Text

NRC Problem Identification and Resolution Inspection Report 05000298/2017010
	ML17219A742
Person / Time
Site:	Cooper
Issue date:	08/07/2017
From:	Thomas Hipschman; Division of Reactor Safety IV
To:	Dent J; Nebraska Public Power District (NPPD)
	Hipschman T
References
	IR 2017010
	Download: ML17219A742 (40)
	v • d • e

UNITED STATES

NUCLEAR REGULATORY COMMISSION

REGION IV

1600 E. LAMAR BLVD.

ARLINGTON, TX 76011-4511

August 7, 2017

Mr. John Dent, Vice President-Nuclear

and CNO

Nebraska Public Power District

Cooper Nuclear Station

72676 648A Avenue

P.O. Box 98

Brownville, NE 68321

SUBJECT: COOPER NUCLEAR STATION - NRC PROBLEM IDENTIFICATION AND

RESOLUTION INSPECTION REPORT 05000298/2017010

Dear Mr. Dent:

On June 29, 2017, the U.S. Nuclear Regulatory Commission (NRC) completed a problem

identification and resolution inspection and a follow-up inspection for multiple Severity Level IV

violations at your Cooper Nuclear Station, and discussed the results of this inspection with

Mr. J. Kalamaja, General Manager Plant Operations and then-acting Vice President and Chief

Nuclear Officer, and other members of your staff. The results of this inspection are documented

in the enclosed report.

The NRC inspection team reviewed the stations corrective action program and the stations

implementation of the program to evaluate its effectiveness in identifying, prioritizing, evaluating,

and correcting problems, and to confirm that the station was complying with NRC regulations.

Based on the samples reviewed, the team concluded that your staffs performance in each of

these areas was adequate to support nuclear safety. However, the team identified some

substantial challenges with the stations implementation of some parts of the corrective action

program and its associated processes. These challenges were primarily in your managements

oversight of the corrective action program, the stations screening processes to determine the

significance of issues, and your staffs implementation of operability determination processes.

The team also evaluated the stations processes for use of industry and NRC operating

experience information, and the effectiveness of the stations audits and self-assessments.

Based on the samples reviewed, the team determined that your staffs performance in each of

these areas adequately supported nuclear safety.

The team reviewed the stations programs to establish and maintain a safety-conscious work

environment, and interviewed station personnel to evaluate the effectiveness of these programs.

Based on the teams observations and the results of these interviews, the team found no

evidence of challenges to your organizations safety-conscious work environment. Your

employees appeared willing to raise nuclear safety concerns through at least one of the several

means available.

J. Dent 2

Finally, the team performed a second inspection to follow up on three Severity Level IV

violations received by Cooper during calendar year 2015. This reinspection followed the

stations failure to meet the objectives of NRC Inspection Procedure 92723 during the first

attempt to perform the inspection in June 2016, which was documented in inspection

report 05000298/2016002. Based on additional analysis performed by the station following the

first inspection attempt, the team determined that the station has now met the objectives. This

inspection activity is now complete; details are documented in the enclosed report.

NRC inspectors documented four findings of very low safety significance (Green) in this report,

all of which involved violations of NRC requirements. Additionally, NRC inspectors documented

one Severity Level IV violation with no associated finding. The NRC is treating all five of these

violations as non-cited violations (NCVs) consistent with Section 2.3.2.a of the Enforcement

Policy.

If you contest any of these violations or their significance, 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

copies to the Regional Administrator, Region IV; the Director, Office of Enforcement; and the

NRC resident inspector at the Cooper Nuclear Station.

If you disagree with a cross-cutting aspect assignment 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 U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk,

Washington, DC 20555-0001; with copies to the Regional Administrator, Region IV; and the

NRC resident inspector at the Cooper Nuclear Station.

This letter, its enclosure, and your response (if any) will be made available for public inspection

and copying at http://www.nrc.gov/reading-rm/adams.html and at the NRC Public Document

Room in accordance with 10 CFR 2.390, Public Inspections, Exemptions, Requests for

Withholding.

Sincerely,

/RA/

Thomas R. Hipschman, Team Leader

Inspection Program and Assessment Team

Division of Reactor Safety

Docket No.: 50-298

License No: DPR-46

Enclosure:

Inspection Report 05000298/2017010

w/ Attachment: Supplemental Information

cc w/ encl: Electronic Distribution

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket: 50-298

License: DPR-46

Report: 05000298/2017010

Licensee: Nebraska Public Power District

Facility: Cooper Nuclear Station

Location: 72676 648A Ave

Brownville, NE

Dates: June 12 through June 29, 2017

Inspectors: E. Ruesch, J.D., Senior Reactor Inspector (Team Lead)

H. Freeman, Senior Reactor Inspector

G. Pick, Senior Reactor Inspector

P. Voss, Senior Resident Inspector

C. Young, Senior Project Engineer

Approved By: Thomas R. Hipschman, Team Leader

Inspection Program and Assessment Team

Division of Reactor Safety

Enclosure

SUMMARY

IR 05000298/2017010; 06/12/2017 - 06/29/2017; COOPER NUCLEAR STATION; PROBLEM

IDENTIFICATION AND RESOLUTION (BIENNIAL)

The inspection activities described in this report were performed between June 12, 2017 and

June 29, 2017, by four inspectors from the NRCs Region IV office and the resident inspector at

Cooper Nuclear Station. The report documents four findings of very low safety significance

(Green), all of which involved violations of NRC requirements. Additionally, NRC inspectors

documented in this report one Severity Level IV violation with no associated finding. The

significance of inspection findings is indicated by their color (Green, White, Yellow, or Red),

which is determined using Inspection Manual Chapter 0609, Significance Determination

Process. Their cross-cutting aspects are determined using Inspection Manual Chapter 0310,

Aspects Within the Cross-Cutting Areas. Violations of NRC requirements are dispositioned in

accordance with the NRC Enforcement Policy. The NRC's program for overseeing the safe

operation of commercial nuclear power reactors is described in NUREG-1649, Reactor

Oversight Process.

Assessment of Problem Identification and Resolution

Based on its inspection sample, the team concluded that the licensee maintained a corrective

action program in which individuals generally identified issues at an appropriately low threshold.

However, once entered into the corrective action program, the licensee had some substantial

programmatic challenges with evaluating these issues appropriately and timely, commensurate

with their safety significance. These challenges were primarily in station managements

oversight of the corrective action program, the stations screening processes to determine the

significance of issues, and timely implementation of operability determination processes. With

the exception of some corrective actions to preclude repetition that lacked sustainability, the

licensees corrective actions were generally effective, addressing the causes and extents of

condition of problems.

The licensee appropriately evaluated industry operating experience for relevance to the facility

and entered applicable items in the corrective action program. The licensee incorporated

industry and internal operating experience in its root cause and apparent cause evaluations.

The licensee performed effective and self-critical nuclear oversight audits and self-assessments.

The licensee maintained an effective process to ensure significant findings from these audits

and self-assessments were addressed.

The licensee maintained a safety-conscious work environment in which personnel were willing

to raise nuclear safety concerns without fear of retaliation.

Cornerstone: Mitigating Systems

Green. The team identified a non-cited violation of Title 10 of the Code of Federal

Regulations (10 CFR) Part 50, Appendix B, Criterion XVI, Corrective Action, for the

licensees failure to assign corrective actions to preclude repetition of a significant condition

adverse to quality associated with the loss of the high pressure coolant injection system.

Specifically, between July 28, 2016, and June 29, 2017, the licensee failed to assign or

complete corrective actions to prevent recurrence to address the failure of a relay coil that

resulted in a loss of safety function for the single train high pressure coolant injection

system. Corrective actions to restore compliance included reevaluation of the corrective

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actions assigned to the root cause of the condition and the creation of corrective actions to

prevent recurrence for the condition. The licensee entered this deficiency into the corrective

action program as Condition Report CR 17 03544.

The licensees failure to assign corrective actions to preclude repetition of a significant

condition adverse to quality, in violation of 10 CFR 50, Appendix B, Criterion XVI, was a

performance deficiency. The performance deficiency was evaluated using Inspection

Manual Chapter 0612, Appendix B, Issue Screening, dated September 7, 2012, and was

associated with the Mitigating Systems cornerstone. The team determined that the

performance deficiency was more than minor, and therefore a finding, because if left

uncorrected, the performance deficiency would have the potential to lead to a more

significant safety concern. Specifically, the licensees failure to assign corrective actions to

preclude repetition of a significant condition adverse to quality could reasonably result in the

condition recurring and creating more safety-significant equipment failures. Using

Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process

(SDP) for Findings At-Power, dated June 19, 2012, the inspectors determined that the

finding had very low safety significance (Green) because it: was not a design deficiency; did

not represent a loss of system and/or function; did not represent an actual loss of function;

did not represent an actual loss of function of at least a single train for longer than its

technical specification allowed outage time; and did not result in the loss of a high safety-

significant non-technical specification train. The finding had a cross-cutting aspect in the

area of problem identification and resolution associated with resolution, because the

licensee failed to ensure that the organization took effective corrective actions to address

issues in a timely manner commensurate with their safety significance [P.3].

(Section 4OA2.5)

Green. The team identified a Green non-cited violation of Technical Specification 5.4.1.a,

for the licensees multiple failures to immediately evaluate operability of degraded or

nonconforming conditions. The team identified multiple examples of these operability

determinations not being performed within one shift, as required by procedure. Further,

aggregate data indicated routine noncompliance with procedural requirements to document

operability immediately and without delay. The licensee entered this violation into its

corrective action program as Condition Report CR-CNS-2017-03937, and began evaluating

actions to restore compliance.

Multiple failures to perform immediate operability determinations timely as required by

station procedures is a performance deficiency. This performance deficiency is more than

minor because it was associated with the equipment performance attribute of the mitigating

systems cornerstone and adversely affected the cornerstone objective to ensure the

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

undesirable consequences. Using Inspection Manual Chapter 0609, Appendix A, dated

June 19, 2012, the inspectors determined that the finding had very low safety significance

(Green) because it did not result in the loss of operability or functionality of any system or

train. This finding has a consistent process cross-cutting aspect in the human performance

cross-cutting area because operators failed to use a consistent, systematic approach to

make decisions regarding operability using the organizations well-defined decision making

process (H.13). (Section 4OA2.5)

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Green. The team identified a Green non-cited violation of 10 CFR 50, Appendix B,

Criterion XVI, for the licensees programmatic failure to promptly identify adverse trends and

enter them into the corrective action program. Often, when adverse trends were identified,

they were addressed using informal processes. This was particularly the case for

safety culture-related trends such as adverse trends in organizational behaviors. The

licensee entered this violation into its corrective action program as Condition

Report CR-CNS-2017-03938, and took action to formalize identification processes for

potential adverse trends.

The programmatic failure to promptly identify adverse trends as required by station

procedures was a performance deficiency. This performance deficiency is more than minor

because if left uncorrected, it has the potential to become a more significant safety concern.

Specifically, failure to arrest an adverse trend, particularly in organizational behaviors, could

lead to increased likelihood of a worker-induced initiating event or a failure to effectively

mitigate an accident. Using Inspection Manual Chapter 0609, Appendix A, dated June 19,

2012, the inspectors determined that the finding had very low safety significance (Green)

because it did not result in the loss of operability or functionality of any system or train. This

finding has a trending cross-cutting aspect in the problem identification and resolution cross-

cutting area because the organization failed to use available information in the aggregate to

identify programmatic and common cause issues (P.4). (Section 4OA2.5)

Green. The team identified a non-cited violation of 10 CFR 50.65(a)(1)/(a)(2), for the

licensees failure to perform an a(1) evaluation and establish a(1) goals when the

No. 2 diesel generator a(2) preventive maintenance demonstration became invalid.

