allowed outage times for the LCO actions were exceeded. Because this violation was of very low safety significance and it was entered into the licensees corrective action program as CAP 064489, this violation may be dispositioned as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy.

(NCV 05000331/2009002-03)

.2 (Closed) Unresolved Item (URI) 05000331/2005002-02:

Failure to Include the Analysis of Thermal Movements in Piping Modifications

a. Inspection Scope

The inspectors reviewed licensee corrective actions pertaining to URI 05000331/2005002-02. Specifically, the inspectors reviewed licensee documentation that included licensee corrective actions following identification that Drywell thermal movement had not been incorporated into the design basis analysis for the Containment Vent Purge Exhaust piping subsystem 18-HLE-023. The licensee documentation reviewed included extent of condition, operability determinations, and plant modifications to restore piping subsystems to compliance with the design basis requirements.

Specific documents reviewed during the inspection are listed in the Attachment to this report.

This inspection did not constitute an inspection sample.

b. Findings

Failure to Consider Design Basis Load in Evaluation for Continued Operation

Introduction:

A finding of very low safety significance and associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was identified by the inspectors for the failure to verify the adequacy of the methodology and design inputs used to support licensee decisions to accept non-conforming piping subsystems and Drywell penetrations for continued operation.

Description:

On March 18, 2005, the licensee identified that calculation CAL-080-312 for piping subsystem 18-HLE-023, Containment Vent Purge Exhaust, did not account for the thermal movement of the Drywell in the analytical stress model. Drywell thermal anchor movements (TAMs) were determined in calculation CAL-003C-F-010, Penetration Movement Thermal, generated in 1971. The licensee further identified that calculation CAL-082-312 for piping subsystem 3/4-HLE-023 test line installed under DCR1167 did not account for thermal movement of the Drywell, this test line was attached to the 18-HLE-023 subsystem, and that installation of this test line included a rigid vertical guide and an anchor piping supports. The licensee initiated CAP 035317 to enter the concern into their CAP. Immediate actions taken by the licensee included a walkdown of the identified piping installations, an operability determination to address functional capability of the identified piping subsystems, and a determination of the likely cause for not evaluating the effect of Drywell thermal movement in the identified piping calculations.

The licensee performed an immediate assessment of the functional capability of the piping subsystem using guidance from NRC Inspection Manual Part 9900, Operable/Operability: Ensuring the Functional Capability of a System or Component, that accepted criteria in Appendix F of Section III of the ASME Boiler and Pressure Vessel Code. Noting Paragraph F-1310(c), Only limits on primary stresses are prescribed. Thermal stresses resulting from Level D Service limits need not be considered, the licensee concluded, in-part, that the non-conformance of not accounting for thermal movement of the Drywell is not an operability concern per Appendix F of Section III of the ASME Code.

The licensee further identified that additional plant modifications installed rigid piping supports to other piping subsystems that were attached to the Drywell. As a part of CAP 035317, the licensee entered an action to perform a condition evaluation, CE 002404 dated March 22, 2005, to determine the extent of piping calculations that did not evaluate the effect of Drywell thermal movement. Based on the results of CE 002404, the licensee initiated an additional corrective action, CA 040021 dated March 30, 2005, to review the remaining Drywell penetrations. Pending the licensees reviews for extent of condition and overall effect on existing designs, the inspectors considered the issue as unresolved (refer to NRC Integrated Inspection Report 05000331/2005002, dated April 29, 2005, ADAMS Accession Number ML051240313).

Based on a subset of Drywell penetrations reviewed as part of CE 002404, on March 30, 2005, the licensee initiated CA 040021 to review the remaining Drywell penetrations for the thermal anchor movement concern.

Following the completion of their extent of condition review, the licensee documented actions to correct the condition in CA 040134, initiated on April 22, 2005: install modifications for 15 Drywell penetrations in the 2005 refueling outage and complete analysis for 16 Drywell penetrations that required follow-up actions. The licensee also documented that 22 Drywell penetrations required no follow-up actions.

The inspectors reviewed the licensees operability determination documented in CAP 035317, and noted that secondary stresses (the basic characteristic of a secondary stress is that it is self-relieving) due to Drywell movement were only applicable to the attached piping; stresses induced in the piping supports due to Drywell movement were primary stresses (the basic characteristic of a primary stress is that it is not self-relieving). Therefore, the inspectors concluded that the correct ASME Code classification for stresses induced into piping supporting structures due to Drywell thermal expansion was primary stress, and the licensees operability determination performed under CAP 035317 was non-conservative because the impact due to Drywell TAM was not considered. In addition, since the licensee had not demonstrated that the affected piping system supporting structures were in compliance with the requirements of Appendix F of ASME Section III, the inspectors concluded that the licensee had not demonstrated the operability of SSCs affected by Drywell thermal movement during design basis accident conditions.

In DAEC letter NG-05-2178, G. Van Middlesworth (Site Vice-President, DAEC) to the NRC, Subject: Additional Information Regarding Unresolved Item 05000331/2005002-02, dated December 12, 2005, the Nuclear Management Company (NMC, the former licensee) provided NRC staff with additional information regarding the DAECs determination of past operability of Drywell penetrations due to TAM. In the enclosure to DAEC letter NG-05-2178, the licensee described the decision process and steps taken for the operability determination performed under CAP 035317:

• Operability was assessed using NRC Inspection Manual Part 9900 guidance regarding operability for non-conforming conditions in piping systems. Part 9900 guidance states licensee may use the criteria in Appendix F of the ASME Code for operability decisions.

• For the evaluation of operability, the licensee used Appendix F of Section III of the ASME Code (1977 Edition/1978 Summer Addenda). This edition/addenda was the current code of record for DAEC Primary Containment.

• Paragraph F-1310(c) stated that Only limits on primary stresses are prescribed.

Thermal stresses resulting from Level D Service Limits need not be considered.

Paragraph F-1370 (Component Supports) does not require consideration of thermally-induced stresses.

• The evaluation documented in CAP 035317 concluded the non-conformance (not accounting for thermal movement of the Drywell on the vent line) was not an operability concern using Part 9900 guidelines and the DAEC code of record.

• The licensee noted that later versions of Appendix F of the ASME Code (e.g., 1989) would require consideration as primary stresses, those from the constraint of free end displacement and anchor point motion, in the evaluation of component supports.

• NMC obtained an opinion from an external peer, recognized as knowledgeable in the ASME Code, regarding which ASME Code Edition/Addenda to use when evaluating operability using Part 9900 guidelines. The external peer concluded that the use of Appendix F from the 1977 code with summer 1978 addenda (DAECs code of record) was acceptable for the use in the NMCs operability determination.

• NMC concluded that the operability determination performed under CAP 035317 was valid.

On December 14, 2005, the licensee initiated CAP 039338 that identified existing support configurations on HLE-21 and HLE-38 that are connected to drywell penetration X-22 required modification to accommodate thermal movement of the Drywell.

