ML101340444

IR 05000331-10-002 on 01/01/2010 - 03/31/2010 for Duane Arnold

ML101340444
Person / Time
Site:	Duane Arnold
Issue date:	05/14/2010
From:	Kenneth Riemer NRC/RGN-III/DRP/B2
To:	Costanzo C NextEra Energy Duane Arnold
References
EA-09-215 IR-10-002
Download: ML101340444 (55)

See also: IR 05000331/2010002

Text

UNITED STATES

NUCLEAR REGULATORY COMMISSION

REGION III

2443 WARRENVILLE ROAD, SUITE 210

LISLE, IL 60532-4352

May 14, 2010

EA-09-215

Mr. Christopher R. Costanzo

Site Vice President

NextEra Energy Duane Arnold, LLC

3277 DAEC Road

Palo, IA 52324-9785

SUBJECT: DUANE ARNOLD ENERGY CENTER INTEGRATED INSPECTION REPORT

05000331/2010002

Dear Mr. Costanzo:

On March 31, 2010, 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 6, 2010, 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, three NRC-identified and one self-revealed findings of

very low safety significance were identified. Three of the four findings involved violations 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.

C. Costanzo -2-

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 05000331/2010002

w/Attachment: Supplemental Information

cc w/encl: Distribution via ListServe

U.S. NUCLEAR REGULATORY COMMISSION

REGION III

Docket No: 50-331

License No: DPR-49

Report No: 05000331/2010002

Licensee: NextEra Energy Duane Arnold, LLC

Facility: Duane Arnold Energy Center

Location: Palo, IA

Dates: January 1 through March 31, 2010

Inspectors: R. Orlikowski, Senior Resident Inspector

R. Murray, Resident Inspector

R. Baker, Resident Inspector

M. Mitchell, Health Physicist

V. Meghani, Reactor Inspector

R. Russell, Emergency Preparedness Inspector

P. Smagacz, Reactor Engineer

Observers: None

Approved by: Kenneth Riemer, Chief

Branch 2

Division of Reactor Projects

Enclosure

TABLE OF CONTENTS

SUMMARY OF FINDINGS ........................................................................................................... 1

REPORT DETAILS ....................................................................................................................... 4

Summary of Plant Status ........................................................................................................... 4

1. REACTOR SAFETY ....................................................................................................... 4

1R01 Adverse Weather Protection (71111.01) .............................................................. 4

1R04 Equipment Alignment (71111.04) ........................................................................ 5

1R05 Fire Protection (71111.05) ................................................................................... 6

1R06 Flooding (71111.06) ............................................................................................. 7

1R07 Heat Sink Performance (71111.07) ..................................................................... 7

1R11 Licensed Operator Requalification Program (71111.11) ...................................... 8

1R12 Maintenance Effectiveness (71111.12) ................................................................ 8

1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13) .......... 9

1R15 Operability Evaluations (71111.15) .................................................................... 10

1R18 Plant Modifications (71111.18) .......................................................................... 11

1R19 Post-Maintenance Testing (71111.19) ............................................................... 11

1R20 Outage Activities (71111.20) .............................................................................. 12

1R22 Surveillance Testing (71111.22) ........................................................................ 17

1EP5 Correction of Emergency Preparedness Weaknesses and Deficiencies

(71114.05) .......................................................................................................... 18

1EP6 Drill Evaluation (71114.06) ................................................................................. 21

2. RADIATION SAFETY ................................................................................................... 21

2RS01 Radiological Hazards Assessment and Exposure Control (71124.01) .............. 21

2RS06 Radioactive Gaseous and Liquid Effluent Treatment (71124.06) ...................... 24

2RS07 Radiological Environmental Monitoring Program and Radioactive

Material Control Program (71124.07)................................................................. 29

4. OTHER ACTIVITIES ..................................................................................................... 32

4OA1 Performance Indicator Verification (71151) ....................................................... 32

4OA2 Identification and Resolution of Problems (71152) ............................................ 33

4OA3 Follow-Up of Events and Notices of Enforcement Discretion (71153) ............... 35

4OA5 Other Activities ................................................................................................... 36

4OA6 Management Meetings ...................................................................................... 37

SUPPLEMENTAL INFORMATION ............................................................................................... 1

Key Points of Contact ................................................................................................................ 1

List of Items Opened, Closed and Discussed............................................................................ 2

List of Documents Reviewed ..................................................................................................... 3

List of Acronyms Used ............................................................................................................ 11

Enclosure

SUMMARY OF FINDINGS

IR 05000331/2010002; 01/01/2010 - 03/31/2010; Duane Arnold Energy Center; Outage

Activities, Correction of Emergency Preparedness Weaknesses and Deficiencies, Radiological

Hazards Assessment and Exposure Control.

This report covers a three-month period of inspection by resident inspectors and announced

baseline inspections by regional inspectors. Three Green findings were identified by the

inspectors and one Green finding was self-revealed. Three of the four 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). Cross-cutting aspects were determined using

IMC 0310, Components Within The Cross-Cutting Areas. Findings for which the SDP does

not apply may be Green or be assigned a severity level after NRC management review.

The 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.

A. NRC-Identified and Self-Revealed Findings

Cornerstone: Initiating Events

• 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

deficiencies in the design documents for the reactor building crane and the special lifting

devices. Specifically, the crane bridge girder rails supporting the trolley were not

evaluated for the design basis seismic loads. In the reactor vessel head special lifting

device calculation, the licensee did not evaluate the hook pins and the calculated safety

factors did not meet the design criteria. In the dryer/separator special lifting device

calculation, the licensee used incorrect stress allowable values. The licensee

documented the condition in their Corrective Action Programs (CAPs) as CAPs 072917,

072568, 072885 and 072880, and initiated actions for calculation revisions and/or

modifications.

The inspectors determined that not evaluating bridge girder rails for seismic loads in

accordance with NUREG-0554, not evaluating the hook pins and accepting safety

factors not meeting the design criteria and American National Standards Institute (ANSI)

Standard N14.6 on the reactor vessel head special lifting device, and the inadequate

calculation of safety factors on the dryer/separator special lifting device in accordance

with ANSI N14.6 was a performance deficiency. The finding was more than minor

because it was associated with the Initiating Events Cornerstone attribute of Equipment

Performance and affected the cornerstone objective to limit the likelihood of those

events that upset the plant stability and challenge critical safety functions during

shutdown as well as power operations. For the item associated with the crane rail,

the Region III Senior Risk Analyst (SRA) performed an SDP Phase 3 risk-assessment

for estimating the frequency of occurrence of an Operating Basic Earthquake (OBE) or

higher seismic event during use of reactor building crane and concluded that the issue

was of very low risk significance (Green). For the item associated with the special lifting

devices, the inspectors evaluated the finding using IMC 0609.04, Phase 1 - Initial

Screening and Characterization of Findings, and based on a No answer to all the

questions in the Initiating Events column of Table 4a, as the licensee demonstrated

adequate safety factors on all components through subsequent evaluations, determined

1 Enclosure

the finding to be of very low safety-significance (Green). The inspectors did not identify

any cross-cutting aspects associated with this finding because, based on the age of the

performance deficiencies, it was not reflective of the current licensee performance.

(Section 1R20.1.b(1))

Cornerstone: Mitigating Systems

• Green. A finding of very low safety significance was identified by the inspectors for

deficiencies in the design documents for failure to translate the lift height assumptions

used in drop load evaluations into field instructions in appropriate rigging procedures.

Specifically, calculations for accidental drop during handling of the fuel pool area

demineralizer shield plug and of the reactor feed pump motor were based on specific

lift heights during rigging; however, no field instructions were provided for limiting the

rigging to the specified heights. The licensee documented the condition in CAPs 072551

and 072811 and initiated actions for calculation/procedure revisions.

The inspectors determined that lack of field instructions or procedures restricting the

lift heights was inconsistent with the assumptions used in the drop load analyses and

was a performance deficiency. The finding was determined to be more than minor

because the finding was associated with the Mitigating Systems Cornerstone attribute of

Equipment Performance and affected the cornerstone objective to ensure availability,

reliability, and capability of systems that respond to initiating events to prevent

undesirable consequences (i.e., core damage). The inspectors evaluated the finding

using the SDP in accordance with IMC 0609, Significance Determination Process,

Attachment 0609.04, Phase I - Initial Screening and Characterization of Findings,

Table 4a for the Mitigating Systems. Using the screening questions in Table 4a, the

inspectors determined that the finding was of very low safety significance because the

deficiency did not result in loss of operability or function. This finding has a cross-cutting

aspect in the area of Problem Identification and Resolution because the licensee did not

perform a thorough evaluation of CAP 053197 in October 2007 which identified that the

lift height assumptions used in the calculation for the stud tensioner load drop were not

translated into field instructions or procedures P.1(c). (Section 1R20.1.b(2))

Cornerstone: Emergency Preparedness

• Green. A finding of very low safety significance and associated NCV of

10 CFR Part 50, Appendix E, Section IV.F.2.g, and of the emergency planning standard

10 CFR 50.47(b)(14) was identified by the inspectors for the failure of the critique to

identify a planning standard weakness. Specifically, during the 2009 Emergency

Response Organization (ERO) Training Drill #2 conducted on May 20, 2009, the

licensees critique process failed to identify a performance problem associated with

communications between the Control Room/Simulator (CRS) and the Technical Support

Center (TSC) and, as a result, the deficiency was not corrected. The CRS provided

inaccurate information necessary for an Emergency Action Level (EAL) classification to

the TSC concerning the reactor water level which prompted a controller injection to stop

a potential inaccurate classification. The licensee entered the finding into their corrective

action program (CAP 068506 and CE 007572).

The performance deficiency was determined to be more than minor because the

deficiency adversely affected the Emergency Preparedness Cornerstone objective to

ensure the licensee is capable of implementing adequate measures to protect the health

2 Enclosure

and safety of the public in a radiological emergency, as demonstrated by the

ERO performance in a drill. The inspectors used IMC 0609, Appendix B, and

determined the deficiency was similar to the Green example of the drill critique process

not properly identifying a weakness resulting from a performance problem associated

with a risk significant planning standard 10 CFR 50.47(b)(14). Therefore, the finding

was screened to be of very low safety significance (Green). The cause of the finding

had a cross -cutting component in the problem identification and resolution area of self

and independent assessments P.3(a). (Section 1EP5).

Cornerstone: Occupational Radiation Safety

• Green. A self-revealed finding of very low safety significance and associated NCV of

Technical Specification (TS) 5.4.1(a) was identified for failure to establish and implement

a procedure for performing decontamination activities associated with a potentially

significant decontamination activity. The issue resulted in an event where a radworker

became internally contaminated. The event was entered in the licensee=s CAP.

Additionally, the licensee completed a Human Performance Review Worksheet.

The licensee also initiated long-term corrective actions including refuel floor procedure

augmentations.

The finding is more than minor because it affected the Occupational Radiation Safety

Cornerstone objective to ensure adequate protection of worker health and safety from

exposure to radiation and the corresponding attributes associated with the occupational

radiation safety program and processes. The finding was determined to be of very low

safety significance because it was not an as-low-as-is-reasonably-achievable (ALARA)

planning issue, there was no over-exposure or substantial potential for an overexposure,

and the licensees ability to assess worker dose was not compromised. The finding

involved a cross-cutting aspect in the area of human performance related to work control

in that the licensee did not coordinate work activities by incorporating actions to address

keeping personnel apprised of the operational impact on work activities [H.3.(b)].

(Section 2RSO1)

B. Licensee-Identified Violations

No violations of significance were identified.

3 Enclosure

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 exception:

• On January 4, 2010, the plant unexpectedly increased power to 105 percent due

to a faulty circuit card causing both Turbine Bypass Valves (TBVs) to reposition

from the full closed to full open position. The plant commenced a fast power

reduction to 68 percent in accordance with procedures. The TBVs were declared

operable on January 5, 2010, and the plant returned to full power on

January 6, 2010.

1. REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection (71111.01)

.1 External Flooding

a. Inspection Scope

The inspectors evaluated the design, material condition, and procedures for coping with

the design basis probable maximum flood. The evaluation included a review to check

for deviations from the descriptions provided in the Updated Final Safety Analysis Report

(UFSAR) for features intended to mitigate the potential for flooding from external factors.

As part of this evaluation, the inspectors checked for obstructions that could prevent

draining, checked that the roofs did not contain obvious loose items that could clog

drains in the event of heavy precipitation, and determined that barriers required to

mitigate the flood were in place and operable. Additionally, the inspectors performed a

walkdown of the protected area to identify any modification to the site which would inhibit

site drainage during a probable maximum precipitation event or allow water ingress past

a barrier. The inspectors also walked down underground bunkers/manholes subject to

flooding that contained multiple train or multiple function risk-significant cables.

