IR 05000331/2015004

NRC Integrated Inspection Report 05000331/2015004; 07200032/2015001

ML16035A054
Person / Time
Site:	Duane Arnold
Issue date:	02/03/2016
From:	Karla Stoedter NRC/RGN-III/DRP/B1
To:	Vehec T NextEra Energy Duane Arnold
References
IR 2015001, IR 2015004
Download: ML16035A054 (50)

Text

February 3, 2016

SUBJECT:

DUANE ARNOLD ENERGY CENTERNRC INTEGRATED INSPECTION REPORT 05000331/2015004; 07200032/2015001

Dear Mr. Vehec:

On December 31, 2015, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Duane Arnold Energy Center. The enclosed report documents the results of this inspection, which were initially discussed on January 7, 2016, and finalized on January 25, 2016, with you 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. 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 2.3.2 of the NRC Enforcement Policy. Additionally, NRC inspectors documented one Severity Level IV violation with no associated finding.

If you contest the violations or the significances 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 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 Duane Arnold Energy Center. In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public Inspections, Exemptions, Requests for Withholding, of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRCs Public Document Room or from the Publicly Available Records (PARS)

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

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

Sincerely,

/RA/

K. Stoedter, Chief Branch 1 Division of Reactor Projects

Docket No. 50-331 License No. DPR-49

Enclosure:

IR 05000331/2015004; 07200032/2015001

REGION III==

Docket No:

50-331 License No:

DPR-49 Report No:

05000331/2015004; 07200032/2015001 Licensee:

NextEra Energy Duane Arnold, LLC Facility:

Duane Arnold Energy Center Location:

Palo, IA Dates:

October 1 through December 31, 2015 Inspectors:

C. Norton, Senior Resident Inspector

J. Steffes, Resident Inspector

C. Phillips, Project Engineer

V. Myers, Senior Health Physicist

R. Walton, Senior Operations Engineer

R. Edwards, Senior Health Physicist

G. Hansen, Senior Emergency Preparedness Inspector

Approved by:

K. Stoedter, Chief Branch 1 Division of Reactor Projects

SUMMARY OF FINDINGS

Inspection Report (IR) 05000331/2015004; 0700032/2015001; 10/01/2015 - 12/31/2015;

Duane Arnold Energy Center; Maintenance Effectiveness, Operability Determinations and Functionality Assessments and Plant Modifications.

This report covers a 3-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 U.S. Nuclear Regulatory Commission (NRC) regulations; one traditional enforcement Severity Level IV violation of NRC requirements was also identified. 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 April 29, 2015. Cross-cutting aspects are determined using IMC 0310, "Aspects Within the Cross-Cutting Areas," dated December 4, 2014. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy, dated February 4, 2015. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," dated February 201

NRC-Identified

and Self-Revealed Findings

Cornerstone: Initiating Events

Green.

The inspectors identified a finding of very low safety significance for the licensees failure to follow procedure EN-AA-205-1102, Temporary Configuration Changes, Revision 6. Specifically, the licensee constructed a shaft housing enclosure on the B condensate pump without applying the rigor provided by the temporary configuration change (TCC) process. This resulted in water intrusion into the B condensate pump lower motor bearing. This finding does not involve enforcement action because no violation of a regulatory requirement was identified. The licensee entered the inspectors concerns into the corrective action program (CAP) as condition report (CR) 2100521. Corrective actions included the performance of an apparent cause evaluation and the creation of a form to document engineering positions with respect to TCC applicability.

The inspectors determined that the failure of the licensee to follow procedure EN-AA-205-1102 to document the addition of the B condensate pump shaft housing shield and forced air blower as TCCs was a performance deficiency. The finding was determined to be more than minor because, if left uncorrected, it could become a more significant safety concern. Specifically, the addition of the shaft housing shield resulted in a very high humidity environment which resulted in water passing through the lower motor shaft seal and entering the lower motor bearing oil reservoir. This resulted in the need for repetitive feeding and bleeding of the lower motor bearing oil reservoir to prevent emulsification of the oil. The feeding and bleeding of the B condensate pump lower motor bearing oil reservoir was an evolution that could have resulted in bearing damage, pump trip, and reactor scram. The finding was determined to be of very low safety significance because the finding did not result in exceeding the reactor coolant system leak rate for a small loss of coolant accident, cause a reactor trip, involve the complete or partial loss of a support system that contributes to the likelihood of or caused an initiating event, and did not affect mitigation equipment. This finding was associated with the cross-cutting aspect of operating experience in the area of problem identification and resolution because the licensee failed to implement relevant internal operating experience in a timely manner. [P.5] (Section 1R18)

Cornerstone: Mitigating Systems

Green.

The inspectors identified a finding of very low safety significance, with two examples, and an associated NCV of Technical Specifications (TS) Sections 3.3.5.1,

Condition D and 3.3.5.2, Condition D, for failure to initiate required TS action statements 3.3.5.1.D.1 and 3.3.5.2.D.1. Specifically, the licensee failed to declare the high pressure coolant injection (HPCI) and the reactor core isolation cooling (RCIC) systems inoperable when the automatic HPCI/RCIC pump suction swap function on low condensate storage tank (CST) level was revealed to be inoperable during surveillance testing. The licensee entered the inspectors concerns into the CAP as CR 2080489 and replaced the failed time delay relay.

The inspectors determined the failure to declare the HPCI/RCIC systems inoperable when the pump suction swap function on low CST level failed during surveillance testing was a performance deficiency because it resulted in the licensees failure to implement TS required actions and the cause was reasonably within the licensees ability to foresee and should have been prevented. The performance deficiency was determined to be more than minor and a finding because if left uncorrected, failing to implement TS required actions reduced the margin of safety and had the potential to lead to significant safety concerns. The finding was determined to be of very low significance because the CST was assumed to contain sufficient inventory for HPCI and RCIC to perform their function for most scenarios. This finding was associated with the cross-cutting aspect of conservative bias in the area of human performance because the licensee failed to use decision-making practices that emphasize prudent choices over those that are simply allowable when the licensee failed to conservatively evaluate unexpected surveillance test results. [H.14] (Section 1R15)

• Severity Level IV. The inspectors identified a Severity Level IV NCV of Title 10 of the Code of Federal Regulations (CFR), Section 50.73, Licensee Event Report System. Specifically, the licensee failed to submit a required Licensee Event Report within 60 days after the discovery of an event that was reportable in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition that was prohibited by the plants TS and 10 CFR 50.73(a)(2)(v)(B) as a condition that could have prevented fulfillment of a safety function. The licensee documented the inspectors concern into the CAP as CR 2099065. Planned corrective actions included the performance of an apparent cause evaluation for the failure to recognize the reportable condition and to submit a licensee event report.

This issue was determined to be more than minor because the NRC relies on licensees to identify and report conditions or events meeting the criteria specified in the 10 CFR 50.73 in order to perform its regulatory function. The inspectors previously determined in Section 1R15 of this report that the underlying issue (i.e., the failure of the HPCI/RCIC suction swap function as discovered during surveillance requirement testing)was a finding of very low safety significance. Consistent with the guidance in Section 6.9, Paragraph d.9, of the NRC Enforcement Policy, the violation associated with this finding was determined to be a Severity Level IV Violation. No cross-cutting aspect was assigned to this traditional enforcement violation. (Section 1R15)

Green.

The inspectors identified a finding of very low safety significance and an associated NCV of 10 CFR 50.65(a)(1), 10 CFR 50.65(a)(2), and 10 CFR 50.65(b), due to the licensees failure to scope the load-shed function of safety related and nonsafety related 4160 volt (V) and 480V breakers into the Maintenance Rule. The load-shed function of the breakers was to ensure upon receipt of load-shed signal that the required breakers would separate from the associated essential buses such that the Standby Diesel Generators (SBDGs) could close into the vital buses. The licensee entered the inspectors concerns into the CAP as CR 2065346. Corrective actions included scoping those breakers of concern into the Maintenance Rule program, establishing breaker performance criteria, and performing a review of past breaker failures against the established criteria.

