IR 05000315/2014003

IR 05000315-14-003; 05000316-14-003, on 04/01/2014 - 06/30/2014; Donald C. Cook Nuclear Power Plant, Units 1 and 2; Operability Determinations and Functional Assessments; Plant Modifications

ML14224A383
Person / Time
Site:	Cook
Issue date:	08/11/2014
From:	Kenneth Riemer NRC/RGN-III/DRP/B2
To:	Weber L Indiana Michigan Power Co
References
IR-14-003
Download: ML14224A383 (47)

Text

UNITED STATES ust 11, 2014

SUBJECT:

DONALD C. COOK NUCLEAR POWER PLANT, UNITS 1 AND 2 NRC INTEGRATED INSPECTION REPORT 05000315/2014003; 05000316/2014003

Dear Mr. Weber:

On June 30, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Donald C. Cook Nuclear Power Plant, Units 1 and 2. The enclosed report documents the results of this inspection, which were discussed on July 8, with Mr. J. Gebbie, and other members of your staff.

Based on the results of this inspection, three NRC-identified findings of very low safety significance were identified. Two findings involved violations of NRC requirements. One of these violations was determined to be Severity Level IV under the traditional enforcement process. However, because of the very low safety significance, and because the issue was entered into your corrective action program, the NRC is treating the issues as non-cited violations (NCVs) in accordance with Section 2.3.2 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 Donald C. Cook Nuclear Power Plant.

If you disagree with the cross-cutting aspect assigned to any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region III, and the NRC Resident Inspector at the Donald C. Cook Nuclear Power Plant. In accordance with Title 10 of the Code of Federal Regulation 2.390, Public Inspections, Exemptions, Requests for Withholding, of the NRC's "Rules of Practice," a copy of this letter and its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records System (PARS)

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

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

Sincerely,

/RA/

Kenneth Riemer, Chief Branch 2 Division of Reactor Projects Docket Nos. 50-315; 50-316 License Nos. DPR-58; DPR-74

Enclosure:

IR 05000315/2014003; 05000316/2014003 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 05000315; 05000316 License Nos: DPR-58; DPR-74 Report No: 05000315/2014003; 05000316/2014003 Licensee: Indiana Michigan Power Company Facility: Donald C. Cook Nuclear Power Plant, Units 1 and 2 Location: Bridgman, MI Dates: April 1 through June 30, 2014 Inspectors: J. Ellegood, Senior Resident Inspector T. Taylor, Resident Inspector J. Mancuso, Reactor Engineer M. Mitchell, Health Physicist R. Jickling, Senior Emergency Preparedness Inspector A. Schwab, Reactor Engineer Approved by: Kenneth Riemer, Chief Branch 2 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

Inspection Report 05000315/2014003; 05000316/2014003, 04/01/2014 - 06/30/2014;

Donald C. Cook Nuclear Power Plant, Units 1 and 2; Operability Determinations and Functional Assessments; Plant Modifications.

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. Two of the findings were considered non-cited violations (NCVs) of NRC regulations. The significance of inspection findings is indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) and determined using Inspection Manual Chapter (IMC) 0609, Significance Determination Process dated June 2, 2011. Cross-cutting aspects are determined using IMC 0310, Aspects Within the Cross-Cutting Areas effective date January 1, 2014. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy dated July 9, 2013. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process Revision 5, dated February 2014.

Cornerstone: Mitigating Systems

Green.

The inspectors identified a finding of very low safety significance with an associated non-citied violation of 10 CFR 50, Appendix B, Criterion XV, Nonconforming Materials, Parts, or Components, for the failure to prevent nonconforming parts from being used on the emergency diesel generators (EDGs). In 2006, the licensee changed the material used to manufacture delivery valve holders to address cracking of the component. However, the licensee failed to ensure all delivery valve holders were replaced. In 2009 and in 2013, the licensee identified installed delivery valve holders made from the susceptible material. In addition, the licensee determined in 2013 that a manufacturing defect impacted a lot of delivery valve holders. The licensee failed to control the non-conforming components and installed one in an EDG. In both cases, although the licensee found the discrepant parts, the site failed to explore broader programmatic issues with nonconforming material control or shortfalls in the root cause evaluation done to address previous issues with cracking. As corrective actions, the licensee has since replaced all suspect pumps and generated action requests to assess programmatic issues with nonconforming material control.

The inspectors determined the finding to be more-than-minor because it adversely affected the Design Control attribute of the Mitigating Systems cornerstone. Specifically, allowing nonconforming parts to be installed on safety-related equipment without proper controls or review adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The issue screened as Green, or very low safety significance, utilizing IMC 0609 Attachment 4, Initial Characterization of Findings.

Specifically, per Exhibit 2, the finding was determined to be a deficiency affecting the design or qualification of a mitigating system, structure or component where operability was maintained. The inspectors determined the finding had an associated cross-cutting aspect in the area of Problem Identification and Resolution. Specifically, programmatic issues associated with material control were not identified for resolution by the corrective action program (CAP) (P.1). (Section 1R15)

Green.

The inspectors identified a finding of very low safety significance associated with the licensees failure to design the annunciator and plant process computer (PPC)systems in accordance with design specifications. Specifically, the licensee failed to design the systems to preclude loss of the system on a single active failure. In part, this issue would result in loss of the annunciator and PPC systems following a loss of offsite power. The licensee recognized a weakness during a loss of power (LOP)/loss-of-coolant accident (LOCA) testing when the annunciator system failed about 15 minutes into the test. Although the licensee corrected the condition related to rack fans, the inspectors identified a similar issue associated with the server rooms. The annunciator and PPC systems do not have regulatory requirements; therefore this finding did not include a violation. The licensee has modified the ventilation system to provide cooling and assure operation following a loss of offsite power.

The inspectors determined that failure to design and install the annunciator system in accordance with the design description of the applicable Engineering Calculation (EC) was a performance deficiency that warranted a significance evaluation. Using IMC 0612, Appendix B, issue screening, the inspectors determined the finding was more than minor because it is associated with mitigating system cornerstone objective of ensuring the availability and reliability of systems that respond to initiating events and is related to the human performance attribute, post event. Specifically, the annunciator and PPC systems aid human performance by alerting operators to degrading plant and equipment conditions. Using IMC 0609, Significance determination process for at power findings, the inspectors determined that the condition would result in loss of the annunciator and PPC function during some accident scenarios. Therefore the inspectors determined a detailed risk analysis was needed and forwarded the issue to the Region III Senior Reactor Analyst (SRA). The Region III SRA performed a detailed risk evaluation for the finding. To perform the risk evaluation, the SRA determined that the reliability of some operator actions modeled in the NRCs Standardized Plant Analysis Risk (SPAR) model for Donald C. Cook would be negatively impacted if annunciators were not available to cue operators to take action. The delta core damage frequency calculated was 5.5E-7/yr, which represents a finding of very low safety significance (Green). The SRA determined delta large early release frequency was minor as well. Because the licensee failed to identify the extent of condition, the inspectors concluded that the finding included cross-cutting aspect, PI.2 Evaluation, in the area of problem identification and resolution. (Section 1R18)

• Severity Level IV. The inspectors identified a Severity Level IV non-citied violation of 10 CFR 50.72, Immediate Notification Requirements for Operating Nuclear Reactors, for the licensees failure to make required event notifications within the specified time following the discovery of a condition which required an event report. Specifically, a member of the public informed the Berrien County Dispatcher about a sounding siren.