The inspectors also reviewed the abnormal operating procedure (AOP) for mitigating the

design basis flood to ensure it could be implemented as written.

This inspection constituted one external flooding sample as defined in

Inspection Procedure (IP) 71111.01-05.

b. Findings

No findings of significance were identified.

4 Enclosure

.2 Readiness for Impending Adverse Weather Condition - Extreme Cold Conditions

a. Inspection Scope

Since extreme cold conditions were forecast in the vicinity of the facility for

February 8, 2010, the inspectors reviewed the licensees overall preparations/protection

for the expected weather conditions. On February 9, 2010, the inspectors walked down

the Turbine Building Heating, Ventilation and Air Conditioning (HVAC), Reactor Building

HVAC and Circulating Water systems because their safety-related functions could be

affected or required as a result of the extreme cold conditions forecast for the facility.

The inspectors observed insulation, heat trace circuits, space heater operation, and

weatherized enclosures to ensure operability of affected systems. The inspectors

reviewed licensee procedures and discussed potential compensatory measures with

control room personnel. The inspectors focused on plant managements actions for

implementing the stations procedures for ensuring adequate personnel for safe plant

operation and emergency response would be available. Specific documents reviewed

during this inspection are listed in the Attachment to this report.

This inspection constituted one readiness for impending adverse weather condition

sample as defined in IP 71111.01-05.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment (71111.04)

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

systems:

• A Emergency Service Water (ESW) system with the B Standby Diesel

Generator (SBDG) out-of-service (OOS) for planned maintenance;

• Reactor Core Isolation Cooling (RCIC) with High Pressure Coolant Injection

(HPCI) OOS for planned maintenance; and

• B ESW system with the A SBDG OOS for planned 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, 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

5 Enclosure

no obvious deficiencies. The inspectors also verified that the licensee had properly

identified and resolved equipment alignment problems that could cause initiating events

or impact the capability of mitigating systems or barriers and entered them into the

corrective action program (CAP) with the appropriate significance characterization.

Documents reviewed are listed in the Attachment to this report.

These activities constituted three partial system walkdown samples as defined in

IP 71111.04-05.

b. Findings

No findings of significance were identified.

1R05 Fire Protection (71111.05)

.1 Routine Resident Inspector Tours (71111.05Q)

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) 08; Standby Gas Treatment and Motor Generator (MG)

Set Rooms;

• AFP 18, 19, and 20; Turbine Building North and South Ground Floor, Tube

Pulling Area, Aux Boiler Room; Emergency Diesel Generator (EDG) and

Day Tank Rooms;

• AFP 31 and 32; Intake Structure Pump Rooms and Traveling Screen Areas;

• AFP 01 and 02; Torus Area and North and South Corner Rooms; and

• AFP 03; HPCI, RCIC and Radwaste Tank Rooms.

The inspectors reviewed areas to assess if the licensee had implemented a fire

protection program that adequately controlled combustibles and ignition sources within

the plant, effectively maintained fire detection and suppression capability, maintained

passive fire protection features in good material condition, and implemented adequate

compensatory measures for out-of-service, degraded or inoperable fire protection

equipment, systems, or features in accordance with the licensees fire plan.

The inspectors selected fire areas based on their overall contribution to internal fire risk

as documented in the plants Individual Plant Examination of External Events with later

additional insights, their potential to impact equipment which could initiate or mitigate a

plant transient, or their impact on the plants ability to respond to a security event.

Using the documents listed in the Attachment 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.

6 Enclosure

These 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 (71111.06)

.1 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

Attachment 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 CAP 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:

• HPCI and RCIC Rooms.

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

b. Findings

No findings of significance were identified.

1R07 Heat Sink Performance (71111.07)

.1 Annual Review of Heat Sink Performance

a. Inspection Scope

The inspectors reviewed the licensees testing of the B SBDG heat exchangers to verify

that potential deficiencies did not mask the licensees ability to detect degraded

performance, to identify any common cause issues that had the potential to increase

risk, and to ensure 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

7 Enclosure

conditions. Documents reviewed for this inspection are listed in the Attachment to this

report.

This annual heat sink performance inspection constituted one sample as defined in

IP 71111.07-05.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program (71111.11)

.1 Resident Inspector Quarterly Review (71111.11Q)

a. Inspection Scope

On February 16 and March 9, 2010, the inspectors observed a crew of licensed

operators in the plants simulator during licensed operator requalification examinations to

verify that operator performance was adequate, evaluators were identifying and

documenting crew performance problems, and training was being conducted in

accordance with licensee procedures. The inspectors evaluated the following areas:

• licensed operator performance;

• crews clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of abnormal and emergency procedures;

• control board manipulations;

• oversight and direction from supervisors; and

• ability to identify and implement appropriate TS actions and Emergency Plan

actions and notifications.

The crews performance in these areas was compared to pre-established operator action

expectations and successful critical task completion requirements. Documents reviewed

are listed in the Attachment to this report.

This inspection constituted one quarterly licensed operator requalification program

sample as defined in IP 71111.11.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness (71111.12)

.1 Routine Quarterly Evaluations (71111.12Q)

a. Inspection Scope

The inspectors evaluated degraded performance issues involving the following

risk-significant systems:

8 Enclosure

• Main Steam Line Turbine Building Steam Leak Detection High Temperature

Indicating Switch TIS-4478 High Resistance; and

• Primary Containment Ventilation 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.

This inspection 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 (71111.13)

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 on the Electro-Hydraulic Control System during

Work Week 9002;

• Emergent Work due to Increase in Unidentified Drywell Leakage during

Work Weeks 9005 and 9006;

• Planned 2 Year Maintenance Inspection of the B SBDG during Work Week 9006;

• Downpower for Rod Sequence Exchange during Work Week 9012

and 9013; and

• Work Week 9013 Risk Assessment.

9 Enclosure

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 (71111.15)

a. Inspection Scope

The inspectors reviewed the following issues:

• Operability of Bypass Valves BPV-1 and BPV-2;

• Operability Evaluation (OPR) 000419, Standby Liquid Control (SBLC)

Pipe Support Discrepancy;

• B SBDG Jacket Water Cooling Heat Exchanger;

• OPR 000422, Structural Bolting Questions in Northwest Corner Room; and

• Operability of Primary Containment Isolations for the Well Water System.

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 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

Attachment to this report.

This operability inspection constituted five samples as defined in IP 71111.15-05.

b. Findings

No findings of significance were identified.

10 Enclosure

1R18 Plant Modifications (71111.18)

.1 Temporary Plant Modifications

a. Inspection Scope

The inspectors reviewed the following temporary modification:

• Jumper Installation and Removal for Electro-Hydraulic Control A61 Card

Replacement.

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 (71111.19)

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:

• B SBDG Operability Test Following 2 Year Maintenance Inspection;

• HPCI Operability Test Following Maintenance Outage; and

• B SBLC Operability Following Maintenance.

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

11 Enclosure

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.

This inspection constituted three post-maintenance testing samples as defined in

IP 71111.19-05.

b. Findings

No findings of significance were identified.

1R20 Outage Activities (71111.20)

.1 Refueling Outage Activities-Crane and Heavy Lifts Inspection (OpESS FY 2007-03)

a. Inspection Scope

During the period from January 19, 2010, through February 5, 2010, the inspectors

performed a review of the licensees control of heavy loads program in accordance

with the NRCs Operating Experience Smart Sample (OpESS) FY 2007-03, Revision 2,

Crane And Heavy Lift Inspection, Supplemental Guidance for IP-71111.20.

The inspection included the activities listed below. Documents reviewed during the

inspection are listed in the Attachment to this report.

• Reviewed licensees submittals and commitments related to Generic Letters80-113 and 81-07, Control of Heavy Loads;

• Reviewed documents supporting the reactor building crane upgrade to

single failure proof;

• Reviewed licensees preventive maintenance program and the vendor

recommendations for the preventive maintenance;

• Reviewed recent crane inspection records;

• Reviewed reactor disassembly and a sampling of other procedures for

consistency with commitments;

• Reviewed calculations and inspection/testing for the reactor vessel head lifting

device and the dryer/separator lifting device for conformance with the applicable

requirements/standards; and

• Reviewed a sample of drop load calculations to verify conformance with the

heavy loads procedures.

12 Enclosure

b. Findings

(1) Inadequate Evaluations for Crane and Special Lifting Devices

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 deficiencies in the design documents for the reactor building crane and the

special lifting devices. Specifically, the crane bridge girder rails were not evaluated

correctly for seismic loads. In addition, in the reactor vessel head special lifting device

calculation, the hook pins were not evaluated and safety factors not meeting the

acceptance criteria were accepted, while in the dryer/separator special lifting device

calculation, safety factors against shear failure of steel members were not calculated

correctly.

Description: The reactor building crane is a Seismic Category I structure described in

Section 3.8.4 of the UFSAR. The licensee upgraded the crane to meet the requirements

of NUREG-0554, Single Failure Proof Cranes for Nuclear Power Plants, to satisfy the

commitments during the Phase I review of their Control of Heavy Loads program by the

NRC. Special lifting devices for the reactor vessel head and dryer/separator are also

Seismic Category I equipment subject to the 10 CFR Part 50, Appendix B quality

assurance requirements as described in Table 3.2-1 of the UFSAR, and per

Section 9.1.4.4 of the UFSAR, they are designed to meet the requirements of

ANSI Standard N14.6-1978.

The following deficiencies were identified by the inspectors:

• The licensee did not evaluate the reactor building bridge girder rails supporting the

trolley for the design basis seismic loads. The licensee upgraded the crane to meet

the NUREG-0554, Single Failure Proof Cranes for Nuclear Power Plants,

by installing a new hoist and trolley system purchased from Ederer in 1985. The new

safety-related Ederer System was evaluated in an NRC Safety Evaluation Report of

the Generic Licensing Topical Report EDR-1, Revision 3. The site-specific seismic

calculation for the trolley was not included in the topical report reviewed by the

NRC staff and was not provided to the licensee by the vendor. The licensee seismic

evaluations for the bridge girders and the crane support structure documented in

calculations CAL-M01-273 and CAL-C01-002 were reviewed by the staff in 2003 as

part of a license amendment. In response to questions from the inspectors, the

licensee obtained a copy of the trolley seismic calculation from the vendor.

After review of the trolley calculation and the bridge girder calculation, the inspectors

identified that while the trolley transferred the lateral seismic loads to the bridge

girders through the rails, the rails were not evaluated for such loads. The licensee

documented the deficiency in their corrective action program as CAP 72917.

• In order to comply with NUREG-0612, Control of Heavy Loads at Nuclear Power

Plants, Section 5.1.6, the licensee upgraded special lifting devices used for

rigging the vessel head and the dryer/separator to the design requirements of

ANSI Standard N14.6-1978, Section 6, Special Lifting Devices for Critical Loads.

• The inspectors identified that in calculation 273C036 for the vessel head lifting

device, the hook pins were not evaluated. The pins are critical components

providing a connection between the lifting device and the reactor building crane hook

13 Enclosure

for load transfer to the crane. In addition, safety factors of 9.76 and 9.55 for stress in

some of the welds and for bearing stress at the hook pins, were accepted by the

licensee while a safety factor of 10 was required based on the design criteria stated

in the calculation, as well as per the ANSI Standard N14.6. The licensee

documented the calculation deficiencies and the need for calculation revisions in

their corrective action program as CAP 072568 and CAP 072885. Subsequently,

the licensee performed a supplemental evaluation for more accurate determination of

the safety factors, which indicated that the pins would meet the design requirements

and that the actual safety factors would be equal to or greater than 10.

• The inspectors also identified that in the calculation, CAL-M07-047, for the

dryer/separator lifting device that was performed to demonstrate compliance with

ANSI Standard N14.6, the safety factors against shear failure of steel members were

not calculated correctly due to use of incorrect shear allowable values for steel

members. The licensee documented the deficiency and the need for calculation

revisions and/or modifications in their corrective action program as CAP 72880.

Subsequently, the licensee performed additional evaluations with the correct

allowable values and with use of the certified material test reports for the hook box

steel plates to conclude that adequate safety factors as required by ANSI N14.6

were available and there were no operability concerns.

Analysis: The inspectors determined that not evaluating bridge girder rails for seismic

loads in accordance with NUREG-0554, not evaluating the hook pins and accepting

safety factors not meeting the design criteria stated in the calculation and the

ANSI Standard N14.6 on the reactor vessel head special lifting device, and the

inadequate calculation of safety factors on the dryer/separator special lifting device in

accordance with ANSI Standard N14.6 was a performance deficiency.