Furthermore, the licensee determined these piping subsystems to be operable based on the evaluation performed and documented in CAP 035317, i.e., thermal stresses resulting from Level D Service Limits need not be considered in accordance with Paragraph F-1310(c) of Appendix F of Section III of the ASME Code.

In January 2006, the inspectors reviewed the enclosure to DAEC letter NG-05-2178 that described the licensees decision process and steps taken for the operability determination performed under CAP 035317. The inspectors further reviewed technical guidance provided in NRC Inspection Manual Part 9900 dated September 26, 2005, with respect to the information the licensee provided in DAEC letter NG-05-2178. The inspectors noted:

• Part 9900, paragraph 3.4, defined an SSC as not fully qualified, i.e., degraded or non-conforming, when it did not conform to all aspects of its current licensing basis, including all applicable codes and standards, design criteria, safety analyses, assumptions and specifications, and licensing commitments.

• The DAEC UFSAR, Section 3.8, Design Criteria of Seismic Category I Structures, Revision 12 dated October 1995, indicated the design code applicable to Primary Containment (including penetrations) as ASME,Section III, Class B [now ASME Section III Subsection NE (Class MC Components)].

• The DAEC UFSAR defined a design basis load, force on structure from the thermal expansion of pipes under accident conditions, (HA), applicable to Primary Containment.

• The inspectors did not identify in Article 3000, Design, of Subsection NE of Section III of the ASME Code (1977 Edition/Summer 1978 Addenda) a paragraph that indicated attached piping constrained free-end displacement and differential support motion effects need not be considered as in paragraph NF-3231.1.

Since the force on Primary Containment (including penetrations) due to thermal expansion of pipes under accident conditions was a design basis load at the DAEC, the inspectors concluded that the effect Drywell thermal expansion needed to be included in the licensees determination of SSC operability as directed in NRC Inspection Manual Part 9900 inspector guidance. Therefore, the inspectors concluded that the licensees operability determination documented in CAP 035317 did not satisfy inspector technical guidance in NRC Inspection Manual Part 9900.

In February 2006, the licensee initiated prompt operability determinations that evaluated the effects of TAM and pressure anchor movement (PAM) for the 16 Drywell penetrations requiring follow-up actions after the spring 2005 refueling outage (CA040134). The licensee determined the affected piping subsystems and Drywell penetrations to be operable but non-conforming.

In DAEC letter NG-06-0305 to the NRC, Subject: Withdrawal of NG-05-2178, dated April 3, 2006, the current licensee, FPL Energy Duane Arnold, LLC,, withdrew its position regarding the use of ASME Section III, Appendix F for the determination of past operability of the DAEC Primary Containment. This letter also indicated that FPL Duane Arnold, LLC would perform new past operability evaluations for those penetrations modified during the spring 2005 outage. In DAEC letter NG-06-0375 to the NRC, Subject: Voluntary Licensee Event Report No. 2006-002-00, dated June 1, 2006, the licensee submitted Voluntary Licensee Event Report (LER) No. 2006-002-00, Drywell Penetrations Calculations Do Not Account for Thermal Movement that committed to complete actions to determine if any past operability concerns existed for the 15 Drywell penetrations that were modified in the 2005 refueling outage. In addition to evaluating TAM, LER No. 2006-002-00 identified that the past operability determinations would also evaluate the effect of Drywell PAM, also not evaluated in the operability determination for the Containment Vent Purge Exhaust line documented in CAP 033317.

The inspectors reviewed the licensees corrective actions and new past operability evaluations for the 15 Drywell penetrations modified in the 2005 refueling outage. The inspectors reviewed the evaluations to ensure the new operability determinations considered the effect of both Drywell TAM and PAM at accident conditions. The inspectors identified that one operability determination, calculation IE-P108274-610, Operability Evaluation of Containment Atmosphere Control Piping @ Penetration X-25, Revision 1, inadvertently evaluated piping load combinations that did not include the effect of Drywell movement. The licensee entered this condition into the corrective action program, CAP 057980, initiated corrective action CA 050263, and revised calculation IE-P108274-610 to correct the error. The inspectors reviewed Revision 2 of calculation IE-P108274-610 to ensure the effect of both TAM and PAM was evaluated.

In summary, the licensee completed evaluations related to the operability of piping subsystems and Drywell penetrations affected by Drywell movement during design basis accident conditions. The licensees extent of condition evaluated all Drywell penetrations. No operability concern related to Drywell movement during design basis accident conditions was identified.

Analysis:

The inspectors determined that licensees failure to consider a design basis load in evaluations of a non-conforming condition to justify continued operation was a performance deficiency. The issue was determined to be more than minor because this performance deficiency also impacted the Barrier Integrity Cornerstone objective to provide reasonable assurance that physical design barriers (containment) protect the public from radionuclide releases caused by accidents or events. Specifically, the omission of the design basis load resulted in a condition where there was reasonable doubt regarding the operability of the Primary Containment and piping subsystems attached to Drywell penetrations during accident conditions.

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 Barrier Integrity Cornerstone. Specifically, since all four questions under the Containment Barrier column were answered no, the finding was determined to be Green, of very low safety significance, because it did not represent an actual open pathway in the physical integrity of reactor containment.

This finding did not have a cross-cutting aspect because the cause of the performance deficiency is not reflective of current licensee performance.

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires, in part, that measures shall be established to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions, and that design control measures provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculation methods, or by the performance of a suitable testing program.

Contrary to the above, on March 18, 2005, and December 14, 2005, the licensees design control measures failed to verify the adequacy of the design of the non-conforming piping systems attached to the Drywell, in that, the methodology and design inputs used did not include a design basis load, Drywell movement during design basis accident conditions, in engineering evaluations used to justify continued operation.

Consequently, the licensee incorrectly concluded that the Primary Containment (Drywell)system and piping subsystems attached to Drywell penetrations satisfied ASME Code requirements for Service Level D loadings. As a result, non-conforming piping subsystems attached to 31 Drywell penetrations were left in-service from March 18, 2005, to the spring 2005 refueling outage, and non-conforming piping subsystems attached to 16 Drywell penetrations were left in-service from the spring 2005 refueling outage to February 2006, without an adequate basis to justify continued operation.

Because this violation was of very low safety significance and it was entered into the licensees corrective action program, CAP042817 to CAP035317, this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy (NCV 05000331/2009002-04).

Based on the above discussion, URI 05000331/2005002-02 is closed.

1R18 Plant Modifications

.1 Temporary Plant Modifications

a. Inspection Scope

The inspectors reviewed the following temporary modification:

• Engineering Change Package (ECP) 1833, 354 Degree Feedwater Sparger Repair.