Specifically, on April 28, 2017, the No. 2 diesel generator exceeded its performance criteria

when it experienced a second maintenance rule functional failure, but the licensee failed to

perform an associated a(1) evaluation. The licensee had failed to appropriately evaluate a

February 4, 2017, failure associated with the No. 2 diesel generator jacket water heater

failure in the Maintenance Rule Program and, as a result, the site failed to evaluate and

monitor the equipment under 10 CFR 50.65(a)(1) as required. Corrective actions taken by

the licensee to restore compliance included reevaluation of the February 4, 2017, functional

failure and performance of an a(1) evaluation. The issue was entered into the licensees

corrective action program as Condition Report CR-17-03930.

The licensees failure to monitor the No. 2 diesel generator in accordance with the

requirements of 10 CFR 50.65(a)(1), due to incorrectly evaluating one maintenance rule

functional failure, in violation of 10 CFR 50.65(a)(1)/(a)(2), was a performance deficiency.

The inspectors screened the performance deficiency using Inspection Manual

Chapter 0612, Appendix B, Issue Screening, dated September 7, 2012, and determined

that the issue was more than minor, and therefore a finding, because it was associated with

the equipment performance attribute of the Mitigating Systems cornerstone and adversely

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

that respond to initiating events. Using Inspection Manual Chapter 0609, Appendix A, The

Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, the

inspectors determined that the finding had very low safety significance (Green) because it:

was not a design deficiency; did not represent a loss of system and/or function; did not

represent an actual loss of function; did not represent an actual loss of function of at least a

single train for longer than its technical specification allowed outage time; and did not result

in the loss of a high safety-significant nontechnical specification train. The finding had a

cross-cutting aspect in the area of problem identification and resolution associated with

evaluation, because the licensee failed to ensure that the organization thoroughly evaluated

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the No. 2 diesel generator issues to ensure that resolutions addressed causes and extent of

conditions commensurate with their safety significance [P.2]. (Section 4OA2.5)

Other Findings and Violations

Severity Level IV. The team identified a violation of 10 CFR 21.21(a), for the licensees

failure to adopt appropriate procedures to evaluate deviations and failures to comply to

identify those associated with substantial safety hazards. Specifically, Procedure EN-LI-108,

10 CFR 21 Evaluations and Reporting, Revision 5C0, was inadequate to ensure that the

correct reportability call was made for a manufacturing flaw discovered in a relay that had

resulted in a loss of safety function for the high pressure coolant injection system on

April 25, 2016. In particular, the procedure (1) led the licensee to incorrectly conclude that a

substantial safety hazard could not be created, (2) allowed a limited extent of condition in

performing the substantial safety hazard evaluation such that similarly dedicated parts were

not included in the scope, and (3) included incorrect guidance in Attachment 9.3. Corrective

actions to restore compliance included re-evaluation of the defect under Part 21

requirements and a procedure adequacy review of the EN-LI-108-01 procedure. The

licensee entered this issue into the corrective action program as Condition

Reports CR-17-03936 and CR-17-04143.

The failure to adopt appropriate procedures to evaluate deviations and failures to comply to

identify those associated with substantial safety hazards, in violation of 10 CFR 21.21(a),

was a performance deficiency. The NRCs reactor oversight process considers the safety

significance of findings by evaluating their potential safety consequences. Using Inspection

Manual Chapter 0612, Appendix B, Issue Screening, dated September 7, 2012, the team

determined that the performance deficiency was of minor safety significance under the

reactor oversight process because it involved a failure to make a report; however the

underlying equipment failure was previously evaluated as having very low safety

significance. The traditional enforcement process separately considers the significance of

willful violations, violations that impact the regulatory process, and violations that result in

actual safety consequences. Traditional enforcement applied to this finding because it

involved a violation that impacted the regulatory process. The team used the NRC

Enforcement Policy, dated November 1, 2016, to determine the significance of the violation.

The inspectors determined that the violation was similar to Examples 6.9.d.10 and 6.9.d.13

of the Enforcement Policy, because although the procedure resulted in an inadequate

reportability review and the issue was not reported as a manufacturing flaw, the licensee

had reported some aspects of the event under the requirements of 10 CFR 50.73. As a

result, the team determined that the violation should be classified as a Severity Level IV

violation. Cross-cutting aspects are not assigned to traditional enforcement violations.

(Section 4OA2.5)

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REPORT DETAILS

4. OTHER ACTIVITIES (OA)

4OA2 Problem Identification and Resolution (71152)

The team based the following conclusions on a sample of corrective action documents that were

open during the assessment period, which ranged from June 24, 2015, to the end of the on-site

portion of this inspection on June 29, 2017.

.1 Assessment of the Corrective Action Program Effectiveness

a. Inspection Scope

The team reviewed approximately 220 Condition Reports (CRs), including associated

root cause analyses and apparent cause evaluations, from approximately 16,000 that

the licensee had initiated or closed between June 2015 and June 2017. The majority of

these (over 15,000) were lower-level condition reports that did not require cause

evaluations. The inspection sample focused on higher-significance condition reports for

which the licensee evaluated and took actions to address the cause of the condition. In

performing its review, the team evaluated whether the licensee had properly identified,

characterized, and entered issues into the corrective action program, and whether the

licensee had appropriately evaluated and resolved the issues in accordance with

established programs, processes, and procedures. The team also reviewed these

programs, processes, and procedures to determine if any issues existed that may impair

their effectiveness.

The team reviewed a sample of performance metrics, system health reports, operability

determinations, self-assessments, trending reports and metrics, and various other

documents related to the licensees corrective action program. The team evaluated the

licensees efforts in determining the scope of problems by reviewing selected logs, work

orders, self-assessment results, audits, system health reports, action plans, and results

from surveillance tests and preventive maintenance tasks. The team reviewed daily

CRs and attended the licensees performance improvement review group (PRG), PRG

pre-screen, operations focus, and aggregate performance review (APRM) meetings.

The team assessed the licensees reporting threshold and prioritization efforts, to

observe the corrective action programs interfaces with the operability assessment and

work control processes. The teams review included an evaluation of whether the

licensee considered the full extent of cause and extent of condition for problems, as well

as a review of how the licensee assessed generic implications and previous occurrences

of issues. The team assessed the timeliness and effectiveness of corrective actions,

completed or planned, and looked for additional examples of problems similar to those

the licensee had previously addressed. The team conducted interviews with plant

personnel to identify other processes that may exist where problems may be identified

and addressed outside the corrective action program.

The team reviewed corrective action documents that addressed past NRC-identified

violations to evaluate whether corrective actions addressed the issues described in the

inspection reports. The team reviewed a sample of corrective actions closed to other

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corrective action documents to ensure that the ultimate corrective actions remained

appropriate and timely.

The team considered risk insights from both the NRCs and Coopers risk models to

focus the sample selection and plant tours on risk-significant systems and components.

The team focused a portion of its sample on the primary containment and high pressure

coolant injection systems, which the team selected for a five-year in-depth review. The

team conducted walk-downs of this system and other plant areas to assess whether

licensee personnel identified problems at a low threshold and entered them into the

corrective action program.

b. Assessments

During the inspection period, the licensee significantly revised its corrective action

program to incorporate two major industry initiatives. Among other enhancements,

these revisions incorporated three significant changes to the program. First, the term

adverse condition was introduced and defined to clarify when conditions or issues are

required to be formally handled through the quality-related corrective action program, or

when they can be handled instead through less-rigorous non-quality processes.

Second, apparent cause evaluations (ACEs) were eliminated as a defined product and

replaced with adverse condition assessments (ACAs) which are procedurally more

flexible. The new ACA process allows station leadership more latitude to determine the

appropriate level of resources to dedicate to evaluating and correcting important, but not

necessarily critical problems. Third, several management-level corrective action

program (CAP) oversight bodies were combined into a single performance improvement

review group (PRG), which now fulfills all the leadership oversight functions formerly

performed by the condition review group and the management performance review

board (MPRB). The team noted that collectively these efficiency enhancements could

improve CAP performance by allowing evaluation and corrective action resources to be

focused on the most important problems.

1. Effectiveness of Problem Identification

The team determined that most conditions that required generation of a condition

report by Procedure 0-CNS-LI-102, Corrective Action Process, had been

appropriately entered into the corrective action program. During the 24-month

inspection period, licensee staff generated and screened over 16,000 condition

reports, roughly 600 per non-outage month. All personnel interviewed by the team

understood the requirements for condition report initiation, and expressed a

willingness to enter newly identified issues into the corrective action program at a

very low threshold.

However, the team noted that the licensee did not always enter adverse conditions

identified through cognitive trending processes into the corrective action program.

The team observed several instances where apparent adverse trends were

discussed at performance improvement review group meetings, but any follow-up

actions were taken informally, and were often documented in non-CAP processes, if

at all. Further, of the 13 conditions being tracked as adverse station trends, five had

been identified, at least in part, by the NRC or another external organization. The

team determined the licensees programmatic failure to enter adverse conditions into

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the corrective action program was a more-than-minor performance deficiency; it is

further discussed in Section 4OA2.5.c of this report.

The team also noted that condition reports were not always initiated timely.

Procedure 0-CNS-LI-102 requires, CR initiation should be completed prior to the

end of the work day in which the condition was recognized, and, CR initiation

should not be excessively delayed while gathering all of the associated information.

On several occasions during the inspection, issues identified by the team were not

entered into the corrective action program until several days to two weeks later. The

licensee entered this issue into the corrective action program as Condition

Report CR-CNS-17-03937. Although this issue should be corrected, it constitutes a

violation of minor significance that is not subject to enforcement action in accordance

with Section 2 of the Enforcement Policy.

Overall, with the exception of organizational and programmatic trends, the team

concluded that the licensee generally maintained a low threshold for the formal

identification of problems and entry of those problems into the corrective action

program for evaluation, though entry was sometimes delayed.

2. Effectiveness of Prioritization and Evaluation of Issues

The team identified multiple concerns with the licensees prioritization and evaluation

processes, or its implementation of these processes. These concerns were primarily

focused in the areas of the licensees condition report screening process,

adverse/non-adverse determinations, immediate operability determination timeliness

and documentation quality, and extent of condition reviews performed during cause

evaluations. Each of these areas is briefly addressed below.

Condition Report Screening

The team noted that the licensees process for initial screening of condition reports

for significance differs significantly from standard industry practices. Preliminary

significance of condition reports is initially assigned by a single member of the

corrective action and assessment (CA&A) group. Significance assigned by CA&A is

then reviewed in a pre-screening meeting, which is procedurally required, but lacks

the formalities associated with most other quality processes, before being screened

by management at PRG.

The team noted that the CA&A pre-screen appeared to introduce a confirmation

bias in the pre-screen meeting. Further, the pre-screen meeting has no quorum

requirement and inconsistent membership. The station has no qualification

requirement for participants in the pre-screen meeting, and some key groups are not

always represented. Though departments at Cooper generally have department

performance improvement coordinators (DPICs), who act as CAP subject-matter

experts for their groups, these DPICs do not represent their departments at the CR

pre-screen. Additionally, during the several pre-screen meetings observed by the

team, meeting participants did not reference the CR screening procedure or appear

to have a copy available.