The finding was determined to be more than minor because the finding was associated

with the Initiating Events Cornerstone attribute of Equipment Performance and affected

the cornerstone objective to limit the likelihood of those events that upset the plant

stability and challenge critical safety functions during shutdown, as well as power

operations. Specifically, the purpose of the crane and the lifting device design

requirements is to limit the likelihood of a component failure in order to ensure safe

handling of heavy loads over the reactor core, the spent fuel pool, or safety-related

components.

For the item associated with the crane rails, the inspectors performed a Phase I SDP

review of this finding using the guidance provided in IMC 0609, Attachment 0609.04,

"Phase 1 -- Initial Screening and Characterization of Findings." In accordance with

Table 4b, "Seismic, Flooding, or Severe Weather Screening Criteria," the finding

screened as potentially risk-significant due to external initiating event core damage

sequences. Therefore, the Region III SRA performed an SDP Phase 3 risk-assessment

of this performance deficiency. The inspectors determined that only seismic events

exceeding the level of an OBE of 0.06g could impact core damage frequency. The SRA

used the Risk-Assessment Standardization Project Handbook and estimated the

frequency of seismic events for Duane Arnold exceeding this g-level to be 1.3E-4/yr.

Assuming the average duration of a crane lift was 30 minutes, the SRA estimated that

there would need to be over 100 lifts performed each year with the reactor building crane

over critical locations to approach a threshold where this issue could become

risk-significant just based on initiating event frequency. The SRA concluded that the risk

14 Enclosure

of a simultaneous occurrence of an OBE or greater magnitude seismic event during

such use of the reactor building crane was of very low safety-significance (Green).

For items associated with the lifting devices, 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. The inspectors answered no

to all the questions in the Initiating Events column based on the licensee demonstrating

adequate safety factors on all components through subsequent evaluations and

concluded that the finding was of very low safety-significance (Green).

The inspectors did not identify a cross-cutting aspect associated with this finding

because, based on the age of the performance deficiencies, it was not reflective of the

current licensee performance.

Enforcement: Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires,

in part, that design control measures shall provide for verifying or checking the adequacy

of design, such as by the performance of design reviews, by the use of alternate or

simplified calculational methods, or by the performance of a suitable testing program.

Contrary to the above, the licensee did not adequately verify or check the adequacy of

the design as stated. During the crane upgrade in 1985 and in the reactor building crane

girder calculations, CAL-M01-273, Revision 2, dated June 16, 2003, the licensee failed

to evaluate the reactor building bridge girder rails for the design basis seismic loads.

Specifically, the licensee calculations evaluated the trolley and the girders for seismic

loads but did not evaluate the rails that transfer the lateral seismic loads from the

trolley to the bridge girders. Also, in reactor vessel head lifting device calculation,

273C036, dated September 13, 1983, and in the dryer/separator lifting device

calculation, CAL-M09-047, performed on November 26, 1997, the licensee failed to

verify adequacy of all structural components. Specifically, in the vessel head lifting

device calculation the licensee failed to evaluate the hook pins and, for some of the

components, accepted safety factors that did not meet the design criteria stated in the

calculation. In the calculation for the dryer/separator lifting device, safety factors were

not adequately calculated due to the use of incorrect shear allowable values for steel

members. Because this violation was of very low safety-significance and it was entered

into the licensees corrective action program as CAPs 072917, 072568, 072885, and

072880, this violation is being treated as a NCV, consistent with Section VI.A.1 of the

NRC Enforcement Policy (NCV 05000331/2010002-01, Inadequate Evaluations for

Crane and Special Lifting Devices).

(2) Lift Height Assumptions in Drop Load Analyses Not Reflected in Rigging Procedures

Introduction: A finding of very low safety-significance was identified by the inspectors for

a failure to translate the lift height assumptions used in drop load evaluations into field

instructions in appropriate rigging procedures.

Description: As part of the control of heavy loads program and determination of safe

load paths for rigging, the licensee identified locations of safe shutdown equipment and

performed drop load analyses for certain areas to ensure that safe shutdown equipment

would not be affected by accidental drops. In calculation 273-33, Revision 1, the

licensee evaluation concluded that an accidental drop of the fuel pool area demineralizer

15 Enclosure

shield plug during handling will not damage the reactor building floor slab at elevation

812-0. The evaluation was based on an assumption that the shield plug will not be

lifted more than a foot above the floor at elevation 833-6. The inspectors found that the

licensee did not have any field instructions or procedures in place to limit the lift height to

one foot above the floor. In calculation 273-17, Revision 1, the licensee evaluated an

accidental drop of a reactor feed pump motor during rigging through the turbine building

hatch on the mat foundation. The evaluation was based on an assumption that the

equipment will not be lifted more than four feet above the operating floor level. The

inspectors found that the licensee did not have any field instructions or procedures in

place to limit the lift height to four feet above the floor. The inspectors also noted that

CAP 053197 issued on October 16, 2007, documented a similar deficiency where the lift

height limit assumed in the reactor vessel head stud tensioner load drop analysis was

not reflected in field procedures or instructions. The inspectors concluded that a

thorough extent of condition review for CAP 053197 by the licensee would have

identified the additional deficiencies noted above.

The licensee documented the deficiencies and the need for calculation/procedure

revisions in their corrective action program as CAP 072551 and CAP 072811.

The licensee reviewed the work requests last used for the above riggings and

concluded that the lift heights assumed in the calculations could have been exceeded.

The licensee performed additional evaluations using greater lift heights based on

feasibility in field and determined that, using the same methodology as used in the

existing calculations, the results would be acceptable.

Analysis: The inspectors determined that the lack of field instructions or procedures

restricting the lift heights was contrary to the assumptions used in the drop load analyses

and was a performance deficiency.

The finding was determined to be more than minor because the finding was associated

with the Mitigating Systems Cornerstone attribute of Equipment Performance and

affected the cornerstone objective to ensure availability, reliability, and capability of

systems that respond to initiating events to prevent undesirable consequences

(i.e., core damage). Specifically, damage from a load drop accident could impact

availability or reliability of safe shutdown equipment.

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.

A drop load event could adversely impact the safety-related function of the affected

equipment. Using the screening questions in Table 4a, the inspectors determined that

the deficiency did not result in a loss of operability or function, and, therefore, the finding

was of very low safety-significance (Green).

This finding has a cross-cutting aspect in the area of Problem Identification and

Resolution, associated with the corrective action program component, because the

licensee did not perform a thorough evaluation of CAP 053197 in October 2007

identifying that the lift height assumptions used in the calculation for the stud tensioner

load drop was not translated into field instructions or procedures. Specifically, during the

CAP 053197 evaluation, the licensee failed to adequately address the extent of condition

by not finding similar problems with the drop load calculations described here P.1(c).

16 Enclosure

Enforcement: No violation of regulatory requirements was identified as the inspectors

could not relate the finding to a safety-related activity or a procedure subject to the

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants and

Fuel Processing Plants. Although safe-shutdown equipment could be within the

confines of the load path, the lifting equipment used was not safety-related

(FIN 05000331/2010002-02, Lift Height Assumptions in Drop Load Analyses Not

Reflected in Rigging Procedures).

1R22 Surveillance Testing (71111.22)

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:

• A SBDG Operability Test Using Normal Starting Air (Routine);

• Technical Support Center Diesel Run (Routine);

• HPCI Steam Supply Pressure Low Functional (Routine);

• A Core Spray Operability (IST); and

• Reactor Coolant System (RCS) Leakage Detection Reclassification

(RCS Leakage Detection).

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 code, and reference values were consistent with the

system design basis;

17 Enclosure

• 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.

This inspection constituted three 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.

Cornerstone: Emergency Preparedness

1EP5 Correction of Emergency Preparedness Weaknesses and Deficiencies (71114.05)

.1 (Closed) Unresolved Item (URI) 05000331/200904-03: Adequacy of the Licensees

Critique for the May 20, 2009, EP Drill

a. Inspection Scope

The inspectors reviewed additional information concerning the Unresolved

Item 05000331/2009004-03 opened during the 2009 biennial emergency

preparedness program inspection. The inspectors reviewed the final drill report from

the 2009 ERO Training Drill #2, the drill scenario, the drill objectives and evaluation

criteria, the actual timeline from the drill, corrective actions resulting from the drill, and

the licensees assessment for the performance indicator (PI) for drill and exercise

performance (DEP). The inspectors reviewed the controllers and evaluators logs and

observation statements along with the Senior Resident Inspectors observations to

determine the circumstances and sequence of events for the drill. The inspectors

reviewed the EALs and other licensee procedures. Documents reviewed are listed in

the Attachment.

b. Findings

(1) Inadequate Critique for the 2009 ERO Training Drill #2

Introduction: A finding of very low safety significance and associated NCV of

10 CFR Part 50, Appendix E, Section IV.F.2.g and of the emergency planning standard

18 Enclosure

10 CFR 50.47(b)(14) was identified by the inspectors for the failure of the emergency

preparedness drill critique to identify a planning standard weakness. Specifically, during

the 2009 ERO Training Drill #2 conducted on May 20, 2009, the licensees critique

process failed to identify a performance problem associated with communications

between the CRS and the TSC and, as a result, was not corrected. The CRS provided

inaccurate information necessary for an EAL classification to the TSC concerning the

reactor water level, which prompted a controller injection to stop a potential inaccurate

classification.

Description: On May 20, 2009, the licensee conducted a training drill that involved the

CRS, the TSC, the Operational Support Center (OSC), the Emergency Operations

Facility (EOF), and the Joint Information Center (JIC). Additionally, Benton County,

Linn County, and Iowa Homeland Security participated in the drill. The drill began just

after 8:00 a.m.

During the drill, a simulated storm caused a loss of offsite power to both station

transformers. The standby diesel generator automatically started in the scenario and

supplied power to the station. The TSC properly classified and declared an Alert based

upon the plant conditions. As the scenario continued, the simulator had the standby

diesel generator fail, which resulted in a loss of both offsite and onsite power.

The facility lead in the TSC began to evaluate the requirements for declaring a Site Area

Emergency based on loss of all offsite power and onsite power.

While the TSC was evaluating the EAL conditions, an entry was made on the Electronic

Status Board (ESB) stating that reactor water level was +15 inches. The ESB was

viewed in all the emergency response facilities. The entry in the log was made in the

CRS after an operator read the simulated RPV level using the wide-range Yarway level

indication. When the operator reported the RPV level was +15 inches to the Shift

Manager, the Shift Manager identified that the reported value was incorrect because the

reactor coolant was greater than 250°F, thus, the wide-range Yarway instrument was not

reading the simulated reactor water level accurately. Although the Shift Manager

identified the RPV level was not +15 inches, the ESB entry was not corrected and no

additional ESB entry was made to notify the other organizations outside of the simulator

of the error on the ESB. The information on the ESB was viewed at the TSC and EOF.

Based upon the erroneous ESB entry, the decision makers in the TSC and EOF began

to look at requirements for declaring a General Emergency (GE) based on loss of all

offsite and onsite power and RPV level was less than +15 inches. The Lead Controller

in the TSC monitoring the progress of the drill recognized the Emergency Coordinator

(EC) was evaluating whether to declare a GE. The controller anticipated the early GE

declaration would cause a deviation from the scenario and would affect drill play and

offsite demonstration of tasks. The Lead Controller interjected and stated the ESB entry

of the RPV level was incorrect. He provided the correct level to the TSC. The lead

controller stated the interjection was intended to provide the correct information and

maintain the organization on-track with expected actions. After the controller interjected,

the EC and other members of the TSC determined the proper classification based on the

corrected RPV level.

On May 21, 2009, the lead controllers from each facility performed a critique of the

previous days drill and discussed the controller interjection that occurred. Corrective

Action Program 067417 requested a condition evaluation (CE) to evaluate the

19 Enclosure

appropriateness of the controller interject (CE 007464). The CE was completed on

June 25, 2009. As part of the CE process, controllers and players from the TSC, CRS,

and the EOF were questioned to attain information concerning the drill occurrences.

Additional action requests and evaluations were generated to further examine various

drill aspects related to the controller intervening and the DEP PI determination. Also, the

condition evaluation (CE 007572) resulting from the action request (CAP 068506) was

conducted. The condition evaluation and corrective actions did not address the

CRS incorrect RPV level communications on the status board that resulted in a

controller intervening.

Analysis: The inspectors determined that the licensees failure to perform an adequate

critique of the ERO performance for the 2009 ERO Training Drill #2 conducted on

May 20, 2009, to be a performance deficiency. Specifically, the licensees critique

process failed to identify a performance weakness related to the improper reading of the

RPV level, the incorrect entry on the ESB and the failure of the CRS to correct the entry,

and the use of the incorrect information in the TSC for event classification. The licensee

failed to fully evaluate the non-risk significant planning standard weakness related to

ineffective communications of plant conditions and the negative effects on the

risk-significant planning standard of accident assessment that prompted a controller to

intervene and provide correct information. As a result of the failure to perform an

adequate and thorough critique, the deficiency was not corrected.