The dispatcher notified the site; however, the license failed to notify the NRC. Because of the age of this issue; the licensee did not make a late report. Since 2012, the licensee has conducted training regarding notifications for alarming sirens.

The inspectors determined that the licensees failure to submit an event notification within the required time was a violation of 10 CFR 50.72(b)(2)(xi). Since the failure to submit a required event report may impact the NRCs ability to regulate, the violation was evaluated using Section 2.2.4 of the NRCs Enforcement Policy. Per the enforcement policy, this violation was of Severity Level IV. The inspectors concluded the reactor oversight process aspects of the finding were minor; therefore there is no cross-cutting aspect. (Section 1R15)

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at or near 100 percent power for the entire inspection period.

Unit 2 operated at or near 100 percent power for the entire inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Readiness of Offsite and Alternate AC Power Systems

a. Inspection Scope

The inspectors verified that plant features and procedures for operation and continued availability of offsite and alternate alternating current (AC) power systems during adverse weather were appropriate. The inspectors reviewed the licensees procedures affecting these areas and the communications protocols between the transmission system operator (TSO) and the plant to verify that the appropriate information was being exchanged when issues arose that could impact the offsite power system. Examples of aspects considered in the inspectors review included:

• coordination between the TSO and the plant during off-normal or emergency events;

• explanations for the events;

• estimates of when the offsite power system would be returned to a normal state; and

• notifications from the TSO to the plant when the offsite power system was returned to normal.

The inspectors also verified that plant procedures addressed measures to monitor and maintain availability and reliability of both the offsite AC power system and the onsite alternate AC power system prior to or during adverse weather conditions. Specifically, the inspectors verified that the procedures addressed the following:

• actions to be taken when notified by the TSO that the post-trip voltage of the offsite power system at the plant would not be acceptable to assure the continued operation of the safety-related loads without transferring to the onsite power supply;

• compensatory actions identified to be performed if it would not be possible to predict the post-trip voltage at the plant for the current grid conditions;

• re-assessment of plant risk based on maintenance activities which could affect grid reliability, or the ability of the transmission system to provide offsite power; and

• communications between the plant and the TSO when changes at the plant could impact the transmission system, or when the capability of the transmission system to provide adequate offsite power was challenged.

Documents reviewed are listed in the Attachment to this report. The inspectors also reviewed CAP items to verify that the licensee was identifying adverse weather issues at an appropriate threshold and entering them into their CAP in accordance with station corrective action procedures.

This inspection constituted one readiness of offsite and alternate AC power systems sample as defined in Inspection Procedure (IP) 71111.01-05.

b. Findings

No findings were identified.

.2 Readiness for Impending Adverse Weather Condition - Thunderstorms

a. Inspection Scope

The inspectors reviewed the licensees lightning protection system prior to the onset of summer. During the summer, the site experiences numerous electrical storms that have the potential to adversely impact plant equipment. The inspectors performed a visual inspection of installed lightning protection equipment and reviewed the plants lightning protection design. Additionally, the inspectors reviewed the Updated Final Safety Analysis Report (UFSAR) and performance requirements for lightning protection. The inspectors also reviewed a sample of CAP items to verify that the licensee identified adverse weather issues at an appropriate threshold and disposed them through the CAP in accordance with station corrective action procedures. Documents reviewed 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 were identified.

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

• Unit 2 west residual heat removal; and

• Unit 1 CD EDG.

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, Technical Specification (TS) requirements, outstanding work orders (WOs), condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also walked down accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the CAP with the appropriate significance characterization. Documents reviewed are listed in the to this report.

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

b. Findings

No findings were identified.

.2 Semiannual Complete System Walkdown

a. Inspection Scope

On May 5, 2014, the inspectors finished a complete system alignment inspection of the Unit 1 component cooling water system to verify the functional capability of the system.

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

These activities constituted one complete system walkdown sample as defined in IP 71111.04-05.

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Routine Resident Inspector Tours

a. Inspection Scope

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

• Unit 1 east and west ESW pump rooms (Fire Zones 29A, 29B, 29E, and 29G);

• Unit 2 east and west ESW (Fire Zones 29C, 29D, 29F, and 29G);

• Unit 1 AB DG room (Fire Zone 16); and

• Unit 1 CD DG room (Fire Zone 15).

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

Using the documents listed in the Attachment to this report, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensees CAP.

Documents reviewed are listed in the Attachment to this report.

These activities constituted four quarterly fire protection inspection samples as defined in IP 71111.05-05.

b. Findings

No findings were identified.

.2 Annual Fire Protection Drill Observation

a. Inspection Scope

On May 16, 2014, the inspectors observed fire brigade training at an offsite fire training facility. The training included drills in search-and-rescue and firefighting in a training building using live fire. Based on this observation, the inspectors evaluated the readiness of the plant fire brigade to fight fires. The inspectors verified that the licensee staff identified deficiencies; openly discussed them in a self-critical manner at the drill debrief, and took appropriate corrective actions. Specific attributes evaluated were:

• proper wearing of turnout gear and self-contained breathing apparatus;

• proper use and layout of fire hoses;

• employment of appropriate firefighting techniques;

• sufficient firefighting equipment brought to the scene;

• effectiveness of fire brigade leader communications, command, and control;

• search for victims and propagation of the fire into other plant areas;

• smoke removal operations;

• utilization of pre-planned strategies;

• adherence to the pre-planned drill scenario; and

• drill objectives.

Documents reviewed are listed in the Attachment to this report.

The activity listed does not constitute a full inspection sample. Observation of an in-plant drill by the inspectors will be performed in a subsequent quarter to ensure all of the requirements of the IP 71111.05 are covered.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review of Licensed Operator Requalification

a. Inspection Scope

On May 20, 2014, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification training 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 simulator sample as defined in IP 71111.11

b. Findings

No findings were identified.