The inspectors compared the temporary configuration changes and associated 10 CFR 50.59 screening and evaluation information against the design basis, the UFSAR, and the TS, as applicable, to verify that the modification did not affect the operability or availability of the affected systems. The inspectors also compared the licensees information to operating experience information to ensure that lessons learned from other utilities had been incorporated into the licensees decision to implement the temporary modification. The inspectors, as applicable, performed field verifications to ensure that the modifications operated as expected; modification testing adequately demonstrated continued system operability, availability, and reliability; and that operation of the modifications did not impact the operability of any interfacing systems. Lastly, the inspectors discussed the temporary modification with operations, engineering, and training personnel to ensure that the individuals were aware of how extended operation with the temporary modification in place could impact overall plant performance.

This inspection activity constituted one temporary modification sample as defined in IP 71111.18-05.

b. Findings

No findings of significance were identified.

.2 Permanent Plant Modifications

a. Inspection Scope

The following engineering design packages were reviewed and selected aspects were discussed with engineering personnel:

• ECP-1865, Refuel Bridge Modification to Connect Air Supply to Instrument Air System.

This modification added a hose reel to connect air for the refueling platform to instrument air, and a connection to the refueling bridge which would allow for a temporary hose to be connected if both the air compressor (1K202) and the hose reel were to fail.

• ECP-1835, B SBDG Voltage Regulator Modification, and ECP-1748, B SBDG Governor Replacement.

This modification replaced the B SBDG governor and the B SBDG voltage regulators to resolve operable but degraded condition OBD 258, Calculation CAL-E02-003 Shows SBDG Voltage Dips less than UFSAR/RG 1.9 Requirements.

These documents and related documentation were reviewed for adequacy of the associated 10 CFR 50.59 safety evaluation screening, consideration of design parameters, implementation of the modification, post-modification testing, and relevant procedures, design, and licensing documents were properly updated. The inspectors observed ongoing and completed work activities to verify that the installations were consistent with the design control documents.

These inspection activities constituted two permanent plant modification samples as defined in IP 71111.18-05.

b. Findings

No findings of significance were identified.

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:

• Refuel Bridge Testing Following Replacement of a Failed Control Joystick;

• B SBDG Governor/Voltage Regulator Tuning and Testing Following Modification Installations;

• A Inboard Main Steam Isolation Valve (MSIV) Leak Rate Testing Following Seat and Disc Repair Maintenance;

• Hydraulic Control Unit (HCU) 34-15 and 10-19 Leakage Testing Following Accumulator Rebuilding and Dragon Valve Replacement;

• Main Turbine Overspeed Testing Following Outage Maintenance; and

• Feedwater Level Control Unit Testing Following Replacement of the FY4450F Compensation Module in the Feedwater Level Control System.

These activities were selected based upon the structure, system, or component's 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 UFSAR, 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 post-maintenance 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 inspection activities constituted six post-maintenance testing samples as defined in IP 71111.19-05.

b. Findings

No findings of significance were identified.

1R20 Outage Activities

.1 Refueling Outage Activities

a. Inspection Scope

The inspectors reviewed the licensees Outage Risk Plan (ORP) and contingency plans for refueling outage (RFO) 21, conducted February 1, through March 3, 2009, to confirm that the licensee had appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense-in-depth. During the RFO, the inspectors observed portions of the shutdown and cooldown processes and monitored licensee controls over the outage activities listed below. Documents reviewed during the inspection are listed in the Attachment to this report.

The inspectors observed all or portions of the following activities:

• Licensee configuration management, including maintenance of defense-in-depth commensurate with the ORP for key safety functions and compliance with the applicable TS when taking equipment out-of-service.

• Implementation of clearance activities and confirmation that tags were properly hung and equipment appropriately configured to safely support the work or testing.

• Installation and configuration of reactor coolant pressure, level, and temperature instruments to provide accurate indication, accounting for instrument error.

• Controls over the status and configuration of electrical systems to ensure that TS and ORP requirements were met, and controls over switchyard activities.

• Monitoring of decay heat removal processes, systems, and components.

• Controls to ensure that outage work was not impacting the ability of the operators to operate the spent fuel pool cooling system.

• Reactor water inventory controls including flow paths, configurations, and alternative means for inventory addition, and controls to prevent inventory loss.

• Controls over activities that could affect reactivity.

• Maintenance of secondary containment as required by TS.

• Refueling activities, including fuel handling and sipping to detect fuel assembly leakage.

• Touring plant areas normally not accessible during power operations for evidence of leakage and integrity of structures, systems, and components, this included a walkdown of the drywell (primary containment) as soon as reasonably possible following shutdown.

• Verify that fuel assemblies were loaded in the reactor core locations specified by the design.

• Startup and ascension to full power operation, tracking of startup prerequisites, walkdown of the drywell to verify that debris had not been left which could block emergency core cooling system suction strainers, and reactor physics testing.

• Licensee identification and resolution of problems related to RFO 21 activities.

These inspection activities constituted one RFO sample as defined in IP 71111.20-05.

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:

• STP 3.5.3-02, RCIC Operability Test (inservice testing);

• STP 3.6.1.3-03, MSIV Trip/Closure Time Check (inservice testing);

• STP 3.8.1-07B, B EDG Loss of Offsite Power (LOOP)/ Loss of Coolant Accident (LOCA) Test (routine);

• STP 3.6.1.1-13, LLRT HPCI/RCIC Valves (containment isolation valve);

• STP 3.8.1-07, A EDG LOOP/LOCA Test (routine); and

• STP 3.3.8.1-05B, 1A4 4KV Emergency Transformer Supply Undervoltage Relay Calibration (routine).

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, demonstrated 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; and the calibration frequencies were in accordance with TSs, the UFSAR, 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 inservice 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 inspection activities constituted three routine surveillance testing samples, two inservice testing samples, and one containment isolation valve sample as defined in IP 71111.22, Sections -02 and -05.

b. Findings

No findings of significance were identified.

RADIATION SAFETY

Cornerstones: Occupational Radiation Safety and Public Radiation Safety 2OS1 Access Control to Radiologically Significant Areas (71121.01)

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

a. Inspection Scope

The inspectors reviewed the licensees Occupational Exposure Control Cornerstone performance indicator (PI) to determine whether the conditions resulting in any PI occurrences had been evaluated and whether identified problems had been entered into the licensees CAP for resolution.

This inspection constitutes one sample as defined in IP 71121.01-05.

b. Findings

No findings of significance were identified.

.2 Plant Walkdowns and Radiation Work Permit Reviews

a. Inspection Scope

The inspectors reviewed licensee controls and surveys in the following radiologically significant work areas within radiation areas, high radiation areas, and airborne radioactivity areas in the plant to determine if radiological controls including surveys, postings, and barricades were acceptable:

• Remove and replace control rod drives;

• Underwater diving work and setup: desludging, inspection and repair of torus coating in a high radiation area;

• In-service examinations on pipes, vessels, snubbers and supports, and flow accelerated corrosion (FAC) exam on pipes in the drywell;

• Refuel outage support work at 360-platform areas; and

• Diving in the torus and reactor cavity.

This inspection constitutes one sample as defined in IP 71121.01-05.