The failure to perform an adequate critique did not meet the criteria for traditional

enforcement and was screened using the Emergency Preparedness SDP Appendix.

The performance deficiency was determined to be more than minor because the

deficiency adversely affected the 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 as demonstrated by the ERO performance in a drill and was

associated with the attribute of the evaluation and correction of deficiencies.

The inspectors evaluated the finding using IMC 0609, Appendix B, and found the

deficiency to be similar to the Green finding example of the drill critique process that not

properly identifying a weakness resulting from a performance problem associated with

risk-significant planning standard in 10 CFR 50.47(b)(14). Specifically, the critique

process did not identify the weakness related to the inaccurate communications of the

reactor water level to the decision makers in the TSC and the resulting performance

problem during the accident assessment in which a controller was prompted to interject.

Also, using the SDP, Appendix B, Sheet 1, Failure to Comply flowchart, the

performance deficiency was evaluated to be a planning standard degraded function and

was screened to be of very low safety significance (Green).

The licensees failure to perform an adequate critique had a cross-cutting component in

the Problem Identification and Resolution area of Self and Independent Assessments.

The licensee did not conduct the self-assessment and drill critique in sufficient depth to

evaluate the effects of the communications of the inaccurate reactor conditions which

prompted a controller injection to stop a potential inaccurate classification P.3(a).)).

Enforcement: Title 10 CFR 50.47(b)(14) requires, in part, that periodic exercises will be

conducted to evaluate major portions of emergency response capabilities and that the

deficiencies identified as a result of these exercises or drills will be corrected.

In addition, 10 CFR Part 50, Appendix E, Section IV.F.2.g., states, in part, that all

20 Enclosure

training, including exercises, shall provide for formal critiques in order to identify weak or

deficient areas that need correction. Contrary to the above requirements, between

May 21, 2009, and June 25, 2009, the licensee failed to identify and correct a weakness

associated with the 2009 ERO Training Drill #2 conducted on May 20, 2009. Because

the finding is of very low safety significance and has been entered into the licensees

corrective action program (CAP 068506 and CE 007572), the violation is being treated

as a NCV, in accordance with Section VI.A.1 of the NRC Enforcement Policy (NCV

05000331/2010002-03, Failure to Conduct an Adequate Critique for the May 20, 2009,

Drill).

The correction of emergency preparedness weaknesses and deficiencies inspection

does not constitute a sample as defined in IP 71114.05-05.

1EP6 Drill Evaluation (71114.06)

.1 Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine licensee emergency drill on

January 27, 2010, to identify any weaknesses and deficiencies in classification,

notification, and protective action recommendation development activities.

The inspectors observed emergency response operations in the simulator control room

and the Emergency Operating Facility 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 corrective action program. As part of the

inspection, the inspectors reviewed the drill package and other documents listed in the

Attachment to this report.

This emergency preparedness drill inspection constituted one sample as defined in

IP 71114.06-05.

b. Findings

No findings of significance were identified.

2. RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

2RS01 Radiological Hazards Assessment and Exposure Control (71124.01)

.1 Follow-up of Contamination Event during Refueling Outage 21 (02.01)

a. Inspection Scope

The inspectors reviewed radiological control problems associated with RPV stud

decontamination activities on the refuel floor during Refueling Outage 21 (RFO-21) that

resulted in internal contamination of an individual.

21 Enclosure

b. Findings

Introduction: A self-revealed finding of very low safety-significance and an associated

NCV of TS 5.4.1(a) was identified for the failure to establish and implement a procedure

for performing decontamination activities associated with a potentially significant

decontamination activity. This failure resulted in a radiological material intake event on

February 6, 2009.

Description: On February 6, 2009, during RFO-21, a radworker was assigned to

decontaminate RPV nuts and bolts. The decontamination activity was to take place in a

specific work area on the refuel floor. The licensee had designated the work area as a

contaminated area (roped off and posted).

Prior to the start of the decontamination activity, a health physics technologist (HPT)

briefed the radworker on the radiological conditions in the area and instructed the

individual to use a pre-staged five-gallon bucket that was fitted with a HEPA hose at the

bottom. This configuration was designed to minimize the spread of contamination during

the evolution and was required when power tools were used during the decontamination

process. Additionally, the HPT also indicated that the area contained a table that was

used for decontaminating items by hand.

Following the briefing, the radworker entered the work area and commenced his work

activity. During a work break, the worker attempted to exit the refuel floor decon area.

The individual passed the refuel floor personnel contamination monitor. However, the

worker was unable to pass the radiologically controlled areas access control

contamination monitor, the second personnel contamination monitor, because of a

detectable facial contamination. The licensee took nasal smears from the worker.

An analysis of the smears indicated the presence of manganese-54 (Mn-54) and

cobalt-60 (Co-60). A whole body count of the worker showed Co-60 activity.

After several showers, the licensee sent the worker home. Prior to being sent home,

the licensee instructed the worker to return the following day for another whole body

count. The following day, a whole body count did not detect internal contamination, and

the individual was assigned a dose of 0.87 millirem from an ingested intake of

approximately 0.017 percent Annual Level of Intake (ALI).

The licensee entered the event in the corrective action program as CAP 063690.

Additionally, the licensee performed an apparent cause evaluation (ACE) 001923,

nasal contamination received while cleaning RPV bolts. The ACE determined that the

internal contamination event was caused by the licensees less-than-adequate task

description for the worker working on highly contaminated equipment. This task was left

up to the HPT briefing without any additional guidance. The second contributing factor

was, according to the licensee, the HEPA hose was found disconnected from the

five-gallon bucket setup, and, therefore, failed to remove any airborne contamination

being generated away from the worker. Additionally, it was unclear whether the

radworker knew the consequence of having the hose disconnected from the bucket.

The connection of the HEPA hose to the bucket was relied upon as the sole barrier

between the activity and the generation of airborne contamination and subsequent

ingestion.

During an interview conducted by the licensee, the radworker indicated that the

preferred method (five-gallon plastic bucket with 2000 cfm HEPA hose attached on the

22 Enclosure

bottom for a negative pressure) was used initially to clean RPV nuts and bolts.

Consequently, the method, as the worker understood, was too difficult and presented a

safety concern. After trying this method, the worker deviated from it. The worker used

Scotch Brite pads to scrub the RPV nuts and washers outside the five-gallon bucket on a

flat table at the decon area instead.

The licensee=s management instructed the individual on the importance of refuel floor

personnel adhering to the specific refuel floor procedures and radiation work permit

requirements. The licensee also initiated long-term corrective actions including refuel

floor procedure augmentations.

Analysis: The inspectors determined that the issue was a performance deficiency

because the licensee failed to provide written instructions regarding the proper

technique to use while performing an activity that could change radiological conditions.

The inspectors determined that the cause of the performance deficiency was reasonably

within the licensees ability to foresee and correct and should have been prevented.

The finding was not subject to traditional enforcement since the issue did not have an

actual or potentially safety-significant consequence, nor did it impact the NRCs ability to

perform its regulatory function, and was not willful.

In accordance with IMC 0612, the inspectors determined the finding is more than minor

because it affected the Occupational Radiation Safety Cornerstone objective to ensure

adequate protection of worker health and safety from exposure to radiation and the

corresponding attributes associated with the occupational radiation safety program and

processes. Specifically, the individual did not fully understand the process preferred by

the licensee, which resulted in an unplanned intake of radioactive material. The finding

was assessed using the Occupational Radiation Safety-Significance Determination

Process and was determined to be of very low safety-significance because it was not an

ALARA planning issue, there was no over-exposure or substantial potential for an

over-exposure, and the licensees ability to assess worker dose was not compromised.

The finding involved a cross-cutting aspect in the area of human performance related to

work control in that the licensee did not coordinate work activities by incorporating

actions to address keeping personnel apprised of the operational impact on work

activities H.3.b].

Enforcement: Duane Arnold Energy Center Technical Specification 5.4.1 requires, in

part, that written procedures be established, implemented, and maintained covering the

applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A,

February 1978.

Section 7.e (4) of Appendix A to Regulatory Guide1.33, AQuality Assurance Program

Requirements (Operation),@ Revision 2, February 1978, provides, in part, that the

licensee establish written procedures for contamination control.

Contrary to the above, on February 6, 2009, the licensee failed to establish and

implement a written procedure for an activity recommended in Regulatory Guide 1.33.

Specifically, an individual was assigned to perform decontamination activities of highly

contaminated components (reactor pressure vessel nuts and studs) without a written

procedure or guidance. Consequently, the individual did not fully understand the

process preferred by the licensee which resulted in an unplanned intake of radioactive

23 Enclosure

material. Since the failure to comply with the TS was of very low safety-significance,

corrective actions were taken, and the issue was entered into the licensees corrective

action program as ACE 001923, the violation is treated as an NCV, consistent with

Section VI.A of the NRC Enforcement Policy (NCV 05000331/2010002-04-03,

An Internal Contamination Occurred while Cleaning RPV Studs and Washers on the

Refuel Floor at Duane Arnold).

2RS06 Radioactive Gaseous and Liquid Effluent Treatment (71124.06)

.1 Inspection Planning and Program Reviews (02.01)

Event Report and Effluent Report Reviews

a. Inspection Scope

The inspectors reviewed the Radiological Effluent Release Reports issued since the last

inspection to determine if the reports were submitted as required by the Offsite Dose

Calculation Manual/Technical Specification (ODCM/TS). The inspectors reviewed

anomalous results, unexpected trends, or abnormal releases identified by the licensee

for further inspection to determine if they were evaluated, were entered in the corrective

action program, and were adequately resolved.

The inspectors identified radioactive effluent monitor operability issues reported by the

licensee as provided in effluent release reports, to review these issues during the onsite

inspection, as warranted, given their relative significance and determine if the issues

were entered into the corrective action program and adequately resolved.

b. Findings

No findings of significance were identified.

Offsite Dose Calculation Manual and Final Safety Analysis Review (FSAR)

a. Inspection Scope

The inspectors reviewed UFSAR descriptions of the radioactive effluent monitoring

systems, treatment systems, and effluent flow paths so they can be verified during

inspection walkdowns. The inspectors reviewed changes to the ODCM made by the

licensee since the last inspection against the guidance in NUREG-1301, 1302 and 0133,

and Regulatory Guides 1.109, 1.21 and 4.1. When differences were identified, the

inspectors reviewed the technical basis or evaluations of the change during the onsite

inspection, to determine whether they were technically justified and maintain effluent

releases ALARA.

The inspectors reviewed licensee documentation to determine if the licensee has

identified any non-radioactive systems that have become contaminated as disclosed

either through an event report or the ODCM since the last inspection. This review

provided an intelligent sample list for the onsite inspection of any 10 CFR 50.59

evaluations and allowed a determination if any newly contaminated systems have an

unmonitored effluent discharge path to the environment, whether any required

24 Enclosure

ODCM revisions were made to incorporate these new pathways and whether the

associated effluents were reported in accordance with Regulatory Guide 1.21.

b. Findings

No findings of significance were identified.

Groundwater Protection Initiative (GPI) Program

a. Inspection Scope

The inspectors reviewed reported groundwater monitoring results and changes to the

licensees written program for identifying and controlling contaminated spills/leaks to

groundwater.

b. Findings

No findings of significance were identified.

Procedures, Special Reports, and Other Documents

a. Inspection Scope

The inspectors reviewed License Event Reports, event reports and/or special reports

related to the effluent program issued since the previous inspection to identify any

additional focus areas for the inspection based on the scope/breadth of problems

described in these reports. The review included effluent program implementing

procedures, particularly those associated with effluent sampling, effluent monitor

set-point determinations, and dose calculations. The review also included copies of

licensee and third party (independent) evaluation reports of the effluent monitoring

program since the last inspection to gather insights into the licensees program and aid

in selecting areas for inspection review (smart sampling).

b. Findings

No findings of significance were identified.

.2 Walkdowns and Observations (02.02)

a. Inspection Scope

The inspectors walked down selected components of the gaseous and liquid discharge

systems to verify that equipment configuration and flow paths align with the documents

reviewed in Section 02.01 above and to assess equipment material condition. Special

attention was made to identify potential unmonitored release points (such as open roof

vents in Boiling Water Reactor turbine decks, temporary structures butted against

turbine, auxiliary or containment buildings), building alterations which could impact

airborne, or liquid, effluent controls, and ventilation system leakage that communicates

directly with the environment.

25 Enclosure

For equipment or areas associated with the systems selected for review that were not

readily accessible due to radiological conditions, the inspectors reviewed the licensee's

material condition surveillance records, as applicable.

The inspectors walked down those filtered ventilation systems whose test results will be

reviewed to verify that there are no conditions, such as degraded HEPA/charcoal banks,

improper alignment, or system installation issues that would impact the performance, or

the effluent monitoring capability, of the effluent system.