.2 Resident Inspector Quarterly Observation of Heightened Activity or Risk

a. Inspection Scope

On June 12, 2014, the inspectors observed the post-maintenance testing of the Unit 2 AB EDG following a planned critical maintenance period. This sample was performed in conjunction with the associated post-maintenance testing sample under IP 71111.19, per the guidance under IP 71111.11Q. This was an activity that required heightened awareness or was related to increased risk. The inspectors evaluated the following areas both in the field and in the control room during portions of the testing:

• 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 (if applicable);

• correct use and implementation of procedures;

• control board (or equipment) manipulations;

• oversight and direction from supervisors; and

• ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications (if applicable).

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

This inspection constituted one quarterly licensed operator heightened activity/risk sample as defined in IP 71111.11.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

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

• Unit 1 and Unit 2 ice condenser system; and

• EDGs.

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 were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

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

• Unit 2 Turbine Driven Auxiliary Feedwater (TDAFW) pump and valve maintenance period with turbine valve testing, week of April 28, 2014; and

• Unit 2 AB EDG maintenance, week of June 9, 2014.

These activities were selected based on their potential risk significance relative to the Reactor Safety Cornerstones. As applicable for each activity, the inspectors verified that risk assessments were performed as required by 10 CFR 50.65(a)(4) and were accurate and complete. When emergent work was performed, the inspectors verified that the plant risk was promptly reassessed and managed. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed TS requirements and walked down portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met.

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

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

b. Findings

No findings were identified.

1R15 Operability Determinations and Functional Assessments

a. Inspection Scope

The inspectors reviewed the following issues:

• Leakage from Unit 2 accumulator #4;

• Unit 1 TDAFW with water in the bearing oil;

• Unit 2 loop resistance temperature detectors;

• Cracking of EDG delivery valve holders;

• Potential leakage from Unit 2 north control room heating, ventilation and air conditioning system;

• Unit 2 TDAFW with room coolers inoperable

• Unit 1 reactor coolant pump seal; and

• Unit 2 CD EDG chemical deposits.

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 to this report.

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

b. Findings

(1)

Introduction:

The inspectors identified a finding of very low safety significance (Green)with an associated NCV of 10 CFR 50, Appendix B, Criterion XV, Nonconforming Materials, Parts, or Components, for the failure to prevent nonconforming parts from being used on the EDGs. Specifically, the licensee failed to replace an installed delivery valve holder manufactured with material susceptible to cracking. In another instance, the licensee installed a part from a suspect manufacturing lot on another EDG without the necessary controls or reviews being performed.

Description:

The inspectors reviewed an apparent cause evaluation associated with a cracked delivery valve holder which caused fuel leakage during an EDG test run in January 2013. The delivery valve holders are part of the fuel injection pumps associated with each cylinder of the EDGs. Since 2005, there have been two different cracking phenomena that have affected the delivery valve holders at Cook. In 2005, a delivery valve holder cracked and leaked in the area where the fuel line connects to the pump.

An apparent cause evaluation, which included a failure analysis by an outside firm, determined that the failure was caused by the use of American National Standards Institute 1141 and 1144 material which was prone to cracking under the conditions experienced by the delivery valve holders. Based on the results of the failure analysis, the licensee concluded that the material, combined with an out of tolerance dimension inside the delivery valve holder, caused the delivery valve holder failure. Per the recommendation of the engineering firm who did the failure analysis, the licensee changed the material specification and took action to replace all of the delivery valve holders on the EDGs. However, after all the replacements were thought to be complete, in June 2009 another delivery valve holder developed a crack and leaked. The licensee determined the failed delivery valve holder was manufactured from the susceptible material and had not been replaced. The licensee performed a root cause analysis and put measures in place to ensure proper material was received from the manufacturer in the future.

In January 2013, a delivery valve holder developed a crack and leaked on the 1CD EDG during a test run. Forensic analysis by outside experts revealed a circumferential crack around the main body of the delivery valve holder. This was a different orientation and location than the previous cracking which had been seen in the industry due to the American National Standards Institute 1141 and 1144 material issues. Failure analysis determined that the cracking was due to a corner inside the delivery valve holder that was machined with too sharp a radius, which created a region of higher stress during operation that allowed a crack to start and propagate. The vendor believed the problem occurred due to a tooling issue with a particular lot of delivery valve holders.

Additionally, the radius had not been included as a critical characteristic and had not received 100 percent inspection during manufacture. Pumps from the suspect lot were identified on the EDGs and scheduled for replacement. One pump was located in stock; however, it was not shipped back to the vendor. Some licensee staff decided to keep it; for use in an emergent situation, with the belief that if it were to be used, there would be an assessment of its suitability and formal approval first. However, no controls were placed on the delivery valve holder identifying it as nonconforming. This part was later installed through normal maintenance processes without special review on one of the EDGs during a preventative maintenance period. A month later, licensee personnel identified the condition while continuing to follow up on the new cracking phenomenon and wrote an Action Request (AR). The pump was replaced soon thereafter. During the follow-up to the new form of cracking, the licensee also discovered another pump installed on one of the EDGs made of the old American National Standards Institute 1141/1144 material, which, despite the root cause done in 2009 described above, somehow remained in place approximately four years later. While licensee personnel did identify the issues with the old-material pump and installation of the other pump from the suspect lot, the corrective actions did not delve into several key issues surrounding control of nonconforming parts, nor were new ARs initiated to have the additional issues assessed in the corrective action program. For instance, the licensee did not investigate potential programmatic issues with material control processes. Additionally, no attempt was made to understand why a formal assessment was not done regarding operability when it was discovered a delivery valve holder with old material remained on an EDG (which remained in place over a year until it was replaced). Further, no investigation was performed to understand how, after a root cause was done in 2009, an old-material delivery valve holder could still exist on an EDG. The inspectors discussed the issues with the licensee and determined the finding could be considered NRC-identified per the definitions in IMC 0612, Power Reactor Inspection Reports. The licensee generated additional ARs to address the issues.

Analysis:

The inspectors determined that the failure of the licensee to control safety-related parts which do not conform to requirements, as described in 10 CFR 50 Appendix B, Criterion XV, Nonconforming Materials, Parts, or Components, was a performance deficiency warranting further evaluation in the Significance Determination Process. The issue screened as more-than-minor because it adversely affected the Design Control attribute of the Mitigating Systems cornerstone. Specifically, allowing nonconforming parts to be installed on safety-related equipment without proper controls or review adversely affects the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding screened as Green, or very low safety significance, utilizing IMC 0609 Attachment 4, Initial Characterization of Findings, dated June 19, 2012. Specifically, per Exhibit 2, the finding was determined to be a deficiency affecting the design or qualification of a mitigating system, structure or component where operability was maintained. The inspectors concluded operability was maintained for these instances of a single nonconforming delivery valve holder impacting an EDG based on a review of existing work done by outside consultants for the licensee, which included tests on faulty delivery valve holders that had been removed from service. The inspectors determined the finding had an associated cross-cutting aspect in the area of Problem Identification and Resolution. Specifically, programmatic issues associated with material control were not identified for resolution by the corrective action program (P.1).