The performance deficiency was determined to be more than minor because it impacted the Mitigating Systems Cornerstone attribute of Equipment Performance, and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage) with respect to the SBDGs. Because the finding did not affect the design or qualification of the SBDGs, nor did it represent a loss of a system or function, the finding screened as very low safety significance. This finding was not indicative of licensee performance since the scoping aspects were determined in 1994, which was prior to the rules effective date of July 10, 1996. Therefore, no cross-cutting aspect was assigned to this finding. (Section 1R12)

REPORT DETAILS

Summary of Plant Status

Duane Arnold Energy Center (DAEC) operated at full power at the beginning of the inspection period. On October 13, 2015, the licensee lowered power to approximately 60 percent to perform a control rod sequence exchange. Following the control rod sequence exchange, power was gradually increased with full power operations re-established on October 16, 2015.

The plant remained at full power for the rest of the inspection period with the exception of brief small down-power maneuvers to accomplish load line adjustments or planned surveillance testing activities.

REACTOR SAFETY

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

1R01 Adverse Weather Protection

.1 Winter Seasonal Readiness Preparations

a. Inspection Scope

The inspectors conducted a review of the licensees preparations for winter conditions to verify that the plants design features and implementation of procedures were sufficient to protect mitigating systems from the effects of adverse weather. Documentation for selected risk-significant systems was reviewed to ensure that these systems would remain functional when challenged by inclement weather. During the inspection, the inspectors focused on plant specific design features and the licensees procedures used to mitigate or respond to adverse weather conditions. Additionally, the inspectors reviewed the Updated Final Safety Analysis Report (UFSAR) and performance requirements for systems selected for inspection and verified that operator actions were appropriate as specified by plant specific procedures. Cold weather protection, such as heat tracing and area heaters, was verified to be in operation where applicable. 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. Documents reviewed are listed in the Attachment to this report. The inspectors reviews focused specifically on plant systems listed in the following procedure due to their risk significance or susceptibility to cold weather issues:

• Winter prep check list.

This inspection constituted one winter seasonal readiness preparations sample as defined in Inspection Procedure (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:

• B standby diesel generator (SBDG) while A SBDG was out-of-service for pre-planned maintenance;

• Core spray (CS) system alignment while low pressure coolant Injection (LPCI)was inoperable;

• High pressure coolant injection (HPCI) system while reactor core isolation cooling (RCIC) system was unavailable for surveillance;

• Automatic depressurization system while HPCI was inoperable; and

• A emergency service water (ESW) system while B SBDG and B ESW were inoperable for surveillance testing.

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

Documents reviewed are listed in the Attachment to this report.

These activities constituted five quarterly partial system walkdown samples 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:

• Turbine building elevation 757 (all fire zones) and radioactive release (fire zones 8-A, 8-D and 8-E);

• Turbine building elevation 780 (all fire zones) and radioactive release (fire zones 9-A, 9-B and 9-C);

• Low level radwaste processing storage facility (fire zones 21-F through 21-M, 21-O and 21-S) and radioactive release (fire zones 21-G, 21-M and 21-S); and

• Reactor building elevation 757 (fire zones 2-C, 2-E, and 2-F) and radioactive release (fire zones 2-F and 2-K).

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 inspections constituted four routine resident inspector tour samples as defined in IP 71111.05-05.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review of Licensed Operator Requalification

a. Inspection Scope

On December 8, 2015, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification training. The inspectors verified that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and that training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas of the crew:

• Licensed operator performance;

• 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 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 resident inspector quarterly review of licensed operator requalification sample as defined in IP 71111.11-05 and satisfied the inspection program requirement for the resident inspectors to observe a portion of an in-progress annual requalification operating test during a training cycle in which it was not observed by the U.S. Nuclear Regulatory Commission (NRC) during the biennial portion of this IP 71111.11-05.

b. Findings

No findings were identified.

.2 Resident Inspector Quarterly Observation During Periods of Heightened Activity or Risk

(71111.11Q)

a. Inspection Scope

On October 13, 2015, the inspectors observed reactivity manipulation for a control rod sequence exchange. On October 26, 2015, the inspectors observed Scenario PDA Ops 2015E-01E. These were activities that required heightened awareness or was related to increased risk. The inspectors evaluated the following areas of the crew:

• Licensed operator performance;

• 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 manipulations;

• Oversight and direction from supervisors; and

• Ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications.

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 two resident inspector quarterly observation of heightened activity or risk samples as defined in IP 71111.11-05.

b. Findings

No findings were identified.

.3 Biennial Written and Annual Operating Test Results

a. Inspection Scope

The inspectors reviewed the overall pass/fail results of the Annual Operating Test and Written Examination required by Title 10 of the Code of Federal Regulation (CFR), Part 55.59(a) and administered by the licensee between November 9, 2015 and December 18, 2015. The results were compared to the thresholds established in Inspection Manual Chapter (IMC) 0609, Appendix I, Licensed Operator Requalification Significance Determination Process, to assess the overall adequacy of the licensees Licensed Operator Requalification Training Program to meet the requirements of 10 CFR 55.59.

This inspection constituted one annual licensed operator requalification inspection sample as defined in IP 71111.11-05.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

.1 Routine Quarterly Evaluations

a. Inspection Scope

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

• Maintenance Rule program periodic review; and

• Surveillance test procedure (STP) 3.5.3-05; RCIC/HPCI suction transfer interlock; WO 40346903 01.

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 Part 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 Part 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

Failure to Scope Safety Related and Nonsafety Related Breakers Into the Maintenance Rule

Introduction:

The inspectors identified a finding of very low safety significance (Green)and an associated non-cited violation (NCV) of 10 CFR 50.65(a)(1), 10 CFR 50.65(a)(2)and 10 CFR 50.65(b) when the licensee failed to scope the load-shed function of safety related and nonsafety related 4160 and 480 volt (V) breakers into the Maintenance Rule.

The breaker load-shed function was to ensure that loads were removed from the associated safety related buses to allow the SBDGs to connect to the vital buses once running and provide power to safety related systems for its required mission time.

Description:

On April 23, 2015, the licensee performed a HPCI confidence run which directed the HPCI system steam exhaust to the torus. The licensee used the residual heal removal (RHR) system to cool the torus which was heated up due to the HPCI exhaust steam. Following the surveillance test, the licensee was securing the RHR system from torus cooling when the C RHR pump breaker failed to open from the control room. The licensee dispatched an operator to the essential switchgear room to trip the pump locally using the electrical switch installed on the breaker cubicle. The breaker failed to trip electrically and was finally secured using the mechanical trip mechanism local to the breaker. The licensee documented the failure to trip the breaker electrically in CR 02042903.

As part of the corrective actions in CR 02042903, the licensee performed an apparent cause evaluation (ACE) and a past operability review (POR) associated with the breaker failure. The ACE and the POR were reviewed as part of the Duane Arnold Energy Center third quarter report, Duane Arnold Energy CenterNRC Integrated Inspection Report 05000331/2015003 (ADAMS Accession number ML15302A159). The licensee also performed a Maintenance Rule Functional Failure (MRFF) evaluation for the failure of the C RHR breaker to operate electrically in accordance with ER-AA-100-2002, Maintenance Rule Program Administration, Revision 2, against the SBDG, RHR, and on-site distribution performance criteria basis documents, Emergency Diesel Generator and the Technical Support Diesel Generator SUS 23.00, 24.01, 24.02, 24.03, 24.04, Revision 7, Residual Heat Removal SUS 49.00, Revision 5 and On-site Distribution SUS 4.00, 5.00, 6.00, 7.00, 17.00, 57.00, Revision 7, respectively. The licensees evaluation, completed on August 8, 2015, concluded that the breakers failure to operate did not constitute a MRFF for any of the above systems. However, the licensee also concluded that the failed breaker did constitute an equipment category failure under SUS 4.00, which was a non-Maintenance Rule monitored function. As stated in the licensees on-site distribution performance criteria basis document, the non-Maintenance Rule monitoring of 4160V breakers was not required and was being performed as an enhancement to the Maintenance Rule program.