At the beginning of the on-site inspection period, the team observed that the PRG

also lacked formality. Similar to the observation above regarding cognitive

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trending, this lack of a rigorous process for ensuring PRG decisions were recorded

and formally tracked appeared to contribute to some intended actions not being

accomplished. Further, the team noted that an observed inconsistent quality of

cause evaluations and adverse condition assessments was likely at least partially

attributable to this lack of rigor in PRG review.

Adverse/Non-adverse Determinations

The team noted that for two categories of adverse conditions, as defined by

Procedure 0-CNS-LI-102, the licensee was inconsistent in its classification,

sometimes designating them non-adverse. The first category, related to the above-

noted lack of rigor in documenting and completing follow-up actions from PRG

decisions, was a failure to consistently identify safety-culture-related adverse trends

as adverse conditions as required by Procedure 0-CNS-LI-102. When behavior-

related adverse trends were identified through discussions at PRG, follow-up actions

to confirm or refute a suspected trend, or to address a known trend, were often taken

informally or through the use of a non-CAP administrative process.

The second category was failures of quality components or subcomponents of

safety-related structures, systems, or components (SSCs) whose failure did not

necessarily directly affect the safety function of the SSC. For example, the licensee

has experienced multiple failures of rod-full-out lights, which are part of the digital rod

position indication system as described in the Updated Safety Analysis Report

(USAR). The licensee usually classified failures of these components as non-

adverse, contrary to the requirements of Procedure 0-CNS-LI-102 (e.g., Condition

Reports CR-CNS-2016-09041 and CR-CNS-2017-03481.) A similar incorrect

classification was also the subject of a minor violation described in the discussion of

an annual problem identification and resolution sample in NRC inspection

report 2016001 (ADAMS Accession No. ML16119A441.) In that case, operators

initially did not recognize indications of a leaking scram outlet valve to be a condition

requiring CR initiation; and once a CR was eventually written, it was improperly

classified as non-adverse.

Additionally, over the previous two years, the NRC has issued three non-cited

violations related to operators failure to recognize degraded or nonconforming

conditionson June 25, 2015, NCV 2015008-03 documented main steam isolation

valve (MSIV) limit switch preconditioning; on June 30, 2016, NCV 2016002-01

documented failure of a ball valve in the traversing in-core probe system; and on

September 30, 2016, NCV 2016003-02 documented operators defeating systems

designed to mitigate internal flooding.

The team determined that the licensees failure to recognize degraded or

nonconforming conditions, and to document some types of conditions as adverse, as

required by corrective action program procedures, was a performance deficiency.

The performance deficiency is subsumed in NCV 2017010-03, documented in

Section 4OA2.5.c of this report, and will not be separately dispositioned.

Immediate Operability Determinations

The team reviewed a number of condition reports that included or should have

included immediate operability determinations to assess the quality, timeliness, and

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prioritization of these determinations. The team identified a number of recent

instances where these immediate operability determinations were untimely or

otherwise not performed in accordance with procedure: The team determined that

the failure to timely screen adverse equipment conditions for operability was a more-

than-minor performance deficiency; it is further discussed in Section 4OA5.5.b of this

report.

Extent of Condition Reviews

The team noted numerous opportunities for improvement in the licensees

implementation of extent of cause and extent of condition analyses as part of its

cause evaluation (and now adverse condition analysis) processes. Multiple lower-

level examples were discussed with licensee personnel during the inspection; two

more significant examples follow.

In June 2016 the NRC implemented Inspection Procedure 92723 at Cooper in

response to three Severity Level IV violations received during calendar year 2015.

One of the goals of that inspection was to ensure the licensee had identified the

extent of cause and extent of conditions of the three violations impacting the

regulatory process. The inspector performing that inspection documented several

inadequacies with the licenses extent of condition and cause evaluations. These

are documented in NRC inspection report 2016002 (ML16211A197). A reinspection

performed as part of this problem identification and resolution inspection determined

that the revised evaluations were adequate to satisfy the inspection objectives,

though some gaps still existed. This is further discussed in Section 4OA5 below.

Following the failure of an Allen-Bradley rotary relay that caused loss of function of

the high-pressure coolant injection (HPCI) system, the licensee performed a failure

analysis under Condition Report CR-CNS-2016-02281. This analysis determined

that the failure had been caused by a faulty solder joint that, because of an

inadequate dedication plan, had not been detected by a vendor during component

dedication. The licensees extent of condition only examined other relays of the

same lot; it did not look for other similar components that may have been dedicated

using similarly inadequate dedication criteria. This evaluation is also the subject of

NCV 2017010-05, documented in Section 4OA2.5.e of this report.

Other Observations Related to Prioritization and Evaluation of Adverse Conditions

On February 4, 2017, the No. 2 emergency diesel generator jacket water heater

failed, after having been in service for 39 years with no preventive maintenance or

replacement schedule. This failure resulted in the inability to maintain the system

above 100 degrees Fahrenheit, as required by system design to support fast-start

capability. This was the second functional failure of the diesel generator during the

cycle, which exceeded maintenance rule performance criteria, but the licensee failed

to perform required monitoring. This issue is further discussed as NCV 2017010-04

in Section 4OA2.5.d of this report.

Finally, the team identified three minor performance deficiencies associated with

prioritization and evaluation, at least two of which were also violations of NRC

requirements:

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Following catastrophic failure of the control room emergency filtration system

(CREFS) fan bearing in October 2016 which resulted in inoperability of an

important safety system, the licensee failed to quarantine the failed parts as

required by Procedure 0-CNS-LI-118, Step 6.1.4. This resulted in the inability

to perform failure modes and effects analysis as required by Procedure

7.0.1.7, Step 1.1. In its cause evaluation for the bearing failure, performed

under Condition Report CR-CNS-2016-07426, the licensee failed to take

actions to ensure that parts were quarantined in the future. The team

determined this was a violation of Criterion V of 10 CFR 50, Appendix B,

which was minor because it was an isolated noncompliance and the failure

has not recurred. However, if a repeat failure were to occur by a similar

failure mechanism, potentially indicating that the lack of failure analysis

caused actions to preclude repetition to be ineffective, the NRC may

reevaluate this performance deficiency.

Also in Condition Report CR-CNS-2016-07426, the licensee noted that the

CREFS fans were classified as criticality level II (Crit-II) for the purpose of

scheduling preventive maintenance. The team noted that this was contrary to

the guidance contained in system engineering Desktop Guide 98-03-02,

Revision 5, which is used by engineering to determine component criticality,

and which indicates that these components should be Crit-I. Further, the

desktop guide itself, which is not controlled as a quality procedure, is

inconsistent with Procedure 7.0.14, Preventive Maintenance Program,

which is quality-related. The team determined that this failure to

appropriately classify component criticality as required by procedure was a

violation of Criterion V of 10 CFR 50, Appendix B. This violation was minor

because the maintenance schedule as implemented met the requirements for

Crit-I components.

In Condition Report CR-CNS-2017-00610, the licensee identified incorrect

mounting bolts installed in an emergency diesel generator fuel injector. The

documented basis for operability included several assumptions regarding the

bolting material. Queries to the vendor revealed that assumptions made in

the initial operability determination about the bolting material were incorrect.

After engineers received more accurate design information, and better

identified the type of bolts that likely were installed, they failed to initiate a

new condition report to ensure operability was addressed using the most up-

to-date information, as required by 0-CNS-LI-012, Revision 7, Step 8.1.1.1.

Although these three issues should be corrected, they constitute violations of minor

significance that are not subject to enforcement action in accordance with Section 2

of the Enforcement Policy.

Overall, the team determined that the licensees process for screening and

prioritizing issues that had been entered into the corrective action program supported

nuclear safety, though some improvements are warranted.

3. Effectiveness of Corrective Actions

In general, the corrective actions identified by the licensee to address adverse

conditions were effective. However, the team noted some challenges in the

11

licensees development and implementation of sustainable corrective actions for

some significant conditions adverse to quality.

Station procedures require corrective actions to preclude repetition (CAPRs) to be

developed during a root cause evaluation for all significant conditions adverse to

quality. The development and implementation of these CAPRs is meant to fulfil

quality assurance requirements of Criterion XVI of 10 CFR 50, Appendix B. The

team noted a number of instances where CAPRs did not appear adequate to

preclude repetition of the subject event:

Under Condition Report CR-CNS-2016-08744, licensee staff performed a

root cause evaluation to determine the causes of a December 7, 2016,

misalignment of the control room emergency air filtration system (CREFS).

The CAPRs developed under this evaluation focused on the actions of an

individual control room operator, and did not address broader organizational

and programmatic causes for the operators inadvertent actions.

Under Condition Report CR-CNS-2016-07426, licensee staff evaluated the

failure of a catastrophic bearing failure of CREFS fan A on October 23, 2016.

The CAPR developed in this root cause evaluation was to revise a

maintenance plan to ensure proper reassembly following maintenance.

However, the revisions lacked the specificity necessary to prevent the same

incorrect component reassembly after future maintenance. (Verify fan

bearings engaged with shaft.) Further, there was no indication that the

revised steps were tied to a CAPR, a requirement to prevent future changes.

On April 25, 2016, the licensee initiated a root cause evaluation under

Condition Report CR-CNS-2016-02281 to evaluate two 2016 high pressure

coolant injection (HPCI) failures that were initially presumed to be related.

Though the failures were later determined to have different causes, the

licensee opted to evaluate both root causes in a single evaluation, with a

separate cause determined for each failure. A CAPR was assigned for one

of the two root causes, but not for the other. This example is further

discussed as NCV 2017010-01 in Section 4OA2.5.a of this report.

Overall, the team concluded that the licensee generally identified and implemented

effective corrective actions for the problems evaluated in the corrective action

program, though additional focus on root-cause CAPRs may be warranted. Where

procedurally required, the licensee generally assessed the effectiveness of the

corrective actions appropriately and made adjustments as necessary.

.2 Assessment of the Use of Operating Experience

a. Inspection Scope

The team examined the licensees program for reviewing industry operating experience,

including reviewing the governing procedures. The team reviewed a sample of

10 industry operating experience communications and the associated site evaluations

out of the 45 completed in 2017 to assess whether the licensee had appropriately

assessed the communications for relevance to the facility. The team also reviewed

assigned actions to determine whether they were appropriate.

12

b. Assessment

Overall, the team determined that the licensee appropriately evaluated industry

operating experience for its relevance to the facility. Operating experience information

was incorporated into plant procedures and processes as appropriate. The licensee was

effective in implementing lessons learned through operating experience. They took full

advantage of being part of the Entergy fleet, to give a thorough review of the operational

experience from a variety of sources. The licensees evaluations conservatively

considered operating experience from a wide variety of sources and provided

appropriate assessment. Licensee personnel ensured that significant issues were dealt

with in a thorough and timely manner. This was also true for the Part 21 process that is

within the licensees operational experience program. The team further determined that

the licensee appropriately reviewed industry operating experience when performing root

cause analysis and apparent cause evaluations.

.3 Assessment of Self-Assessments and Audits

a. Inspection Scope

The team reviewed a sample of licensee self-assessments and audits to assess whether

the licensee was regularly identifying performance trends and effectively addressing

them. The team also reviewed audit reports to assess the effectiveness of assessments

in specific areas. The specific self-assessment documents and audits reviewed are

listed in Attachment 1.

b. Assessment

Overall, the team concluded that the licensee had an effective self-assessment and audit

process. The team determined that self-assessments were self-critical and thorough

enough to identify deficiencies.