Enforcement:

10 CFR 50, Appendix B, Criterion XV, Nonconforming Materials, Parts, or Components, requires, in part, that measures shall be established to control materials, parts, or components which do not conform to requirements in order to prevent their inadvertent use or installation. Contrary to these requirements, subsequent to completion of corrective actions to replace all delivery valve holders with a material not susceptible to cracking on January 27, 2011, the licensee discovered a delivery valve holder still installed with the material prone to cracking on the 2CD EDG during a walkdown on February 4, 2013. After identification, the part remained installed without formal assessment regarding the operability of the EDG until it was replaced on June 4, 2014. Additionally, on September 12, 2013, the licensee installed a delivery valve holder on the 1AB EDG from a known suspect manufacturing lot. The part had not been labeled as nonconforming nor was any assessment done on the acceptability of using a nonconforming part. The part was replaced on November 13, 2013. The licensee replaced the suspect parts and generated ARs 2014-7560 and 2014-7605 to investigate the issues raised by the inspectors. This violation is being treated as a NCV, consistent with Section 2.3.2 of the Enforcement Policy because it was of very low safety significance and was entered into the licensees CAP. (NCV 05000315/2014003-01; 05000316/2014003-01, Failure to Control Nonconforming Delivery Valve Holders on Emergency Diesel Generators).

(2)

Introduction:

The inspectors identified a Severity Level IV NCV of 10 CFR 50.72, Immediate Notification Requirements for Operating Nuclear Reactors, for the licensees failure to make required event notifications within the specified time following the discovery of a condition which required an event report.

Description:

On June 30, 2012, the Berrien County 911 Dispatcher notified the site a member of the public had called regarding activation of an emergency siren. The siren was shut down and disabled pending investigation and repair. At the time, the licensee determined that the event was not reportable. However, NUREG-1022, Revision 2 includes public notification to local government as an example of a required report under 50.72(b)(2)(xi), Notification of other Government Agency. Because of the age of this issue, the licensee did not make a late report. Since 2012, the licensee has conducted training regarding notifications for alarming sirens.

The inspectors also noted weaknesses in plant knowledge regarding other reporting requirements of 10 CFR 50.72. Specifically, on May 25 at 09:35 am licensee personnel were performing a weekly required door function check on Door 2-DR-Aux410A, the back door into the Unit 2 control room. At 09:36 a.m., the door failed to secure properly, bringing into question Control Room Envelope operability. Compensatory actions were put into place and Operations made an Immediate Operability determination, calling the Control Room Envelope inoperable. However, the licensee did not make an Event Notification. In response to the inspectors questions, the licensee later made an Event Notification (Event Notification 50149) at 02:10 p.m. on May 29. Later, on June 20, the licensee issued a retraction for Event Notification 50149 based on a determination that the control room envelope had not been inoperable.

Analysis:

The inspectors determined that the licensees failure to submit an event notification within the required time in each circumstance was a violation of 10 CFR 50.72(b)(2)(xi). Since the failure to submit a required event report may impact the NRCs ability to regulate, the violation was evaluated using Section 2.2.4 of the NRCs Enforcement Policy, Revision 3. In accordance with Section 6.9 of the Enforcement Policy, the failure to make a report required by 10 CFR 50.72 or 10 CFR 50.73 corresponds to a Severity Level IV violation. In accordance with the guidance of IMC 0612, Power Reactor Inspection Reports, Section 07.03, cross-cutting aspects are not assigned to traditional enforcement violations. The inspectors reviewed the condition for reactor oversight process significance. Since a single siren had failed, and the licensee has overlapping siren coverage, the inspectors concluded any performance deficiency that impacted the lone siren would be of minor safety significance.

Enforcement:

10 CFR 50.72(b)(2)(xi) requires, in part, that the licensee notify the NRC as soon as possible and in all cases within four hours in Any event or situation, related to the health and safety of the public or onsite personnel, or protection of the environment, for which a news release is planned or notification to other government agencies has been or will be made. In the case of the Berrien County 911 Dispatcher alerting the licensee to the spurious activation of their siren, such an event is deemed reportable due to the concern of members of the public for their radiological health and safety. Contrary to the above, on June 30, 2012, the licensee failed to notify the NRC within four hours of being contacted by local officials due to public concern over the spurious activation of one of the sites emergency sirens.

As the violation was of very low safety significance and promptly entered into the licensees CAP (AR 2014-7074), there is no on-going violation, and the violation was not repetitive or willful, this Severity Level IV violation is being treated as an NCV, consistent with section of 2.3.2 of the NRC Enforcement Policy. (NCV 05000315/2014002-02; 05000316/2014002-02, Missed Event Notification).

1R18 Plant Modifications

a. Inspection Scope

The inspectors reviewed the following modifications:

• Unit 1 annunciator temporary power supply; In NRC Inspection Report 05000315/316-2014003, the inspectors reviewed the above temporary modification. At the time of the review, the inspectors did not have enough information to determine if deficiencies associated with the temporary modification represented a violation of NRC requirements. Subsequently, the inspectors determined that no violation of NRC requirements occurred; however, the licensee did not meet self-imposed requirements for the above system.

This inspection did not constitute a temporary modification samples as defined in IP 71111.18-05.

b. Findings

Introduction:

The inspectors identified a finding of very low safety significance (GREEN)associated with the licensees failure to design the annunciator and PPC systems in accordance with design specifications. Specifically, the licensee failed to design the systems to preclude loss of the system on a single active failure. In part, this issue would result in loss of the annunciator and PPC systems following a loss of offsite power.

Description:

On October 31, 2013, the licensee completed the replacement modification of the Unit 2 Annunciator System. On November 2, 2013, while in Mode 5, the site began performing Train A Loss of Power (LOP)/ Loss-of-Coolant Accident (LOCA)surveillance testing. As part of the test, control room operators initiated a loss of power to Train A control room power. Unknown to the licensee, this action removed power to the annunciator chassis cooling fans. Fifteen minutes after power loss to the fans, the Unit 2 Control Room received high temperature alarms for the annunciator system and multiple control room annunciator visual display units turned magenta- indicative of a fault. The licensee determined the cooling fans had lost power and the logic cabinet chassis power supplies had shut down on thermal protection. Control room operators opened the logic cabinet doors to allow ambient temperatures to cool the power supplies and to stop the thermal protection shutdown on the remaining power supplies. The annunciators returned once cooling was stabilized and power was restored to the fans.

