IR 05000331/2009004

IR 05000331-09-004 on 07/01/2009 - 09/30/2009 for Duane Arnold

ML093140128
Person / Time
Site:	Duane Arnold
Issue date:	11/09/2009
From:	Kenneth Riemer NRC/RGN-III/DRP/B2
To:	Costanzo C NextEra Energy Duane Arnold
References
IR-09-004
Download: ML093140128 (49)

Text

mber 9, 2009

SUBJECT:

DUANE ARNOLD ENERGY CENTER INTEGRATED INSPECTION REPORT 05000331/2009004

Dear Mr. Costanzo:

On September 30, 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 October 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 findings of very low safety significance were identified. Each finding involved a violation of NRC requirements. However, because of their very low safety significance, and because the issues were entered into your corrective action program, the NRC is treating the issues as non-cited violations (NCVs) in accordance with Section VI.A.1 of the NRC Enforcement Policy.

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 the Duane Arnold Energy Center. The information that 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 Website 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 05000331/2009004 w/Attachment: Supplemental Information

REGION III==

Docket No: 50-331 License No: DPR-49 Report No: 05000331/2009004 Licensee: FPL Energy Duane Arnold, LLC Facility: Duane Arnold Energy Center Location: Palo, IA Dates: July 1 through September 30, 2009 Inspectors: R. Orlikowski, Senior Resident Inspector R. Baker, Resident Inspector T. Go, Health Physicist L. Haeg, Resident Inspector, Monticello Nuclear Generating Plant B. Cushman, Resident Inspector, Quad Cities Nuclear Power Station R. Russell, Emergency Preparedness Inspector C. Scott, Reactor Engineer Observers: M. Audrain, Materials Engineer Approved by: K. Riemer, Chief Branch 2 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000331/2009004; 07/01/2009 - 09/30/2009; Duane Arnold Energy Center; Operability

Evaluations and Correction of Emergency Preparedness Weaknesses and Deficiencies.

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. The findings were considered Non-Cited Violations (NCVs) of NRC regulations.

The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,

Revision 4, dated December 2006.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Mitigating Systems

Green.

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

Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified by the inspectors for a failure of the Shift Manager to perform an Immediate Operability Determination (IOD) of the B Standby Diesel Generator (SBDG) after being notified by engineers of a concern with the seismic adequacy of the B SBDG normal air start system. The Shift Managers failure to follow procedure EN-AA-203-1001,

Operability Determinations/Functionality Assessments, and Administrative Control Procedure (ACP) 110.1, Conduct of Operations, was considered a performance deficiency. The licensee entered this issue into the Corrective Action Program (CAP) as item CAP 070061, and isolated the B SBDG normal air start system from the emergency air start system. A detailed seismic analysis was performed on the B SBDG normal air start system to fully evaluate operability of the system during the design basis earthquake.

The performance deficiency was determined to be more than minor because if left uncorrected, the failure to adequately implement the operability procedures could result in safety-related components being incorrectly declared operable rather than inoperable or operable but non-conforming (a more significant safety concern). The inspectors evaluated this finding using the SDP and determined the finding was of very low safety significance (Green) because it did not represent an actual loss of safety function of a single train for longer than its Technical Specification (TS) allowed outage time. The inspectors also determined that this finding has a cross-cutting aspect in the area of Human Performance, Decision-Making, because the licensee failed to make a safety-significant or risk-significant decision using a systematic process, especially when faced with uncertain or unexpected plant conditions, and thereby demonstrate that nuclear safety is an overriding priority. Specifically, the licensee did not make and document an IOD for the B SBDG once an adverse condition affecting a SBDG support system was identified. H.1(a) (Section 1R15)

Cornerstone: Emergency Preparedness

Green.

A finding of very low safety significance and associated NCV of the emergency planning standard 10 CFR 50.47(b)(4) was identified by the inspectors. The finding involved an inadequate threshold for river water level indentified in the emergency classification scheme. The classification scheme did not provide the threshold values related to specific instruments, parameters, and status indicators for river water low level and low water depth and did not address the effect of sand and silt accumulation on the River Water Supply (RWS) and Ultimate Heat Sink (UHS) systems. The thresholds for the Notification of Unusual Event and Alert were unusable for the condition of low river water level when the river bed elevation becomes greater than the low river water level threshold. The licensee entered the finding into their CAP (CAP 068505 and CE 007573).

The inspectors determined the licensees failure to adjust the Emergency Action Level (EAL) threshold criteria for river water low level at the Unusual Event and Alert classification was a performance deficiency. Because the licensee did not recognize the challenge to the RWS and the UHS due to increasing river bed level in the EALs, the EAL thresholds were not adjusted to accommodate for sand accumulation and the river bed rising. The performance deficiency was more than minor since the Emergency Preparedness Cornerstone objective to ensure the licensee is capable of implementing adequate measures to protect the health and safety of the public in a radiological emergency was adversely affected, and the finding involved a risk-significant planning standard. The finding impacted the attribute of procedure quality (emergency planning standard, emergency classification, and action level scheme). The finding was assessed using the emergency preparedness SDP and was determined to be of very low safety significance (Green). The finding was similar to the example given of the emergency classification process would not declare any Alert or Notification of Unusual Event that should be declared, as in the case when the river bed elevation exceeds the river water low level threshold values. 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 use conservative assumptions and validate the underlying assumption in the decision to not change the EAL scheme and assumed the technical specifications for the RWS and the UHS systems would address the EAL requirement.

H.1(b) (Section 1EP5.b1)

Licensee-Identified Violations

No violations of significance were identified.

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.