.4 Assessment of Safety-Conscious Work Environment

a. Inspection Scope

The team interviewed 51 licensee personnel45 in five focus groups and six

individually(1) to evaluate the willingness of licensee staff to raise nuclear safety

issues, either by initiating a condition report or by another method, (2) to evaluate the

perceived effectiveness of the corrective action program at resolving identified problems,

and (3) to evaluate the licensees safety-conscious work environment. The focus group

participants included personnel from operations, training, engineering, planning and

scheduling, electrical, mechanical, instrumentation, and control. At the teams request,

the licensees regulatory affairs staff selected the participants blindly from these work

groups, based partially on availability. To supplement these focus group discussions,

the team interviewed the employee concerns program manager to assess her perception

of the site employees willingness to raise nuclear safety concerns. The team reviewed

the employee concerns program case log and select case files.

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b. Assessment

1. Willingness to Raise Nuclear Safety Issues

All individuals interviewed indicated that they would raise nuclear safety concerns by

one or more of the methods available. All felt that their management was receptive

to raising nuclear safety concerns and encouraged them to do so. All of the

interviewees agreed that if they were not satisfied with the response from their

immediate supervisor, they had the ability to write a condition report or to escalate

the concern to a higher organizational level. All individuals indicated that they were

aware of changes that had been implemented earlier in the year associated with the

submittal of condition reports anonymously [anonymous concerns are now screened

by the Employee Concerns Program who either addresses the concern or directs it

to the appropriate venue]. All individuals felt that this was appropriate because most

of the anonymous condition reports had become a forum or submitting personal

character attacks that should not be viewed by the general workforce.

2. Employee Concerns Program

All interviewees were aware of the employee concerns program. Most explained that

they had heard about the program through various means, such as posters, training,

presentations, and discussion by supervisors or management at meetings. Most

interviewees stated that they would use the employee concerns program if they felt it

was necessary.

3. Preventing or Mitigating Perceptions of Retaliation

When asked if there have been any instances where individuals experienced

retaliation or other negative reaction for raising issues, all individuals interviewed

stated that they had neither experienced nor heard of an instance of retaliation,

harassment, intimidation, or discrimination at the site. The team determined that

processes in place to mitigate these issues were being successfully

implemented. Responses from the focus group interviewees indicate that they

believe that management has established and promoted a safety-conscious work

environment where individuals feel free to raise safety concerns without fear of

retaliation. Overall, employees indicated that there has been a steady improvement

of the culture on-site.

.5 Findings

a. Failure to Assign Corrective Actions to Prevent Recurrence of High Pressure Coolant

Injection Failure

Introduction. The team identified a non-cited violation of 10 CFR 50, Appendix B,

Criterion XVI, Corrective Action, for the licensees failure to assign corrective actions to

preclude repetition (CAPRs) of a significant condition adverse to quality (SCAQ)

associated with the loss of the high pressure coolant injection (HPCI) system.

Specifically, between July 28, 2016, and June 29, 2017 the licensee failed to assign or

complete CAPRs to address the failure of a relay coil that resulted in a loss of safety

function for the single train HPCI system.

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Description. On April 25, 2016, a licensed operator performing a control room panel

walkdown noted that the green light for the HPCI auxiliary lube oil pump (ALOP) was not

illuminated. Operations personnel attempted to start the ALOP and it failed to start. Due

to the inoperability of the ALOP, the licensee declared the HPCI system inoperable and

entered the associated technical specifications (TSs). The licensee reported the event

as a loss of safety function under the requirements of 10 CFR 50.72 and 50.73

(Licensee Event Report 2016-001).

The licensee initiated a root cause evaluation (RCE) under Condition Report

CR-17-02281 to determine the cause of the condition. Investigation revealed that an

Allen-Bradley 700DC relay for the ALOP that had been installed during a maintenance

window 6 days earlier had failed due to infant mortality. Specifically, the relay coil

internal to the relay had failed after approximately 133 hours0.00154 days 0.0369 hours 2.199074e-4 weeks 5.06065e-5 months of service. The failure was

attributed to the overheating of the coil windings, caused by a manufacturing defect.

The licensees root cause evaluation found that the commercial grade dedication

process used by the Nutherm vendor did not have sufficient checks to identify the infant

mortality failure of the relay.

On June 29, 2017, during review of the RCE, the inspectors found that the licensee had

not issued any corrective actions to prevent recurrence or preclude repetition (CAPRs)

of the significant condition adverse to quality (SCAQ) associated with the relay failure

and the inadequate Nutherm dedication process. Instead, the root cause corrective

action (CA) plan stated, in part (with some portions crossed out), The newly revised

dedication process used by Nutherm takes care of the issues related to this specific

RC1. This is why there is no CAPR. CA-A2 is an "insurance" action. The corrective

action this statement referred to directed that a review of all current dedication pre-

installation checks shall be conducted to determine what is necessary to reasonably

ensure that infant mortality failures of the HPCI ALOP control relay are minimized. The

review shall include the recently revised dedication process, dated May 13, 2016, used

by Nutherm and the findings by Exelon in their analysis of the relay failure. The

inspectors did not identify any definitions for insurance actions in the licensees

corrective action program procedures.

Upon the inspectors review of this corrective action, they discovered that it did not have

any completion documentation to demonstrate that the action was, in fact, completed.

Instead, the action was listed directly in the RCE as being completed on May 25, 2016,

(before the RCE was even complete.) The inspectors noted that the action could not

have been fully completed at that time, because the final Exelon Labs report was not

received and reviewed by the station until July 29, 2016. In addition, the inspectors

reviewed the changes made to the dedication plan for the relay that appeared to be

completed in response to this corrective action. The inspectors noted that although the

dedication plan was changed to include cycling the relays 30 times, measuring

resistance across the relay coils, and testing for dielectric strength of the relays, there

appeared to be no actions in place in the dedication plan or in the stations procedure to

ensure that the changes would remain in place. As a result, the inspectors concluded

that there were no actions in place to ensure the corrective action was sustainable and

would preclude repetition of the SCAQ.

The inspectors reviewed the corrective action program (CAP) procedures that were in

effect at the time of the inspection. Procedure 0-CNS-LI-118, Cause Evaluation

15

Process, Revision 0, Section 3.5 states in part, At least one CAPR is required for a

SCAQ.

The inspectors also reviewed the CAP procedures that were in place at the time of

performance of the RCE. Procedure 0-CNS-LI-102, Revision 3, Step 10.2.2 states in

part, the Responsible Manager must (1) ensure a Root Cause Evaluation is performed

for Category "A" CRs and that appropriate CAPRs are issued, and (2) ensure

formulation of a proposed CA Plan to correct the condition and to preclude repetition.

This procedure also requires that, The Corrective Action Plan includes an action to

perform an Effectiveness Review of the CAPRs. The inspectors concluded that the

licensees responsible manager had not ensured any appropriate CAPRs were issued

for the Category A CR associated with a loss of the HPCI system due to a relay failure.

The inspectors noted that assigning a CAPR would have required performance of an

effectiveness review which would have provided programmatic oversight over whether or

not the CAPRs were succeeding in preventing recurrence. Section 11.1.4 of this

procedure stated, in part, For CAPRs that are credited as being implemented by

revising training documents or procedure actions or requirements, the applicable steps

in the associated procedure should be annotated or flagged as obligations in accordance

with applicable site procedures. The inspectors noted that the changes made to the

dedication process requirements for these relays were not annotated or flagged, to

ensure they would remain in place.

The inspectors reviewed licensee Procedure EN-LI-118, Cause Evaluation Process,

Revision 22, which was also in place at the time the RCE was performed. Section 4.(g)

of this procedure states, the Cause Evaluator is responsible for developing a corrective

action plan that will resolve the condition, the cause(s), and any other issues identified in

the cause evaluation requiring correction. For root causes, develop corrective actions to

preclude repetition (CAPR). The inspectors noted that for the root cause associated

with the failure of the HPCI relay, the cause evaluator did not develop CAPRs as

required by the procedure. Section 5.12.11 states, RCEs for Adverse Conditions

require a Corrective Action to Preclude Repetition (CAPR). CAPRs should:

(a) Eliminate the causes of the significant event so that the same or similar events

are not repeated, or

(b) Mitigate the consequences of a repeat event, or

(c) Significantly reduce the probability of occurrence of similar events of lower

significance.

(d) Clearly result in long-term correction and are sustainable.

Section 5.13.1.1 also states, Effectiveness Review Plans are required for CAPRs. The

inspectors concluded that the RCE had not established any CAPRs that met these

requirements and had not established necessary effectiveness review to ensure that

assigned CAs were performing long sustainable correction of the SCAQ.

During the inspectors review of the RCE associated with this event, they identified

several weaknesses and deficiencies associated with the evaluation, in addition to the

lack of an assigned CAPR for the relay-related SCAQ. In particular, the inspectors

noted that many of the issues they identified during their review of this revision of the

16

RCE had been identified by the inspectors previously and documented in Condition

Report CR-16-04137. The inspectors noted that the licensee had attempted to address

these weaknesses in response to the CR, but these actions had fallen short of their

intended goal. The RCE weaknesses that the inspectors identified included: incorrect

information regarding local operation of HPCI contained in the RCE resulted in the

conclusion that the event only had medium risk (Condition Report CR-17-03570); the

extent of cause did not consider whether the cause of the light bulb event had extended

to other modifications performed by the site (Condition Report CR-17-3917); the extent

of cause did not review whether the relay dedication issues associated with the relay

failure were specific to the Nutherm vendor or if they were a more generic procurement

and dedication issue (Condition Report CR-17-03915); the corrective action related to

establishing improved relay testing methods had inadequate closure documentation

(Condition Report CR-17-03920); and the Part 21 reportability evaluation was

inadequate (addressed as a separate NCV in this report.) These issues were entered

into the licensees corrective action program for further evaluation.

Analysis. The licensees failure to assign corrective actions to preclude repetition

of a significant condition adverse to quality, in violation of 10 CFR 50, Appendix B,

Criterion XVI, was a performance deficiency. The performance deficiency was

evaluated using Inspection Manual Chapter 0612, Appendix B, Issue Screening,

dated September 7, 2012, and was associated with the Mitigating Systems cornerstone.

The team determined that the performance deficiency was more than minor, and

therefore a finding, because if left uncorrected, the performance deficiency would have

the potential to lead to a more significant safety concern. Specifically, the licensees

failure to assign corrective actions to preclude repetition of an SCAQ could reasonably

result in the condition recurring and creating more safety-significant equipment failures.

Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination

Process (SDP) for Findings At-Power, dated June 19, 2012, the inspectors determined

that the finding had very low safety significance (Green) because it: was not a design

deficiency; did not represent a loss of system and/or function; did not represent an actual

loss of function; did not represent an actual loss of function of at least a single train for

longer than its technical specification allowed outage time; and did not result in the loss

of a high safety-significant non-technical specification train. The finding had a

cross-cutting aspect in the area of problem identification and resolution associated with

resolution, because the licensee failed to ensure that the organization took effective

corrective actions to address issues in a timely manner commensurate with their safety

significance [P.3].

Enforcement. 10 CFR 50, Appendix B, Criterion XVI requires, in part, that measures

shall be established to assure that conditions adverse to quality, such as failures,

malfunctions, deficiencies, deviations, defective material and equipment, and

nonconformances are promptly identified and corrected. In the case of significant

conditions adverse to quality, the measures shall assure that the cause of the condition

is determined and corrective action taken to preclude repetition. Contrary to the above,

between July 28, 2016, and June 29, 2017, in the case of a significant condition adverse

to quality associated with HPCI, the measures did not assure that the cause of the

condition was determined and corrective action taken to preclude repetition.

Specifically, the licensee failed to assign or complete corrective actions to prevent

recurrence (CAPRs) to address a significant condition adverse to quality associated with

the failure of a relay coil that resulted in a loss of safety function of the HPCI system.