The inspectors reviewed the radiation work permits (RWPs) and work packages used to access these areas and other high radiation work areas. The inspectors assessed the work control instructions and control barriers specified by the licensee. Electronic dosimeter alarm set points for both integrated dose and dose rate were evaluated for conformity with survey indications and plant policy. The inspectors interviewed workers to verify that they were aware of the actions required if their electronic dosimeters noticeably malfunctioned or alarmed.

This inspection constitutes one sample as defined in IP 71121.01-05.

The inspectors walked down and surveyed (using an NRC survey meter) these areas to verify that the prescribed RWP, procedure, and engineering controls were in place; that licensee surveys and postings were complete and accurate; and that air samplers were properly located.

This inspection constitutes one sample as defined in IP 71121.01-05.

The inspectors reviewed RWPs for airborne radioactivity areas to verify barrier integrity and engineering controls performance (e.g., high-efficiency particulate air ventilation system operation) and to determine if there was a potential for individual worker internal exposures in excess of 50 millirem committed effective dose equivalent. During the inspection period there were no airborne radioactivity work areas. Work areas having a history of, or the potential for, airborne transuranics were evaluated to verify that the licensee had considered the potential for transuranic isotopes and had provided appropriate worker protection.

This inspection constitutes one sample as defined in IP 71121.01-05.

The inspectors assessed the adequacy of the licensees internal dose assessment process for internal exposures in excess of 50 millirem committed effective dose equivalent, and there were no internal exposure greater than 50 millirem committed effective dose equivalent.

This inspection constitutes one sample as defined in IP 71121.01-05.

b. Findings

No findings of significance were identified.

.3 Problem Identification and Resolution

a. Inspection Scope

The inspectors reviewed a sample of the licensees self-assessments, audits, LERs, and Special Reports related to the access control program to verify that identified problems were entered into the CAP for resolution.

This inspection constitutes one sample as defined in IP 71121.01-05.

The inspectors reviewed corrective action reports related to access controls and any high radiation area radiological incidents (issues that did not count as PI occurrences identified by the licensee in high radiation areas less than 1R/hr). Staff members were interviewed and corrective action documents were reviewed to verify that follow-up activities were being conducted in an effective and timely manner commensurate with their importance to safety and risk based on the following:

• initial problem identification, characterization, and tracking;

• disposition of operability/reportability issues;

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

• identification of repetitive problems;

• identification of contributing causes;

• identification and implementation of effective corrective actions;

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

• implementation/consideration of risk-significant operational experience feedback.

This inspection constitutes one sample as defined in IP 71121.01-05.

b. Findings

No findings of significance were identified.

.4 Job-In-Progress Reviews

a. Inspection Scope

The inspectors observed the following four jobs that were being performed in radiation areas, airborne radioactivity areas, or high radiation areas for observation of work activities that presented the greatest radiological risk to workers:

• Boilermaker support for N2 nozzle activities in the drywell;

• In-service examinations on pipes, vessels, snubbers and supports, and FAC exam on pipes in the drywell;

• Refuel outage support work at 360-platform areas; and

• Diving in the torus and reactor cavity.

The inspectors reviewed radiological job requirements for these activities, including RWP requirements and work procedure requirements and attended As-Low-As-Is-Reasonably Achievable (ALARA) job briefings.

This inspection constitutes one sample as defined in IP 71121.01-05.

Job performance was observed with respect to the radiological control requirements to assess whether radiological conditions in the work area were adequately communicated to workers through pre-job briefings and postings. The inspectors evaluated the adequacy of radiological controls, including required radiation, contamination, and airborne surveys for system breaches; radiation protection job coverage, including any applicable audio and visual surveillance for remote job coverage; and contamination controls.

This inspection constitutes one sample as defined in IP 71121.01-05.

The inspectors reviewed radiological work in high radiation work areas having significant dose rate gradients to evaluate whether the licensee adequately monitored exposure to personnel and to assess the adequacy of licensee controls. These work areas involved areas where the dose rate gradients were severe; thereby increasing the necessity of providing multiple dosimeters or enhanced job controls.

This inspection constitutes one sample as defined in IP 71121.01-05.

b. Findings

No findings of significance were identified.

.5 High Risk Significant, High Dose Rate, High Radiation Area and Very High Radiation

Area Controls

a. Inspection Scope

The inspectors held discussions with the Radiation Protection Manager concerning high dose rate, high radiation area and very high radiation area controls and procedures, including procedural changes that had occurred since the last inspection, in order to assess whether any procedure modifications substantially reduced the effectiveness and level of worker protection.

This inspection constitutes one sample as defined in IP 71121.01-05.

The inspectors discussed with radiation protection supervisors the controls that were in place for special areas of the plant that had the potential to become very high radiation areas during certain plant operations. The inspectors assessed if plant operations required communication beforehand with the radiation protection group, so as to allow corresponding timely actions to properly post and control the radiation hazards.

This inspection constitutes one sample as defined in IP 71121.01-05.

The inspectors conducted plant walkdowns to assess the posting and locking of entrances to high dose rate high radiation areas and very high radiation areas.

This inspection constitutes one sample as defined in IP 71121.01-05.

b. Findings

No findings of significance were identified

.6 Radiation Worker Performance

a. Inspection Scope

During job performance observations, the inspectors evaluated radiation worker performance with respect to stated radiation safety work requirements. The inspectors evaluated whether workers were aware of any significant radiological conditions in their workplace, of the RWP controls and limits in place, and of the level of radiological hazards present. The inspectors also observed worker performance to determine if workers accounted for these radiological hazards.

This inspection constitutes one sample as defined in IP 71121.01-05.

b. Findings

No findings of significance were identified.

.7 Radiation Protection Technician Proficiency

a. Inspection Scope

During job performance observations, the inspectors evaluated radiation protection technician performance with respect to radiation safety work requirements. The inspectors evaluated whether technicians were aware of the radiological conditions in their workplace, the RWP controls and limits in place, and if their performance was consistent with their training and qualifications with respect to the radiological hazards and work activities.

This inspection constitutes one sample as defined in IP 71121.01-05.

b. Findings

No findings of significance were identified.

2OS2 As-Low-As-Is-Reasonably-Achievable (ALARA) Planning And Controls (71121.02)

.1 Inspection Planning

a. Inspection Scope

The inspectors reviewed plant collective exposure history, current exposure trends, and ongoing and planned activities in order to assess current performance and exposure challenges. The inspectors reviewed the plants current 3-year rolling average for collective exposure in order to help establish resource allocations and to provide a perspective of significance for any resulting inspection finding assessment.

This inspection constituted one required sample as defined in IP 71121.02-05.

The inspectors reviewed the outage work scheduled during the inspection period and associated work activity exposure estimates for the following work activities, which were likely to result in the highest personnel collective exposures:

• Boilermaker support for N2 nozzle activities in the drywell;

• In-service examinations on pipes, vessels, snubbers and supports, and FAC exam on pipes in the drywell;

• Refuel outage support work at 360-platform in the refuel floor areas; and

• Diving in the torus and reactor cavity.