The inspectors reviewed the licensees MRFF evaluation and questioned the licensees conclusion that the breakers failure to open did not constitute a MRFF. During accident scenarios, the SBDG is required to startup and load onto the essential electrical buses to provide power to safety related systems such as RHR pumps, CS pumps and residual heat removal service water (RHRSW) pumps, all of which are powered by 4160V breakers. The inspectors questioned why the ability of these breakers to open or load-shed was not scoped into the Maintenance Rule given that multiple breakers failing to open could impact the SBDGs ability to perform its safety related function. The licensee entered the inspectors concern as CR 02065346.

As part of CR 02065346, the licensee determined that the ability for 4160V and 480V essential load breakers as well as 480V non-essential bus tie breakers to open or load-shed during a design bases event was a required function of those breakers. As a result, the licensee developed Maintenance Rule performance criteria for the breakers of concern and incorporated those criteria in the performance criteria basis document On-site Distribution SUS 4.00, 5.00, 6.00, 7.00, 17.00, 57.00, Revision 8. The licensee used the developed performance criteria to re-perform the MRFF evaluation and concluded that the failure of the C RHR breaker to open electrically on demand was a MRFF and a maintenance preventable functional failure.

Analysis:

The inspectors determined that the failure to scope the load-shed function of 4160V and 480V essential load breakers, as well as 480V non-essential bus tie breakers, into the Maintenance Rule program in accordance with 10 CFR Part 50.65(b)was a performance deficiency that was reasonably within the licensees ability to foresee and correct and therefore should have been prevented. The performance deficiency was determined to be more than minor because it impacted the Mitigating Systems Cornerstone attribute of Equipment Performance and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage) with respect to the SBDGs.

The inspectors applied IMC 0609, Attachment 4, Initial Characterization of Findings, issued June 19, 2012, to this finding. The inspectors answered No to all questions within Table 3, SDP Appendix Router, and transitioned to IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, issued June 19, 2012.

Per Exhibit 2, Mitigating Systems Screening Questions, the inspectors determined that because the finding did not affect the design or qualification of the SBDGs nor did it represent a loss of a system or function, the finding screened as very low safety significance (Green).

The inspectors determined that since the licensee originally performed Maintenance Rule scoping efforts in 1994 and the Maintenance Rules effective date was July 10, 1996, the finding was not indicative of current licensee performance. Therefore, no cross-cutting aspect was assigned to this finding.

Enforcement:

Title 10 of the CFR, Section 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, Paragraph (a)(1) requires, in part, that licensees shall monitor the performance or condition of SSCs, against licensee-established goals, in a manner to provide reasonable assurance that these SSCs are capable of fulfilling their intended functions.

In addition, 10 CFR 50.65(a)(2) requires, in part, that monitoring as specified in paragraph (a)(1) is not required when it has been demonstrated that the performance or condition of an SSC is being effectively controlled through the performance of appropriate preventative maintenance.

Also, 10 CFR 50.65(b) requires, in part, that the scope of the monitoring program specified in paragraph (a)(1) shall include safety related and nonsafety related SSCs, as follows:

(1) safety-related SSCs that are relied upon to remain functional during and following design basis events to ensure the integrity of the reactor coolant pressure boundary, the capability to shutdown the reactor and maintain it in a safe shutdown condition, or the capability to prevent or mitigate the consequences of accidents that could result in potential offsite exposure comparable to the guidelines in 10 CFR 50.34(a)(1), 50.67(b)(2), or 100.11 of this chapter, as applicable.

Contrary to the above, since the Maintenance Rule became effective in July 10, 1996, the licensee failed to include the load-shed function of 4160V and 480V essential load breakers as well as 480V non-essential bus tie breakers in the scope of the (a)(1) or (a)(2) monitoring program specified in the Maintenance Rule. The inclusion of these breakers within the rule was required because failure of these breakers to divorce from the safety related buses as required through the load-shed function could prevent the SBDGs from providing power to those buses and prevent multiple safety related systems from fulfilling their safety related functions.

Corrective actions included scoping the load-shed function of 4160V and 480V essential load breakers as well as 480V non-essential bus tie breakers into the Maintenance Rule program, establishing breaker performance criteria, and performing a review for past breaker failures against the established criteria. Because this violation was of very low safety significance and because the issue was entered into the licensees CAP as CR 02065346, it is being treated as a NCV consistent with Section 2.3.2 of the Enforcement Policy. (NCV 05000331/2015004-01, Failure to Scope Safety Related and Nonsafety Related Breaker into the Maintenance Rule)

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:

• Work Week 1542 - remote shutdown panel work, imminent foul weather and electrical transient with an associated start of both A and B SBDGs;

• Foreign material exclusion cover over fuel pool;

• RHRSW flow control valve stem disc unthreading; and

• A SBDG maintenance outage.

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 Part 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 inspections constituted four maintenance risk assessments and emergent work control samples as defined in IP 71111.13-05.

b. Findings

No findings were identified.

1R15 Operability Determinations and Functional Assessments

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• Operator challenge list; (Operator Workaround)

• HPCI/RCIC operability after STP 3.3.5.1-23 failure; and

• B SBDG heating ventilation air conditioning control air.

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 inspection constituted three operability evaluations samples as defined in IP 71111.15-05. One of these samples was an operator workaround review.

b. Findings

(1) Failure to Declare High Pressure Cooling Injection and Reactor Core Isolation Cooling Inoperable when the Condensate Storage Tank Level-Low High Pressure Cooling Injection and Reactor Core Isolation Cooling Pump Suction Swap Function was Inoperable

Introduction:

The inspectors identified a finding of very low safety significance (Green)and an associated NCV, with two examples, of TS Sections 3.3.5.1.D and 3.3.5.2.D, for the failure to initiate required TS Action Statements 3.3.5.1.D.1 and 3.3.5.2.D.1.

Specifically, the licensee failed to declare HPCI and RCIC inoperable when the HPCI/RCIC pump suction swap function was revealed to be inoperable.

Description:

On October 2, 2015, the licensee performed a functional test of the condensate storage tank (CST) level instrumentation to initiate a CST low level HRCI/RCIC pump suction swap from the CST to the suppression pool in accordance with STP 3.3.5.1-23, Functional Test of the Condensate Storage Tank Level (Low)

Instrumentation. In the surveillance test for the B channel, if the suction swap function had worked as designed, the annunciator for the HPCI/RCIC pump suction swap would have activated. The annunciator, however, did not activate and the acceptance criterion for the surveillance was not met.

After failing to satisfy the acceptance criterion, the licensee did not declare HPCI and RCIC systems inoperable within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> as required by TS 3.3.5.1, Condition D and TS 3.3.5.2, Condition D. Instead, the licensee repeated the test. The second test resulted in the actuation of the annunciator. The licensee subsequently initiated a condition report describing the initial failure to satisfy the acceptance criterion. The licensee performed an immediate operability determination (IOD) declaring the CST low level suction swap function operable based on anecdotal evidence of relay binding caused by relay contact blocks and the successful completion of the second test. The licensee requested a prompt operability determination (POD) to support the IOD.

On October 6, 2015, the inspectors challenged the IOD based on the following:

• applicability of performing an IOD instead of declaring the CST low level HPCI and RCIC pump suction swap functions inoperable when the acceptance criteria was not satisfied;

• using anecdotal evidence rather than direct observation to support the theory that relay contact blocks bound the relay; and

• preconditioning of the second test by the first test.