REACTOR SAFETY

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

1R01 Adverse Weather Protection

.1 Readiness for Impending Adverse Weather Condition - Severe Thunderstorm Watch

a. Inspection Scope

Since thunderstorms with potential tornados and high winds were forecasted in the vicinity of the facility for August 7, 2009, the inspectors reviewed the licensees overall preparations/protection for the expected weather conditions. On August 3rd and 4th, 2009, the inspectors walked down the licensees emergency alternating current (AC)power systems, because their safety-related functions could be affected or required as a result of high winds or tornado-generated missiles or the loss of offsite power. The inspectors evaluated the licensee staffs preparations against the sites procedures and determined that the staffs actions were adequate. During the inspection, the inspectors focused on plant-specific design features and the licensees procedures used to respond to specified adverse weather conditions. The inspectors also toured the plant grounds to look for any loose debris that could become missiles during a tornado. The inspectors evaluated operator staffing and accessibility of controls and indications for those systems required to control the plant. Additionally, the inspectors reviewed the Updated Final Safety Analysis Report (UFSAR) and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant specific procedures. The inspectors also reviewed a sample of CAP items to verify that the licensee identified adverse weather issues at an appropriate threshold and dispositioned them through the CAP in accordance with station corrective action procedures. Specific documents reviewed during this inspection are listed in the to this report.

This inspection activity constituted one readiness for impending adverse weather condition sample as defined in Inspection Procedure (IP) 71111.01-05.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

• B Residual Heat Removal (RHR) System with A RHR Out-of-Service (OOS);

• A RWS System with B RWS OOS;

• B Emergency Service Water (ESW) System with High Pressure Coolant Injection (HPCI) System OOS; and

• Reactor Core Isolation Cooling (RCIC).

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, UFSAR, TS requirements, outstanding work orders (WOs), 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 to this report.

These inspection activities constituted four partial system walkdown samples as defined in IP 71111.04-05.

b. Findings

No findings of significance were identified.

.2 Semi-Annual Complete System Walkdown

a. Inspection Scope

On September 2, 2009, the inspectors performed a complete system alignment inspection of the core spray system to verify the functional capability of the system.

This system was selected because it was considered both safety significant and risk significant in the licensees probabilistic risk assessment. The inspectors walked down the system to review mechanical and electrical equipment line ups, electrical power availability, system pressure and temperature indications, as appropriate, component labeling, component lubrication, component and equipment cooling, hangers and supports, operability of support systems, and to ensure that ancillary equipment or debris did not interfere with equipment operation. A review of a sample of past and outstanding WOs was performed to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the CAP database to ensure that system equipment alignment problems were being identified and appropriately resolved. Documents reviewed are listed in the Attachment to this report.

These inspection activities constituted one complete system walkdown sample as defined in 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) 03, Reactor Building HPCI, RCIC, and RadWaste Tank Rooms;

• AFP 13, Reactor Building Refueling Floor;

• AFP 14 and 16, North Turbine Building Basement Reactor Feed Pump Area and Turbine Lube Oil Tank Area & Turbine Building Basement Condensate Pump Area;

• AFP 34, 35, & 36, RadWaste Building Drum Filling, Storage, and Shipping Area,

& RadWaste Treatment and Access Area, & Precoat and Access Area, Control Room, and HVAC [Heating, Ventilation, and Air Conditioning] Equipment Rooms; and

• AFP 69, 70, 71, & 72, Yard Main Transformer 1X1, Standby Transformer 1X4, Startup Transformer 1X3, and Auxiliary Transformer 1X2.

The inspectors reviewed areas to assess if the licensee had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant, effectively maintained fire detection and suppression capability, maintained passive fire protection features in good material condition, and implemented adequate compensatory measures for out-of-service, degraded or inoperable fire protection equipment, systems, or features in accordance with the licensees fire plan.

The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to impact equipment which could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event.

Using the documents listed in the Attachment to this report, 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.

1R06 Flooding

.1 Underground Vaults

a. Inspection Scope

The inspectors selected underground manholes (MHs) subject to flooding that contained cables whose failure could disable risk-significant equipment. The inspectors determined that the cables were not submerged, that splices were intact, and that appropriate cable support structures were in place. In those areas where dewatering devices were used, such as a sump pump, the device was operable and level alarm circuits were set appropriately to ensure that the cables would not be submerged. In those areas without dewatering devices, the inspectors verified that drainage of the area was available, or that the cables were qualified for submergence conditions.

The inspectors also reviewed the licensees corrective action documents with respect to past submerged cable issues identified in the CAP to verify the adequacy of the corrective actions. The inspectors performed a walkdown of the following underground MHs located between the RWS intake structure and the essential switchgear rooms in the control building:

• 1MH109, 1MH110, 1MH111, 1MH112, & 1MH113; and

• 2MH207, 2MH208, 2MH209, 2MH210, & 2MH211.

Documents reviewed are listed in the Attachment to this report.

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

.2 Internal Flooding

a. Inspection Scope

The inspectors reviewed selected risk important plant design features and licensee procedures intended to protect the plant and its safety-related equipment from internal flooding events. The inspectors reviewed flood analyses and design documents, including the UFSAR, engineering calculations, and abnormal operating procedures to identify licensee commitments. The specific documents reviewed are listed in the to this report. In addition, the inspectors reviewed licensee drawings to identify areas and equipment that may be affected by internal flooding caused by the failure or misalignment of nearby sources of water, such as the fire suppression or the circulating water systems. The inspectors also reviewed the licensees corrective action documents with respect to past flood-related items identified in the corrective action program to verify the adequacy of the corrective actions. The inspectors performed a walkdown of the following plant area(s) to assess the adequacy of watertight doors and verify drains and sumps were clear of debris and were operable, and that the licensee complied with its commitments:

• Reactor Building basement Torus area and Core Spray/RHR Corner rooms.

This inspection activity constituted one internal flooding sample as defined in IP 71111.06-05.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review

a. Inspection Scope

On August 20 and September 15, 2009, the inspectors observed an initial license training crew, conducting an audit examination scenario in the plants simulator, and a crew of licensed operators, during licensed operator requalification examinations, in the plants simulator to verify that student and operator performances were adequate, that evaluators were identifying and documenting crew performance problems, and that 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 and successful critical task completion requirements. 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:

• HPCI System;

• A Control Building Chiller ESW System; and

• B RWS System.