This inspection constituted one required sample as defined in IP 71121.02-05.

b. Findings

No findings of significance were identified.

.2 Job Site Inspections and ALARA Control Inspection Scope

The inspectors observed the following jobs that were being performed in radiation areas, airborne radioactivity areas, or high radiation areas to evaluate work activities that presented the greatest radiological risk to workers:

• Boilermaker support for N2 nozzle activities in the drywell;

• In-service examinations on pipes, vessels, snubbers, and supports, and FAC exam on pipes in the drywell;

• Refuel outage support work at 360-platform areas; and

• Diving in the torus and reactor cavity.

The inspectors reviewed the licensees use of ALARA controls for the work activities.

The licensees use of engineering controls to achieve dose reductions was evaluated to verify that procedures and controls were consistent with the licensees ALARA reviews, that sufficient shielding of radiation sources was provided, and that the dose expended to install/remove the shielding did not exceed the dose reduction benefits afforded by the shielding.

This inspection constituted one required sample as defined in IP 71121.02-05.

.3 Problem Identification and Resolutions

a. Inspection Scope

The inspectors reviewed the licensees CAP to determine if repetitive deficiencies and/or significant individual deficiencies in problem identification and resolution had been addressed.

This inspection constituted one required sample as defined in IP 71121.02-05.

b. Findings

Introduction:

No findings of significance were identified. However, a URI was identified during the inspectors review of a CAP record that described a radiological contamination of a contractor on February 6, 2009. This item will be resolved pending review by the NRC.

Description:

During the inspectors review of a corrective action program record (CAP #0063690) that described a positive facial and internal contamination of a contractor who had performed decontamination of the reactor pressure vessel (RPV)studs and washers on the refuel floor, it was noted that the individual deviated from the instructions provided by radiation protection staff concerning the method that was to be used to decontaminate the above items.

The licensees management instructed the contractor on the importance of refuel floor personnel to adhere to the specific refuel floor procedure and RWP requirements. The refuel floor procedure and the RWP requirements stated that radiation protection staff must be notified and agree upon any deviation from the job scope prior to continuing with the evolution.

The licensees initial review of the incident appeared to indicate that the work instructions had been clearly provided to the worker. Based on the information provided by the licensee and additional information obtained during the inspection, this issue remains under review by the NRC and is categorized as a URI, (URI 05000331/2009002-01).

2PS3 Radiological Environmental Monitoring Program And Radioactive Material Control Program (71122.03)

.1 Inspection Planning

a. Inspection Scope

The inspectors reviewed the 2007 Annual Environmental Monitoring Report, sample results obtained in 2008, and licensee assessment results to verify that the Radiological Environmental Monitoring Program (REMP) was implemented as required by TSs and the offsite dose assessment manual (ODAM). The inspectors reviewed the report for changes to the ODAM with respect to environmental monitoring, commitments in terms of sampling locations, monitoring and measurement frequencies, land use census, interlaboratory comparison program, and analysis of data. The inspectors reviewed the ODAM to identify environmental monitoring stations and reviewed licensee self-assessments, audits, LERs, and inter-laboratory comparison program results. The inspectors reviewed the UFSAR for information regarding the environmental monitoring program and meteorological monitoring instrumentation. The inspectors reviewed the scope of the licensees audit program to verify that it met the requirements of 10 CFR 20.1101(c).

This radiological environmental monitoring program inspection planning constituted one sample as defined in IP 71122.03-05.

b. Findings

No findings of significance were identified.

.2 Onsite Inspection

a. Inspection Scope

The inspectors walked-down 20 percent of the air sampling stations and approximately 10 percent of the thermoluminescence dosimeter (TLD) monitoring stations to determine whether they are located as described in the ODAM and to determine the equipment material condition.

This radiological environmental monitoring program and radioactive material control program onsite equipment location and equipment material condition inspection constituted one sample as defined in IP 71122.03-05.

The inspectors observed the collection and preparation of a variety of environmental samples (e.g., ground and surface water, milk, vegetation, sediment, and soil) and verified that environmental sampling was representative of the release pathways as specified in the ODAM and that sampling techniques were in accordance with procedures.

This environmental sample collection and preparation inspection constituted one sample as defined in IP 71122.03-05.

The inspectors verified that the meteorological instruments were operable, calibrated, and maintained in accordance with guidance contained in the UFSAR, NRC Safety Guide 23, and licensee procedures. The inspectors verified that the meteorological data readout and recording instruments in the control room and at the tower were operable.

The inspectors compared readout data (i.e., wind speed, wind direction, and delta temperature) in the control room and at the meteorological tower to identify if there were any line loss differences.

This meteorological instruments inspection constituted one sample as defined in IP 71122.03-05.

The inspectors reviewed each event documented in the Annual Environmental Monitoring Report, which involved a missed sample, inoperable sampler, lost TLD, or anomalous measurement for the cause and corrective actions and conducted a review of the licensees assessment of any positive sample results (i.e., licensed radioactive material detected above the lower limits of detection (LLDs). The inspectors reviewed the associated radioactive effluent release data that was the likely source of the released material.

This annual environmental monitoring report events inspection constituted one sample as defined in IP 71122.03-05.

The inspectors reviewed significant changes made by the licensee to the ODAM as the result of changes to the land census or sampler station modifications since the last inspection. The inspectors reviewed technical justifications for changed sampling locations. The inspectors verified that the licensee performed the reviews required to ensure that the changes did not affect its ability to monitor the impacts of radioactive effluent releases on the environment.

This ODAM significant changes review constituted one sample as defined in IP 71122.03-05.

The inspectors reviewed the calibration and maintenance records for two air samplers and composite water samplers. The inspectors reviewed calibration records for the environmental sample radiation measurement instrumentation (i.e., count room). The inspectors verified that the appropriate detection sensitivities with respect to TS/ODAM were utilized for counting samples (i.e., the samples meet the TS/ODAM required LLDs).

The inspectors reviewed quality control charts for maintaining radiation measurement instrument status and actions taken for degrading detector performance.

The inspectors reviewed the results of the REMP sample vendors quality control program including the interlaboratory comparison program to verify the adequacy of the vendors program and the corrective actions for any identified deficiencies. The inspectors reviewed audits and technical evaluations the licensee performed on the vendors program. The inspectors reviewed QA audit results of the program to determine whether the licensee met the TS/ODAM requirements.

This radiological environmental monitoring program sampler maintenance records and quality control inspection constituted one sample as defined in IP 71122.03-05.

b. Findings

No findings of significance were identified.

.3 Unrestricted Release of Material from the Radiologically Controlled Area (RCA)

a. Inspection Scope

The inspectors observed several locations where the licensee monitors potentially contaminated material leaving the RCA, and inspected the methods used for control, survey, and release from these areas. The inspectors observed the performance of personnel surveying and releasing material for unrestricted use to verify that the work was performed in accordance with plant procedures.