On October 8, 2015, after performing troubleshooting activities, the licensee determined that the functional test performed on October 2, 2015, was a failure due to a malfunctioning time delay relay in the HPCI/RCIC suction swap function circuitry. The time delay relay was replaced and subsequently tested satisfactorily.

During a historical review of the HPCI/RCIC pumps suction swap logic testing documentation, the licensee found that a failure of the time delay relay was not properly evaluated on July 23, 2015. During testing on that date, the as-found time delay of 19.86 seconds was out of the relay design band of 0.0 - 5.0 seconds and could not be attributed to instrument drift. The time delay relay was then recalibrated, immediately retested and returned to service. Procedural guidance was not available at the time to require that, if the as-found time delay was out of the design band, operability needed to be evaluated. As such, the CST low level HPCI/RCIC pump suction swap function was not declared inoperable and required TS actions taken.

Analysis:

The inspectors determined that the failure to declare the CST low level suction swap function inoperable when it failed to meet surveillance acceptance criterion on October 2, 2015, and when the time delay relay was found out of band on July 23, 2015, represented issues of concern. The inspectors determined the issues of concern represented a performance deficiency because it resulted in the licensees failure to implement TS required actions, and the cause was reasonably within the licensees ability to foresee and should have been prevented. The performance deficiency was determined to be more than minor and a finding because if left uncorrected, failing to implement TS required actions reduced the plants margin of safety and had the potential to lead to significant safety concerns.

The inspectors applied IMC 0609, Attachment 4, Initial Characterization of Findings, Table 2, Cornerstones Affected by Degraded Condition or Programmatic Weakness, to this finding and determined the finding was associated with the Mitigating Systems Cornerstone. Table 3, SDP Appendix Router, directed the inspectors to IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power.

The inspectors answered No to Question 1 and Yes to Question 2 of Section A, of Exhibit 2, Mitigating Systems Screening questions. Therefore, a detailed risk evaluation was required. A Region III Senior Reactor Analyst (SRA) performed a detailed risk evaluation of the degraded condition associated with the finding.

For the degraded risk evaluation, the SRA assumed that both the HPCI and RCIC suctions would fail to automatically swap from the CST to the torus due to the failed relay when the low level set point was reached. The exposure time used in the evaluation was from July 23, 2015, the first time the relay was known to be in a degraded state, until October 8, 2015, when it was replaced and returned to an operable status. The SRA used revision 8.26 of the NRCs Standardized Plant Analysis Risk Model for Duane Arnold. The model did not specifically contain a basic event representing the automatic suction transfer. The SRA used basic events representing failures of the HPCI and RCIC torus suction valves as a surrogate for the automatic suction transfer. These basic events were set to True or failed. The inspectors and the SRA determined that the function of the automatic suction transfer was recoverable by operators manually swapping the suction source. However, it was not necessary to model this recovery action in the detailed risk evaluation because the change in core damage frequency without considering recovery was already less than 1.0E-7/yr. The risk of this finding was determined to be very low (Green) because the CST was assumed to contain sufficient inventory for HPCI and RCIC to perform their function for most scenarios. The dominant core damage sequence was a small loss of coolant accident followed by the failure of all high pressure injection sources and the failure to depressurize and use low pressure sources.

The inspectors determined that this issue was associated with the cross-cutting aspect of conservative bias in the human performance cross-cutting area because involved individuals failed to use decision-making practices that emphasize prudent choices over those that are simply allowable. Specifically, the licensee failed to consider the significance of unexpected surveillance test results when performing operability determinations [H.14].

Enforcement:

Technical Specification 3.3.5.1, Emergency Core Cooling System Instrumentation, Condition D, requires that HPCI system be declared inoperable in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> from discovery of loss of HPCI suction transfer capability. Similarly, TS 3.3.5.2, RCIC System Instrumentation, Condition D, requires that RCIC system to be declared inoperable in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> from discovery of loss of RCIC suction transfer capability.

Contrary to above, the licensee failed to comply with TS 3.3.5.1, Condition D and TS 3.3.5.2, Condition D, to declare HPCI and RCIC inoperable within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> of the discovery that the B channel of the CST level low suction swap function was inoperable. Specifically, on October 2, 2015, during the performance of STP 3.3.5.1-23, the licensee failed to declare the CST low level suction swap function inoperable when the acceptance criterion established in STP 3.3.5.1-23 was not satisfied. Similarly, on July 23, 2015, when a time delay relay for the low level suction swap function was found out of band, the licensee failed to consider that the as-found condition was not attributable to normal instrument drift and failed to declare the CST low level suction swap function inoperable. The licensee entered this issue into the CAP as CR 2080489 and CR 2080185 and replaced the failed time delay relay.

Because this violation was of very low safety significance and was entered into the licensees CAP, the violation is being treated as a NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000331/2015004-02, Failure to Declare HPCI/RCIC Inoperable when the Condensate Storage Tank Level-Low HPCI/RCIC Pump Suction Swap Function was Inoperable)

(2) Failure to Satisfy 10 CFR 50.73 Reporting Requirements

Introduction:

The inspectors identified a Severity Level IV NCV of 10 CFR 50.73, Licensee Event Report System, due to the licensees failure to submit a Licensee Event Report (LER) within 60 days. Specifically, the licensee failed to submit an LER within 60 days after the discovery of a condition that not only was prohibited by the plants TS but also a condition that could have prevented the fulfillment of the safety function of systems that are needed to remove residual heat. The condition involved the inoperability of the HPCI and RCIC systems for a time frame longer than the TS completion time for restoration.

Description:

As discussed above, the licensee experienced a failure of the CST low level HPCI/RCIC pump suction swap function on October 2, 2015. On October 8, 2015, the licensee performed a historical review of the HPCI/RCIC pumps suction swap logic test results discussed in the previous section of this report and discovered that the results of the July 23, 2015, test on a time delay relay had not been properly evaluated.

Specifically, the test results showed that the as-found time delay of 19.86 seconds was outside of the relay design band of 0.0 - 5.0 seconds and could not be attributed to instrument drift.

The licensee conducted a past operability review of this issue and determined that the CST low level HPCI/RCIC suction swap function was operable but degraded. The inspectors reviewed the past operability determination in December 2015 and disagreed with the licensees conclusion. Specifically, the inspectors were concerned that the licensee had not considered that the time delay relays failure was random in nature and that the relay appeared not to function unless it was preconditioned. The inspectors also determined that the licensee had failed to restore the HPCI system to an operable condition in accordance with TS required actions 3.3.5.1.D.1, 3.5.1.F.2, 3.5.1.J.1 and 3.5.1.J.2. As a result, the system had remained inoperable from July 23, 2015, until October 8, 2015, which exceeded the time allowed by TS. Similarly, the licensee had failed to restore the RCIC system to an operable condition in accordance with TS required actions 3.3.5.2.D.1, 3.5.3.A.2, 3.5.3.B.1 and 3.5.3.B.2. This system had also remained inoperable for a period of time longer than allowed by TS.

The inspectors determined that the licensees failure to restore the HPCI and RCIC systems to an operable status as required by TS constituted a reportable condition in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by TS. The inspectors further determined that the failed time delay relay caused the inoperability of the HPCI system, a single-train system, and therefore, should have been reported in accordance with 10 CFR 50.73(a)(2)(v)(B) as a condition that could have prevented fulfillment of a safety function. Finally, the inspectors identified that the licensee failed to report the above conditions to the NRC within 60 days of discovery, in this case, 60 days from October 8, 2015. The inspectors discussed this issue with the licensee who documented the inspectors concerns in CR 2099065. Corrective actions included performing an ACE for the failure to recognize the reportable condition and submitting a LER.