Corrective actions to restore compliance included reevaluation of the corrective actions

17

assigned to the root cause of the condition and the creation of corrective actions to

prevent recurrence for the condition. Because this violation was of very low safety

significance (Green) and was entered into the licensees corrective action program

as Condition Report CR-17-03544, this violation is being treated as a non-cited

violation (NCV) in accordance with Section 2.3.2.a of the NRC Enforcement Policy:

NCV 05000298/2017002 01, Failure to Assign Corrective Actions to Prevent

Recurrence of High Pressure Coolant Injection Failure.

b. Failure to Perform Timely Operability Determinations

Introduction. The team identified a Green non-cited violation of Technical

Specification 5.4.1.a for the licensees multiple failures to immediately evaluate

operability of degraded or nonconforming conditions. The team identified multiple

examples of these operability determinations not being performed within one shift, as

required by procedure. Further, aggregate data indicated routine noncompliance with

procedural requirements to document operability immediately and without delay.

Description. Licensee Procedure 0.5.OPS, Operations Review of Condition

Reports/Operability Determination, Revisions 56 and 57, define immediate

determination as, The Operability Determination performed immediately after

confirmation that a Degraded or Non-Conforming Condition exists for a [structure,

system, or component] required to be operable by Technical Specifications. It further

states, Operability should be determined immediately upon discoverywithout

delayusing the best information available. A separate process is provided to gather

initial information to support the immediate determination: Prompt Determination is a

follow-up and is warranted when additional information is needed to confirm the

immediate determination.

The team reviewed a population of 543 immediate operability determinations performed

on degraded or nonconforming conditions between January 1, 2017, and June 13, 2017.

Of this population, approximately 35 (6.5 percent) took greater than 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , meaning

they could not have been accomplished within one shift as required by procedure. A

number of others that were accomplished within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months likely also exceeded the one-

shift requirement, but the team did not review actual times of documentation as

compared to shift-change times to determine an accurate count. The median time from

CR initiation to operability declaration was over 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , with nearly a third (31 percent)

taking greater than 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

The team reviewed several examples where substantial time had elapsed between

identification of the degraded or nonconforming condition and the documentation of

operability. Two examples follow:

On February 7, 2017, during emergency diesel generator (EDG) maintenance,

personnel discovered incorrect bolting installed in the injector and documented

the condition in Condition Report CR-CNS-2017-00610. The EDG was returned

to service at 0817 on February 9, 2017. A final operability declaration was not

made by the shift manager until 1843 that evening, over 2 days after discovery

and over 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months after the equipment was returned to service.

On June 12, 2017, the licensee initiated Condition Report CR-CNS-2017-03505,

documenting receipt of NRC Part 21 report 2017-31-00, which described a

18

potential defect in Curtiss-Wright Grayboot socket contacts. The condition report

was generated at 0952 on June 12 with an operability assignment to operations.

After four revisions to the immediate determination documentation between 2336

on June 12 and 0311 on June 13 an operability declaration was made by the shift

manager at 0320, almost 18 hours2.083333e-4 days 0.005 hours 2.97619e-5 weeks 6.849e-6 months after the condition was formally identified.

These extended time periods appeared to be primarily due to efforts by operations or

engineering to confirm operability, an activity which should procedurally be performed

under the prompt determination process after operations has made an immediate

declaration immediatelyusing the best information available.

Analysis. Multiple failures to perform immediate operability determinations timely as

required by station procedures is a performance deficiency. This performance

deficiency is more than minor because it was associated with the equipment

performance attribute of the mitigating systems cornerstone and adversely affected the

cornerstone objective to ensure the availability, reliability, and capability of systems that

respond to initiating events to prevent undesirable consequences. Using Inspection

Manual Chapter 0609, Appendix A, dated June 19, 2012, the inspectors determined that

the finding had very low safety significance (Green) because it did not result in the loss

of operability or functionality of any system or train. This finding has a consistent

process cross-cutting aspect in the human performance cross-cutting area because

operators failed to use a consistent, systematic approach to make decisions regarding

operability using the organizations well-defined decision making process (H.13).

Enforcement. Cooper Nuclear Plant Technical Specification 5.4.1.a requires that written

procedures shall be established, implemented, and maintained covering the applicable

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

February 1978. Contrary to this requirement, between January 1, 2017,

and June 13, 2017, the licensee failed to establish, implement, and maintain written

procedures recommended in Regulatory Guide 1.33. Specifically, the list in Appendix A

of the Regulatory Guide includes procedures governing authorities and responsibilities

for safe operation and shutdown. One of the procedures used by NPPD to meet this

requirement is 0.5.OPS. The licensee failed to implement the procedure as written. The

licensee entered this violation into its corrective action program as Condition

Report CR-CNS-2017-03937, and began evaluating actions to restore compliance.

Because the finding was of very low safety significance and has been entered into the

licensees corrective action program, the violation is being treated as a non-cited

violation, consistent with Section 2.3.2.a of the NRC Enforcement Policy:

NCV 05000298/2017010-02, Failure to Perform Timely Operability Determinations.

c. Programmatic Failure to Identify and Correct Adverse Trends

Introduction. The team identified a Green non-cited violation of 10 CFR 50, Appendix B,

Criterion XVI for the licensees programmatic failure to promptly identify adverse trends

and enter them into the corrective action program. Often, when adverse trends were

identified, they were addressed using informal processes. This was particularly the case

for safety-culture-related trends such as adverse trends in organizational behaviors.

Description. The licensees corrective action program is governed by

Procedure 0-CNS-LI-102, which describes the roles and responsibilities of various site

personnel in implementing aspects of the program. Leadership oversight of the

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corrective action program is provided by the performance improvement review group

(PRG), which consists of senior site management from all major departments. The PRG

meets three times each week to review products generated by the corrective action

program, including condition report, cause evaluations, effectiveness reviews, and other

documents. The team observed several of these meetings and noted that on a number

of occasions multiple issues were discussed in the aggregate, but no actions were taken

to determine whether that aggregation represented an early indication of a declining

trend. Further, when actions were taken to evaluate trends, they were often tracked as

LO or WT actions, which are not governed by the quality processes of the corrective

action program.

The team also noted several specific adverse trends that were not promptly identified by

the licensee:

During the first several months of operation following the past five or more

outages, the station has experienced failures of the rod-full-out lights in the digital

rod position indication system. Each time, the licensee had documented the

failure, but had failed to take action to review the failures in the aggregate or to

fix the underlying cause. The licensee documented this issue in Condition

Report CR-CNS-2017-04571.

The licensee periodically conducts an Aggregate Performance Review Meeting,

where managers review station performance and ongoing improvement efforts.

This meeting includes a review of adverse trend CRs with actions currently in

progress to correct the trend. At the June 2017 meeting, of the 13 adverse

trends being tracked, 5 (38 percent) were identified at least in part by the NRC.

On May 22, 2017, the licensee declared the traversing in-core probe (TIP) C ball

valve inoperable as a primary containment isolation valve (PCIV) due to the

failure of the in-shield limit switch. Although the TIP ball valves have

experienced multiple failures for the same or similar causes dating back to 2006,

including seven TIP ball valve limit switch-related failures since February 2016,

no trend CR was generated by the licensee until approximately one month later

when the NRC inspection team was onsite.

In January 2017 the resident inspectors identified that over the course of 2016,

there had been over 30 instances where the control room experienced the

momentary loss of annunciator chassis that supply power to the control room

panel annunciators. Although in each case the control room only lost one

chassis at a time and annunciator functionality was maintained, the licensee was

required to enter Abnormal Procedure 2.4ANN, Annunciator Abnormal, during

each occurrence and to perform the required actions. In most cases, the

licensee did not know what caused the temporary failure. The inspectors

challenged the licensee on whether these events represented an adverse trend,

and after several discussions with station personnel, the licensee initiated

Condition Report CR-17-00373 to evaluate the trend.

Analysis. The programmatic failure to promptly identify adverse trends as required by

station procedures was a performance deficiency. This performance deficiency is more

than minor because if left uncorrected, it has the potential to become a more significant

20

safety concern. Specifically, failure to arrest an adverse trend, particularly in

organizational behaviors, could lead to increased likelihood of a worker-induced initiating

event or a failure to effectively mitigate an accident. Using Inspection Manual

Chapter 0609, Appendix A, dated June 19, 2012, the inspectors determined that the

finding had very low safety significance (Green) because it did not result in the loss of

operability or functionality of any system or train. This finding has a trending cross-

cutting aspect in the problem identification and resolution cross-cutting area because the

organization failed to use available information in the aggregate to identify programmatic

and common cause issues (P.4).

Enforcement. Title 10 CFR 50, Appendix B, Criterion XVI requires that measures shall

be established to assure that conditions adverse to quality are promptly identified and

corrected. Contrary to this requirement, for an indeterminate period of time prior to

June 29, 2017, the licensee failed to establish measures to assure that conditions

adverse to quality are promptly identified and corrected. Specifically, measures

established by station corrective action program procedures were not effective in

promptly identifying and correcting adverse trends in equipment and organizational

performance. The licensee entered this violation into its corrective action program as

Condition Report CR-CNS-2017-03938, and took action to formalize identification

processes for potential adverse trends. Because the finding was of very low safety

significance and has been entered into the licensees corrective action program, the

violation is being treated as non-cited violation, consistent with Section 2.3.2.a of the

NRC Enforcement Policy: NCV 05000298/2017010-03, Programmatic Failure to

Identify and Correct Adverse Trends.

d. Failure to Monitor No. 2 Diesel Generator Under 50.65(a)(1) due to Inadequate

Maintenance Rule Evaluation

Introduction. The team identified a Green, non-cited violation of 10 CFR

50.65(a)(1)/(a)(2), for the licensees failure to perform an a(1) evaluation and establish

a(1) goals when the No. 2 diesel generator (DG) a(2) preventive maintenance

demonstration became invalid. Specifically, on April 28, 2017, the No. 2 DG exceeded

its performance criteria when it experienced a second maintenance rule functional failure

(MRFF), but the licensee failed to perform an associated a(1) evaluation. The licensee

had failed to appropriately evaluate a February 4, 2017, failure associated with the No. 2

DG jacket water heater failure in the maintenance rule program and, as a result, the site

failed to evaluate and monitor the equipment under 10 CFR 50.65(a)(1) as required.

Description. On June 21 during a review of the licensees Maintenance Rule Program

functional failure evaluations and corrective action reports, the inspectors noted that one

component failure did not appear to be correctly evaluated in the licensees Maintenance

Rule Program as a MRFF. Specifically, the inspectors identified that

on February 4, 2017, a failure of the No. 2 diesel generator jacket water heater resulted

in the need to take the DG out of service due to the fact that jacket water temperatures

were quickly approaching the minimum required operability limit of 100 degrees F

(Condition Report CR-17-00551). Although the condition resulted in the need to declare

the DG inoperable, the licensee had determined that this issue was not a MRFF. The

inspectors reviewed the event to assess the appropriateness of the licensees

evaluation.

21

At 2038 on February 4, 2017, the licensee received alarms in the control room which

indicated that there was a ground on the No. 2 DG motor control center transformer.

The licensee discovered that the jacket water heater had failed, and as a result, the

licensee was required to secure power to the heater and jacket water temperature began

to lower. Operations personnel initiated actions to monitor the temperature trends to

ensure that action was taken prior to the lower temperature limit being exceeded. At the

time of discovery, temperatures were indicating 131 degrees F on the inlet to the heater

and 136 degrees F on the outlet of the heater. By approximately 0443

on February 5, 2017, temperatures had dropped to 102 degrees F on the inlet to the

heater and 118 degrees F on the outlet of the heater. At that time, the licensee declared

No. 2 DG inoperable.