This inspection constituted one sample as defined in IP 71122.03-05.

The inspectors verified that the radiation monitoring instrumentation was appropriate for the radiation types present and was calibrated with appropriate radiation sources. The inspectors reviewed the licensees criteria for the survey and release of potentially contaminated material and verified that there was guidance on how to respond to an alarm, which indicates the presence of licensed radioactive material. The inspectors reviewed the licensees equipment to ensure the radiation detection sensitivities were consistent with the NRC guidance contained in IE Circular 81-07 and IE Information Notice 85-92 for surface contamination and health physics positions (HPPOS-221) for volumetrically contaminated material. The inspectors verified that the licensee performed radiation surveys to detect radionuclides that decay via electron capture. The inspectors reviewed the licensees procedures and records to verify that the radiation detection instrumentation was used at its typical sensitivity level based on appropriate counting parameters (i.e., counting times and background radiation levels). The inspectors verified that the licensee had not established a release limit by altering the instruments typical sensitivity through such methods as raising the energy discriminator level or locating the instrument in a high radiation background area.

This unrestricted release of material from the RCA inspection constituted one sample as defined in IP 71122.03-05.

b. Findings

No findings of significance were identified.

.4 Identification and Resolution of Problems

a. Inspection Scope

The inspectors reviewed the licensees self assessments, audits, LERs, and Special Reports related to the radiological environmental monitoring program since the last inspection to determine if identified problems were entered into the CAP for resolution.

The inspectors also verified that the licensee's self-assessment program was capable of identifying repetitive deficiencies or significant individual deficiencies in problem identification and resolution.

The inspectors also reviewed corrective action reports from the radioactive effluent treatment and monitoring program since the previous inspection, interviewed staff and reviewed documents to determine if the following activities were being conducted in an effective and timely manner commensurate with their importance to safety and risk:

• initial problem identification, characterization, and tracking;

• disposition of operability/reportability issues;

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

• identification of repetitive problems;

• identification of contributing causes;

• identification and implementation of effective corrective actions;

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

• implementation/consideration of risk-significant operational experience feedback.

This radiological environmental monitoring program and radioactive material control program problem identification and resolution inspection constituted one sample as defined in IP 71122.03-05.

b. Findings

No findings of significance were identified.

4OA1 Performance Indicator Verification

.1 Data Submission Issue

a. Inspection Scope

The inspectors performed a review of the data submitted by the licensee for the fourth quarter 2008 performance indicators for any obvious inconsistencies prior to its public release in accordance with IMC 0608, Performance Indicator Program.

This review was performed as part of the inspectors normal plant status activities and, as such, did not constitute a separate inspection sample.

b. Findings

No findings of significance were identified.

.2 Unplanned Scrams per 7000 Critical Hours

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Scrams per 7000 Critical Hours PI for the period from the first quarter of 2008 through the fourth quarter of 2008.

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 5, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports and NRC Inspection Reports for the period of first quarter of 2008 through the fourth quarter of 2008 to validate the accuracy of the submittals. The inspectors also reviewed the licensees CAP 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 constituted one unplanned scrams per 7000 critical hours sample as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

.3 Unplanned Scrams with Complications

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Scrams with complications PI for the period from the first quarter of 2008 through the fourth quarter of 2008. 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 5, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports and NRC Integrated Inspection Reports for the period of first quarter of 2008 through the fourth quarter of 2008 to validate the accuracy of the submittals. The inspectors also reviewed the licensees CAP 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 constituted one unplanned scrams with complications sample as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

.4 Unplanned Power Changes 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 of 2008 through the fourth quarter of 2008. 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 5, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, maintenance rule records, event reports and NRC Integrated Inspection Reports for the period of first quarter of 2008 through the fourth quarter of 2008 to validate the accuracy of the submittals. The inspectors also reviewed the licensees CAP 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 constituted one unplanned power changes per 7000 critical hours sample as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

.5 Occupational Exposure Control Effectiveness

a. Inspection Scope

The inspectors sampled licensee submittals for the Occupational Radiological Occurrences performance indicator for the period from the first quarter 2008 through fourth quarter 2008. To determine the PI 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 5, were used. The inspectors reviewed the licensees assessment of the PI for occupational radiation safety to determine if indicator related data was adequately assessed and reported. To assess the adequacy of the licensees PI data collection and analyses, the inspectors discussed with radiation protection staff, the scope and breadth of its data review, and the results of those reviews. The inspectors independently reviewed electronic dosimetry dose rate and accumulated dose alarm and dose reports and the dose assignments for any intakes that occurred during the time period reviewed to determine if there were potentially unrecognized occurrences. The inspectors also conducted walkdowns of numerous locked high and very high radiation area entrances to determine the adequacy of the controls in place for these areas. Documents reviewed are listed in the to this report.

This inspection constituted one occupational radiological occurrences sample as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

.6 Radiological Effluent TS/Offsite Dose Calculation Manual Radiological Effluent

Occurrences

a. Inspection Scope

The inspectors sampled licensee submittals for the Radiological Effluent TS (RETS)/

ODAM Radiological Effluent Occurrences performance indicator for the period of January 2008 through December 2008. The inspectors used PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5 to determine the accuracy of the PI data reported during those periods. The inspectors reviewed the licensees issue report database and selected individual reports generated since this indicator was last reviewed to identify any potential occurrences such as unmonitored, uncontrolled, or improperly calculated effluent releases that may have impacted offsite dose. The inspectors reviewed gaseous effluent summary data and the results of associated offsite dose calculations for selected dates between January 2008 and December 2008 to determine if indicator results were accurately reported. The inspectors also reviewed the licensees methods for quantifying gaseous and liquid effluents and determining effluent dose. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one RETS/ODAM radiological effluent occurrences sample as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Physical Protection

.1 Routine Review of items Entered Into the CAP

a. Scope

As part of the various baseline inspection procedures 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 occurrences 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.

Minor issues entered into the licensees CAP as a result of the inspectors observations are included in the attached List of Documents Reviewed.

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 CAP Reviews

a. 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 condition report 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.

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

.1 Cooling Tower Riser Break Leads to Manual Reactor Scram

a. Inspection Scope

The inspectors reviewed the plant operators response to a break in the B Cooling Tower West Riser during a planned downpower prior to commencing RFO 21. While preparing to secure the B Cooling Tower per Operating Instruction (OI) 442, Circulating Water System, operators observed indications of cavitation of both circulating water pumps. They also noted a lowering circulating water pit level. At time 1801, operators inserted a manual reactor scram as directed by Alarm Response Procedure (ARP)1C06A, D-11, Circ Water Pit Lo Level. Documents reviewed in this inspection are listed in the Attachment.

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

b. Findings

Introduction:

A finding of very low safety significance was self-revealed when the operators exceeded the operational limit of the cooling tower riser by failing to secure one of the two running circulating water pumps prior to securing flow to the A cooling tower.