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

• implementing appropriate work practices;

• identifying and addressing common cause failures;

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

• characterizing system reliability issues for performance;

• charging unavailability for performance;

• trending key parameters for condition monitoring;

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

• verifying appropriate performance criteria for structures, systems, and components (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 three 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:

• Emergent Work Related to the RCIC System Division 1 Leak Detection Power Monitor Relay Failure and Replacement During Work Week 9928;

• Emergent Work Related to the A Control Building Chiller ESW System Discharge Isolation Valve Failure to Open While Conducting the A ESW System Brominating Activities During Work Week 9931;

• Emergent Work to Inspect and Replace Fuse FU6 located in the B SBDG Control Power Circuitry During Work Week 9933;

• Emergent Work Revisions Related to Planned HPCI Outage Window During Work Week 9935;

• Multiple Work Activities Affecting Plant Risk During Work Week 9937; and

• Emergent Work to Troubleshoot Moisture Separator Reheater Second Stage Drain Valve, CV-1068, During Work Week 9939.

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

These inspection activities constituted six samples as defined in IP 71111.13-05.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• HPCI Response Time Correction Factor Outside of the Band;

• B Standby Filter Unit (SFU) Bolting Deficiencies Found During System Walkdown;

• A SBDG Exhaust Header Candle Flame Occurring During Slow Start Surveillance Testing;

• Thermography Anomaly in Panel 1C118, B SBDG 1G21 Control Relay and Terminal Panel;

• A Standby Liquid Control (SBLC) Pump Declared Inoperable; and

• Seismic Issues Identified on A SBDG Air Start Piping.

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 six samples as defined in IP 71111.15-05.

b. Findings

Failure to Perform an Immediate Operability Determination for B Standby Diesel Generator

Introduction:

A Green finding and associated NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified by the inspectors for the failure to follow procedures EN-AA-203-1001, Operability Determinations/Functionality Assessments, and Administrative Control Procedure (ACP) 110.1, Conduct of Operations, to adequately address a degraded condition on the B SBDG.

Description:

On September 28, 2009, the A SBDG was declared inoperable to support TS surveillance testing. During the testing, engineers discovered that two seismic supports on the normal air start piping were not installed per design requirements.

Calculation CAL-M84-034, Revision 1, was reviewed and it was determined that the calculation did not analyze the actual configuration of the supports in the plant.

During the review, engineers raised additional questions about the adequacy of the analysis and the piping support configuration. A preliminary review of the A SBDG normal air start piping calculation determined that the existing support arrangement would not pass design basis seismic requirements or Appendix F operability basis requirements. The licensee isolated the normal air start system piping from the A SBDG.

At the time of discovery of the issue with the A SBDG (approximately 3:27 PM),engineers initiated CAP 070040 to document the identified discrepancy with the A SBDG normal air start piping. Additionally, it was not known if a similar condition existed with the B SBDG normal air start system seismic supports. As a precautionary measure, Operations personnel isolated the normal air start piping from the B SBDG air start system by shutting valve V32-0147 at 3:55 PM. A separate CAP document was never initiated to identify if a similar issue with the B SBDG normal air start piping existed.

Because the A SBDG was inoperable for surveillance testing, the B SBDG was being guarded per station procedure OP-AA-102-1003, Guarded Equipment (DAEC).

Although procedure OP-AA-102-1003 (DAEC) does not explicitly prohibit personnel entry into areas that are guarded, DAEC management made the decision to delay an engineering inspection of the B SBDG air start piping until the A SBDG surveillance testing was completed and the A SBDG was declared operable.

ACP 110.1, Attachment 10, states that shift supervision is ultimately responsible for making timely operability determinations. Additionally, Attachment 10 states that when there is cause to question the status of a structure, system or component, the process of determining its status is expected to be thorough and prompt.

DAEC procedure EN-AA-203-1001, step 4.1.7, states an Immediate Operability Determination (IOD) of SSC Operability is required following discovery of a degraded or nonconforming condition. If the Shift Manager declares the SSC Operable, the basis used for the IOD is required to be documented in the CAP identifying the concern. If the SSC is declared inoperable, the Shift Manager is required to document the SSC as Inoperable and implement any TS required actions.

A review of the DAEC station logs and CAP system by the inspectors did not identify any documented operability determination of the B SBDG between the period of 3:27 PM and 3:55 PM on September 28, 2009. At 3:55 PM, the DAEC station logs contained an entry that stated V-32-147, DIESEL AIR START ISOL [Isolation] FROM ELECTRIC COMPRESSOR has been unlocked and closed due to concerns over an Air Start Piping Support discrepancy that was discovered on the A SBDG. This valve is for the B SBDG and is being closed as a precaution and to ensure operability is maintained for the B SBDG until an inspection can occur on that unit. The inspectors concluded that the licensee failed to follow Attachment 10 of ACP 110.1 and step 4.1.7 of procedure EN-AA-203-1001 when the Shift Manager was notified by engineers of a concern with the seismic adequacy of the B SBDG normal air start piping, and failed to make and document an IOD for the B SBDG.

Analysis:

The inspectors determined that the failure to declare and document operability of the B SBDG was contrary to Attachment 10 of ACP 110.1 and step 4.1.7 of procedure EN-AA-203-1001, Operability Determinations/Functionality Assessments, and was a performance deficiency.

The inspectors determined that the performance deficiency was more than minor because, if left uncorrected, failure to adequately implement the operability procedure could result in safety-related components being incorrectly declared operable rather than inoperable or operable but non-conforming (a more significant safety concern).

This finding affects the Mitigating Systems Cornerstone.

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

Initial Screening and Characterization of findings, Table 4a for the Mitigating Systems Cornerstone. The finding screens as Green because the finding did not represent an actual loss of safety function of a single train for longer than its TS allowed outage time.

This finding has a cross-cutting aspect in the area of Human Performance, Decision-Making, because the licensee failed to make a safety-significant or risk-significant decision using a systematic process, especially when faced with uncertain or unexpected plant conditions, and thereby demonstrate that nuclear safety is an overriding priority. Specifically, the licensee did not make and document an IOD for the B SBDG once an adverse condition affecting a SBDG support system was identified. H.1(a)

Enforcement:

10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be prescribed and accomplished by procedures appropriate to the circumstances. The licensee established ACP 110.1, Conduct of Operations, and EN-AA-203-1001, Operability Determinations/Functionality Assessment, as the implementing procedures for declaring operability of safety systems, an activity affecting quality.