When the licensee initiated repairs on the heater, they learned that the heater elements

had overheated and melted open in several locations. The licensee performed a

C - Fix level evaluation for the heater failure. This evaluation revealed that the heater

had been in place since the beginning of plant life and was installed in 1974. The

evaluation also revealed that there was no preventive maintenance (PM) activity in place

that would drive replacement of the heater. Instead, the licensee was performing 5-year

cleaning and inspection PMs. As a result, the licensee created a PM activity to drive

replacement of the heater on a 16-year frequency.

The inspectors reviewed the MRFF determination documentation and discussed the

conclusions with systems engineering personnel. The inspectors learned that the

licensee had not counted the failure as an MRFF because they had concluded that there

was no lower limit on temperature for the jacket water system. The licensee had relied

on a letter, dated March 26, 1998, which was received from MPR Associates, Inc., who

had taken on vendor responsibilities for the Cooper-Bessemer DGs in operation at the

station. Licensee personnel pointed to a statement in this letter that said, No design

lower temperature limit for C-B Model KSV Diesel Engine Jacket Water System. As a

result, the licensee had determined that this equipment failure did not constitute an

MRFF.

The inspectors challenged the licensee on this assessment. In particular, Station

Operating Procedure 2.2.20, Standby AC Power System (Diesel Generator),

Revision 95, Section 2.2 (Precautions and Limitations) stated, If jacket water or lube oil

temperature is less than or equal to 100 degrees F while DG is in standby, DG shall be

declared inoperable. In addition, Section 1.2.4 explained that the procedure contained

minimum required temperature limitations for jacket water and lube oil in order to meet

the diesel generator fast start requirements. In addition, the inspectors noted that the

Maintenance Rule Basis Document for the DG system function included specific

provisions for jacket water temperatures. Specifically, the Function Description section

stated, The Jacket Water (DGJW) sub-systems consist of a standpipe, connecting

pipes, pumps, temperature control valves, coolers, standby heaters, valves, and

instrumentation necessary to remove heat from the engine jackets during operations or

provide heat during standby conditions to maintain the engine jackets greater than or

equal to 100 degrees F for fast-starting capability.

Finally, the inspectors reviewed the MPR letter that the licensee had used as the basis

for the decision not to classify the failure as a MRFF. The inspectors discovered that the

statement the licensee relied on for their determination that there were no low

temperature limits for the DG was applicable only for performing non-timed starts from

22

maintenance conditions. The inspectors noted that the line below it included different

guidance with respect to low temperature limits for normal EDG fast starts. For fast

starts, the low limit for the jacket water was listed as 100 degrees F. In response to

inspector questions on the basis for the 100 degree F limit throughout station

procedures, the licensee discovered that historical procedure change requests had also

referenced the fast start limitations derived from the same MPR letter. As a result, the

licensee agreed that there was a lower temperature limit for DG jacket water. The

inspectors concluded that the heater failure represented a MRFF because:

1. The heating function of the heater was directly described as part of the DG

function in the Basis Document and failure of the component represented a

functional failure; and

2. Due to the equipment failure, the licensee was required to take the DG out of

service and declare it inoperable when jacket water temperatures reached the

lower temperature limit.

The inspectors reviewed the Maintenance Rule performance criteria for the No. 2 DG.

The inspectors determined that the No. 2 DG was allowed one MRFF in a 24 month

cycle. The inspectors noted that the No. 2 DG already had one MRFF counted against it

due to a relay failure that resulted in the DG being declared inoperable on April 28, 2017,

(Condition Report CR-17-02533). With the additional failure associated with the jacket

water heater, the inspectors concluded that the No. 2 DG had exceeded its performance

criteria on April 28, 2017, and invalidated its (a)(2) preventive maintenance

demonstration. As a result, the inspectors concluded that the licensee had failed to take

the necessary actions required by (a)(2)/(a)(1).

Analysis. The licensees failure to monitor the No. 2 DG in accordance with the

requirements of 10 CFR 50.65(a)(1) due to incorrectly evaluating one MRFF, in violation

of 10 CFR 50.65(a)(1)/(a)(2), was a performance deficiency. The inspectors screened

the performance deficiency using Inspection Manual Chapter 0612, Appendix B, Issue

Screening, dated September 7, 2012, and determined that the issue was more than

minor, and therefore a finding, because it was associated with the equipment

performance attribute of the Mitigating Systems cornerstone and adversely affected the

cornerstone objective to ensure availability, reliability, and capability of systems that

respond to initiating events. Using Inspection Manual Chapter 0609, Appendix A, The

Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012,

the inspectors determined that the finding had very low safety significance (Green)

because it: was not a design deficiency; did not represent a loss of system and/or

function; did not represent an actual loss of function; did not represent an actual loss of

function of at least a single train for longer than its technical specification allowed outage

time; and did not result in the loss of a high safety-significant nontechnical specification

train. The finding had a cross-cutting aspect in the area of problem identification and

resolution associated with evaluation, because the licensee failed to ensure that the

organization thoroughly evaluated the No. 2 diesel generator issues to ensure that

resolutions addressed causes and extent of conditions commensurate with their safety

significance [P.2].

Enforcement. Title 10 CFR 50.65 (a)(1), requires in part, that holders of an operating

license shall monitor the performance or condition of SSCs within the scope of the rule

as defined by 10 CFR 50.65 (b), against licensee established goals, in a manner

23

sufficient to provide reasonable assurance that such SSCs are capable of fulfilling their

intended functions. Title 10 CFR 50.65 (a)(2) states, in part, that monitoring, as

specified in 10 CFR 50.65 (a)(1), is not required where it has been demonstrated that

the performance or condition of an SSC is being effectively controlled through the

performance of appropriate preventive maintenance, such that the SSC remains capable

of performing its intended function. Contrary to the above, on April 28, 2017, the

licensee failed to demonstrate that the performance or condition of the No. 2 DG was

being effectively controlled through the performance of appropriate preventive

maintenance, such that the SSC remained capable of performing its intended function,

and failed to monitor the performance or condition of the SSC against licensee-

established a(1) goals. Specifically, the No. 2 DG exceeded its performance criteria

when it experienced a second MRFF, but the licensee failed to perform an associated

a(1) evaluation because engineering personnel had not correctly evaluated

a February 4, 2017, failure associated with the No. 2 DG jacket water heater in the

Maintenance Rule Program. As a result, the site failed to evaluate and monitor the

equipment under 10 CFR 50.65(a)(1) as required. Corrective actions taken by the

licensee to restore compliance included reevaluation of the February 4, 2017, functional

failure and performance of an a(1) evaluation. Because the finding was of very low

safety significance and has been entered into the licensees corrective action program

(Condition Report CR-17-03930), this violation is being treated as an NCV, consistent

with Section 2.3.2.a of the NRC Enforcement Policy: NCV 05000298/2017010-04,

Failure to Monitor No. 2 Diesel Generator under 50.65(a)(1) due to Inadequate

Maintenance Rule Evaluation.

e. Failure to adopt appropriate procedures in accordance with 10 CFR Part 21

Introduction. The team identified a Severity Level (SL) IV violation of 10 CFR 21.21(a)

for the licensees failure to adopt appropriate procedures to evaluate deviations and

failures to comply to identify those associated with substantial safety hazards.

Specifically, Procedure EN-LI-108, 10 CFR 21 Evaluations and Reporting,

Revision 5C0, was inadequate to ensure that the correct reportability call was made for a

manufacturing flaw discovered in a relay that had resulted in a loss of safety function for

the high pressure coolant injection (HPCI) system on April 25, 2016.

Description. On April 25, 2016, a licensed operator performing a control room panel

walkdown noted that the green light for the HPCI auxiliary lube oil pump (ALOP) was not

illuminated. Operations personnel attempted to start the ALOP, and it failed to start.

Due to the inoperability of the ALOP, the licensee declared HPCI inoperable and entered

Technical Specification Limiting Condition for Operation (LCO) 3.5.1, Condition C.

Condition C required verification by administrative means that the reactor core isolation

cooling (RCIC) system was operable within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months ; and restoration of the HPCI system

to operable status within 14 days. The licensee also reported the event as a loss of

safety function under the requirements of 10 CFR 50.72 and 50.73 (Licensee Event

Report 2016-001).

The licensee initiated a root cause evaluation (RCE) under Condition

Report CR-17-02281 to determine the cause of the condition. Investigation revealed

that an Allen-Bradley 700DC relay for the ALOP that had been installed during a

maintenance window 6 days earlier had failed due to infant mortality. Specifically, the

relay coil internal to the relay had failed after approximately 133 hours0.00154 days 0.0369 hours 2.199074e-4 weeks 5.06065e-5 months of service. The

failure was attributed to the overheating of the coil windings, caused by a manufacturing

24

defect. The licensees root cause evaluation found that the commercial grade dedication

process used by the Nutherm vendor did not have sufficient checks to identify the infant

mortality failure of the relay. Specifically, the dedication plan lacked testing described in

C37.90-1989, ANSI/IEEE Standard for Relays and Relay Systems Associated with

Electric Power Apparatus, including testing of the dielectric strength of the relay coil and

testing for relay coil resistance. The RCE determined that these checks would likely

have prevented the relay failure that resulted in the loss of the HPCI system.

On June 21, 2017, the inspectors reviewed the RCE and questioned why the defect had

not been reported under the requirements of 10 CFR Part 21. The licensee initially

explained that the issue had not been determined to be a manufacturing flaw. In

response, the inspectors pointed out that the RCE and the lab failure analysis had both

determined that the relay failure was the result of a manufacturing defect. The licensee

then provided the inspectors with the documented Part 21 reportability evaluation. This

evaluation stated, This condition is not reportable per 10 CFR 21. The failure of HPCI

by itself is not a substantial safety hazard. Alternate depressurization system (ADS) and

low pressure emergency core cooling system (ECCS) were unaffected by the relay issue

and were still available for accident mitigation and decay heat removal.

The inspectors reviewed 10 CFR Part 21 requirements and NUREG 0302, Reporting

and Defects and Noncompliance. As a result of their review, and in consultation with

NRC headquarters staff, the inspectors determined that the loss of HPCI should be

categorized as a potential substantial safety hazard (SSH). Specifically, in the category

of a major degradation which could create an SSH, NUREG 0302 states, the loss of

safety function of a basic component is considered a major reduction in the degree of

protection provided to the public health and safety. The inspectors noted that HPCI is a

single train system for accident conditions, and as a result, loss of the system created a

loss of a safety function, as described by 10 CFR 50.72 and 10 CFR 50.73

requirements. The inspectors concluded that the ADS referenced in the licensees

evaluation did not perform the same safety function. Specifically, ADS allows operations

personnel to reduce pressure in the reactor in order to initiate another mitigating system.

The ADS function does not allow for operators to add high pressure inventory to the

vessel; rather, it relies on the availability of the low pressure injection systems, which

serve a separate safety function.

In addition, the inspectors noted that the SSH review should have included in its scope,

other places where the defect potentially could exist. The inspectors and licensee

agreed that both the relay equipment failure and the inadequate dedication plan for the

relay were defects. As a result, the licensee should have assessed whether the defect -

both the relay flaw and the inadequate dedication plan - could exist elsewhere in the

plant or in the warehouse inventory. This review would help to identify additional plant

vulnerabilities and would allow for a more appropriate assessment of whether an SSH

could be created. The inspectors requested information on other locations that the same

defective Nutherm dedication plan could be in place for other relays. Because the

licensee had not yet completed this review, and an in depth review was required, the

licensee initiated Condition Reports CR-17-03915 and CR-17-04112 to drive review of

the concern. As a result of these factors, the inspectors determined that the licensees

evaluation was inadequate and that the issue should have been reportable under

Part 21.