Description:

On February 1, 2009, operators were lowering reactor power in preparation for RFO 21. Using OI 442, operators were preparing to secure the A circulating water pump and the A cooing tower. Per the OI, operators were assigned to throttle the cooling tower riser valves on the tower to be removed from service until circulating water discharge pressure was about 35 psig and then secure the circulating water pump. The operators in the control room were monitoring circulating water discharge pressure using computer point F015, which is fed from pressure transmitter PT4205. An operator in the pump house was assigned to monitor the local circulating water pump discharge pressure.

Operators at the cooling tower were responsible for closing the cooling tower riser valves. In coordination with the control room operators, the cooling tower operators bumped the cooling tower riser valves in the closed direction in 10-second intervals.

After each bump, the control room operators and the pump house operators monitored the cooling pump discharge pressure at their respective indications. The pump house operators noted a slightly higher discharge pressure than the control room operators and, therefore, the decision was made to use the local indication at the pump house since it was more conservative.

At 1755, the control room ordered the cooling tower operators to give a 5-second close signal to the cooling tower riser valves. After the 5-second close signal, the pump house operator noted that the local circulating water pump discharge pressure still indicated 33 psig, the same reading as before the 5 second close signal. Also, both cooling tower riser valves indicated fully closed after the 5 second close signal. The cooling tower operators reported the valve position to the control room operators and the control room operators then secured the A circulating water pump.

Shortly after the cooling tower riser valves were shut, the pump house operator observed signs of circulating water pump cavitation. He also observed a lowering level in the circulating water pit. Operators also observed a lowering circulating water pit level, and at 1801 hours0.0208 days <br />0.5 hours <br />0.00298 weeks <br />6.852805e-4 months <br />, they inserted a manual reactor scram per the guidance in ARP 1C06A, D-11, since circulating water pit level was less than eight feet and could not be restored.

Following the reactor scram, operators found that the west riser of the B cooling tower had catastrophically failed by separating at the slip joint between the riser and the distribution header and the top of the cooling tower. The Root Cause Evaluation (RCE)determined that the cooling towers were not designed to have both circulating water pumps discharging over a single cooling tower. The station determined that the root cause of the event was that OI 442 was inadequate to prevent an inappropriate operational configuration because the procedure did not prevent operators from operating both circulating water pumps over one cooling tower.

The RCE also identified a contributing cause to the event in that PT4205, the pressure transmitter that provided circulating water pump discharge pressure indication to the control room, was plugged. This plugging resulted in the indicated circulating water discharge pressure in the control room being lower than the actual discharge pressure.

This resulted in the control room operators allowing for further throttling of the cooling tower riser valves until the riser isolation valves were fully closed. It was also found that there was a Work Request Card (WRC) associated with PT4205 that had been written on November 10, 2008, to address erratic indication associated with the pressure transmitter. This WRC was scheduled to be worked during RFO 21.

Analysis:

The inspectors determined that the operators exceeding the operational limit of the B cooling tower west riser by failing to secure one of two circulating water pumps prior to securing flow to the A cooling tower was contrary to the guidance for safe operation of plant equipment contained in ACP 110.1, Conduct of Operations, and therefore was a performance deficiency.

The finding was determined to be more than minor because the finding was associated with the Reactor Safety Cornerstone attribute of procedure quality and affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown. Specifically, operating the plant in an inappropriate configuration resulted in the loss of the normal plant heat sink, which required the operators to manually scram the reactor and rely on safety-related equipment to cool the plant down.

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 Initiating Events Cornerstone. Because the finding only resulted in a reactor scram and did not contribute to the likelihood that mitigation equipment or functions would not be available, the finding screened as Green.

This finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Corrective Action, because the licensee did not take appropriate corrective actions to address safety issues and adverse trends in a timely manner. Specifically, maintenance and operations personnel failed to adequately address a known deficiency with a plugged pressure transmitter, which resulted in the control room allowing throttling of the A cooling tower riser valves until they were fully shut, thus exceeding an operational limit by operating two circulating water pumps with only one cooling tower in service. P.1(d)

Enforcement:

No violation of regulatory requirements occurred.

(FIN 05000331/2009002-02)

.2 Observation of Personnel Performance During Planned Non-Routine Evolutions:

Plant Special Testing for Increased Recirculation System Core Flow and Phase IV Power Uprate

a. Inspection Scope

The inspectors observed personnel performance during planned non-routine evolutions using special testing procedures for increased recirculation system core flow and phase IV power uprate testing from the previous operating limit of 1880 MWth to the licensed thermal power limit of 1912 MWth. The inspectors performed reviews of the special test procedures, and observed expert panel meetings and briefings conducted to review the new plant operating data obtained during the tests. The inspectors also observed the licensed operators performing reactivity manipulations during the testing as well as the plants operation at the increased power level. The documents listed in the Attachment were used by the inspectors to accomplish the objectives of the inspection procedure.

These inspection activities constituted one sample as defined in IP 71153-05.

b. Findings

No findings of significance were identified.

.3 (Closed) LER 05000331/2009002-00: Outdoor Liquid Radwaste Storage Tank

Radioactive Concentration Limit Exceeded On February 1, 2009, reactor water was directed from the reactor to the radwaste system in order to adjust the reactor water level. The water was directed to the radwaste tanks via the reactor water clean-up and RHR systems. However, most of the RHR water was inadvertently directed to the radwaste surge tank, IT-88. A subsequent sampling of IT-088 determined that the tank contained elevated levels of radioactivity that exceeded the Technical Specification administrative limit and the ODAM limit. The licensee was able to reduce the activity of the tank to less than the TS administrative limit. As corrective actions, the licensee revised the operation and radwaste procedures and implemented actions to improve communication between operation and radwaste staff in order to prevent recurrences when adjusting reactor water levels. Documents reviewed as part of this inspection are listed in the Attachment to this report. This LER is closed.

A licensee identified violation of very low safety significance was identified and is documented in Section 4OA7.

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

4OA5 Other Activities

.1 Unit 1 Power Uprate-Related Inspection Activities

a. Inspection Scope

During this inspection period, the inspectors observed several activities related to the power uprate amendment. The inspectors observed the following tests:

• Special Test Procedure (SpTP) 213, Increased Core Flow and Power Ascension Test to Greater Than 1880 MWth, Revision 0; and

• SpTP 214, Pressure Regulator Dynamic Tuning, Revision 0.

These inspection activities did not constitute any additional inspection samples. Rather, they were documented as a sample in Section 4OA3 above, as defined in IP 71153-05.

This inspection documents the completion of two surveillance samples. No concerns were identified.

a. Findings

No findings of significance were identified.