Analysis:

The inspectors determined that the licensees failure to report the inoperability of the HPCI and RCIC systems as a condition which was prohibited by the plants TS and the failure to report the issue as condition that could have prevented fulfillment of a safety function for the HPCI system within 60 days of discovery was a performance deficiency that was reasonably within the licensees ability to foresee and correct and therefore, should have been prevented. The inspectors screened the performance deficiency in accordance with IMC 0612, Appendix B, Issue Screening, dated September 7, 2012, and determined that because the performance deficiency involved a violation of NRCs reporting requirements and this affected the NRCs ability to perform its regulatory function, it screened as more than minor. The inspectors evaluated the violation using the traditional enforcement process in accordance with the NRC Enforcement Policy and assessed the significance of the underlying issue using the SDP.

The inspectors previously determined, in Section 1R15.1.b(1) of this report, that the underlying issue was a finding of very low safety significance (Green). Consistent with the guidance in Section 6.9, Paragraph d.9, of the NRC Enforcement Policy, the failure to report the HPCI/RCIC system inoperability was determined to be a Severity Level IV violation. No cross-cutting aspect was assigned to traditional enforcement violations.

Enforcement:

Title 10 of the CFR, Section 50.73(a)(1) requires, in part, that the licensee submit a LER for any event of the type described in the paragraph within 60 days after the discovery of the event. In addition, 10 CFR 50.73(a)(2)(i)(B) requires, in part, that the licensee report any condition which was prohibited by the plants TS. Furthermore, 10 CFR 50.73(a)(2)(v)(B) requires, in part, that the licensee report any condition that could have prevented the fulfillment of the safety function of systems that are needed to remove residual heat.

Contrary to the above, the licensee failed to submit a required LER within 60 days of October 2, 2015, after discovering that the failure of the CST low level HPCI/RCIC suction swap time delay relay constituted a condition prohibited by TS and a condition that could have prevented the fulfillment of a safety function. Planned corrective actions included submitting the LER and performing an ACE for the failure to recognize the reportable condition and to reevaluate reportability thereafter. Because this Severity Level IV violation of the NRC reporting requirements is associated with a Green SDP finding and because the issue was entered in the licensees CAP as CR 02099065, consistent with Section 2.3.2 of the Enforcement Policy, it is being treated as a NCV.

(NCV 05000331/2015004-03, Failure to Satisfy 10 CFR 50.73 Reporting Requirements for a Condition Prohibited by Technical Specifications and for a Condition that Could Have Prevented Fulfillment of a Safety Function)

1R18 Plant Modifications

.1 Plant Modifications

a. Inspection Scope

The inspectors reviewed the following modifications:

• Hydrogen seal oil vacuum pump temporary modification;

• A Standby gas treatment (SBGT) 1V-SGT-1A\\B flow indicating controller replacement;

• Condensate pump seal well enclosure; and

• RHR/CS pump seal cavity covers.

The inspectors reviewed the configuration changes and the associated 10 CFR Part 50.59 safety evaluation screenings 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(s). The inspectors, as applicable, observed ongoing and completed work activities to ensure that the modifications were installed as directed and consistent with the design control documents; the modifications operated as expected; post-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. As applicable, the inspectors verified that relevant procedure, design, and licensing documents were properly updated.

Lastly, the inspectors discussed the plant modification with operations, engineering, and training personnel to ensure that the individuals were aware of how the operation with the plant modification in place could impact overall plant performance. Documents reviewed are listed in the Attachment to this report.

This inspection constituted two temporary modification samples and two permanent plant modification samples as defined in IP 71111.18-05.

b. Findings

Failure to Follow Temporary Configuration Control Procedure

Introduction:

The inspectors identified a finding of very low safety significance (Green)for the licensees failure to follow procedure EN-AA-205-1102, Temporary Configuration Changes, Revision 6. Specifically, the licensee constructed a shaft housing enclosure on the B condensate pump without applying the rigor provided by the temporary configuration change (TCC) process. This resulted in water intrusion into the B condensate pump lower motor bearing. Multiple high risk feed and bleed evolutions were required to prevent bearing oil emulsification.

Description:

During the daily CR review, the inspectors evaluated CR 02091112, Temporary Power Cord Not Labeled, and questioned whether changes made to the B condensate pump were a temporary modification. On October 14, 2015, the licensee documented in CR 02082102, 1P008B Cond Pump Seal Leakage Spraying out of Casing Area; that the B condensate pump shaft packing leaked excessively. The licensee placed an additional plexiglas shield above the existing two-thirds shield. The additional shield completely enclosed the shaft housing to prevent the shaft packing leakage from spreading potentially contaminated water onto the floor. The inspectors identified that this new shield was installed without a work order so the exact date of installation was unknown.

On October 21, 2015, the licensee generated CR 02084176, 1P008B-Motor Lower Bearing Oil Sample Contains Free Water. The CR stated that free water was found in the oil sample taken from the B condensate pump lower bearing on September 29, 2015. The CR also stated that it was highly suspected that the water was from the excessive shaft leakage and recommended a feed and bleed of the B condensate pump lower bearing oil.

The licensee performed multiple feed and bleed evolutions of the B condensate pump lower bearing oil reservoir, which proved to be effective in lowering the concentration of water in the oil. The licensee also determined that a forced air blower to the enclosed shaft housing was necessary to prevent water from getting into the motor lower bearing oil reservoir and requiring multiple oil feed and bleed evolutions. The licensee considered the installation of the forced air blower as minor maintenance and the work was performed under the original work request and not a work order. The exact date that the blower was added to the B condensate pump shaft housing was unknown.

The inspectors questioned whether the addition of the additional plexiglas screen and the installation of the blower should have been identified as one or more modifications to the condensate pump that should have fallen under the licensees design control process. The inspectors questioned both operations and engineering management personnel. The engineering management personnel stated that the additions to the B condensate pump shaft housing were comparable to EN-AA-205-1102, Temporary Configuration Changes, Revision 6, Attachment 2, Examples of Temporary Configuration Change Exclusions, example number 5. This example excluded hoses that connect to existing vent or drain connections, and therefore the additions were not a TCC. It appeared to the inspectors, based on interviews and the lack of work order documentation, that this evaluation was performed after the equipment was installed.

The licensee wrote CR 02091781, Temporary Ventilation On B Cond Pump, in response to the inspectors questions regarding the changes to the B condensate pump shaft housing to get an independent review as to whether the changes were a temporary modification. The licensee obtained an independent review from their corporate engineering department, who the licensee stated, agreed that the addition of the screen and the blower was not a temporary modification. The logic for that decision was that there were no equipment concerns that would affect equipment operability or functionality as defined in EN-AA-203-1001, Operability Determinations/Functionality Assessments. The inspectors disagreed with this assessment because if the forced air blower was removed then water would enter the lower motor bearing oil reservoir and the licensee would be forced to feed and bleed the oil reservoir repeatedly or the oil would eventually become emulsified.

Licensee procedure EN-AA-205-1102, Step 4.1, required a determination of whether a TCC was warranted. The procedure refers the user to Attachments 1 and 2 for examples of what are or are not TCCs or the user should contact engineering personnel for assistance. The licensee referred to Attachment 2, example number 5, as mentioned above, to determine that the changes made were not TCCs. However, the inspectors disagreed that the attachment of the screens and forced air blower met this definition.

Instead, the inspectors referred to Step 2.14, which defined a TCC as, A temporary alteration made to systems, structures, or components that does not conform to the approved design configuration. TCCs are made to address degraded conditions, implement temporary repairs, and support short-term operational or maintenance needs and one time plant evolutions.

The inspectors concluded that the changes to the shield on the shaft housing and the subsequent addition of the forced air blower met the definition of a TCC in procedure EN-AA-205-1102, Step 2.14. The licensee did not follow through with the rest of the procedure as required.