Contrary to the above, on September 28, 2009, the Shift Manager failed to follow 10 of ACP 110.1 and step 4.1.7 of procedure EN-AA-203-1001. Specifically, the Shift Manager failed to declare and document operability of the B SBDG after being notified by engineers of a concern with the seismic adequacy of the B SBDG normal air start. Because this violation was of very low safety significance and it was entered into the licensees corrective action program as CAP 070061, this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy (NCV 05000331/2009004-01).

1R18 Plant Modifications

.1 Temporary Plant Modifications

a. Inspection Scope

The inspectors reviewed the following temporary modification(s):

• Troubleshooting and installation of gag device on CV-1068, Moisture Separator Reheat Second Stage Drain Tank Drain Valve.

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 system. 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 were installed as directed; 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. Documents reviewed in the course of this inspection are listed in the Attachment to this report.

This inspection constituted one temporary modification sample 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:

• Calibration and Functional Testing Following Replacement of the RCIC Division 1 Steam Leak Detection Power Monitor Relay;

• Operational Testing Following Repair of the A RHR Torus Suction Isolation Valve (MO-2069) Power Supply Breaker (1B3448);

• Post Maintenance Testing Activities Following Performance of the Annual Inspection and Oil Change for the 1K090B Instrument Air Compressor;

• Calibration and Functional Testing of the B RWS Stilling Basin Inlet Flow Instrument to Support Inservice Testing of the B & D RWS Pumps;

• Calibration and Operational Testing Following Replacement of the Drywell Floor Drain Sump Level Switch; and

• Post Maintenance Testing Activities Following Replacement of the Packing of the B ESW Pump Discharger Strainer.

These activities were selected based upon the SSCs ability to impact risk. The inspectors evaluated these activities for the following (as applicable): the effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed; acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate; tests were performed as written in accordance with properly reviewed and approved procedures; equipment was returned to its operational status following testing (temporary modifications or jumpers required for test performance were properly removed after test completion); and test documentation was properly evaluated. The inspectors evaluated the activities against TS, the UFSAR, 10 CFR 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.

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:

• Surveillance Test Procedure (STP) 3.3.1.1-05, Reactor High and Lo Water Level (HPCI, RCIC, RPS [Reactor Protection System], PCIS [Primary Containment Isolation System]) Instrument Channel Calibration;

• STP NS160004, RHR Service Water (RHRSW) Operability Test and Comprehensive Pump Test;

• STP 3.5.3-02, RCIC System Operability Test;

• STP 3.8.1-06B, B SBDG Operability Test (Fast Start);

• STP 3.4.5-01, Calibration of Equipment Drain Sump and Floor Drain Sump Flow Integrators; and

• STP 3.3.5.1-14; A Core Spray Logic System Functional Test.

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 frequency 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, American Society of Mechanical Engineers (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 four routine surveillance testing samples, one inservice testing sample, and one reactor coolant system leak detection inspection sample as defined in IP 71111.22, Sections -02 and -05.

b. Findings

No findings of significance were identified.

1EP2 Alert and Notification System Evaluation

a. Inspection Scope

The inspectors held discussions with plant Emergency Preparedness (EP) staff regarding the operation, maintenance, and periodic testing of the Alert and Notification System (ANS) in the Duane Arnold Energy Centers plume pathway Emergency Planning Zone. The inspectors reviewed monthly trend reports and siren test failure records from July 2007 through June 2009. Information gathered during document reviews and interviews was used to determine whether the ANS equipment was maintained and tested in accordance with Emergency Plan commitments and procedures. Documents reviewed are listed in the Attachment to this report.

This ANS inspection constituted one sample as defined in IP 71114.02-05.

b. Findings

No findings of significance were identified.

1EP3 Emergency Response Organization Augmentation Testing

a. Inspection Scope

The inspectors reviewed and discussed with plant EP staff the emergency plan commitments and procedures that addressed the primary and alternate methods of initiating an Emergency Response Organization (ERO) augmentation to the on-shift ERO as well as the provisions for maintaining the plants ERO emergency telephone book. The inspectors also reviewed reports and a sample of CAP records of unannounced off hour augmentation tests, which were conducted from July 2007 through June 2009, to determine the adequacy of post-drill critiques and associated corrective actions. The inspectors also reviewed the EP training records of a sample of approximately 19 ERO personnel assigned to key and support positions to determine the current status of their ERO position training. Documents reviewed are listed in the to this report.

This ERO augmentation testing inspection constituted one sample as defined in IP 71114.03-05.

b. Findings

No findings of significance were identified.

1EP5 Correction of Emergency Preparedness Weaknesses and Deficiencies

a. Inspection Scope

The inspectors reviewed a sample of Nuclear Oversight staffs 2008 and 2009 audits of the DAEC EP program to determine if the independent assessments met the requirements of 10 CFR 50.54(t). The inspectors also reviewed critique reports and samples of CAP records associated with the 2008 biennial exercise, as well as various EP drills conducted in 2008 and 2009, in order to determine if the licensee fulfilled drill commitments, and to evaluate the licensees efforts to identify, track, and resolve identified concerns. Additionally, the inspectors reviewed a sample of EP items and corrective actions related to the facilitys EP program and activities to determine whether corrective actions were completed in accordance with the sites corrective action program.

The inspectors reviewed the event summary for an implementation of the emergency plan for an actual event declared on June 12, 2008, to determine if the licensee effectively implemented the requirements of the plan. The licensee declared a Notification of Unusual Event for loss of communications (SU 6.2) as a result of the flooding of the Cedar River. The flooding caused numerous communications failures outside of the Duane Arnold Energy Center and resulted in the loss of the sites commercial phone system, the Federal Telephone System, and the microwave phone system. The event was exited on June 19, 2008, after minimum communication requirements had been restored.

b. Findings

(1) Inadequate threshold for river water low level indentified in the emergency classification scheme

Introduction:

A finding of very low safety significance and associated NCV of the emergency planning standard 10 CFR 50.47(b)(4) was identified by the NRC inspectors.

The finding involved an inadequate threshold for river water level indentified in the emergency classification scheme.