The inspectors observed selected portions of the routine processing and discharge of

radioactive gaseous effluent (including sample collection and analysis) to verify that

appropriate treatment equipment was used and the processing activities align with

discharge permits.

The inspectors determined if the licensee has made significant changes to their effluent

release points, e.g., changes subject to a 10 CFR 50.59 review or require NRC approval

of alternate discharge points.

The inspectors observed selected portions of the routine processing and discharge liquid

waste (including sample collection and analysis) to verify that appropriate effluent

treatment equipment is being used and that radioactive liquid waste is being processed

and discharged in accordance with procedure requirements and aligns with discharge

permits.

b. Findings

No findings of significance were identified.

.3 Sampling and Analyses (02.03)

a. Inspection Scope

The inspectors selected three effluent sampling activities, consistent with smart

sampling, to verify that adequate controls have been implemented to ensure

representative samples are obtained (e.g., provisions for sample line flushing, vessel

recirculation, composite samplers, etc.).

The inspectors selected three effluent discharges made with inoperable

(declared out-of-service) effluent radiation monitors to verify that controls are in place to

ensure compensatory sampling is performed consistent with the Radiological Effluent

Technical Specification (RETS)/ODCM and that those controls are adequate to prevent

the release of unmonitored liquid and gaseous effluents.

The inspectors determined whether the facility is routinely relying on the use of

compensatory sampling in-lieu of adequate system maintenance, based on the

frequency of compensatory sampling since the last inspection.

The inspectors reviewed the results of the inter-laboratory comparison program to verify

the quality of the radioactive effluent sample analyses to verify that the inter-laboratory

comparison program include hard-to-detect isotopes as appropriate.

26 Enclosure

b. Findings

No findings of significance were identified.

.4 Instrumentation and Equipment (02.04)

Effluent Flow Measuring Instruments

a. Inspection Scope

The inspectors reviewed the methodology the licensee uses to determine the effluent

stack and vent flow rates to verify that the flow rates are consistent with RETS/ODCM or

FSAR values, and that differences between assumed and actual stack and vent flow

rates do not affect the results of the projected public doses.

b. Findings

No findings of significance were identified.

Air Cleaning Systems

a. Inspection Scope

The inspectors evaluated whether surveillance test results since the previous inspection

for TS required ventilation effluent discharge systems (HEPA and charcoal filtration),

such as the Standby Gas Treatment System, meet TS acceptance criteria.

b. Findings

No findings of significance were identified.

.5 Dose Calculations (02.05)

a. Inspection Scope

The inspectors reviewed all significant changes in reported dose values compared to the

previous Radiological Effluent Release Report (e.g., a factor of 5, or increases that

approach Appendix I Criteria) to evaluate the factors, which may have resulted in the

change.

The inspectors reviewed three gaseous waste discharge permits to verify that

the projected doses to members of the public were accurate and based on

representative samples of the discharge path.

Inspectors evaluated the methods used to determine the isotopes that are included in

the source term to ensure all applicable radionuclides are included, within detectability

standards. The review included the current 10 CFR Part 61 analyses to ensure

hard-to-detect radionuclides are included in the source term.

The inspectors reviewed changes in the licensees offsite dose calculations since the

last inspection to verify the changes are consistent with the ODCM and

Regulatory Guide 1.109. Inspectors reviewed meteorological dispersion and deposition

27 Enclosure

factors used in the ODCM and effluent dose calculations to ensure appropriate factors

are being used for public dose calculations.

The inspectors reviewed the latest Land Use Census to verify that changes

(e.g., significant increases or decreases to population in the plant environs, changes in

critical exposure pathways, the location of nearest member of the public or critical

receptor, etc.) have been factored into the dose calculations.

For the releases reviewed above, the inspectors assessed whether the calculated doses

(monthly, quarterly, and annual dose) are within the 10 CFR Part 50, Appendix I, and

TS dose criteria.

The inspectors selected, as available, records of any abnormal gaseous or liquid tank

discharges (e.g., discharges resulting from misaligned valves, valve leak-by, etc.)

to ensure the abnormal discharge was monitored by the discharge point effluent monitor.

There were no abnormal discharges. Discharges made with inoperable effluent

radiation monitors, or unmonitored leakages were reviewed to ensure that an evaluation

was made of the discharge to satisfy 10 CFR 20.1501 so as to account for the source

term and projected doses to the public.

b. Findings

No findings of significance were identified.

.6 GPI Implementation (02.06)

a. Inspection Scope

The inspectors assessed whether the licensee was continuing to implement the

Voluntary NEI/Industry GPI since the last inspection. The inspectors reviewed:

• monitoring results of the GPI to determine if the licensee has implemented its

program as intended, and to identify any anomalous results; (anomalous results or

missed samples were reviewed to determine if the licensee has identified and

addressed deficiencies through its corrective action program.);

• identified leakage or spill events and entries made into 10 CFR 50.75 (g) records to

assess any remediation actions taken for effectiveness and onsite contamination

events involving contamination of ground water to assess whether the source of the

leak or spill was identified and mitigated; and

• unmonitored spills, leaks, or unexpected liquid or gaseous discharges, to ensure that

an evaluation was performed to determine the type and amount of radioactive

material that was discharged, assess whether sufficient radiological surveys were

performed to evaluate the extent of the contamination and the radiological source

term and verify that a survey/evaluation had been performed to include consideration

of hard-to-detect radionuclides.

The inspectors reviewed whether the licensee completed offsite notifications

(State, local, and if appropriate, the NRC), as provided in its GPI implementing

procedures.

28 Enclosure

The inspectors reviewed the evaluation of discharges from onsite surface water bodies

(ponds, retention basins, lakes) that contain or potentially contain radioactivity, and the

potential for ground water leakage from these onsite surface water bodies to determine if

licensees are properly accounting for discharges from these surface water bodies as

part of their effluent release reports.

The inspectors assessed whether onsite ground water sample results and a description

of any significant onsite leaks/spills into ground water for each calendar year was

documented in the Annual Radiological Environmental Operating Report for REMP or

the Annual Radiological Effluent Release Report for the RETS. For significant, new

effluent discharge points (such as significant or continuing leakage to ground water that

continues to impact the environment if not remediated), the inspectors determined if the

ODCM was updated to include the new release point.

b. Findings

No findings of significance were identified.

.7 Problem Identification and Resolution (02.07)

a. Inspection Scope

Inspectors evaluated whether problems associated with the effluent monitoring and

control program are being identified by the licensee at an appropriate threshold and are

properly addressed for resolution in the licensee corrective action program. In addition,

they assessed appropriateness of the corrective actions for selected sample of problems

documented by the licensee involving radiation monitoring and exposure controls.

b. Findings

No findings of significance were identified.

This inspection constituted one sample as defined in IP 71124.06-5.

2RS07 Radiological Environmental Monitoring Program and Radioactive Material Control

Program (71124.07)

.1 Inspection Planning (02.01)

a. Inspection Scope

The inspectors reviewed the annual radiological environmental operating reports and the

results of any licensee assessments since the last inspection, to verify that the

Radiological Environmental Monitoring Program (REMP) was implemented in

accordance with the TS and ODCM. This review included report changes to the ODCM

with respect to environmental monitoring, commitments in terms of sampling locations,

monitoring and measurement frequencies, land use census, inter-laboratory comparison

program, and analysis of data.

29 Enclosure

The inspectors reviewed the ODCM to identify locations of environmental monitoring

stations and the FSAR for information regarding the environmental monitoring program

and meteorological monitoring instrumentation.

The inspectors reviewed quality assurance audit results of the program to assist in

choosing inspection smart samples and audits and technical evaluations performed on

the vendor laboratory program.

The inspectors reviewed the annual effluent release report and the 10 CFR Part 61,

Licensing Requirements for Land Disposal of Radioactive Waste, report, to determine if

the licensee is sampling, as appropriate, for the predominant and dose-causing

radionuclides likely to be released in effluents.

b. Findings

No findings of significance were identified.

.2 Site Inspection (02.02)

a. Inspection Scope

The inspectors walked down three of the air sampling stations and five of the

thermoluminescent dosimeter (TLD) monitoring stations to determine whether they are

located as described in the ODCM and to determine the equipment material condition.

Consistent with smart sampling, the air sampling stations were selected based on the

locations with the highest X/Q, D/Q wind sectors, and TLDs were selected based on the

most risk-significant locations (e.g., those that have the highest potential for public dose

impact). For the air samplers and TLDs selected, the inspectors reviewed the calibration

and maintenance records to verify that they demonstrate adequate operability of these

components. Additionally, the review included the calibration and maintenance records

of composite water samplers and evaluation to determine if the licensee has initiated

sampling of other appropriate media upon loss of a required sampling station.

The licensee does not use composite samplers.

The inspectors observed the collection and preparation of two to four environmental

samples from different environmental media (e.g., ground and surface water, milk,

vegetation, sediment, and soil) as available to verify that environmental sampling is

representative of the release pathways as specified in the ODCM and that sampling

techniques are in accordance with procedures.

By direct observation and review of records, the inspectors evaluated the

meteorological instruments to verify they are operable, calibrated, and maintained in

accordance with guidance contained in the FSAR, NRC Regulatory Guide 1.23,

Meteorological Monitoring Programs for Nuclear Power Plants, and licensee

procedures. Also, the inspectors assessed whether the meteorological data readout and

recording instruments in the control room and, if applicable, at the tower were operable.

The inspectors assessed whether missed and or anomalous environmental samples are

identified and reported in the annual environmental monitoring report. They selected

five events that involved a missed sample, inoperable sampler, lost TLD, or anomalous

measurement to verify that the licensee has identified the cause and has implemented

30 Enclosure

corrective actions. The inspectors reviewed the licensees assessment of any positive

sample results (i.e., licensed radioactive material detected above the lower limits of

detections and reviewed the associated radioactive effluent release data that was the

source of the released material.

Inspectors selected three SSCs that involve, or could reasonably involve, licensed

material for which there is a credible mechanism for licensed material to reach ground

water, and evaluated whether the licensee has implemented a sampling and monitoring

program sufficient to detect leakage of these SSCs to ground water.

The inspectors assessed whether records, as required by 10 CFR 50.75(g), of leaks,

spills, and remediation since the previous inspection are retained in a retrievable

manner.

The inspectors reviewed any significant changes made by the licensee to the ODCM

as the result of changes to the land census, long-term meteorological conditions

(3-year average), or modifications to the sampler stations since the last inspection.

They reviewed technical justifications for any changed sampling locations to verify 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.

The inspectors evaluated whether the appropriate detection sensitivities with respect to

TS/ODCM are used for counting samples (i.e., the samples meet the TS/ODCM required

lower limits of detections). The inspectors reviewed the results of the vendors quality

control program, including the inter-laboratory comparison program to verify the

adequacy of the environmental sample analyses vendor laboratory program and verify

inter-laboratory comparison test included the media/nuclide mix was appropriate for the

facility.

b. Findings

No findings of significance were identified.

.3 Identification and Resolution of Problems (02.03)

a. Inspection Scope

The inspectors assessed whether problems associated with the REMP are being

identified by the licensee at an appropriate threshold and are properly addressed for

resolution in the licensees corrective action program. Additionally, they evaluated the

appropriateness of the corrective actions for a selected sample of problems documented

by the licensee that involved the REMP.

b. Findings

No findings of significance were identified.

This inspection constituted one sample as defined in IP 71124.07-05.

31 Enclosure

4. OTHER ACTIVITIES

4OA1 Performance Indicator Verification (71151)

.1 Unplanned Scrams per 7000 Critical Hours

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Scrams per 7000 Critical

Hours Performance Indicator (PI) for the period from the first quarter 2009 through the

fourth quarter 2009. To determine the accuracy of the PI data reported during those

periods, PI definitions and guidance contained in the Nuclear Energy Institute (NEI)

Document 99-02, Regulatory Assessment Performance Indicator Guideline,

Revision 6, were used. The inspectors reviewed the licensees operator narrative logs,

issue reports, event reports and NRC Inspection Reports for the period of first quarter

2009 through fourth quarter 2009 to validate the accuracy of the submittals.

The inspectors also reviewed the licensees issue report database to determine if any

problems had been identified with the PI data collected or transmitted for this indicator

and none were identified. Documents reviewed are listed in the Attachment to this

report.

This inspection constituted one unplanned scrams per 7000 Critical Hours sample as

defined in IP 71151-05.

b. Findings

No findings of significance were identified.

.2 Unplanned Scrams with Complications

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Scrams with

Complications PI for the period from the first quarter 2009 through the fourth

quarter 2009. To determine the accuracy of the PI data reported during those periods,

PI definitions and guidance contained in the NEI Document 99-02,

Regulatory Assessment Performance Indicator Guideline, Revision 6, were used.