.2 (Closed) NRC Temporary Instruction 2515/173 Review of the Industry Ground Water

Protection Voluntary Initiative

a. Inspection Scope

An NRC assessment was performed of the licensees implementation at DAEC of the NEI - Ground Water Protection Initiative (dated August 2007 (ML072610036)). The inspectors verified that the licensee evaluated work practices that could lead to leaks and spills and performed an evaluation of systems, structures, and components that contain licensed radioactive material to determine potential leak or spill mechanisms.

The inspectors verified that 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 onsite locations to offsite locations. The inspectors also verified that an onsite ground water monitoring program had been implemented to monitor for potential licensed radioactive leakage into groundwater and that the licensee had provisions for the reporting of its ground water monitoring results (annual effluent report). (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 verified that 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 Groundwater Protection Initiative. The inspectors assessed whether the licensee identified the appropriate local and state officials and conducted briefings on the licensees ground water protection initiative. The inspectors also verified that 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.

.3 Quarterly Resident Inspector Observations of Security Personnel and Activities

a. Inspection Scope

During the inspection period, the inspectors conducted observations of security force personnel and activities to ensure that the activities were consistent with licensee security procedures and regulatory requirements relating to nuclear plant security.

These observations took place during both normal and off-normal plant working hours.

These quarterly resident inspector observations of security force personnel and activities did not constitute any additional inspection samples. Rather, they were considered an integral part of the inspectors' normal plant status review and inspection activities.

b. Findings

No findings of significance were identified.

4OA6 Management Meetings

Exit Meeting Summary

On April 2, 2009, the inspectors presented the inspection results to Mr. R. Anderson, Site Vice President, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors confirmed that none of the potential report input discussed was considered proprietary.

.2 Interim Exit Meetings

Interim exits were conducted for:

• The results of the Inservice Inspection with Site Vice President, Mr. R. Anderson, on February 11, 2009.

• Access control to radiologically significant areas and as-low-as-is-reasonably-achievable (ALARA) planning and control under the Occupational Radiation Safety Cornerstone with Site Vice President, Mr. R. Anderson, on February 13, 2009.

• REMP and radiological material control program and a review of the implementation of the industry ground water protection voluntary initiative under the public radiation safety cornerstone with Mr. R. Anderson, Site Vice President on March 20, 2009.

• The inspectors presented the results of the inspection review of licensee corrective actions pertaining to URI 05000331/2005005-02 to Licensing Manager, Mr. S. Catron, and other members of the licensees staff via telephone on March 31, 2009. Licensee personnel acknowledged the inspection results presented.

The inspectors confirmed that none of the potential report input discussed was considered proprietary.

.3 End of Cycle Assessment Results Discussion

On April 2, 2009, directly following the quarterly integrated resident inspection exit meeting, the NRC met with Mr. R. Anderson, Site Vice President, and members of the licensee staff to discuss their performance during the previous four quarters for the 2008 End-of-Cycle assessment, which was continually within the Licensee Response Column of the Action Matrix, in accordance with Section 06.05 of IMC 0305.

4OA7 Licensee-Identified Violations

A violation of very low safety significance (Green) was identified by the licensee. This violation meets the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as an NCV.

Cornerstone: Public Radiation Safety

Technical Specification 5.5.8 states explosive gas and storage tank radioactive monitoring program, Section b., limits the liquid radwaste storage tanks in the low-level radwaste processing and storage facility (LLRPSF) to less than 50 curies. Contrary to this requirement, on February 3, 2009, a radwaste operator discovered that the dose rate at the vicinity of radwaste surge tank IT-088 was elevated. A subsequent sample of IT-088 determined that the tank contained approximately 88 curies of total radioactivity.

This exceeded the Technical Specification administrative limit of 50 curies. As a result, the licensee submitted event report (LER No. 2009-002-00) as required by 10 CFR 20.2203(a)(3)(i). On February 3, 2009, ODAM limiting condition for operations 6.1.5 Condition A: quantity of radioactive material in the tanks exceeding the limit, was entered. The actions associated with Condition A required suspension of all additions of radioactive material to IT-088 tank and to reduce tank concentration limits to less than 50 curies within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. On February 4, 2009, the IT-088 tanks radioactivity concentration was reduced below 50 curies in less than 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />; subsequently, ODAM OLCO 6.1.5 Condition A was exited. This issue was entered into the licensees corrective action program as CAP 063486. The finding was reviewed using IMC 0609, Appendix D, Public Radiation Safety Significance Determination Process, and was determined to be of very low safety significance. Specifically, the finding was not a radioactive material control or transportation issue and the finding was not indicative of a failure to implement the effluent control program and did not result in a dose to the public greater than 0.005 rem or in excess of the criterion in Appendix I to 10 CFR Part 50 or CFR 20.1301(e).

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

R. Anderson, Site Vice President

D. Curtland, Plant General Manager

B. Eckes, NOS Manager

S. Catron, Licensing Manager

J. Cadogan, Engineering Director

B. Kindred, Security Manager

J. Morris, Training Manager

C. Dieckmann, Operations Manager

G. Rushworth, Assistant Operations Manager

P. Giroir, Operations Support Manager

R. Porter, Chemistry & Radiation Protection Manager

M. Davis, Emergency Preparedness Manager

M. Lingenfelter, Design Engineering Manager

J. Swales, Design Engineering Supervisor

K. Kleinheinz, Maintenance Manager

D. Albrecht, Radwaste Supervisor

G. Park, ISI Program Owner

F. Dohmen, NDE Level III

N. McKenney, General Supervisor Radiation Protection

S. Funk, CHP, REMP Program Manager

D. Johnson, Radwaste Operator/Chem Tech, Radiation Environmental Technician

C. Harberts, Refuel Floor Project Manager

D. Barta, Licensing

Nuclear Regulatory Commission

K. Feintuck, Project Manager, NRR

K. Riemer, Chief, Reactor Projects Branch 2

LIST OF ITEMS

Opened

05000331/2009002-01 URI An Internal Contamination Occurred while Cleaning RPV Studs and Washers on the Refuel Floor at Duane Arnold (Section 2OS2.3)

05000331/2009002-02 FIN Cooling Tower Riser Break Leads to Manual Reactor Scram (Section 4OA3.1)

05000331/2009002-03 NCV Failure to perform required actions for existing LCO conditions during in-vessel fuel movements (Section 1R15.1.b)

05000331/2009002-04 NCV Failure to Consider Design Basis Load in Evaluation for Continued Operation (1R15.2.b)

Closed

05000331/2009002-02 FIN Cooling Tower Riser Break Leads to Manual Reactor Scram (Section 4OA3.1)

05000331/2009002-03 NCV Failure to perform required actions for existing LCO conditions during in-vessel fuel movements (Section 1R15.1.b)

05000331/2009002-00 LER Outdoor Liquid Radwaste Storage Tank Radioactive Concentration Limit Exceeded

05000331/2005002-02 URI Failure to Include the Analysis of Thermal Movements in Piping Modifications (1R15.2)

05000331/2009002-04 NCV Failure to Consider Design Basis Load in Evaluation for Continued Operation (1R15.2.b)