The reaction of the annunciator system during this surveillance showed that, as installed, the annunciator system would not function during a LOP. On November 07, 2013, the site implemented EC 53257, Alternate AC Feed to Annunciator Logic Cabinet I/O Chassis Fans which modified the power source of the fans from control room power to critical control room power. Critical control room power has a back-up source; therefore, during a LOP, the chassis cooling fans would still have a power source.

As an extent of condition, the licensee recognized Unit 1 control room annunciator system had the same vulnerability. Although the licensee completed Unit 1 annunciator modification on April 23, 2013, the failure didnt materialize during the Unit 1 LOP/ LOCA testing because the fans switched to a different available control room power supply once loss of primary power was initiated its A Train. The licensee modified the fans power source from control room power to critical control room power On March 13 2014, the inspectors performed a walkdown of one of the locations used to house electronics for the annunciator and PPC power supplies. During the walkdown, the inspectors noted that the licensee had installed a temporary cooling system for the room. The inspectors reviewed the temporary modification used to install the system and noted that the temporary modification allowed the cooling units to be powered from any convenient power source. The inspectors asked the licensee about the power to source to determine if the ventilation would remain functional on a LOP. The licensee investigated the power sources and determined that the temporary ventilation was not from a diesel backed source. In addition, to install the equipment in the selected location the licensee had altered the ventilation pattern. This change, coupled with material deficiencies with the ventilation prevented the permanently installed ventilation from removing the heat generated by the electronics. The inspectors and licensee concluded that the poor ventilation would result in overheating of the electronics- and loss of the annunciator/PPC system, on a LOP.

Updated Final Safety Analysis Report Section 7.7.3 Design Bases states, in part, Alarms and Annunciators in the control room provide the operators warning of abnormal plant conditions which might lead to damage of components, fuel or other unsafe conditions. In addition, loss of annunciators also causes the site to enter into their Emergency Action Levels. In MODE 1-4, an unplanned loss of safety system annunciators and/ or indication in the Control Room for greater than 15 minutes is an Unusual Event. The Emergency Action Level classification escalates if there is transient in progress (Alert) or if there is an inability to monitor a significant transient in progress (Site Area Emergency). For these reasons, during the modification process the licensees description of the Replacement Annunciator System was that a loss of a single active component does not cause the loss of the overall annunciator system. As initially designed and installed, upon a LOP ventilation for cabinets and a room housing some of the servers would have been de-energized. Without adequate heat removal, Unit 1 and Unit 2 Annunciator System would have overheated and not functioned. The licensee did not recognize ventilation as a support system to the annunciators during the design process and therefore did not ensure that the Annunciator system was not subjected to failure by a single component.

Analysis:

The inspectors determined that failure to design and install the annunciator system in accordance with the design description of the applicable engineering change was a performance deficiency that warranted a significance evaluation. Specifically, EC 51357 (Unit 1) and EC 51357(Unit 2) MCR Annunciator Replacement Modification state:

(1) Loss of a single active component does not cause the loss of the overall annunciator system;

(2) the replacement annunciator system to exhibit similar functions and appearance as the existing annunciator system; and

(3) adequate instrumentation to provide operators with sufficient information for proper and safe operation of the plant at all times. In addition, EC-51359 and EC 51360, Unit 1 and 2 PPC modifications state the replacement PPC is designed to be functionally consistent with the existing PPC.

Contrary to the above, the annunciator/PPC modifications changed the design such that both would be lost on a loss of offsite power because of lost ventilation and chassis fans.

Using IMC 0612, Appendix B, issue screening, dated September 12, 2012, the inspectors determined the finding was more than minor because it is associated with mitigating system cornerstone objective of ensuring the availability and reliability of systems that respond to initiating events and is related to the human performance attribute, post event. Specifically, the annunciator and PPC systems failure would adversely affect operator performance because these systems aid operators by alerting them to degrading plant and equipment conditions.

The inspectors determined that the finding could be evaluated using the Significance Determination Process (SDP) in accordance with IMC 0609, Significance Determination Process. Using Attachment 0609.04, Initial Characterization of Findings, dated June 19, 2012, Table 2, the inspectors determined that the finding affected the Mitigating Systems cornerstone. As a result, the inspectors evaluated the finding using Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012 Exhibit 2 for the Mitigating Systems Cornerstone. The inspectors determined that the condition would result in loss of the annunciator and PPC function during some accident scenarios. Therefore the inspectors determined a detailed risk analysis was needed and forwarded the issue to the Region III SRA.

The Region III SRA performed a detailed risk evaluation for the finding. The SRA assumed the performance deficiency impacted the annunciator system such that the annunciators would be non-functional shortly after a loss of offsite power event. To perform the risk evaluation, the SRA determined that the reliability of some operator actions modeled in the NRCs SPAR model for D. C. Cook would be negatively impacted if annunciators were not available to cue operators to take action. The SRA reviewed the operator actions in the model and concluded that many actions, such as actions to recover offsite power, actions to align emergency power, and actions to control auxiliary feedwater would either be taken immediately in response to the initiating event or would be procedurally-driven by emergency operating procedures used in responding to those events. For these actions, the SRA determined that operator reliability would not be significantly impacted by the loss of annunciators.

For other modeled actions that are taken in response to equipment failures during response to the initial event, the SRA determined that operator reliability would be impacted if annunciators were not available as a cue for action. After reviewing the SPAR model, the SRA concluded the reliability of the following modeled operator actions could be impacted by a lack of control room annunciators.

• AFW-XHE-XM-ROOMU1, Operator Fails to Open AFW Pump Room Doors Unit 1

• AFW-XHE-XM-ROOMU2, Operator Fails to Open AFW Pump Room Doors Unit 2

• CVC-XHE-XM-CVCSXTIE, Operator Fails to Align CVCS Crosstie to Alternate Unit

• DCP-XHE-XM-DCNBCH, Operator Fails to align Standby Battery Charger (N train only)

The SRAs used a modified version of the Donald C. Cook SPAR model, version 8.23.

Modifications to the model logic were necessary to account for the operation of the chemical volume control system (CVCS) cross-tie as an alternate reactor coolant system inventory makeup source and to properly model the N train battery charger as requiring re-set during an event involving a loss of offsite power or an SI signal since these battery chargers were automatically load shed. The Donald C. Cook SPAR model is an all-hazards model that contains external event initiators such as fire, seismic and high wind events. For the analysis, the SRA used an exposure period of 1 year. The actual exposure period for the finding was less than one year so the result of this evaluation can be considered bounding with respect to the exposure period. Additionally, some of the exposure period included times when the reactor was in a shutdown condition.