Description:

The DAEC Emergency Plan describes the EALs, which provide the threshold values related to specific instruments, parameters, and status indicators used to establish the emergency classification. In the hazards category of the emergency classification scheme, the EAL HU 1.9 and HA 1.7 are associated with river water level for the Unusual Event and Alert classification, respectively. The EAL threshold value for HU 1.9 of 725.5 feet and for HA 1.7 of 724.5 feet addresses the effects of water level on the River Water Supply (RWS) System and the Ultimate Heat Sink (UHS) for the safety-related cooling water for systems, such as RHR service water and Emergency Service Water (ESW). The RWS also provides make-up water to the Circulating Water System.

The plant takes water in for system cooling at the intake structure for the safety-related RWS system and is located on the west bank of the Cedar River. The minimum river water level requirement ensures sufficient suction pressure and water volume to allow the RWS system pumps to provide sufficient flow of water for cooling safety-related heat loads and providing make-up water to the UHS. If the river water level drops below the threshold levels, the pump suction would not have the continuous supply of water needed and a potentially substantial degradation in the level of safety of the plant and challenge to the UHS could occur.

The intake structure has a sand gate to control the sand entering the structure pits where the pumps are located. As the sand accumulates at the base of the intake structure, the gate is raised to hold back the sand. As the gate is raised, the opening allowing water into the intake structure is reduced. The river bed in front of the intake structure has to be maintained below the sill level per the UFSAR in order to ensure adequate flow to meet UHS requirements.

In 1990, an NRC inspection report identified concerns with the intake structure sand accumulation and sand gate position. The licensees corrective actions included several commitments to provide direction for the operation and control of the sand gates and precautions and limitations for the gate positions.

In 2006, a condition evaluation was conducted to evaluate the sand gate position since the gate was one foot of being full up with a build up of sand below the gate.

The evaluation concluded the gate should be lowered and the sand removed so if the river water level lowered the gate could be adjusted to allow water to flow into the intake structure. In addition, a concern was expressed by the NRC inspectors relative to the RWS and UHS systems because of the effects of significant sand accumulation.

An operability review and recommendation was conducted and determined the RWS and UHS were fully capable of performing their functions; however, the UHS was considered to be non-conforming to the requirements in the UFSAR due to sand build-up in front of the structure. A determination was made that the RWS and UHS could perform their function if 725.2 feet and a water depth of 6.5 inches of water are present at the inlet to the intake structure. Surveillances, TSs, and procedures were established to periodically measure the water depth and sand height in front of the intake structure to coordinate for dredging and removal of the sand at established action levels.

Wing dams/spur dikes and riprap were installed to increase river flow at the inlet and to control erosion.

An additional corrective action was initiated by the licensee to review the effects of increased river bed elevation due to sand accumulation on the EALs for low river water level since the EALs addressed the water level and not the river bed level. The licensee concluded no changes to the EALs were warranted because the changes to the TS surveillance requirements would preclude the RWS and UHS water supply being challenged.

In 2008, the NRC expressed concern with the adequacy of the EALs for low river water level due to the river bed level increase. The licensee conducted a condition evaluation and concluded no changes to the EALs were warranted even though the river bed elevation was higher than the low river water level action threshold.

Analysis:

The inspectors determined the licensees failure to adjust the EALs threshold criteria for low river water level at the Unusual Event and Alert classification was a performance deficiency. Because the licensee did not recognize the challenge to the RWS and the UHS due to increasing river bed level in the EALs, the EAL thresholds were not adjusted to accommodate for sand accumulation and the river bed rising.

The EALs at the Notification of Unusual Event and Alert levels were invalid in the case for actual river bed elevation greater than low river water level threshold EALs.

Traditional enforcement did not apply since there were no actual safety consequences, no potential for impacting the NRCs regulatory function, and the performance deficiency was not the result of any willful violation. The performance deficiency was more than minor since the EP cornerstone objective to ensure the licensee is capable of implementing adequate measures to protect the health and safety of the public in a radiological emergency was adversely affected and the finding involved a risk-significant planning standard. The finding had the attribute of procedure quality (emergency plan standard emergency classification and action level scheme). The finding was assessed using the emergency preparedness SDP and was determined to be of very low safety significance (Green) and was similar to the example given of the emergency classification process would not declare any Alert or Notification of Unusual Event that should be declared, as in the case when the river bed elevation exceeds the river water low level threshold values.

The licensees failure to maintain the EAL scheme to provide the proper threshold values for maintaining the RWS and the UHS to ensure an adequate river water level and water depth had a cross cutting aspect in the Human Performance area of the decision-making component. Specifically, the licensee did not use conservative assumptions and validate the underlying assumption in the decision to not change the EAL scheme and assumed the technical specifications for the RWS and the UHS systems would address the EAL requirement. H.1(b)

Enforcement:

In accordance with 10 CFR 50.54(q), a licensee authorized to possess and operate a nuclear power reactor shall follow and maintain in effect emergency plans which meet the standards in 10 CFR 50.47(b). In accordance with 10 CFR 50.47(b)(4),a standard emergency classification and action level scheme shall be in use by facility licensees which provide the threshold values related to specific instruments, parameters, and status indicators used to establish the emergency classification. State and local response plans call for reliance on information provided by facility licensees for the determination of minimum initial offsite response measures.

Contrary to the above, the licensee did not maintain the EAL scheme to provide the proper threshold values for river water low level in all conditions. The EAL scheme did not provide the threshold values related to specific instruments, parameters, and status indicators for river water low level and low water depth and did not address the effect of sand and silt accumulation on the RWS and UHS systems. The EALs for the Notification of Unusual Event and Alert were unusable for the condition of low river water level when the river bed elevation became greater than the low river water level threshold. Because the finding is of very low safety significance and has been entered into the licensees CAP (CAP 068505 and CE 007573), the violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy (NCV 05000331/2009004-02).

(2) Adequacy of the licensees critique for the May 20, 2009, EP Drill

Introduction:

During a drill conducted on May 20, 2009, the resident inspector observed a drill controller interject concerning a simulated plant parameter posted on the electronic status board. The controller interject was near the time of the Site Area Emergency declaration by the Emergency Coordinator (EC) in the Technical Support Center. The licensee credited all the performance indicators for Drill/Exercise Performance as successful. The failure of the licensee to critique the potential impact of the controller interject on the EROs performance is being considered an Unresolved Item (URI) pending final review by the licensees staff.