The inspectors reviewed the licensees operator narrative logs, issue reports, event

reports and NRC Integrated Inspection Reports for the period of first quarter 2009

through the fourth quarter 2009 to validate the accuracy of the submittals.

The inspectors also reviewed the licensees issue report database to determine if any

problems had been identified with the PI data collected or transmitted for this indicator

and none were identified. Documents reviewed are listed in the Attachment to this

report.

This inspection constituted one unplanned scrams with complications sample as defined

in IP 71151-05.

b. Findings

No findings of significance were identified.

32 Enclosure

.3 Unplanned Transients per 7000 Critical Hours

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Transients per 7000

Critical Hours PI for the period from the first quarter 2009 through the fourth quarter

2009. To determine the accuracy of the PI data reported during those periods,

PI definitions and guidance contained in the NEI Document 99-02,

Regulatory Assessment Performance Indicator Guideline, Revision 6, were used.

The inspectors reviewed the licensees operator narrative logs, issue reports,

maintenance rule records, event reports and NRC Integrated Inspection Reports for the

period of first quarter 2009 through the fourth quarter 2009 to validate the accuracy of

the submittals. The inspectors also reviewed the licensees issue report database to

determine if any problems had been identified with the PI data collected or transmitted

for this indicator and none were identified. Documents reviewed are listed in the

Attachment to this report.

This inspection constituted one unplanned transients per 7000 Critical Hours sample as

defined in IP 71151-05.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems (71152)

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

33 Enclosure

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 Selected Issue Follow-Up Inspection: Review of Licensees Causal Evaluations for

NRC Findings with Cross-Cutting Aspects

a. Inspection Scope

The inspectors chose to follow-up on the licensees analysis and actions implemented to

address two emerging cross-cutting themes. This annual sample was chosen in the first

quarter of 2010 as it provided meaningful input into 2009 end-of-cycle assessment

process. Duane Arnold Energy Center has received multiple findings with cross-cutting

aspects in the areas of Human Performance, Decision Making, and Problem

Identification and Resolution, Corrective Action Program.

b. Observations

The licensee initiated CAP 072908, NRC Finding Cross-Cutting Aspect - H.1.b, and

CAP 072909, NRC Findings with Cross-Cutting Aspects - P.1.c. The inspectors

reviewed these CAPs and the causal evaluations performed for each CAP.

Corrective Action Program 072908 was initially screened by the IST and the

Management Review Committee (MRC) as a level A CAP using the guidance contained

in station procedure PI-AA-204, Condition Identification and Screening Process.

The IST and MRC recommended that an ACE be performed. The inspector reviewed

station procedure LI-AA-200, Regulatory Margin Corrective Action Strategy, and noted

that the procedure stated that Should the NRC issue a finding or violation with a

cross-cutting aspect, the manager who owns the condition report shalltake the

following actions: for the third current cross-cutting finding in an aspect, complete a root

cause evaluation to determine the cause of the cross-cutting aspect, the extent of

34 Enclosure

condition, the extent of cause, the cause for the repetitive findings, and the required

corrective actions including the milestones and due dates.

The inspector questioned members of the MRC as to why CAP 072908 did not follow the

guidance of LI-AA-200, since the CAP identified that DAEC had three findings that all

shared the cross-cutting aspect of H.1(b). Management Review Committee personnel

stated that the guidance contained in PI-AA-204 was used by the MRC to assign an

ACE to CAP 072908. The inspector reviewed the guidance contained in PI-AA-204.

While PI-AA-204 did allow for the MRC to assign an ACE instead of a RCE, certain

criteria were required to be met and documented for justification. Those criteria

included:

• The issue has been previously evaluated or identified as a result of an extent of

condition review under a previous evaluation. The cause is understood and

corrective actions are being implemented.

• The cause, corrective action, and extent of condition are simple and known.

This knowledge may be the result of previous assessments.

After reviewing the guidance in PI-AA-204, and the documentation in CAP 072809,

the inspector noted that CAP 072908 did not document any justification for

non-performance of an RCE as required by PI-AA-204. This was discussed with

members of the MRC, and the station wrote CAP 073088, Need for Clarity of

instructions between CAP Procedures. This CAP documented apparent discrepancies

between station procedures LI-AA-200 and PI-AA-204.

After additional review of CAP 072908, the MRC rescreened the CAP and changed the

required evaluation from an ACE to a RCE. This evaluation was still being performed at

the end of this inspection period.

This review constituted one in-depth problem identification and resolution sample as

defined in IP 71152-05.

c. Findings

No findings of significance were identified.

4OA3 Follow-Up of Events and Notices of Enforcement Discretion (71153)

.1 Both Turbine Bypass Valves Failed Open

a. Inspection Scope

The inspectors reviewed the plants response to both Turbine Bypass Valves

unexpectedly opening from 100 percent power on January 4, 2010. This caused reactor

power to spike to 105 percent and the plant commenced a subsequent fast power

reduction to 68 percent power. Documents reviewed in this inspection are listed in the

Attachment to this report.

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

35 Enclosure

b. Findings

No findings of significance were identified.

.2 (Closed) Licensee Event Report (LER) 05000331/2010-001-00: Emergency Diesel

Generator Start Due to Failed Arrestor in Switchyard

This event, which occurred on January 1, 2010, was initiated by a failed lightning

arrestor on the 161 kilovolt (kV) Vinton line in the DAEC switchyard. This caused an

undervoltage condition which automatically started the A EDG, which did not load onto

its 4160 VAC bus since the bus remained powered from its normal power supply

throughout the transient. The licensee determined the cause of the event to be a lack of

coordination between the EDG automatic start logic and the DAEC switchyard protective

relaying. Corrective actions included replacing the Vinton line lightning arrestors and

planning modifications to EDG start logic which will coordinate start logic and protective

relaying. Documents reviewed as part of this inspection are listed in the Attachment to

this report. This LER is closed.

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

4OA5 Other Activities

.1 (Closed) URI 05000331/2009004-03: Adequacy of the Licensees Critique for the

May 20, 2009, EP Drill

The inspectors reviewed the final drill report from the 2009 ERO Training Drill #2,

the drill scenario, the drill objectives and evaluation criteria, the actual timeline from

the drill, corrective actions resulting from the drill, and the licensees assessment for the

DEP PI. The inspectors reviewed the controllers and evaluators logs and observation

statements along with the Senior Resident Inspectors observations to evaluate the

circumstances and sequence of events to determine if the critique met the requirements

of 10 CFR Part 50, Appendix E, Section IV.F.2.g and 10 CFR 50.47(b)(14).

The inspectors determined a violation of NRC requirements had occurred.

An NRC-Identified NCV was documented in 1EP5 of this report and the unresolved

issue was closed. Documents reviewed are listed in the Attachment to this report.

.2 (Closed) URI 05000331/2009002-01: An Internal Contamination Occurred while

Cleaning RPV Studs and Washers on the Refuel Floor at Duane Arnold

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 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.

Section 2RS01.1 discusses details of this event and also documents that a Green

finding and associated NCV of TS 5.4.1(a) was identified for the failure to establish and

implement a procedure for performing decontamination activities associated with a

potentially significant decontamination activity. This URI is closed.

36 Enclosure

4OA6 Management Meetings

.1 Exit Meeting Summary

On April 6, 2010, 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:

• The results of the Radiological Hazards Assessment and Exposure Control,

Radioactive Gaseous and Liquid Effluent Treatment, Radiological Environmental

Monitoring Program And Radioactive Material Control Program inspection with

the Site Vice President, Mr. C. Costanzo, on January 29, 2010.

• The results of the Crane and Heavy Lift Inspection with the Site Vice President,

Mr. C. Costanzo, on February 5, 2010.

• An Emergency Preparedness URI inspection interim exit was conducted by

phone on February 4, 2010, with Site Vice President, Mr. C. Costanzo.

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

considered proprietary. Proprietary material received during the inspection was returned

to the licensee.

ATTACHMENT: SUPPLEMENTAL INFORMATION

37 Enclosure

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

B. Murrell, Licensing Engineer Analyst

K. Kleinheinz, Engineering Director

B. Kindred, Security Manager

B. Simmons, 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

M. Ogden, Maintenance Manager

M. Heermann, Radwaste Shipper in Training

N. McKenney, General Supervisor Radiation Protection

J. Karrich, ALARA Coordinator

R. Schlueter, ALARA Coordinator

W. Render, Instructor, DAEC Operator Training

L. Swenzkinski, Sr. Licensing Engineer

J. Dvorski, Plant Engineer

M. Lingenfetter, Design Engineering Manager

F. Lucas, Design Engineer

T. Browning, Licensing Engineer

R. Cole, PI Manager

S. Inghram, Engineering Supervisor

K. Furman, Safety Manager

J. Dubois, Program Engineering Manager

R. Harter, O & S Manager

Nuclear Regulatory Commission

K. Feintuch, Project Manager, NRR

K. Riemer, Chief, Reactor Projects Branch 2

B. C. Dickson, Branch Chief, Plant Support Team

1 Attachment

LIST OF ITEMS OPENED, CLOSED AND DISCUSSED

Opened

05000331/2010002-01 NCV Inadequate Evaluations for Crane and Special Lifting

Devices (1R20.1.b(1))05000331/2010002-02 FIN Lift Height Assumptions in Drop Load Analyses Not

Reflected in Rigging Procedures (1R20.1.b(2))05000331/2010002-03 NCV Failure to Conduct an Adequate Critique for the

May 20, 2009, Drill (1EP5)05000331/2010002-04 NCV An Internal Contamination Occurred while Cleaning RPV

Studs and Washers on the Refuel Floor at Duane Arnold

(2RSO1.1)

Closed

05000331/2010002-01 NCV Inadequate Evaluations for Crane and Special Lifting

Devices (1R20.1.b(1))05000331/2010002-02 FIN Lift Height Assumptions in Drop Load Analyses Not

Reflected in Rigging Procedures (1R20.1.b(2))05000331/2010002-03 NCV Failure to Conduct an Adequate Critique for the

May 20, 2009, Drill (1EP5)05000331/2010002-04 NCV An Internal Contamination Occurred while Cleaning RPV

Studs and Washers on the Refuel Floor at Duane Arnold

(2RSO1.1)05000331/2009004-03 URI Adequacy of the Licensees Critique for the May 20, 2009,

EP Drill (1EP5.b2)05000331/2009002-01 URI An Internal Contamination Occurred while Cleaning RPV

Studs and Washers on the Refuel Floor at Duane Arnold

05000331/2010-001 LER Emergency Diesel Generator Start Due to Failed Arrestor in

Switchyard (4OA3.2)

2 Attachment

LIST OF DOCUMENTS REVIEWED

The following is a list of documents reviewed during the inspection. Inclusion on this list does

not imply that the NRC inspectors reviewed the documents in their entirety, but rather, that

selected sections of portions of the documents were evaluated as part of the overall inspection

effort. Inclusion of a document on this list does not imply NRC acceptance of the document or

any part of it, unless this is stated in the body of the inspection report.