The inspectors determined through review of licensee CAP documentation and interviews with engineering department personnel that the addition of the extra plexiglas screen increased the water/humidity enclosed in the B condensate pump shaft housing that resulted in an increased water content in the motor lower bearing oil. If the licensee did not identify water in the oil and did not take corrective actions before the motor lower bearing oil became emulsified, the motor lower bearing may fail and result in a reactor scram due to loss of feed.

The inspectors also determined through interviews with engineering personnel that the condition of water getting into the motor lower bearing oil reservoir had previously occurred under similar conditions. The condition evaluation associated with CR 02084176, 1P008B-M Motor Lower Bearing Oil Sample Contains Free Water, stated, When these pumps were commissioned the cavities were completely enclosed and excess leak-off from the A pump had led to the same presence of moisture in its lower motor bearing reservoir. The inspectors reviewed CR 00307609, Water Intrusion In A Condensate Pump Lower Bearing, dated June 2005. This CR stated that the condensate pump motors were installed in 2005 with no barriers around the shaft housing. The licensee installed 100 percent barrier shields to control contaminated leak off. This enclosure of the shaft housing resulted in water getting into the lower motor bearing reservoir. The licensee did not use this existing internal operating experience to evaluate the installation of the current shaft housing shield prior to its installation.

Analysis:

The inspectors determined that the failure of the licensee to follow through and complete procedure EN-AA-205-1102 and document the addition of the B condensate pump shaft housing shield and forced air blower as a TCC was a performance deficiency.

The finding was determined to be more than minor because, if left uncorrected, it could become a more significant safety concern. Specifically, the addition of the shaft housing shield resulted in a very high humidity environment which resulted in water passing through the lower motor shaft seal and entering the lower motor bearing oil reservoir.

This subsequently required repetitive feeding and bleeding of the lower motor bearing oil reservoir to prevent emulsification of the oil. The feeding and bleeding of the B condensate pump lower motor bearing oil reservoir was an evolution that could have resulted in bearing damage, pump trip, and reactor scram. Using IMC 0609, 4, Initial Characterization of Findings, and Appendix A, The Significance Determination Process for Findings at Power, issued June 19, 2012, the finding was screened against the Initiating Events cornerstone, and determined to be of very low safety significance (Green) because the finding did not result in exceeding the reactor coolant system leak rate for a small loss of coolant accident, cause a reactor trip, involve the complete or partial loss of a support system that contributes to the likelihood of, or caused, an initiating event and did not affect mitigation equipment.

The inspectors determined that the performance characteristic of the finding that was the most significant causal factor of the performance deficiency was associated with the cross-cutting aspect of operating experience in the Problem Identification and Resolution cross-cutting area, and involved implementing relevant internal operating experience in a timely manner. Specifically, the licensee failed to identify and incorporate internal operating experience that previously had identified water intrusion into the lower condensate pump motor bearing when the shaft housing was enclosed. [P.5]

Enforcement:

No violation of NRC requirements was identified due to the B condensate pump being nonsafety related. The licensee entered this issue into their CAP as CR 2100521. Corrective actions included the performance of an ACE for the lack of TCC control associated with the B condensate pump seal leakage shield and forced ventilation and the creation of a form to document engineering positions with respect to TCC applicability. Because this finding does not involve a violation and is of very low safety significance, it is identified as a FIN. (FIN 05000331/2015004-04, Failure to Follow Temporary Configuration Control Procedure)

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:

• CST low level RCIC/HPCI suction swap;

• A SBDG operability test following critical maintenance management;

• B SBDG air compressor and air start check valve tests following check valve replacement;

• Hydrogen seal oil vacuum pump temporary modification removal;

• STP 3.6.4.3-05 SBGT operation following EC 283785; and

• A and C RHR pumps wetted cable replacement.

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

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

This inspection constituted six 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:

• Turbine bypass valve, control valve, stop valve, and combined intermediate valve functional testing (Routine);

• Remote shutdown panel functional test for division 2 switchgear and B SBDG (Routine);

• B standby filter unit logic system functional test and simulated automatic actuation (Routine);

• SBGT system unit A operation; STP 3.6.4.3-01A (Routine);

• LPCI loop select recirculation pump differential pressure instrument channel functional test (Routine);

• Functional test of B CS pump and B/D RHR pump discharge pressure-high instrumentation (Routine); and

• B ESW operability test; STP NS540002B (Routine).

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 seven routine surveillance testing samples as defined in IP 71111.22, Sections-02 and-05.

b. Findings

No findings were identified.

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

The regional inspectors performed an in-office review of the latest revisions to the Emergency Plan and Emergency Action Levels (EALs).

The licensee transmitted the Emergency Plan and EAL revisions to the NRC pursuant to the requirements of 10 CFR Part 50, Appendix E, Section V, "Implementing Procedures." The NRC review was not documented in a safety evaluation report and did not constitute approval of licensee-generated changes; therefore, this revision is subject to future inspection.

This inspection constituted one EAL and Emergency Plan Changes sample as defined in IP 71114.04.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

.1 Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine licensee emergency drill on October 21, 2015, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the simulator 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 inspection constituted one emergency preparedness drill sample as defined in IP 71114.06-06.

b. Findings

No findings were identified.

RADIATION SAFETY

Cornerstones: Occupational and Public Radiation Safety

2RS5 Radiation Monitoring Instrumentation

The inspection activities supplement those documented in IR 05000331/2014003 and IR 05000331/2015002, and constitute one complete sample as defined in IP 71124.05-05.

.1 Inspection Planning (02.01)

a. Inspection Scope

The inspectors reviewed the plant UFSAR to identify radiation instruments associated with monitoring area radiological conditions including airborne radioactivity, process streams, effluents, materials/articles, and workers. Additionally, the inspectors reviewed the instrumentation and the associated TS requirements for post-accident monitoring instrumentation, including instruments used for remote emergency assessment.

The inspectors reviewed a listing of in-service survey instrumentation including air samplers and small article monitors, along with instruments used to detect and analyze workers external contamination. Additionally, the inspectors reviewed personnel contamination monitors and portal monitors, including whole-body counters, to detect workers internal contamination. The inspectors reviewed this list to assess whether an adequate number and type of instruments were available to support operations.

The inspectors reviewed licensee and third-party evaluation reports of the radiation monitoring program since the last inspection. These reports were reviewed for insights into the licensees program and to aid in selecting areas for review (smart sampling).

The inspectors reviewed procedures that govern instrument source checks and calibrations, focusing on instruments used for monitoring transient high radiological conditions, including instruments used for underwater surveys. The inspectors reviewed the calibration and source check procedures for adequacy and as an aid to smart sampling.

The inspectors reviewed the area radiation monitor alarm setpoint values and setpoint bases as provided in the TSs and the UFSAR.

The inspectors reviewed effluent monitor alarm setpoint bases and the calculational methods provided in the offsite dose calculation manual.

b. Findings

No findings were identified.

.2 Walkdowns and Observations (02.02)

a. Inspection Scope

The inspectors observed licensee staff performance as the staff demonstrated source checks for various types of portable survey instruments. The inspectors assessed whether high-range instruments were source checked on all appropriate scales.

b. Findings

No findings were identified.

Laboratory Instrumentation

a. Inspection Scope

The inspectors assessed laboratory analytical instruments used for radiological analyses to determine whether daily performance checks and calibration data indicated that the frequency of the calibrations was adequate and there were no indications of degraded instrument performance.

The inspectors assessed whether appropriate corrective actions were implemented in response to indications of degraded instrument performance.

b. Findings

No findings were identified.

Whole-Body Counter

a. Inspection Scope

The inspectors reviewed the methods and sources used to perform whole-body count functional checks before daily use of the instrument and assessed whether check sources were appropriate and aligned with the plants isotopic mix.