These periods were small in comparison to the time the reactor was at-power.

Therefore, the SRA concluded that an at-power analysis for the entire exposure period was appropriate.

The human error probabilities for the operator actions listed above were modified to account for an increased failure probability for diagnosis. For the actions to open the auxiliary feedwater pump room doors, the SRA assumed a failure probability of 1.0, since a room temperature alarm would likely be one of the primary cues to take action. These actions were set to True to represent the inspection finding. For the actions to align the CVCS cross-tie and to align the N Train Battery Charger, the SRA used the NRC SPAR-H Human Reliability Analysis Method to calculate an increased diagnosis human error probability. The performance shaping factor for Ergonomics was evaluated as poor to represent the lack of annunciator cues to assist in diagnosis.

The diagnosis HEP was also assigned a high stress performance shaping factor because the actions would need to be taken under accident conditions involving multiple failures. Additionally, the diagnosis for the N train battery charger action was assumed to involve extra time, which has a positive impact on the overall human error probability.

The human error probability for the CVCS cross-tie was determined to be 2.2E-1 and the HEP for the N train battery charger was determined to be 2.4E-2 using these assumptions.

For the internal event risk contribution the loss of offsite power event trees were solved.

For external events, the SRAs solved only those event trees that could cause a loss of offsite power. These trees included all seismic events, all high wind/tornado events and fire events in the following fire areas:

• FA 2, Unit 1 and 2 Screen House

• FA 40, Unit 1 Engineering Safety Systems and MCC Room (41-T28)

• FA 46, Control Room Back Panel (No evacuation)

• FA 46, MCR Panel 1 propagating to Panel 2

• FA 46, MCR Main Control Board 2

• FA 46, MCR Main Control Board 2 and 3

• FA 46, MCR Main Control Board 8/9

• FA 48, Unit 1 Switchgear Room and Cable Vault (T02)

• FA 79, Unit 1 Turbine Building Northeast

• FA YARD, Transformers in the NW section The delta core damage frequency calculated given these assumptions was 5.5E-7/yr, which represents a finding of very low safety significance (Green). The dominant internal event sequence cut-set involved a loss of offsite power event, failure of reactor coolant pump seal cooling, and the failure to cross-tie the CVCS system for inventory makeup. The dominant external event sequence was similar, involving a fire-induced loss of offsite power, failure of reactor coolant pump seal cooling and the failure to cross-tie the CVCS system.

To evaluate the delta large early release frequency, the SRAs used IMC 0609, Appendix H, Containment Integrity Significance Determination Process.

Donald C. Cook is a pressurized water reactor with an ice condenser containment.

Since the dominant sequences did not involve inter-system loss-of-coolant accidents, steam generator tube rupture, or station blackout, the delta large early release frequency significance was also determined to be of very low safety significance (Green).

The inspectors determined that the associated finding had a cross-cutting aspect of Evaluation in the Problem Identification and Resolution cross-cutting area because the licensee did not thoroughly evaluate problems to ensure that resolutions addressed causes and extent of conditions, commensurate with their safety significance.

Specifically, the licensee failed to address the extent of condition following the November annunciator and PPC system failure which contributed to the systems being susceptible to a single failure for several additional months. [P.2]

Enforcement:

This finding does not involve enforcement action because no regulatory requirement violation was identified. The licensee entered the issue into the CAP as AR 2013-16909, Loss of CR Annunciators during LOP/ LOCA, corrected the design deficiency of the fans, and evaluated their modification process.

(FIN 05000315/2014003-03; 05000316/2014003-03, Deficient Annunciator/PPC Design).

1R19 Post-Maintenance Testing

a. Inspection Scope

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

• West diesel fire pump after maintenance;

• Unit 2 AB EDG after critical maintenance period;

• Replacement of Unit 2 north control room chiller; and

• Unit 2 TDAFW valve refurbishments and steam leak repair.

These activities were selected based upon the structure, system, or component's ability to impact risk. The inspectors evaluated these activities for the following (as applicable):

the effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed; acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate; tests were performed as written in accordance with properly reviewed and approved procedures; equipment was returned to its operational status following testing (temporary modifications or jumpers required for test performance were properly removed after test completion); and test documentation was properly evaluated. The inspectors evaluated the activities against TSs, 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 four post-maintenance testing samples as defined in IP 71111.19-05.

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

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

• 1-IHP-4030-111-001A SSPS Logic (Routine);

• 12-IHP-4030-082-002, AB,CD and N-Train Battery Quarterly Surveillance and Maintenance (routine);

• Unit one flux mapping (routine); and

• Routine testing of the Unit 1 TDAFW pump (IST)

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

• did preconditioning occur;

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

• acceptance criteria were clearly stated, demonstrated operational readiness, and were 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 was 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;

• 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 and one inservice testing sample as defined in IP 71111.22, Sections -02 and -05.

b. Findings

No findings were identified.

1EP2 Alert and Notification System Evaluation

a. Inspection Scope

The inspectors reviewed documents and conducted discussions with Emergency Preparedness (EP) staff and management regarding the operation, maintenance, and periodic testing of the back-up and primary Alert and Notification System (ANS) in Donald C. Cook Nuclear Power Plants plume pathway Emergency Planning Zone. The inspectors reviewed monthly trend reports and the daily and monthly operability records from February 2012 through May 2014. Information gathered during document reviews and interviews was used to determine whether the ANS equipment was maintained and tested in accordance with Emergency Plan commitments and procedures. Documents reviewed are listed in the Attachment to this report.

This ANS inspection constituted one sample as defined in IP 71114.02-06.

b. Findings

No findings were identified.

1EP3 Emergency Response Organization Staffing and Augmentation System

a. Inspection Scope

The inspectors reviewed and discussed with plant EP management and staff the Emergency Plan commitments and procedures that addressed the primary and alternate methods of initiating an Emergency Response Organization (ERO) on-shift and augmentation staffing levels. The inspectors reviewed reports and a sample of CAP records of the 2013 drive-in drill and unannounced off-hour augmentation call-in tests, which were conducted between June 2012 and January 2014, to determine the adequacy of the drill critiques and associated corrective actions. The inspectors also reviewed a sample of the EP training records of approximately 20 ERO personnel, who were assigned to key and support positions, to determine the status of their training as it related to their assigned ERO positions. Documents reviewed are listed in the to this report.

This ERO augmentation testing inspection constituted one sample as defined in IP 71114.03-06.

b. Findings

No findings were identified.