Section 1R01

OI 733; Turbine Building HVAC; Revision 22

AOP 904; Extreme Cold Weather (< 0F); Revision 2

NG-270K; Plant Winterization Checklist; Revision 2

OI 442; Circulating Water System; Revision 79

OI 734; Reactor Building HVAC System; Revision 53

AOP-902; Flood; Revision 35

CAP 073778; CAQ-Higher than Normal Water Level Forecast is Greater than AOP 902 of

742 Feet

Section 1R04

ISO-HBD-024-03; Isometric - Water Pumphouse Emergency Service Water; Revision 14

BECH-M146; P&ID [Piping and Instrument diagram] Service Water System Pumphouse;

Revision 82

MECH-M113; P&ID RHR Service Water and Emergency Service Water Systems; Revision 65

OI 454A6; ESW System Control Panel Lineup; Revision 2

OI 454A1; ESW System Electrical Lineup; Revision 3

OI 454A2; A ESW System valve Lineup and Checklist; Revision 10

OI 150A2; RCIC System Valve Lineup and Checklist; Revision 12

OI 150A4; RCIC System Control Panel Lineup; Revision 3

OI 454A4; B ESW System Valve Lineup and Checklist; Revision 11

Section 1R05

AFP-01; Torus Area and North Corner Rooms, Revision 25

AFP 08; Standby Gas Treatment System and MG Set Rooms;

Revision 25

AFP 31; Intake Structure Pump Rooms; Revision 26

AFP 32; Intake Structure Traveling Screen Areas; Revision 27

Fire Plan, Volume 1, Program; Revision 57

ACP 1412.4; Impairments to the Fire Protection Systems; Revision 57

FPIR-09-7320; Fire Protection Impairment Request for Reactor Building 1st Floor - 757

Hourly Fire Watch Surveillance Checklist for February 17, 2010 through February 21, 2010

CAP 073385; CAQ - Inadequacy in Fire Patrols Identified; dated February 23, 2010

CAP 073378; NCAQ Fire Patrol Checklist Initials Omission; dated February 23, 2010

AFP 18; Turbine Building North Turbine Building Ground Floor and Tube Pulling Area;

Revision 28

AFP 19; Turbine Building South Turbine Building Ground Floor and Tube Pulling Area;

Revision 25

3 Attachment

AFP 20; Aux Boiler Room, Emergency Diesel Generator Rooms and Generator Day Tank

Rooms; Revision 29

AFP 03; Reactor Building HPCI, RCIC & Radwaste Tank Rooms; Revision 26

Section 1R07

CAP 061393; NCAQ - Heat Exchanger Leaks Identified During A SBDG STP

CAP 061471; CAQ - B SBDG Jacket Cooling Water Heat Exchanger Leak

CAP 62018; NCAQ - Leak on B EDG Jacket Coolant Heat Exchanger

CAP 066838; CAQ - 1G031 Heat Exchanger Leak

CAP 072204; NCAQ - ESW Leak from B Jacket Cooling Water Heat Exchanger

CAP 072892; NCAQ- Leak of B EDG Heat Exchanger During Maintenance Run

CAP 072819; CAQ - 1E053B1 Inspection Findings

CAP 072842; CAQ - Eddy Current Testing Results on B EDG Heat Exchangers

Maintenance WO 1148982; Perform Eddy Curent Testing on the Diesel Generator Heat

Exchangers

CAP 073076; CAQ - EDG Heat Exchanger ESW Leaks Have Occurred Since Tube Bundle

Replacement

Section 1R11

ACP 110.1; Conduct of Operations; Revision 24

Integrated Plant Operating Procedure 5; Reactor Scram; Revision 53

Emergency Operating Procedure 1; RPV [Reactor Pressure Vessel] Control; Revision 16

DAEC Emergency Action Level Notification Form; NOTE 5; Revision 12

Emergency Plan Implementing Procedure 1.1; Determination of Emergency Action Levels;

Revision 28

Emergency Action Level Matrix - Hot Modes; Revision 7

CAP 073637; NCAQ Security Unavailable for a DEP PI Opportunity in LOR

CAP 073659; NCAQ Attention to Detail Error during LOR Notification Process

Section 1R12

DAEC Corrective Work Order (CWO)/Preventative Work Order (PWO) System Health Report

for System 58.02: Primary Containment Isolation; Period 2009-04

DAEC System Checklist/Health Report for System 58.02: Primary Containment Isolation;

Period 2009-04

PWO 1150330; Inspect and Check Calibration of Temperature Element TE4478A

PWO 1150331; Inspect and Check Calibration of Temperature Element TE4478B

CWO A101838; TIS [Temperature Indicating Switch] 4478 Reading Unexpectedly High. Went

from 134-148 Deg F to 165 Deg F for no apparent reason.

CWO A96383; Channel B1, Group 1 Isolation, Spurious. Suspect TIS4478 is Causing 1/4

Group 1 Isolation

CAP 072457; NCAQ - Unexpected Change in TIS 4478 Ch 1 Temperature Reading to 169 F

CAP 072477; CAQ - Unexpected Half Group 1 Isolation Signal

CAP 072404; NCAQ Main Steam Line Leakage Detection Panels 1C193A-D and 1C194A-D

Switch Corrosion

CAP 071275; CAQ - TIS4477 Channel 1 Turbine Building High Temperature Failed

Channel Check

CAP 071148; CAQ - Technical Specification Reading TIS 4478 Channel 1 High

Out-of-Specification

4 Attachment

CAP 046359; TIS4480 at Limit

CAP 033449; TIS 4480 Channel 1 Temperature is elevated at 174 F

CAP 028527; Setpoint Design Control Incomplete for Installed Equipment

CAP 026795; Received Unexpe3cted B Side Group 1 from TIS-4478 Becoming De-energized

Section 1R13

Work Planning Guideline 1; Work Process Guideline; Revisions 37 and 38

Work Planning Guideline 2; On-Line Risk Management Guideline; Revisions 55 and 56

WM-AA-1000; Work Activity Risk Management Process; Revision 4

OP-AA-102-1003; Guarded Equipment; Revision 1

OP-AA-102-1003 (DAEC); Guarded Equipment (DAEC Specific Information);

Revisions 3, 4, and 5

OP-AA-104-1007; Online Aggregate Risk; Revision 0

Maintenance Risk Evaluations for Work Week 9002; Revisions 0 and 1

DAEC On-line Schedule for Work Week 2

Maintenance Risk Evaluations for Work Week 9005; Revisions 0, 1, and 2

DAEC On-line Schedule for Work Week 5

Maintenance Risk Evaluations for Work Week 9006; Revision 0

DAEC On-line Schedule for Work Week 6

WO A101823; Both BPVs Fail Open/Closed/Open Several Times

OI 920; Drywell Sump System; Revision 40

CAP 072511; CAQ Increase in Unidentified Drywell Leakage Observed after RCIC STP

CAP 072636; CAQ Pipe Support Discrepancies Found

CAP 072925; CAQ 1C94 D-5 Generator Filed Ground In and Clear on Diesel Start

WO 1152941; March 2010 Control Rod Sequence Exchange

Work Week 9013 Weekly PRA Risk Profile

Work Week 9013 Work Activity High Risk Summary

CAP 073959; NCAQ 1G-201B Recirc MG Set Lube Oil Temperatures LOOS

Section 1R15

CAL-M05-027; Emergency Diesel Generator Heat Exchanger Heat Transfer Calculation;

Revision 3

CAP 072842; CAQ - Eddy Current Testing Results on B EDG Heat Exchangers

ANATEC Report FPLE33-DAEC-01; Emergency Diesel Coolers B Train HX-1E053B-1, 2, 3;

dated February 3, 2010

CAP 072636; CAQ - Pipe Support Discrepancies Found

OPR 419; Pipe Support Discrepancies Found; dated January 26, 2010

STP 3.7.7-03; MCPR [Minimum Critical Power Ratio] Limit Verification; Revision 10

CAP 073296; CAQ Structural Bolting Questions raised by NRC Resident in Northwest

Corner Room

M095-067; Seismic Analysis of Air Handling Units; Revision 3

OPR 000422; Structural Bolting Questions raised by NRC Resident in Northwest Corner Room

WO A101823; Both BPVs Fail Open/Closed/Open Several Times

STP 3.7.7-01; Bypass Valve Test; Revision 12

Section 1R18

WO A101823; Both BPVs Fail Open/Closed/Open Several Times

5 Attachment

Section 1R19

STP 3.8.1-06B; B Standby Diesel Generator Operability Test (Fast Start); Revision 9

CAP 072910; NCAQ - Data not Recorded during B EDG Fast Start Surveillance STP 3.8.1-06B

CAP 072926; NCAQ - Question about B SBDG Frequency

STP 3.7.7-01; Bypass Valve Test; Revision 12

STP 3.5.-05; HPCI System Operability Test; Revision 48

CAP 073450; NCAQ Failed to Capture ASME Data During STP 3.5.1-05, Due to Burnt Out bulb

CAP 072066; NCAQ - HPCI STP Alignment

CAP 073433; CAQ MO-2318, HPCI MIN FLOW BYPASS valve failed to meet required ASME

times

CAP 073432; NCAQ HPCI quarterly STP and HPCI System Operability Test- Null Voltage Test

Starts Late

STP 3.1.7-04; SBLC Pump Operability Test and Comprehensive Pump Test; Revision 11

Section 1R20

NG-04-003; NMC Letter to NRC, Clarification of Assumptions Regarding Reactor Building

Crane; dated January 7, 2004

NG-02-1106; NMC Letter to NRC, Single Failure Proof Status of Reactor Building Crane; dated

December 4, 2002

NG-01-1428; NMC Letter to NRC, Clarification of Assumptions Regarding Reactor Building

Crane; dated December 21, 2001

LDR-81-342; Iowa Electric Light and Power Company Letter to NRC, Supplemental Response,

Control of Heavy Loads; dated December 15, 1981

NG-82-2530; Iowa Electric Light and Power Company Letter to NRC, Supplement and

Clarifications to the Report on Control of Heavy Loads; dated December 2, 1982

OE 009533; NRC RIS2005-25, Clarification of NRC Guidelines for Control of Heavy Loads;

dated November 15, 2005

CAP 049731; Use of Intermediate Hoists Not Addressed By Site Heavy Loads Procedures

OE019864; Perform OE Evaluation - NRC RIS-2005-25, Sup 1 Heavy Loads; May 31, 2007

CAP 059560; NCAQ - NEI 08-05 Requires Heavy Loads Actions

NRC Letter; Acceptance for Referencing of Licensing Topical Report EDR-1(P), Revision 3,

Ederer Nuclear Safety-Related Extra Safety and Monitoring (X-SAM) Cranes, Cecil O. Thomas

to C. William Clark Jr., Ederer Corporation; dated August 26, 1983

BECH-MRS-M023A; Technical Specification for Modification to the Reactor Building Crane;

Revision 2

Calculation CAL-M01-273; Reactor Building Crane Girder Check; Revision 2

Calculation 273-17; Effects of Impact of Reactor Feed Pump Motor with Turbine Building Mat

Foundation; Revision 1

Calculation 273-33; Fuel Pool Demineralizer Plugs; Revision 1

Calculation CAL-M09-047; Remote Steam Dryer/Separator Strongback Structural Analysis;

Revision 0

Calculation 273C036; Reactor Vessel Head Strongback Modified to Meet NUREG-0612

Requirements; Revision 0

Procedure ACP 1408.19; Control of Generic Heavy Loads; Revision 20

DWG APED-F13-006 (2); Modification of the Reactor Vessel Head Strongback; Revision 2

Procedure ACP 1203.55; Control of Heavy Loads Analyses, Revision 6

Procedure Reactor Feed Pump 110; Reactor Pressure Vessel Disassembly; Revision 22

-

6 Attachment

CAP 071410; NCAQ-Establish Correct Weight for The Reactor Vessel Head

CAP 072492; NCAQ-ECH-LHR Drawings in MDL are Illegible

CAP 072530; CAQ - Revisit NEI 08-05 Requirements for UFSAR

CAP 072538; NCAQ-Review Reactor Feed Pump 110 and 210 for Heavy Load Restrictions

CAP 072550; CAQ-UFSAR Should Be Enhanced To Clearly Call Out COHL Design Basis Info

CAP 072551; NCAQ-Fuel Pool Demin Area Shield Plugs Need Lift Height Limitations

Proceduralized

CAP 072568; NCAQ-Factor of Safety Less Than 10 in CAL-273-C-036 for DW Head Strbck

TOOL-E189

CAP 072570; NCAQ-Determine the Weight of the Rx Vessel Head Strongback

CAP 072811; NCAQ-FP Motor Maximum Lift Height Not Proceduralized

CAP 072812; NCAQ-CAL-M09-047 Listed Misstated Allowable Tensile as 5.0 Instead of 7.5 ksi

CAP 072838; NCAQ Section C of GMP-MECH-06 May Not Perform an Adequate NDE

CAP 072880; NCAQ CAL-M09-047 Incorrectly Calculates Allowable Shear Stress for

TOOL-E206

CAP 072885; NCAQ CAL-273-C036 Rx Vessel Strongback Calc Does Not Explicitly Evaluate

Hook Pins

CAP 072886; NCAQ Reactor Building Crane Cold Proof Test Continued Compliance Not Met

CAP 072912; CAQ NES calc 2941-130 Incorrectly Calculates Allowable Shear Stress for

TOOL-E195

CAP 072917; NCAQ Seismic Evaluation for Rx Bldg Crane Trolley Rail

CAP 072924; NCAQ Generate A List of Loads That Have Restrictions On Max Lift Heights

Section 1R22

STP 3.8.1-04A; A Standby Diesel Generator Operability Test (Slow Start from Normal Start Air);

Revision 5

Maintenance WO 1148081; TSC/ DAC Standby Diesel Generator Engine

GENERA-C170-01; Caterpillar TSC Standby Diesel Generator Engine Inspections

CAP 071387; NCAQ - TSC Diesel Engine Battery Voltage Reads High

CAP 073074; NCAQ TSC Diesel Field Observation

STP 3.3.6.1-45; HPCI Steam Supply Pressure Low Channel Functional Test; Revision 9