The inspectors reviewed whole-body count calibration records since the last inspection and evaluated whether calibration sources were representative of the plant source term and that appropriate calibration phantoms were used. The inspectors looked for anomalous results or other indications of instrument performance problems.

b. Findings

No findings were identified.

Post-Accident Monitoring Instrumentation

a. Inspection Scope

Inspectors selected containment high-range monitors and reviewed the calibration documentation since the last inspection.

The inspectors assessed whether an electronic calibration was completed for all range decades above 10 rem/hour, and whether at least 1 decade at or below 10 rem/hour was calibrated using an appropriate radiation source.

The inspectors assessed whether calibration acceptance criteria were reasonable; accounting for the large measuring range and the intended purpose of the instruments.

The inspectors selected effluent/process monitors that were relied on by the licensee in its emergency operating procedures as a basis for triggering emergency action levels and subsequent emergency classifications, or to make protective action recommendations during an accident. The inspectors evaluated the calibration and availability of these instruments.

The inspectors reviewed the licensees capability to collect high-range, post-accident iodine effluent samples.

As available, the inspectors observed electronic and radiation calibration of these instruments to assess conformity with the licensees calibration and test protocols.

b. Findings

No findings were identified.

Portal Monitors, Personnel Contamination Monitors, and Small Article Monitors

a. Inspection Scope

For each type of these instruments used on site, the inspectors assessed whether the alarm setpoint values were reasonable under the circumstances to ensure that licensed material is not released from the site.

The inspectors reviewed the calibration documentation for each instrument selected and discussed the calibration methods with the licensee to determine consistency with the manufacturers recommendations.

b. Findings

No findings were identified.

Portable Survey Instruments, Area Radiation Monitors, Electronic Dosimetry, and Air Samplers/Continuous Air Monitors

a. Inspection Scope

The inspectors reviewed calibration documentation for at least one of each type of instrument. For portable survey instruments and area radiation monitors, the inspectors reviewed detector measurement geometry and calibration methods and had the licensee demonstrate use of its instrument calibrator as applicable. The inspectors conducted comparison of instrument readings versus an NRC survey instrument if problems were suspected.

As available, the inspectors selected portable survey instruments that did not meet acceptance criteria during calibration or source checks to assess whether the licensee had taken appropriate corrective action for instruments found significantly out of calibration (e.g., greater than 50 percent). The inspectors evaluated whether the licensee had evaluated the possible consequences of instrument use since the last successful calibration or source check.

b. Findings

No findings were identified.

Instrument Calibrator

a. Inspection Scope

As applicable, the inspectors reviewed the current output values for the licensees portable survey and area radiation monitor instrument calibrator unit(s). The inspectors assessed whether the licensee periodically measures calibrator output over the range of the instruments used through measurements by ion chamber/electrometer.

The inspectors assessed whether the measuring devices had been calibrated by a facility using National Institute of Standards and Technology traceable sources and whether corrective factors for these measuring devices were properly applied by the licensee in its output verification.

b. Findings

No findings were identified.

Calibration and Check Sources

a. Inspection Scope

The inspectors reviewed the licensees 10 CFR Part 61, Licensing Requirements for Land Disposal of Radioactive Waste, source term to assess whether calibration sources used were representative of the types and energies of radiation encountered in the plant.

b. Findings

No findings were identified.

.4 Problem Identification and Resolution (02.04)

a. Inspection Scope

The inspectors evaluated whether problems associated with radiation monitoring instrumentation were being identified by the licensee at an appropriate threshold and were properly addressed for resolution in the licensees CAP. The inspectors assessed the appropriateness of the corrective actions for a selected sample of problems documented by the licensee that involve radiation monitoring instrumentation.

b. Findings

No findings were identified.

OTHER ACTIVITIES

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

4OA1 Performance Indicator Verification

.1 Safety System Functional Failures

a. Inspection Scope

The inspectors sampled licensee submittals for the safety system functional failures performance indicator (PI) for the period from the fourth quarter 2014 through the third quarter 2015. 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 7, dated August 31, 2013, and NUREG-1022, Event Reporting Guidelines 10 CFR Part 50.72 and 50.73" definitions and guidance, were used. The inspectors reviewed the licensees operator narrative logs, operability assessments, maintenance rule records, maintenance work orders, issue reports, event reports and NRC Integrated Inspection Reports for the period of October 2014 through September 2015 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 to this report.

This inspection constituted one safety system functional failures sample as defined in IP 71151-05.

b. Findings

No findings were identified.

.2 Mitigating Systems Performance IndexResidual Heat Removal System

a. Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance Index (MSPI) - Residual Heat Removal System PI for the period from the fourth quarter 2014 through the third quarter 2015. 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 7, dated August 31, 2013, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, MSPI derivation reports, event reports and NRC Integrated Inspection Reports for the period of October 2014 through September 2015 to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the to this report.

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

b. Findings

No findings were identified.

.3 Mitigating Systems Performance IndexCooling Water Systems

a. Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance Index - Cooling Water Systems PI for the period from the fourth quarter 2014 through the third quarter 2015. 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 7, dated August 31, 2013, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, MSPI derivation reports, event reports and NRC Integrated Inspection Reports for the period of October 2014 through September 2015 to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one MSPI cooling water system sample as defined in IP 71151-05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

.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 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 were identified.

.3 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a review of the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screening discussed in Section 4OA2.2 above, licensee trending efforts, and licensee human performance results. The inspectors review nominally considered the 6-month period of July 1, 2015, through December 31, 2015, although some examples expanded beyond those dates where the scope of the trend warranted.

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

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

b. Findings

No findings were identified.

.4 Annual Follow-up of Selected Issues:

Assessment of Sustainability of Corrective Actions to Address the Open Cross Cutting Issue in Human Performance-Consistent Process (H.13)

a. Inspection Scope

During the end-of-cycle assessment for the 2014 calendar year, NRC staff identified a cross-cutting issue in the area of human performance related to the use of a consistent, systematic approach to decision making. The results of this assessment were provided to the licensee in Report 05000331/2014001, Annual Assessment Letter for Duane Arnold Energy Center, dated March 4, 2015 (ML15062A582).

The licensee completed root cause analysis (RCA) 02015746, NRC Cross-Cutting Issue H.13, Adverse Trend, dated April 7, 2015. During the second quarter of 2015, the inspectors assessed and documented in DAEC NRC Integrated Inspection Report, 05000331/2015002 (ML15219A175), that the corrective actions imposed by the RCA appeared to correctly identify and adequately address the root cause and contributing causes of the cross-cutting issue. However, since most of the corrective actions were put in place during the second quarter of 2015, the inspectors determined that additional monitoring was required to assess sustainability.

During the third and fourth quarters of 2015, the inspectors assessed the sustainability of the corrective actions identified in RCA. The inspectors reviewed, among other documentation: CRs, IODs, PODs, PORs, management review committee (MRC)reports, work packages, procedures, and temporary modifications. The inspectors observed, among other activities: plan of the day meetings, end of the day meetings, MRC meetings, pre-job briefs, post-job critiques, operations shift manager turnovers, beginning of shift briefs, end of shift briefs, in plant work activities, control room activities, outage control center activities and work control center activities. During 2015, the inspectors identified eight findings, with seven associated NCVs of very-low safety significance, and one associated violation of low to moderate safety significance, where human performance was identified as the major causal factor for the findings. However, in all instances, cross-cutting aspect H.13, a consistent and systematic approach to decision making, was not identified as the major causal factor. As such, the inspectors determined that the corrective actions to improve human performance associated with cross-cutting aspect H.13 appeared appropriate and sustainable.

This review constituted one in-depth problem identification and resolution sample as defined in IP 71152-06.

b. Findings

No findings were identified.