25

The inspectors reviewed licensee Procedure EN-LI-108, 10 CFR 21 Evaluations and

Reporting, Revision 5C0, and determined it was inadequate to ensure that the correct

reportability call was made for the HPCI relay failure that occurred on April 25, 2016.

Specifically, the procedure (1) led the licensee to incorrectly conclude that an SSH could

not be created, (2) allowed a limited extent of condition in performing the SSH evaluation

such that similarly dedicated parts were not included in the scope, and (3) included

incorrect guidance in Attachment 9.3. In particular, Attachment 9.3 states, assuming

that 10 CFR 21 requires an automatic application of a single failure to the redundant

component or system would set a threshold for reporting under 10 CFR 21 lower than

10 CFR 50.72 and 1OCFR 50.73. Such an interpretation would be contrary to the

principles in 10 CFR 21 which establish that reporting under Part 21 applies when there

is a loss of safety function and when there is a major reduction in the degree of

protection provided to the public health and safety. The inspectors noted that these

statements were inconsistent with the guidance contained in NUREG 0302, and the

requirements of Part 21. In addition, Attachment 9.3 included incorrect information from

the previous revision of NUREG 1022, which discussed reporting of Part 21 defects.

The information was removed for the current revision of NUREG 1022 (Revision 3), but it

remained in Attachment 9.3 of the procedure. As a result of this inadequate procedure,

the licensee failed to recognize that the HPCI relay defect was reportable under Part 21.

Analysis. The failure to adopt appropriate procedures to evaluate deviations and failures

to comply to identify those associated with substantial safety hazards, in violation of

10 CFR 21.21(a), was a performance deficiency. The NRCs reactor oversight process

considers the safety significance of findings by evaluating their potential safety

consequences. Using Inspection Manual Chapter 0612, Appendix B, Issue Screening,

dated September 7, 2012, the team determined that the performance deficiency was of

minor safety significance under the reactor oversight process because it involved a

failure to make a report; however the underlying equipment failure was previously

evaluated as having very low safety significance.

The traditional enforcement process separately considers the significance of willful

violations, violations that impact the regulatory process and violations that result in

actual safety consequences. Traditional enforcement applied to this finding because it

involved a violation that impacted the regulatory process. The team used the NRC

Enforcement Policy, dated November 1, 2016, to determine the significance of the

violation. The inspectors determined that the violation was similar to Examples 6.9.d.10

and 6.9.d.13 of the Enforcement Policy, which discussed, a failure to identify all

applicable reporting codes on a Licensee Event Report that may impact the

completeness or accuracy of other information submitted to the NRC, and failure to

implement adequate 10 CFR Part 21 or 10 CFR 50.55(e) processes or procedures that

has more than minor safety or security significance. Specifically, although the

procedure resulted in an inadequate reportability review and the issue was not reported

as a manufacturing flaw, the licensee had reported some aspects of the event under the

requirements of 10 CFR 50.73. As a result, the team determined that the violation

should be classified as a Severity Level IV violation. Cross-cutting aspects are not

assigned to traditional enforcement violations.

Enforcement. Title 10 CFR 21.21(a)(1) requires, in part, that entities subject to the

regulations in this part shall adopt appropriate procedures to evaluate deviations and

failures to comply to identify defects associated with SSH as soon as practicable except

as provided in paragraph (a)(2) of this section, and in all cases within 60 days of

26

discovery, in order to identify a reportable defect that could create a substantial safety

hazard, were it to remain uncorrected. Contrary to the above, prior to June 29, 2017, the

licensee failed to adopt appropriate procedures to evaluate deviations and failures to

comply to identify defects associated with substantial safety hazards as soon as

practicable, and in all cases within 60 days of discovery, in order to identify a

reportable defect that could create a substantial safety hazard, were it to remain

uncorrected. Specifically, Procedure EN-LI-108, 10 CFR 21 Evaluations and

Reporting, Revision 5C0, was inadequate to ensure that the correct reportability call

was made for a manufacturing flaw discovered in an Allen-Bradley 700DC relay that had

resulted in a loss of safety function for the HPCI system on April 25, 2016. In particular,

the procedure (1) led the licensee to incorrectly conclude that an SSH could not be

created, (2) allowed a limited extent of condition in performing the SSH evaluation such

that similarly dedicated parts were not included in the scope, and (3) included incorrect

guidance in Attachment 9.3. Corrective actions to restore compliance included

re-evaluation of the defect under Part 21 requirements and a procedure adequacy

review of the EN-LI-108-01 procedure. Because this violation was of Severity Level IV

significance and was entered into the licensees corrective action program as Condition

Reports CR-17-3936 and CR-17-4143, this violation is being treated as a non-cited

violation (NCV) in accordance with Section 2.3.2.a of the NRC Enforcement Policy:

NCV 05000298/2017010-05, Failure to adopt appropriate procedures in accordance

with 10 CFR Part 21.

4OA5 Other Activities

Follow Up Inspection for Three of More Severity Level IV Traditional Enforcement

Violations in the Same Area in a 12-Month Period

a. Inspection Scope

The inspectors performed Inspection Procedure (IP) 92723, Follow Up Inspection for

Three of More Severity Level IV Traditional Enforcement Violations in the Same Area in

a 12-Month Period, based on the results of the NRCs annual review of station

performance as documented in the 2015 assessment letter, dated March 2, 2016

(ADAMS Accession No. ML16061A312). In 2015, the NRC issued the following three

Severity Level IV traditional enforcement violations in the area of impeding the regulatory

process:

NCV 05000298/2015004-02, Failure to Update the Updated Safety Analysis

Report

NCV 05000298/2015007-03, Failure to Update the Final Safety Analysis Report

(FSAR)

NCV 05000298/2015003-04, Failure to Make a 10 CFR 50.72(b)(2)(xi)

Notification

The inspectors reviewed the licensees cause evaluations and corrective actions

associated with these issues in order to determine whether the licensees actions met

the IP 92723 inspection objectives to provide assurance that: (1) the cause(s) of the

violations are understood by the licensee, (2) the extent of condition and extent of cause

27

of the violations are identified, and (3) licensee corrective actions to the violations are

sufficient to address the cause(s).

In June 2016 the inspectors reviewed the licensees actions to address these violations.

In NRC Inspection Report 05000298/2016002 (ADAMS Accession No. ML16211A197),

the inspectors documented their conclusion that objective (2) above was not met, in that

the licensee did not fully identify the extent of condition and extent of cause of multiple

Severity Level IV traditional enforcement violations. In this inspection (June 2017) the

inspectors assessed the licensees actions to address the weaknesses identified in the

initial evaluation.

b. Assessment

The inspectors determined that the licensees corrective actions were adequate to meet

the inspection objectives. The inspectors developed the following observations with

regard to the licensees actions to meet objective (2) regarding identification of extent of

condition and extent of cause.

The inspectors noted that the NCVs referenced above included five examples of failures

to update the updated safety analysis report (USAR) in accordance with the

requirements of 10 CFR 50.71(e). Three of these examples involved new or updated

information that was included in license amendments, while two examples involved new

information that was introduced in licensee procedure changes. The inspectors

determined that the licensees initial extent of condition evaluation included a review of a

sample of license amendments to determine whether additional examples of failures to

make appropriate corresponding updates to the USAR existed. The inspectors

observed that the initial evaluation did not include a sample output of any other change

processes by which new or updated information affecting the content of the USAR could

be developed, such as licensee procedure changes. The inspectors determined that the

licensee supplemented their extent of condition evaluation to include a sample of

procedure revisions to determine whether corresponding USAR updates were

implemented, if applicable. The licensees evaluation also acknowledged that other

change process output (e.g. engineering evaluations, plant modifications, and design

changes) could result in the need for a USAR update. The licensees evaluation

included a search for past condition reports documenting problems in these areas. The

license also performed a review of three USAR sections against other applicable

licensing basis documentation to verify accuracy and consistency of USAR content.

The inspectors also observed that, for the identified cause of, failure to apply the proper

rigor for regulatory requirements associated with USAR maintenance, the licensees

initial extent of cause evaluation did not assess the applicability of the cause for other

programs or activities, such as whether proper rigor is being applied for maintaining

licensee-controlled licensing basis documents other than the USAR. The inspectors

determined that the licensee supplemented their extent of cause evaluation to include a

sample of the last 3 years of revisions to licensing basis documents other than the

USAR (e.g. Technical Specifications (TS) Bases, Technical Requirements Manual) to

determine whether the changes were made properly (in accordance with established

processes and procedures) and accurately (in accordance with the information that

prompted the need for the change.)

28

The inspectors determined that the licensees extent of condition evaluation did not

include any independent sample of change process output other than license

amendments and procedure changes, and the licensees extent of cause evaluation did

not include an effort to identify potential instances where no licensing basis document

change occurred when there should have been, based on new or updated information

being issued. The licensee entered these observations into the corrective action

program as Condition Report CR-CNS-2017-04036.

c. Findings

No findings were identified.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On June 29, 2017, the inspectors presented the inspection results to Mr. J. Kalamaja, General

Manager Plant Operations and then-acting Vice President and Chief Nuclear Officer, and other

members of the licensee staff. The licensee acknowledged the issues presented. The licensee

confirmed that any proprietary information reviewed by the inspectors had been returned or

destroyed.

29

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

R. Aue, Employee Concerns Program Coordinator

T. Barker, EP&C Manager

T. Chard, Quality Assurance Manager

L. Dewhirst, CA&A Manager

J. Dykstra, EP&C Engineer

J. Ehlers, System Engineering Supervisor

T. Forland, Licensing Engineer

E. Fulton, System Engineer

S. Gocek, Design Engineer

D. Kiekel, Design Engineer

M. Metzger, System Engineer

J. Reimers, System Engineering Manager

J. Shaw, Licensing Manager

R. Shaw, Assistant Operations Manager - Support

D. Van Der Kamp, Licensing Technical Specialist

NRC Personnel

C. Henderson, Resident Inspector

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

Failure to Assign Corrective Actions to Prevent Recurrence of High

05000298/2017010-01 NCV

Pressure Coolant Injection Failure (Section 4OA2.5.a)

Failure to Perform Timely Operability Determinations 05000298/2017010-02 NCV

(Section 4OA2.5.b)

Programmatic Failure to Identify and Correct Adverse Trends05000298/2017010-03 NCV

(Section 4OA2.5.c)

Failure to Monitor No. 2 Diesel Generator under 50.65(a)(1) due to

05000298/2017010-04 NCV

Inadequate Maintenance Rule Evaluation (Section 4OA2.5.d)