1EP5 Maintenance of Emergency Preparedness

a. Inspection Scope

The inspectors reviewed a sample of Performance Assurance staffs 2012 and 2013 audits of Donald C. Cook Nuclear Power Plant 's EP Program to determine that the independent assessments met the requirements of 10 CFR 50.54(t). The inspectors also reviewed samples of CAP records associated with the 2013 Biennial Exercise, as well as various EP drills conducted in 2013 and 2014, in order to determine whether the licensee fulfilled drill commitments and to evaluate the licensees efforts to identify and resolve identified issues. The inspectors reviewed a sample of EP items and corrective actions related to the facilitys EP Program and activities to determine whether corrective actions were completed in accordance with the sites CAP. Documents reviewed are listed in the Attachment to this report.

This correction of EP weaknesses and deficiencies inspection constituted one sample as defined in IP 71114.05-06.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

a. Inspection Scope

The inspectors evaluated the conduct of a routine licensee emergency drill on May 14, 2014, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the technical support center, simulator and emergency operations 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 to this report.

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

b. Findings

No findings were identified.

2RS6 Radioactive Gaseous and Liquid Effluent Treatment

This inspection constituted one complete sample as defined in IP 71124.06-05.

.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 (ODCM)/TSs. 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 CAP, and were adequately resolved.

The inspectors selected 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 CAP and adequately resolved.

b. Findings

No findings were identified.

Offsite Dose Calculation Manual and Final Safety Analysis Report Review

a. Inspection Scope

The inspectors reviewed UFSAR descriptions of the radioactive effluent monitoring systems, treatment systems, and effluent flow paths so they could be evaluated during inspection walkdowns.

The inspectors reviewed changes to the ODCM made by the licensee since the last inspection against guidance in NUREG-0133, 1301, 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 as-low-as-reasonably-achievable (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 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 were identified.

Groundwater Protection Initiative 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 were identified.

Procedures, Special Reports, and Other Documents

a. Inspection Scope

The inspectors reviewed Licensee 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 inspectors reviewed Effluent Program implementing procedures, particularly those associated with effluent sampling, effluent monitor set-point determinations, and dose calculations.

The inspectors reviewed 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 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 evaluate whether 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.

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 filtered ventilation systems to assess for conditions such as degraded high-efficiency particulate air/charcoal banks, improper alignment, or system installation issues that would impact the performance or the effluent monitoring capability of the effluent system.

As available, the inspectors observed selected portions of the routine processing and discharge of radioactive gaseous effluent (including sample collection and analysis) to evaluate whether 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).

As available, the inspectors observed selected portions of the routine processing and discharging of liquid waste (including sample collection and analysis) to determine if 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 were identified.

.3 Sampling and Analyses (02.03)

a. Inspection Scope

The inspectors selected effluent sampling activities, consistent with smart sampling, and assessed whether adequate controls have been implemented to ensure representative samples were obtained (e.g., provisions for sample line flushing, vessel recirculation, composite samplers, etc.).

The inspectors selected effluent discharges made with inoperable (i.e., declared out-of-service) effluent radiation monitors to assess whether controls were in place to ensure compensatory sampling was performed consistent with the radiological effluent Technical Specifications (RETS)/ODCM and that those controls were adequate to prevent the release of unmonitored liquid and gaseous effluents.

The inspectors determined whether the facility was 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 evaluate the quality of the radioactive effluent sample analyses and assessed whether the Inter-Laboratory Comparison Program includes hard-to-detect isotopes as appropriate.

b. Findings

No findings 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 determine if the flow rates were consistent with RETS/ODCM or UFSAR values, and that differences between assumed and actual stack and vent flow rates did not affect the results of the projected public doses.

b. Findings

No findings were identified.

Air Cleaning Systems

a. Inspection Scope

The inspectors assessed whether surveillance test results since the previous inspection for TS required ventilation effluent discharge systems (high-efficiency particulate air and charcoal filtration), such as the Standby Gas Treatment System and the Containment/Auxiliary Building Ventilation System, met TS acceptance criteria.

b. Findings

No findings 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 five, or increases that approach Appendix I criteria) to evaluate the factors which may have resulted in the change.

The inspectors reviewed radioactive liquid and gaseous waste discharge permits to assess whether the projected doses to members of the public were accurate and based on representative samples of the discharge path.

The 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 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 evaluate whether changes were consistent with the ODCM and Regulatory Guide 1.109. The inspectors reviewed meteorological dispersion and deposition factors used in the ODCM and effluent dose calculations to evaluate whether appropriate factors were being used for public dose calculations.

The inspectors reviewed the latest Land Use Census to assess whether 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 evaluated whether the calculated doses (monthly, quarterly, and annual dose) are within 10 CFR Part 50, Appendix I, and TS dose criteria.

The inspectors reviewed, 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.

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 were identified.

.6 Groundwater Protection Initiative Implementation (02.06)

a. Inspection Scope

The inspectors reviewed monitoring results of the Groundwater Protection Initiative to determine if the licensee implemented its program as intended and to identify any anomalous results. For anomalous results or missed samples, the inspectors assessed whether the licensee identified and addressed deficiencies through its CAP.

The inspectors reviewed identified leakage or spill events and entries made into 10 CFR 50.75

(g) records. The inspectors reviewed evaluations of leaks or spills and reviewed any remediation actions taken for effectiveness. The inspectors reviewed onsite contamination events involving contamination of ground water and assessed whether the source of the leak or spill was identified and mitigated.

For unmonitored spills, leaks, or unexpected liquid or gaseous discharges, the inspectors assessed whether an evaluation was performed to determine the type and amount of radioactive material that was discharged by:

• Assessing whether sufficient radiological surveys were performed to evaluate the extent of the contamination and the radiological source term and assessing whether a survey/evaluation had been performed to include consideration of hard-to-detect radionuclides.

• Determining whether the licensee completed offsite notifications as provided in its Groundwater Protection Initiative implementing procedures.

The inspectors reviewed the evaluation of discharges from onsite surface water bodies that contain, or potentially contain radioactivity, and the potential for ground water leakage from these onsite surface water bodies. The inspectors assessed whether the licensee was 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 were documented in the Annual Radiological Environmental Operating Report for the Radiological Environmental Monitoring Program 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 evaluated whether the ODCM was updated to include the new release point.

b. Findings

No findings were identified.

.7 Problem Identification and Resolution (02.07)

a. Inspection Scope

The inspectors assessed whether problems associated with the Effluent Monitoring and Control Program were being identified by the licensee at an appropriate threshold and were properly addressed for resolution in the licensees CAP. In addition, they evaluated the appropriateness of the corrective actions for a selected sample of problems documented by the licensee involving radiation monitoring and exposure controls.

b. Findings

No findings were identified.