Description:

On May 20, 2009, the licensee conducted an ERO training drill involving the licensees emergency response facilities with participation of the offsite response agencies. A controller interject was made to correct a simulated plant parameter posted on the electronic status board in the TSC involving reactor water level. The controller interject was made near the time when the EC was considering the plant status and evaluating the EAL classification scheme for the proper declaration of the emergency level. The licensees review and critique of the drill concluded the interjection did not affect the Site Area Emergency declaration, all Drill/Exercise Performance PI opportunities were successful, and the interjection met procedural guidance.

The licensee initiated corrective actions to evaluate the effects of the controller interject during the drill. Pending further review of the licensees drill evaluation and supporting documentation by the NRC staff to determine if the critique was accurate for the events and circumstances during the drill, the issue is considered an Unresolved Item (URI 05000331/2009004-03).

Documents reviewed are listed in the Attachment to this report.

This correction of EP weaknesses and deficiencies inspection constituted one sample as defined in IP 71114.05-05.

1EP6 Drill Evaluation

.1 Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine licensee emergency drill on September 16, 2009, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities.

The inspectors observed emergency response operations in the Control Room Simulator and Technical Support Center to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the licensee drill critique to compare any inspector-observed weakness with those identified by the licensee staff in order to evaluate the critique and to verify whether the licensee staff was properly identifying weaknesses and entering them into the CAP. As part of the inspection, the inspectors reviewed the drill package and other documents listed in the Attachment to this report.

This inspection activity constituted one sample as defined in IP 71114.06-05.

b. Findings

No findings of significance were identified.

RADIATION SAFETY

Cornerstone: Public Radiation Safety

2PS2 Radioactive Material Processing and Transportation (71122.02)

.1 Radioactive Waste System

a. Inspection Scope

The inspectors reviewed the liquid and solid radioactive waste system description in the UFSAR for information on the types and amounts of radioactive waste (radwaste)generated and disposed. The inspectors reviewed the scope of the licensees audit program with regard to radioactive material processing and transportation programs to verify that it met the requirements of 10 CFR 20.1101(c).

This inspection activity constituted one sample as defined in IP 71122.02-5.

b. Findings

No findings of significance were identified.

.2 Radioactive Waste System Walk-downs

a. Inspection Scope

The inspectors performed walkdowns of the liquid and solid radwaste processing systems to verify that the systems agreed with the descriptions in the UFSAR and the Process Control Program and to assess the material condition and operability of the systems. The inspectors reviewed the status of radwaste processing equipment that was not operational and/or was abandoned in place. The inspectors reviewed the licensees administrative and physical controls to ensure that the equipment would not contribute to an unmonitored release path or be a source of unnecessary personnel exposure.

The inspectors reviewed changes to the waste processing system to verify that the changes were reviewed and documented in accordance with 10 CFR 50.59 and to assess the impact of the changes on radiation dose to members of the public. The inspectors reviewed the current processes for transferring waste resin into shipping containers to determine if appropriate waste stream mixing and/or sampling procedures were utilized. The inspectors also reviewed the licensees methods for waste concentration averaging to determine if representative samples of the waste product were provided for the purposes of waste classification, as required by 10 CFR 61.55.

This inspection activity constituted one sample as defined in IP 71122.02-5.

b. Findings

No findings of significance were identified.

.3 Waste Characterization and Classification

a. Inspection Scope

The inspectors reviewed the licensees radiochemical sample analysis results for each of the licensees waste streams, including dry active waste (DAW), spent resins, and filters.

The inspectors also reviewed the licensees use of scaling factors to quantify difficult-to-measure radionuclides (e.g., pure alpha or beta emitting radionuclides).

The reviews were conducted to verify that the licensees program assured compliance with 10 CFR 61.55 and 10 CFR 61.56, as required by Appendix G of 10 CFR 20.

The inspectors also reviewed the licensees waste characterization and classification program to ensure that the waste stream composition data accounted for changing operational parameters and thus remained valid between the annual sample analysis updates.

This inspection activity constituted one sample as defined in IP 71122.02-5.

b. Findings

No findings of significance were identified.

.4 Shipment Preparation and Shipment Manifests

a. Inspection Scope

The inspectors reviewed the documentation of shipment packaging, radiation surveys, package labeling and marking, vehicle inspections and placarding, emergency instructions, determination of waste classification/isotopic identification, and licensee verification of shipment readiness for a sample of non-excepted material and radwaste shipments made in 2008 and 2009. The shipment documentation reviewed consisted of:

• Four LSA-II, Two LSA-1, One SCO-1, and Two Type-A Shipments to Waste Processors; and

• One Type-B(M) Package to Envirocare of Utah, Inc.

For each shipment, the inspectors determined if the requirements of 10 CFR Parts 20 and 61 and those of the Department of Transportation (DOT) in 49 CFR Parts 170-189 were met. Specifically, records were reviewed and staff involved in shipment activities was interviewed to determine if packages were labeled and marked properly, if package and transport vehicle surveys were performed with appropriate instrumentation, if radiation survey results satisfied DOT requirements, and if the quantity and type of radionuclides in each shipment were determined accurately. The inspectors also determined whether shipment manifests were completed in accordance with DOT and NRC requirements, if they included the required emergency response information, if the recipient was authorized to receive the shipment, and if shipments were tracked as required by 10 CFR Part 20, Appendix G.

This inspection activity constitutes one sample as defined in IP 71122.02-5.

Selected staff involved in shipment activities were interviewed by the inspectors to determine if they had adequate skills to accomplish shipment related tasks and to determine if the shippers were knowledgeable of the applicable regulations to satisfy package preparation requirements for public transport with respect to NRC Bulletin 79-19, Packaging of Low-Level Radioactive Waste for Transport and Burial, and 49 CFR Part 172 Subpart H.

This inspection activity constitutes one sample as defined in IP 71122.02-5.

b. Findings

No findings of significance were identified.