CA 53763; SCAQ - CATPR1 - Revise STPs

CA 53724; NCAQ - Potential Scram Reduction Technique

OTH 6693; Review All Instrument STPs for proper restoration steps that prevent perturbations/

transients

PCR 52764; CAQ - FSA SA# 34037, Configuration Control, AFI, Surveillance Line Up

Deficiencies; dated June 26, 2009

STP 3.5.1-01A; A Core Spray System Operability Test; Revision 4

CAP 073761; CAQ Received Unexpected Alarm 1C03A(C-9) A Core Spray Discharge Line

Hi Pressure

NAP-201; Human Performance; Revision 11

STP 3.4.4-01; Reclassification of Drywell Leakage; Revision 3

STP 3.0.0-01; Instrument Checks; Revision 105

CAP 073872; NCAQ Remove Polyphosphates from STP 3.0.001 INSTRUMENT CHECK

Section 4.0

Adverse Condition Monitoring Plan; Increased Drywell Leakage, Revision 3; dated

March 16, 2010

7 Attachment

Section1EP5

NEP # 2009-0010; 2009 ERO Training Drill #2 Final Report; dated June 24, 2009

2009 ERO Training Drill #2 Information - Scenario, Master Sequence of Events, Drill Objectives;

Drill Conducted May 20, 2009

Controller, Evaluator, and Players Event Logs; dated May 20, 2009

EPIP 1.1; Determination of Emergency Action Levels; Revision 28

EBD-S; EAL Bases Document; System Malfunction Category; Revision 7

CAP 0067417; NCAQ -09TD2 - Appropriateness of Controller Interjection Questioned; dated

May 20, 2009

CAP 072877; Revise Drill Development Process Based on NRC Observation

CAP 067460; NCAQ-09TD2 - WR Yarway Indication in the Simulator Related to MIL and ED

Decision

CAP 068506; CAQ - 09TD2 - Evaluate Impact of May 20, 2009 ERO Training Drill Controller

Interject

CE 007464; NCAQ -09TD2 - Appropriateness of Controller Interjection Questioned; dated

May 28, 2009

CE 007572; CAQ - 09TD2 - Evaluate Impact of May 20, 2009 ERO Training Drill Controller

Interject; dated July 23, 2009

Section 1EP6

CAP 072710; NCAQ - Evaluate Potential Delta between reported Reactor Pressure Vessel

Level Water Level for General Emergency and Drill

CAP 072673; CAQ 10TD1 - Note 05 Error in Block 7 at Emergency Operation Facility

CAP 072681; NCAQ 10TD1 - How to Correct Note 5 Information

CAP 072715; NCAQ 10TD1 - Revised Note 05 for Block 7 Missing Date in Message Initiated

Box

CAP 072692; NCAQ 10TD1 - Invoking 10 CFR 50.54x for Security Related Matters Remains

Unclear

2010 Emergency Response Organization Training Drill 1 Final Report; January 27, 2010

Emergency Department Preparedness Manual EPDM 1010; EP PIs; Revision 13

Section 2RS01

ACE 001923; Nasal Contamination Received While Cleaning of Reactor Pressure Vessel Bolts;

April 9, 2009

CAP 065072; CAQ Refuel Floor GE Worker Receives Unanticipated Dose Alarm

CAP 065156; NCAQ Issues Found with Administrative Control of LHRA

Section 2RS06

5059SCRN025543; 50.59 Screening for PCP 8.2 per PWR 40948, Kaman Operating

Procedures; January 23, 2008

CA 050729; Corrective Action-Rad Monitor Sensor Checks Not Done for Kaman 2;

September 25, 2008

CAP 059407; CAQ Condition Adverse to Quality-Increased Inventory Los Rate from the

Condensate Storage Tanks; August 8, 2008

CAP 063486; CAQ Liquid Effluent LCO

8 Attachment

CE 006979; Condition Adverse to Quality-Loss of Off-Site Dose Assessment Manual

Continuous Sampling for Particulate and Iodine (K-12); January 27, 2009

ORTH028262; Determine If Air Sampling Equipment is the Best Tool for the Job; April 28, 2008

ORTH038870; Kaman Noble Gas Conversion Factor Conservatively High; May 26, 2009

ORTH041066; Locate the Calculation Used to Demonstrate Isokinetic Sampling;

August 31, 2009

PCP 10.4; Accumulation of Offsite Effluent Dose Calculational Data; Revision 1

PCR053259; Procedure Change Request-No Longer Able to Obtain REMP Sample;

September 8, 2009

REC 07-001-C; Radiological Engineering Calculation-Demonstration of the Effect of RFO-20

Radiation Workers on Site Sewage Treatment Plant Effluent tritium Concentrations;

October 22, 2007

REC 08-001-R; Radiological Engineering Calculation-10CFR61 Compliance Data Technical

Basis for Reactor Water Clean-up Resin; May 1, 2008

STP NS790206; Surveillance Test Procedure Quarterly Off-Gas Stack Flow Monitor Calibration;

November 19, 2008

STP NS790207; Surveillance Test Procedure 18 Month Off-Gas Stack Flow Monitor Calibration;

November 19, 2008

STP NS790302; Surveillance Test Procedure Liquid Process Rad Monitor Inoperable Sampling

and Analysis; January 6, 2010

STP NS790505; Surveillance Test Procedure Effluent Nobel Gas Sampling and Analysis;

January 4, 2010

STP NS790601; Surveillance Test Procedure Effluent Particulate and Iodine Sampling

Procedure Analysis; January 10, 2010

STP NS790708; Surveillance Test Procedure Monthly Off Site Dose Calculation;

January 2, 2010

STP NS791014; Surveillance Test Procedure Quarterly Turbine Building Flow Monitor

Calibration; October 20, 2009

STP NS791015; Surveillance Test Procedure 18 Month Turbine Building Flow Monitor

Calibration; October 20, 2009

STP NS791016; Surveillance Test Procedure Kaman Monitor; October 20, 2009

2007 Annual Radioactive Material Release Report; April 24, 2008

2008 Annual Radioactive Material Release Report; April 27, 2009

Duane Arnold Energy Company Operations Log Book- Limiting Conditions for Operation;

January 2009 to January 2010

Section 2RS07

Material Control Program

ACP 1411.356; DAEC Ground Water Protection Program; Revision 1

DAEC-SC-PD-13; Meteorological System Equipment; Revision 0

ESP 1.0; Radiological Environmental Monitoring Quality Control Program; Revision 9

ESP 4.3.1.1; Airborne Particulate and Iodine sampling; Revision 27

ESP 4.3.1.2; Ambient Radiation Sampling; Revision 15

EAP 4.3.1.3; Surface Water Sampling; Revision 17

ESP 4.3.1.5A Sampling Site Monitoring Wells; Revision 2

ESP 4.4; Land Use Census; Revision 9

EV-AA-100; FPL Nuclear fleet Ground Water Protection Program; Revision 0

Off Site Dose Assessment Manual - Gaseous and Liquid Effluents; Revision 26

9 Attachment

2008 Annual Radiological Environmental Operating Report; February 5, 2009

REC 09-001-C; Radiological Engineering Calculation-Public Dose Due to the Washout of

Tritium during Rain Events; August 1, 2009

Section 4OA1

DAEC PI Report for Unplanned Scrams per 7000 Critical Hours for January 2009 through

December 2009

DAEC PI Report for Unplanned Scrams with Complications for January 2009 through

December 2009

DAEC PI Report for Unplanned Power Changes per 7000 Critical Hours for January 2009

through December 2009

NEI 99-02; Regulatory Assessment Performance Indicator Guideline; Revision 6

Section 4OA2

CAP 072908; CAQ - NRC Finding Cross-Cutting Aspect - H.1.b

CAP 071962; CAQ - NRC Cross-Cutting Aspects

RCE 001035; Root Cause Analysis of the Events Contributing to the NRC Mid-Cycle Review,

DAEC Cross-Cutting Finding in the area of Human Performance

RCE 001084; Root Cause Analysis of Negative Trend in NRC PI&R Cross-Cutting Aspect P.1.c

CAP 072909; CAQ - NRC Findings with Cross-Cutting Aspects - P.1.c

CAP 067166; CAQ - Trend Identified in PI&R Cross-Cutting Area

CAP 037726; NRC Cross-Cutting Finding - HU

CAP 073088; NCAQ - Need for Clarity of Instructions between CAP Procedures

PI-AA-204; Condition Identification and Screening Process; Revision 5

PI-AA-205; Condition Evaluation and Corrective Action; Revision 3

LI-AA-203; Regulatory Issue Management; Revision 1

LI-AA-200; Regulatory Margin Corrective Action Strategy; Revision 2

LI-AA-200-1000-10000; FPL Fleet Licensing Performance Indicators; Revision 01

CCEM; Common Cause Evaluation Manual; Revision 3

ACEM; Apparent Cause Evaluation Manual; Revision 13

RCEM; Root Cause Evaluation Manual; Revision 18

CAP 073796; NCAQ RCE 1088 Data Review Identified Inadequate Correct Action for ACE 1983

CAP 073793; NCAQ RCE 1088 Data Review Identified RCE 1071 Poor Corrective Action

Closure Quality

Section 4OA3

AOP 646; Loss of Feedwater Heating; Revision 19

AOP 255.2; Power/Reactivity Abnormal Change; Revision 34

AOP 262 Loss of Reactor Pressure Control; Revision 4

CAP 072125; SCAQ - Both Turbine Bypass Valves Failed Open

LER 2010-001-00; Emergency Diesel Generator Start due to Failed Arrester in Switchyard;

dated March 2, 2010

10 Attachment

LIST OF ACRONYMS USED

ACE Apparent Cause Evaluation

ADAMS Agencywide Documents Access and Management System

AFP Area Fire Plan

ALARA As-Low-As-Is-Reasonably-Achievable

ALI Annual Level of Intake

ANSI American National Standards Institute

AOP Abnormal Operating Procedure

ASME American Society of Mechanical Engineers

CAP Corrective Action Program

CE Condition Evaluation

CFR Code of Federal Regulations

CRS Control Room/Simulator

CWO Corrective Work Order

DAEC Duane Arnold Energy Center

DEP Drill and Exercise Performance

DRP Division of Reactor Projects

EAL Emergency Action Level

EDG Emergency Diesel Generator

EOF Emergency Operations Facility

ERO Emergency Response Organization

ESB Electronic Status Board

ESW Emergency Service Water

FSAR Final Safety Analysis Report

GE General Emergency

GL Generic Letter

GPI Groundwater Protection Initiative

HEPA High Efficiency Particulate Air

HPCI High Pressure Coolant Injection

HPT Health Physics Technologist

HVAC Heating, Ventilation and Air Conditioning

IMC Inspection Manual Chapter

IP Inspection Procedure

JIC Joint Information Center

IST Initial Screening Team

LER Licensee Event Report

LLC Limited Liability Corporation

LPCI Low Pressure Core Injection

MG Motor-Generator

MRC Management Review Committee

NCV Non-Cited Violation

NEI Nuclear Energy Institute

NRC U.S. Nuclear Regulatory Commission

NRR Office of Nuclear Reactor Regulations

OBE Operating Basic Earthquake

ODCM Offsite Dose Calculation Manual

OI Operating Instruction

OOS Out-of-Service

OpESS Operating Experience Smart Sample

OPR Operability Evaluation

11 Attachment

OSC Operations Support Center

P&ID Piping and Instrumentation Diagrams

PARS Publicly Available Records

PI Performance Indicator

PI&R Problem Identification and Resolution

PWO Preventative Work Order

RCE Root Cause Evaluation

RCIC Reactor Core Isolation Cooling

RCS Reactor Coolant System

REMP Radiological Environmental Monitoring Program

RETS Radiological Effluent Technical Specification

RHR Residual Heat Removal

RPV Reactor Pressure Vessel

SBDG Standby Diesel Generator

SBLC Standby Liquid Control

SDC Shutdown Cooling

SDP Significance Determination Process

SRA Senior Reactor Analyst

SSC Structures, Systems, and Components

TBV Turbine Bypass Valve

TI Temporary Instruction

TLD Thermoluminescent Dosimeters

TS Technical Specification

TSC Technical Support Center

UFSAR Updated Final Safety Analysis Report

URI Unresolved Item

UT Ultrasonic Testing

WO Work Order 12 Attachment

C. Costanzo -2-

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 05000331/2010002

w/Attachment: Supplemental Information

cc w/encl: Distribution via ListServe

DOCUMENT NAME: G:\1-SECY\1-WORK IN PROGRESS\DUA 2010-002.DOC

G Publicly Available G Non-Publicly Available G Sensitive G Non-Sensitive

To receive a copy of this document, indicate in the concurrence box "C" = Copy without attach/encl "E" = Copy with attach/encl "N" = No copy

OFFICE RIII E RIII RIII RIII

NAME KRiemer:cs SOrth (Section 2RS01)

DATE 05/14/10 05/12/10

OFFICIAL RECORD COPY

Letter to C. Costanzo from K. Riemer dated May 14, 2010

SUBJECT: DUANE ARNOLD ENERGY CENTER INTEGRATED INSPECTION REPORT

05000331/2010002

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