OTHER ACTIVITIES

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

4OA1 Performance Indicator Verification

.1 Drill/Exercise Performance

a. Inspection Scope

The inspectors sampled licensee submittals for the Drill/Exercise Performance Indicator (PI) for the period from the second quarter 2013 through the first quarter 2014.

Performance Indicator definitions and guidance contained in Nuclear Energy Institute (NEI) 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, were used to determine the accuracy of the PI data reported during those periods. The inspectors reviewed the licensees records associated with the PI to verify that the licensee accurately reported the Drill/Exercise Performance indicator in accordance with relevant procedures and NEI guidance. Specifically, the inspectors reviewed licensee records and processes, including procedural guidance, on assessing opportunities for the PI; assessments of PI opportunities during pre-designated control room simulator training sessions; performance during the 2013 Biennial Exercise; and performance during other drills. Specific documents reviewed are listed in the Attachment to this report.

This inspection constitutes one Drill/Exercise Performance sample as defined in IP 71151-05.

b. Findings

No findings were identified.

.2 Emergency Response Organization Drill Participation

a. Inspection Scope

The inspectors sampled licensee submittals for the ERO Drill Participation PI for the period from the second quarter 2013 through the first quarter 2014. The PI data reported during those periods, PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, was used to determine the accuracy. The inspectors reviewed the licensees records associated with the PI to verify that the licensee accurately reported the indicator in accordance with relevant procedures and NEI guidance. Specifically, the inspectors reviewed licensee records and processes including procedural guidance on assessing opportunities for the PI; performance during the 2013 biennial exercise and other drills; and revisions of the roster of personnel assigned to key ERO positions. Specific documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

.3 Alert and Notification System

a. Inspection Scope

The inspectors sampled licensee submittals for the ANS PI for the period from the second quarter 2013 through the first quarter 2014. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, was used. The inspectors reviewed the licensees records associated with the PI to verify that the licensee accurately reported the indicator in accordance with relevant procedures and NEI Guidance. Specifically, the inspectors reviewed licensee records and processes including procedural guidance on assessing opportunities for the PI and results of periodic ANS operability tests. Specific documents reviewed are listed in the Attachment to this report.

This inspection constitutes one ANS sample as defined in IP 71151-05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

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

.1 Routine Review of Items Entered into the Corrective Action Program

a. Inspection Scope

As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify 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: identification of the problem was complete and accurate; timeliness was commensurate with the safety significance; 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 Attachment to this report.

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

b. Findings

No findings 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 followup, 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 were identified.

.3 Semiannual Trend Review

a. Inspection Scope

The inspectors performed a review of the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screening discussed in Section 4OA2.2 above, licensee trending efforts, and licensee human performance results. The inspectors review nominally considered the 6-month period of October 2013 through March 2014, although some examples expanded beyond those dates where the scope of the trend warranted.

The review also included attendance by the inspectors at Management Screening Committee meetings and Corrective Action Review Board Meetings, where the inspectors observed screening of daily ARs and review of apparent cause evaluations.

Through review of several ARs and known plant issues, the inspectors noted general weaknesses at times in the amount of rigor expended towards identifying and clearly documenting the basis for operability for conditions adverse to quality. Specifically, when new or additional information became available regarding previously assessed conditions for components/systems, the licensee did not utilize the CAP (via new ARs or revised operability reviews in existing ARs) to formally document a basis for continued operability. In each case, the inspectors validated there were no actual operability concerns and engaged the licensee to ensure results of their reviews were formally documented. Additionally, the inspectors noted a weakness in licensee application of the specific criteria required to assess operability in the case of leakage from Code-class components. Again, in the instances observed, the inspectors validated no immediate operability concerns actually existed. During their review, the inspectors also observed one of the licensees corporate Management Review Meetings, which are held quarterly and cover performance in each department as well as site performance indicators. In addition, the inspectors reviewed an adverse trend from 2013 regarding implementation of the work hours control program onsite. The inspectors reviewed the individual and programmatic issues identified by the licensee and concluded that the corrective actions put in place by the licensee were appropriate to address the issues.

This review constituted one semiannual trend inspection sample as defined in IP 71152-05.

b. Findings

No findings were identified.

.4 Selected Issue Followup Inspection: Scaffold Construction

a. Inspection Scope

During a review of items entered in the licensees CAP, the inspectors recognized a several ARs documenting issues with scaffold construction. In 2013 the inspectors identified a performance deficiency associated with scaffold construction and documented it as NRC Inspection Report 05000315/2013003-02. In order to determine if similar issues were occurring, the inspectors reviewed the newly generated ARs and performed walkdowns of numerous scaffolds to determine if the scaffolds adversely impacted safety-related equipment. Based on the review and walkdowns, the inspectors concluded that no significance deficiencies existed in scaffold construction.

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

b. Findings

No findings were identified.

4OA6 Management Meetings

.1 Exit Meeting Summary

On July 8, 2014, the inspectors presented the inspection results to Mr. J. Gebbie 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 inspection results for the area of radioactive gaseous and liquid effluent treatment with Mr. J. Gebbie, Site Vice President, on May 9, 2014; and

• The results of the EP Program inspection with Mr. S. Partin conducted at the site on June 27, 2014.

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

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

S. Partin, Plant Manager

R. Becvar, Emergency Preparedness Coordinator

J. Calhoun, Emergency Preparedness Coordinator

K. Henderson, Licensing Activities Coordinator

R. Hite, Radiation Protection Manager

C. Hutchinson, Nuclear Site Services Director

V. Locklair, Emergency Preparedness Coordinator

M. Scarpello, Regulatory Assurance Manager

R. Sieber, Emergency Preparedness Manager

A. Thompson, Emergency Preparedness Supervisor

C. Wohlgamuth, Compliance Supervisor

Nuclear Regulatory Commission

T. Wengert, Project Manager

L. Kozak, Senior Risk Analyst

LIST OF ITEMS

Opened

05000315/2014003-01; NCV Failure to Control Nonconforming Delivery Valve Holders

05000316/2014003-01 on Emergency Diesel Generators (Section 1R15)

05000315/2014003-02; SLIV Missed Event Notification (Section1R15)

05000316/2014003-02

05000315/2014003-03; FIN Deficient Annunciator/PPC Design (Section 1R18)

05000316/2014003-03

Closed

05000315/2014003-01; NCV Failure to Control Nonconforming Delivery Valve Holders

05000316/2014003-01 on Emergency Diesel Generators (Section 1R15)

05000315/2014003-02; SLIV Missed Event Notification (Section 1R15)

05000316/2014003-02

05000315/2014003-03; FIN Deficient Annunciator/PPC Design (Section1R18)

05000316/2014003-03