.5 Identification and Resolution of Problems

a. Inspection Scope

The inspectors reviewed condition reports, audits and self-assessments that addressed radioactive waste and radioactive materials shipping program deficiencies since the last inspection to verify that the licensee had effectively implemented the corrective action program and that problems were identified, characterized, prioritized and corrected.

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 reviewed corrective action reports from the radioactive material and shipping programs 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 inspection activity constituted one sample as defined in IP 71122.02-5.

b. Findings

No findings of significance were identified.

4OA1 Performance Indicator Verification

.1 Mitigating Systems Performance Index - Emergency AC Power System

a. Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance Index (MSPI) - Emergency AC Power System performance indicator for the period from the third quarter 2008 through the second quarter 2009. To determine the accuracy of the Performance Indicator (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, MSPI derivation reports, issue reports, event reports and NRC Integrated Inspection Reports for the period from the third quarter 2008 through the second quarter 2009 to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one MSPI emergency AC power system sample as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

.2 Mitigating Systems Performance Index - High Pressure Injection Systems

a. Inspection Scope

The inspectors sampled licensee submittals for the MSPI - High Pressure Injection Systems performance indicator for the period from the third quarter 2008 through the second quarter 2009. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, were used.

The inspectors reviewed the licensees operator narrative logs, issue reports, MSPI derivation reports, event reports and NRC Integrated Inspection Reports for the period from the third quarter 2008 through the second quarter 2009 to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the to this report.

This inspection constituted one MSPI high pressure injection system sample as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

.3 Mitigating Systems Performance Index - Heat Removal System

a. Inspection Scope

The inspectors sampled licensee submittals for the MSPI - Heat Removal System performance indicator for the period from the third quarter 2008 through the second quarter 2009. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, were used.

The inspectors reviewed the licensees operator narrative logs, issue reports, event reports, MSPI derivation reports, and NRC Integrated Inspection Reports for the period from the third quarter 2008 through the second quarter 2009 to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance.

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

This inspection constituted one MSPI heat removal system sample as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

.4 Drill/Exercise Performance

a. Inspection Scope

The inspectors sampled licensee PI submittals for the Drill/Exercise Performance for the period from the third quarter 2008 through the first quarter 2009. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, were used. The inspectors verified the accuracy of the number of reported drill and exercise opportunities and the licensees critiques and assessments for timeliness and accuracy of the opportunities. The inspector reviewed the licensees documentation for control room simulator training sessions, the 2008 biennial exercise, and other designated drills and tabletops to validate the accuracy of the submittals.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted one drill/exercise performance sample as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

.5 Emergency Response Organization Drill Participation

a. Inspection Scope

The inspectors sampled licensee submittals for the ERO Drill Participation PI for the period from the third quarter 2008 through the first quarter 2009. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, were used. The inspectors reviewed the licensees records and ERO roster to validate the accuracy of the submittals for the number of ERO members assigned to fill key positions and the percentage of ERO members who had participated in a performance enhancing drill or exercise. Documents reviewed are listed in the to this report.

This inspection constituted one ERO drill participation sample as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

.6 Alert and Notification System

a. Inspection Scope

The inspectors sampled licensee submittals for the ANS PI for the period from the third quarter 2008 through the first quarter 2009. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, were used. The inspectors reviewed the licensees siren tests processes and procedures on assessing opportunities for the PI. The licensee siren operability records were reviewed to validate the accuracy of the submittals of the licensees reported number of successful siren tests and the number of siren tests conducted during the reporting period. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one ANS 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 Corrective Action Program

a. Inspection 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 Corrective Action Program Reviews

a. Inspection Scope

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

.3 Annual Sample: Review of Operator Workarounds

a. Inspection Scope

The inspectors evaluated the licensees implementation of their process used to identify, document, track, and resolve operational challenges. Inspection activities included, but were not limited to, a review of the cumulative effects of the operator workarounds (OWAs) on system availability and the potential for improper operation of the system, for potential impacts on multiple systems, and on the ability of operators to respond to plant transients or accidents.

The inspectors performed a review of the cumulative effects of OWAs. The documents listed in the Attachment to this report were reviewed to accomplish the objectives of the inspection procedure. The inspectors reviewed both current and historical operational challenge records to determine whether the licensee was identifying operator challenges at an appropriate threshold, had entered them into their CAP and proposed or implemented appropriate and timely corrective actions which addressed each issue.

Reviews were conducted to determine if any operator challenge could increase the possibility of an Initiating Event, if the challenge was contrary to training, required a change from long-standing operational practices, or created the potential for inappropriate compensatory actions. Additionally, all temporary modifications were reviewed to identify any potential effect on the functionality of Mitigating Systems, impaired access to equipment, or required equipment uses for which the equipment was not designed. Daily plant and equipment status logs, degraded instrument logs, and operator aids or tools being used to compensate for material deficiencies were also assessed to identify any potential sources of unidentified OWAs.

This inspection activity constituted one OWA annual inspection sample as defined in IP 71152-05.

b. Findings

No findings of significance were identified.

.4 Selected Issue Follow-Up Inspection: Duane Arnold Energy Centers Implementation of

the Operability Determination Process

a. Inspection Scope

During a review of items entered in the licensees corrective action program, the inspectors recognized that the use of the stations Prompt Operability Determination (POD) documentation form was not being consistently utilized. The inspectors decided to perform a closer inspection of the stations operability determination process, and compare DAECs process to the guidance contained in Regulatory Issue Summary 2005-20, Revision to NRC Inspection Manual Part 9900 Technical Guidance, Operability Determinations and Functionality Assessments for Resolution of Degraded or Nonconforming Conditions Adverse to Quality or Safety.

b. Observations and Assessment The inspectors reviewed DAECs procedure EN-AA-203-1001, Operability Determinations/Functionality Assessments, and compared the procedure to the Part 9900 guidance. For clarification, the Part 9900 Technical Guidance is provided to NRC inspectors to assist their review of licensee determinations of operability and resolution of degraded or nonconforming conditions. In addition, many licensees have found this guidance useful in developing their plant-specific operability determination process. Users of the guidance should be aware that, although it generally reflects existing practice, it may not be directly applicable in every case at every plant. The Part 9900 Technical Guidance does not contain any regulatory requirements.