.5 Annual Follow-up of Selected Issues: Troubleshooting Process Associated with Residual

Heat Removal Service Water Heat Exchanger Outlet Valves Dual Indication

a. Inspection Scope

The inspectors reviewed the licensees problem identification and resolution actions associated with troubleshooting the dual indication when full closed of the RHRSW heat exchanger outlet throttle valves, MO2046 and MO1947. The licensee appeared to have completely and accurately identified the problem in a timely manner commensurate with the problem significance and ease of discovery. The licensee appeared to have adequately addressed operability and reportability issues. The licensee appeared to have adequately considered extent of condition and generic implications. The licensee appeared to have classified and prioritized the resolution of the problem commensurate with its safety significance. The licensee appeared to have identified corrective actions that were appropriately focused to correct the problem. Documents reviewed are listed in the Attachment to this report.

This review constituted one in-depth problem identification and resolution sample as defined in IP 71152-06.

b. Findings

No findings were identified.

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

.1 (Closed) Licensee Event Report 05000331/2015-004-00:

Both Doors in Secondary Containment Airlock Opened Concurrently This event, which occurred on August 27, 2015, involved the simultaneous opening of two doors (Door 225 and 227) while workers were traversing through a secondary containment access airlock. The doors being open at the same time caused a failure to meet the TS Surveillance Requirement 3.6.4.1.2 to verify that either the outer or inner door(s) in each secondary containment are closed. The condition also caused secondary containment to be considered inoperable per TS Limiting Condition for Operation (LCO) 3.6.4.1. The workers immediately closed the doors allowing TS Surveillance Requirement 3.6.4.1.2 to be met. These actions were taken within the four hours allowed by TS. As a result, no violation of NRC requirements occurred. In addition to previous corrective actions instructing personnel who were accessing or leaving the air lock to wait 2 seconds after activating the interlock before opening the door, cameras were installed at Door 228 on the reactor building side and at Door 225 on the access control point side. Monitors showing the view of the opposite camera were installed at these locations. Personnel were instructed on how to use the monitors to prevent simultaneous airlock access. Also, Door 227 was posted as emergency use only. Documents reviewed 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. Operation of an Independent Spent Fuel Storage Installation at Operating Plants

a. Inspection Scope

The inspectors conducted document reviews, held discussions with licensee staff, and performed a walk-down of the Independent Spent Fuel Storage Installation (ISFSI) to verify compliance with the applicable Certificate of Compliance (CoC), TS, UFSAR, and approved ISFSI procedures. During the walk-down, the material condition of the ISFSI pad and horizontal storage modules were evaluated.

Site procedures were reviewed to verify that adequate controls were in place to monitor the dose resulting from the operation of the ISFSI. The inspectors reviewed several routine surveys performed by the licensee around the pad and conducted independent surveys to verify dose rates. Additionally, the inspector reviewed the associated procedures for unloading a dry fuel storage canister, should that be necessary.

Condition reports and the associated follow-up actions were reviewed to determine whether corrective actions were adequate and conducted in a timely manner to correct the issues. In addition, a number of documents related to 10 CFR 72.48, Changes, Tests, and Experiments, were reviewed, specifically those associated with the operation of the ISFSI.

b. Findings

(1) Certificate of Compliance 1004 Updated Final Safety Analysis Report Revision Control

Introduction:

An unresolved item (URI) was identified by the inspectors regarding whether the appropriate cask UFSAR revision was being used for the cask amendments in service.

Description:

The inspectors identified that the licensee loaded and currently monitored the first campaign dry fuel storage casks in accordance with TN NUHOMS CoC 1004, Amendment 8. The licensee then loaded and currently monitored the second campaign dry fuel storage casks in accordance with CoC 1004, Amendment 9. Amendment 8 to CoC 1004 was initially issued with UFSAR Revision 9 and Amendment 9 was issued with UFSAR Revision 10. Using the 10 CFR 72.48, Changes, Tests, and Experiments, process, the licensee reconciled both amendments UFSARs into one UFSAR revision.

Specifically, both casks were being monitored to TN NUHOMS UFSAR Revision 11.

UFSAR Revision 11 was issued upon approval of Amendment 10. The inspectors questioned whether it was acceptable to have two different cask amendments being monitored by one UFSAR. NRC Region III requested assistance from the NRCs Division of Nuclear Materials Safety and Safeguards to determine whether a regulatory requirement would prohibit this action. Guidance was also requested on whether the UFSARs are specific to an amendment in service or if the latest UFSAR revision can be used with an older amendment. (URI 07200032/2015001-01; Certificate of Compliance 1004 Updated Final Safety Analysis Report Revision Control)

4OA6 Management Meetings

Exit Meeting Summary

On January 25, 2016, the inspectors exited with Mr. T. Vehec, Site Vice President, and other members of the licensee staff. The licensee acknowledged the issue presented.

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

.2 Interim Exit Meetings

Interim exits were conducted for:

• The results of the ISFSI operational inspection were presented on November 24, 2015, to Mr. M. Davis;

• The inspection results for the area of radiation monitoring instrumentation with Mr. P. Hansen, Plant General Manager, on December 4, 2015;

• The Annual Review of EAL and Emergency Plan Changes with Mr. M. Fritz, Emergency Preparedness Manager, on December 8, 2015; and

• The results of the baseline inspections to Mr. S. Brown, acting Site Vice President, on January 7, 2016.

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. The licensee acknowledged the issues presented.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

T. Vehec, Site Vice President

P. Hansen, Plant General Manager

S. Brown, Site Engineering Director

M. Davis, Licensing Manager

M. Fritz, Emergency Preparedness Manager

B. Simmons, Nuclear Oversight Manager

R. Wheaton, Operations Director

R. Porter, Radiation Protection Manager

D. Olsen, Chemistry Manager

J. Schwertfeger, Security Manager

C. Hill, Training Manager

B. Murrell, Licensing Senior Engineer

L. Swenzinski, Licensing Senior Engineer

P. Collingsworth, System Engineering

D. Church, Engineering Programs Manager

B. Clark, Senior System Engineer

U.S. Nuclear Regulatory Commission

K. Stoedter, Chief, Reactor Projects Branch 1

M. Chawla, Project Manager, NRR

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000331/2015004-01 NCV Failure to Scope Safety Related and Nonsafety Related Breaker Into the Maintenance Rule (Section 1R12)

05000331/2015004-02 NCV Failure to Declare High Pressure Coolant Injection and Reactor Core Isolation Cooling Inoperable when the High Pressure Coolant Injection and Reactor Core Isolation Cooling Pump Suction Swap Logic was Inoperable (Section IR15)

05000331/2015004-03 NCV Failure to Satisfy 10 CFR Part 50.73 Reporting Requirements for a Condition Prohibited by Technical Specifications and for a Condition that Could Have Prevented Fulfillment of a Safety Function (Section 1R15)

05000331/2015004-04 FIN Failure to Follow Temporary Configuration Control Procedure (Section 1R18)

200032/2015001-01 URI Certificate of Compliance 1004 Updated Final Safety Analysis Report Revision Control (Section 4OA5)

Closed

05000331/2015004-01 NCV Failure to Scope Safety Related and Nonsafety Related Breaker Into the Maintenance Rule (Section 1R12)

05000331/2015004-02 NCV Failure to Declare High Pressure Coolant Injection and Reactor Core Isolation Cooling Inoperable when the High Pressure Coolant Injection and Reactor Core Isolation Cooling Pump Suction Swap Logic was Inoperable (Section IR15)

05000331/2015004-03 NCV Failure to Satisfy 10 CFR Part 50.73 Reporting Requirements for a Condition Prohibited by Technical Specifications and for a Condition that Could Have Prevented Fulfillment of a Safety Function (Section 1R15)

05000331/2015004-04 FIN Failure to Follow Temporary Configuration Control Procedure (Section 1R18)

05000331/2015004-00 LER Both Doors in Secondary Containment Airlock

Opened

Concurrently (Section 71153)

Discussed

None.