Failure to adopt appropriate procedures in accordance with

05000298/2017010-05 NCV

10 CFR Part 21 (Section 4OA2.5.e)

LIST OF DOCUMENTS REVIEWED

Quality Surveillances

QS-2017-CNS-016

QS-2016-CNS-003

Attachment

Condition Reports

12-03456 15-02747 16-01485 16-05717 16-09041 17-02533

12-03456 15-03008 16-01523 16-05963 16-09048 17-02544

12-05871 15-03188 16-01647 16-06000 16-09126 17-02599

12-06346 15-03292 16-02183 16-06056 17-00002 17-02638

12-06369 15-03292 16-02191 16-06109 17-00039 17-02708

12-06417 15-03672 16-02217 16-06185 17-00185 17-02708

12-07528 15-03786 16-02281 16-06185 17-00278 17-02714

12-07529 15-03787 16-02281 16-06497 17-00322 17-02715

12-09106 15-03788 16-02318 16-06582 17-00373 17-02718

12-09529 15-04229 16-02401 16-06604 17-00373 17-02794

12-09908 15-04417 16-02402 16-06605 17-00408 17-02875

13-00474 15-04418 16-02402 16-06901 17-00426 17-03182

13-00475 15-04801 16-02424 16-07042 17-00472 17-03267

13-00475 15-05006 16-02589 16-07044 17-00474 17-03400

13-01500 15-05056 16-02638 16-07329 17-00551 17-03481

13-01500 15-05167 16-02753 16-07426 17-00610 17-03505

13-03145 15-05190 16-03413 16-07494 17-01168 17-03539

13-03456 15-05217 16-03434 16-07634 17-01169 17-03544

13-03591 15-05357 16-03665 16-07645 17-01195 17-03570

13-05836 15-05831 16-03665 16-07742 17-01227 17-03573

13-07276 15-06036 16-03708 16-07991 17-01370 17-03610

14-01622 15-06240 16-03780 16-08112 17-01405 17-03703

14-06170 15-06281 16-03783 16-08122 17-01430 17-03706

14-07389 15-06477 16-03874 16-08122 17-01457 17-03711

14-08117 15-06547 16-04104 16-08156 17-01668 17-03714

14-08656 15-06873 16-04137 16-08319 17-01718 17-03718

15 03672 15-06877 16-04355 16-08337 17-01741 17-03721

15-00403 16 01282 16-04487 16-08338 17-02067 17-03730

15-01179 16-00075 16-04628 16-08363 17-02091 17-03883

15-01268 16-00227 16-04649 16-08369 17-02280 17-03915

15-01908 16-00498 16-04705 16-08373 17-02289 17-03917

15-02085 16-00716 16-05196 16-08461 17-02383 17-03920

15-02337 16-00815 16-05361 16-08493 17-02412 17-03934

15-02387 16-00905 16-05558 16-08539 17-02419 17-03936

15-02718 16-01227 16-05607 16-08744 17-02428 17-04036

15-02736 16-01282 16-05628 16-08905 17-02430 17-04112

Other

LO-2015-0004-021 LO-2016-0062-002 LO-2017-0010-004 LO-2017-0010-029

LO-2015-0004-022 LO-2017-0010-003 LO-2017-0010-005 LO-2017-0010-031

LO-2017-0010-034 LO-2017-0010-042 LO-2017-0134

LO-2017-0010-041 LO-2017-0010-045 OLC 2016-0071-029

A-2

Work Orders

4717267 4923199 5035100 5115933 5152489 5162880

4747977 4923240 5045188 5129400 5155046 5170176

4818769 4924316 5064347 5129938 5155419 5186551

4858438 4934981 5070290 5130230 5157275 5192179

Procedures

Number Title Revision

0.29.1 Licensing Basis Document Changes 35

0.29.2 USAR Control and Maintenance 21

0.4 Procedure Change Process 65

0.5OPS Operations Review of Condition Reports/Operability 57

Determination

0-CNS-FAP-LI-001 Performance Improvement Review Group (PRG) Process 0

0-CNS-LI-102 Corrective Action Process 3-7

0-CNS-LI-118 Cause Evaluation Process 0

0-CNS-WM-100 Work Order Generation, Screening, and Classification 7

0-EN-LI-100 Process Applicability Determination 18C1

0-QA-01 CNS Quality Assurance Program 22

15.SUMP.101 Sump Pump Operability Test 25

2.0.11 Entering and Exiting Technical Specification/TRM/ODAM 41

LCO Condition(s)

2.0.11.1 Safety Function Determination Program 9

2.0.12 Operator Challenges 10-11

2.0.2 Operations Logs and Reports 111

2.1.10 Station Power Changes 113

2.2.20 Standby AC Power System (Diesel Generator) 95

2.2.33 High Pressure Coolant Injection System 79

A-3

Procedures

Number Title Revision

2.2.33A High Pressure Coolant Injection System Component 29

Checklist

2.2.68.1 Reactor Recirculation System Operations 81

3.4.4 Temporary Configuration Change 19

3-EN-DC-203 Maintenance Rule Program 3C0

3-EN-DC-204 Maintenance Rule Scope and Basis 3C0

3-EN-DC-205 Maintenance Rule Monitoring 5C0

3-EN-DC-206 Maintenance Rule (a)(1) Process 3C1

3-EN-DC-207 Maintenance Rule Periodic Assessment 3C0

5.1ASD Alternate Shutdown 18

6.PC.203 Tip Ball Valve Exercising and Timing Test (IST) 9

6.PCIS.302 Group 1, Group 7, and Mechanical Vacuum Pump Isolation 15

Logic Functional Test

7.0.14 Predictive Maintenance Program 7

7.2.51.1 Air-Operator Valve Actuator Setup/Testing 22

98-03-02 System Engineering Desktop Guide 5

Section II - Identification of Critical Components

DGHV-PF04 Maintenance Rule System Basis Document - Diesel 2

Generator HVAC Function 4

DG-PF01 Maintenance Rule System Basis Document - Diesel 5

Generator Function 1

DGSA-PF01 Maintenance Rule System Basis Document - Diesel 3

Generator Starting Air Function 1

EN-DC-178 System Walkdowns 4C0

EN-LI-108-01 10 CFR 21 Evaluations and Reporting 5C0

EN-LI-118 Cause Evaluation Process 22

A-4

Other Documents

Number Title Revision/Date

List of HPCI Maintenance Rule Functional Failures May 2017

List of PCI Maintenance Rule Functional Failures May 2017

HPCI and PCI Surveillance Performance History May 2017

Cooper Nuclear Station Nuclear Safety Culture May 2017

Assessment

List of relays associated with Material Master June 29, 2017

MM2049261 and MM2107105

Nuclear Safety Culture Assessment May 31, 2017

12186-DD-01 Nutherm Dedication Documentation Package for Allen- 0

Bradley Auxiliary Relays

14194-DD-01 Nutherm Dedication Documentation Package for Allen- 0 & 1

Bradley Auxiliary Relays

6.HPCI.103 HPCI IST and 92 Day Test Mode April 20, 2017

July 19, 2016

July 25, 2014

July 26, 2012

September 9, 2014

September 21, 2012

98-03-05 System Engineer Desktop Guide - System Trending 10

ANSI/IEEE IEEE Standard for Relays and Relay Systems December 7, 1989

C37.90-1989 Associated with Electric Power Apparatus

CC05920 Air Operated Control Valve

EE 13-041 Turbine Building Blowout Panels/Metal Wall System 3

ESC 88-330 Documentation of DG Lube Oil and Jacket Water December 27, 1988

Motors

HPCI HPCI System Health Report March 2017

HPCI-PF01 Maintenance Rule System Basis Document - HPCI 4

System Function 1

A-5

Other Documents

Number Title Revision/Date

HV-F16 Maintenance Rule System Basis Document - Control 3

Room Emergency Filtration System Function

IST RAL Inservice Testing Reference Acceptance Limits Data 219

File

LO 2015- ISFSI Self-Assessment October 9, 2015

0184-003

LO 2015-201- Occupational ALARA Planning and Controls January 15, 2016

003 (IP-71124.02) and Occupational Dose Assessment

(IP-71124.04)

MPR Cooper-Bessemer Model KSV Diesel Engine March 26, 1998

Associates Operating Temperature Ranges

Letter

MR (a)(1) Maintenance Rule (a)(1) Summary May 2017

MR 1Q2017 Maintenance Rule Program Health Report April 5, 2017

MS-F04 (a)(1) Maintenance Rule (a)(1) Evaluation and Action Plan December 15, 2017

Plan CR 16-07742

NEDC 13-028 Ultimate Internal Pressure of Turbine Building Blowout March 23, 2016

Panels and Metal Wall System

NEDC 16-028 Operability Analysis of Residual Heat Removal Service 2

Water B Piping Minimum Thickness

NEDC 91-239 DGLO/DGJW/DG Intercooler Heat Exchanger 5

Evaluation

NEDC 94-021 REC-HX-A & REC-HX-B Maximum Allowable Accident 7

Case Fouling

NMT-F02 Maintenance Rule (a)(1) Evaluation and Action Plan 0

(a)(1) Plan CR 17-00039

OC MNT Online Corrective Maintenance Backlog May 2017

OD MNT Online Deficient Maintenance Backlog May 2017

PC Primary Containment System Health Report December 2016

A-6

Other Documents

Number Title Revision/Date

PC-COMP1 Maintenance Rule System Basis Document - Primary 3

Containment Components Function 1

PC-CONT1 Maintenance Rule System Basis Document - Primary 4

Containment Leakage Function 1

PC-CONT2A Maintenance Rule System Basis Document - Primary 5

Containment Leakage Function 2A

PC-CONT2B Maintenance Rule System Basis Document - Primary 4

Containment Leakage Function 2B

PC-F01 Maintenance Rule System Basis Document - Primary 4

Containment Function 1

PC-F02 Maintenance Rule System Basis Document - Primary 4

Containment Function 2

PC-F03 Maintenance Rule System Basis Document - Primary 3

Containment Function 3

PC-F04 Maintenance Rule System Basis Document - Primary 4

Containment Function 4

PC-F05 Maintenance Rule System Basis Document - Primary 3

Containment Function 5

PC-F07 Maintenance Rule System Basis Document - Primary 3

Containment Function 7

PC-F08 Maintenance Rule System Basis Document - Primary 3

Containment Function 8

PC-F09 Maintenance Rule System Basis Document - Primary 3

Containment Function 9

PC-F10 Maintenance Rule System Basis Document - Primary 4

Containment Function 10

PCI Trend Primary Containment System Engineer MOV Trend January 7, 2016

Data

PCLRT Primary Containment Leakage Rate Testing Program 22

Document

A-7

Other Documents

Number Title Revision/Date

PCR 2.2.20 Procedure Change Notice for System Operating 37

Rev. 37 Procedure 2.2.20

PCR 2.2.20 Procedure Change Request for System Operating 71

Rev. 71 Procedure 2.2.20

QAD 2016- QA Audit 15-10 "Training" January 7, 2016

0001

QAD20150015 QA Audit 15-05, "Maintenance" August 5, 2015

QAD20160009 QA Audit 16-02, "Engineering" April 6, 2016

REC-F01 Maintenance Rule System Basis Document - Reactor 4

Equipment Cooling Noncritical Function 1

REC-PF01 Maintenance Rule System Basis Document - Reactor 3

Equipment Cooling Critical Function 1

RMA-F02 Maintenance Rule (a)(1) Evaluation and Action Plan 0

(a)(1) Plan CR 17-02637

A-8

ML17219A742

SUNSI Review: ADAMS: Non-Publicly Available Non-Sensitive Keyword:

By: EAR Yes No Publicly Available Sensitive NRC-002

OFFICE RIV/DRS RIV/DRS RIV/DRP RIV/DRP RIV/DRP RIV/DRS

NAME GPick HFreeman PVoss CYoung JKozal ERuesch

SIGNATURE /RA/ /RA/ /RA/E CHY JWK EAR

DATE 07/20/2017 07/26/2017 07/14/2017 07/28/2017 07/31/2017 08/03/2017

OFFICE RIV/DRS

NAME THipschman

SIGNATURE /RA/

DATE 08/07/2017

E=Email

ML17219A742

Text

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