The inspectors reviewed issues entered into the DAEC corrective action program that resulted in equipment being declared Operable but Degraded (OBD) or Operable but Nonconforming (OBN). Procedure EN-AA-203-1001 defines a degraded condition as one in which the qualification of an SSC or its functional capability is reduced.

Examples of degraded conditions are failures, malfunctions, deficiencies, deviations, and defective material and equipment. EN-AA-203-1001 defines a nonconforming condition as a condition of an SSC that involves a failure to meet the CLB [Current Licensing Basis] or a situation in which quality has been reduced because of factors such as improper design, testing, construction, or modification.

The Shift Manager is responsible for making an Immediate Operability Determination (IOD) of an SSC following discovery of a degraded or nonconforming condition.

Following the IOD, the Shift Manager may request a POD to document the basis for the declaration of Operability or conformance with the CLB. The Part 9900 Technical Guidance for Operability Determinations, Section 4.4, provides guidance for the scope of Operability Determinations. The inspectors compared DAECs EN-AA-203-1001 procedure and determined that when the station performs a POD, the items in Section 4.4 of the Part 9900 Technical Guidance are documented.

The inspectors identified several instances where a CAP documented an SSC as OBD or OBN, however, the Shift Manager did not request a POD. Because a POD was never prepared, the scope of the Operability Determination did not include all of the items that section 4.4 of the Part 9900 Technical Guidance recommends. Specific examples include:

• CAP 067132 was written to document the failure of CV-1956A, the ESW supply valve to the A Control Building Chiller. The Shift Manager determined that CV-1956A was OBD, and the basis for operability was documented in the CAP, and not in a POD. However, the CAP did not document the extent of condition relative to the B Control Building Chiller.

• CAP 069503 was written to document a nonconformance identified with the seismic support for the discharge piping on the A Core Spray Pump suction pressure relief valve. The Shift Manager declared the support OBN, documented the basis for operability in the CAP, but did not request a POD. The CAP did not document the specified safety function of the affected SSC.

• CAP 068410 was written to document a discrepancy when it was discovered that the actual weight of valve V-44-0043 was 20 pounds greater than the weight used in calculation CAL-M05-043 to analyze the Well Water Piping from Penetration X24A outside the Drywell. The Shift Manager declared V-44-0043 OBN, but did not request a POD. The CAP documented the basis for operability, but did not address the effect or potential effect of the nonconforming condition on the Drywell. Additionally, the extent of condition was not addressed in the CAP.

• CAP 068701 was written to document a discrepancy between the actual plant configuration and the plant drawings for circuit sensors installed upstream of the Drywell Cooling Well Water Return Isolation valves V-44-0033 and V-44-0031.

The Shift Manager declared the system OBD but did not request a POD. The CAP documents the basis for operability, but did not document the extent of condition. The CAP documented the basis for operability, but did not address the effect or potential effect of the nonconforming condition on the Drywell.

Additionally, the extent of condition was not addressed in the CAP.

The inspectors discussed the above discrepancies with the licensee. CAP 069987 was written to address DAECs practice of not requiring PODs for SSCs that are declared OBD or OBN. The documents listed in the Attachment to this report were reviewed to accomplish the objectives of the inspection procedure. The inspectors did not identify any findings of significance.

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

.5 Annual Sample: Root Cause Evaluation 1078, B Emergency Diesel Generator Output

Breaker Trip NRC Inspection Report 05000331/2009009 documents an annual Problem Identification and Resolution inspection sample that was performed to close Unresolved Item (URI)05000331/2008005-03.

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

.6 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.

4OA5 Other Activities

.1 (Closed) NRC Temporary Instruction 2515/175 Emergency Response Organization,

Drill/Exercise Performance Indicator, Program Review The inspectors performed Temporary Instruction 2515/175, ensured the completeness of the Temporary Instructions Attachment 1 and then forwarded the data to NRC Headquarters.

a. Findings

No findings of significance were identified.

4OA6 Management Meetings

.1 Exit Meeting Summary

On October 2, 2009, the inspectors presented the inspection results to Mr. C. Costanzo, 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:

• Radioactive material processing and transportation with Mr. R. Anderson, Site Vice President on August 07, 2009.

• Emergency Preparedness inspection interim exit with the Site Vice President, Mr. R. Anderson, was conducted at the site on July 17, 2009, and a final EP inspection exit meeting with Site Vice President, Mr. C. Costanzo, was conducted by telephone on September 22, 2009. Proprietary material received during the inspection was returned to the licensee.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

C. Costanzo, Site Vice President

D. Curtland, Plant General Manager

B. Eckes, NOS Manager

S. Catron, Licensing Manager

K. Kleinheinz, Engineering Director

B. Kindred, Security Manager

R. Minear, Training Manager

C. Dieckmann, Operations Manager

G. Rushworth, Assistant Operations Manager

R. Porter, Chemistry & Radiation Protection Manager

M. Davis, Emergency Preparedness Manager

M. Lingenfelter, Design Engineering Manager

J. Swales, Design Engineering Supervisor

G. Pry, Maintenance Manager

D. Albrecht, Radwaste Supervisor

R. Patrilla, Radwaste Instructor

M. Heerman, Radwaste Shipper in Training

N. McKenney, General Supervisor Radiation Protection

T. Zimmerman, EP Coordinator

J. Mac Intyre, EP/Scheduling Coordinator

Nuclear Regulatory Commission

K. Feintuck, Project Manager, NRR

K. Riemer, Chief, Reactor Projects Branch 2

LIST OF ITEMS

Opened

05000331/2009004-01 NCV Failure to Perform an Immediate Operability Determination for the B Standby Diesel Generator (1R15)

05000331/2009004-02 NCV Failure to Maintain EAL Scheme for River Low Level

((1EP5.b1)

05000331/2009004-03 URI Adequacy of the licensees critique for the May 20, 2009, EP Drill (1EP5.b2)

Closed

05000331/2009004-01 NCV Failure to Perform an Immediate Operability Determination for the B Standby Diesel Generator (1R15)

05000331/2009004-02 NCV Failure to Maintain EAL Scheme for River Low Level

((1EP5.b1)

Attachment