IR 05000045/1961013

IR 050004561-13-007, on 08/12/13 - 08/30/13; Clinton Power Station; Biennial Baseline Inspection of the Identification and Resolution of Problems

ML13274A698
Person / Time
Site:	Clinton, 05000045
Issue date:	10/01/2013
From:	Christine Lipa NRC/RGN-III/DRP/B1
To:	Pacilio M Exelon Generation Co, Exelon Nuclear
References
IR-13-007
Download: ML13274A698 (32)

Text

UNITED STATES ber 1, 2013

SUBJECT:

CLINTON POWER STATION PROBLEM IDENTIFICATION AND RESOLUTION INSPECTION REPORT 05000461/2013007

Dear Mr. Pacilio:

On August 30, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed a Problem Identification and Resolution (PI&R) inspection at Clinton Power Station. The enclosed report documents the inspection results, which were discussed on August 30, 2013, with Mr. B. Taber and other members of the licensee staff.

The inspection was an examination of activities conducted under your license as they relate to problem identification and resolution and compliance with the Commissions rules and regulations and with the conditions of your license. Within these areas, the inspection involved examination of selected procedures and representative records, observations of activities, and interviews with personnel.

Based on the inspection sample, the inspection team concluded that the implementation of the corrective action program and overall performance related to identifying, evaluating, and resolving problems at Clinton Power Station was effective. Licensee identified problems were entered into the corrective action program at a low threshold. Problems were effectively prioritized and evaluated commensurate with the safety significance of the problems and corrective actions were generally implemented in a timely manner commensurate with their importance to safety and addressed the identified causes of problems. Lessons learned from industry operating experience were generally reviewed and applied when appropriate. Audits and self-assessments were effectively used to identify problems and appropriate actions.

One NRC-identified finding of very low safety significance (Green) was identified during this inspection. This finding was determined to involve a violation of NRC requirements. The NRC is treating this violation as a non-cited violation (NCV) consistent with Section 2.3.2 of the Enforcement Policy. If you contest the violation or significance of the NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator, Region III; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at Clinton Power Station.

If you disagree with the 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 Regional Administrator, Region III and the NRC Resident Inspector at Clinton Power Station.

In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter and its enclosure will be made available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records System (PARS)

component of NRCs Agencywide Documents Access and Management System (ADAMS),

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

Sincerely,

/RA/

Christine Lipa, Chief Branch 1 Division of Reactor Projects Docket No. 50-461 License No. NPF-62

Enclosure:

Inspection Report 05000461/2013007 w/Attachment: Supplemental Information

REGION III==

Docket No: 50-461 License No: NPF-62 Report No: 05000461/2013007 Licensee: Exelon Generation Company, LLC Facility: Clinton Power Station Location: Clinton, IL Dates: August 12 - 30, 2013 Inspectors: L. Haeg, Senior Resident Inspector, Duane Arnold, Team Lead R. Langstaff, Senior Reactor Inspector D. Lords, Resident Inspector, Clinton Power Station C. Zoia, Operations Inspector S. Mischke, Resident Inspector, Illinois Emergency Management Agency Approved by: Christine Lipa, Chief Branch 1 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

Inspection Report (IR) 05000461/2013007, 08/12/13 - 08/30/13; Clinton Power Station;

Biennial Baseline Inspection of the Identification and Resolution of Problems.

This team inspection was performed by the Duane Arnold Senior Resident Inspector, the Clinton Resident Inspector, two Region III inspectors, and the Clinton Illinois Emergency Management Agency Resident Inspector. One Green finding was identified by the inspectors.

The finding was considered a non-cited violation (NCV) of NRC regulations. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review.

The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

Identification and Resolution of Problems Overall, the Clinton Power Station Corrective Action Program (CAP) was appropriately identifying, evaluating, and correcting issues. Issues were generally being identified at a low threshold, evaluated appropriately, and corrected in the CAP. Overall performance in prioritization and evaluation of issues was acceptable. Issues were appropriately screened by both the Station Ownership Committee and the Management Review Committee and the inspectors had no concerns with those items assigned an apparent cause evaluation or root cause evaluation. Corrective actions were generally appropriate for the identified issues.

Those corrective actions addressing selected NRC documented violations were also generally effective and timely. The inspectors review going back five years of the licensees efforts to address issues with Service Water (SX) system did not identify any negative trends or inability by the licensee to address long term issues. However, the inspectors determined that corrective actions for some issues had not been effective.

In general, operating experience (OE) was effectively utilized at the station. The inspectors observed that OE was discussed as part of the daily station and pre-job briefings. Industry OE was effectively disseminated across the various plant departments and no significant issues were identified during the inspectors review of licensee OE evaluations.

The inspectors concluded that self-assessments and audits were typically accurate, thorough, and effective at identifying issues and enhancement opportunities at an appropriate threshold level. The inspectors observed that CAP items had been initiated for issues identified through Nuclear Oversight department audits and self-assessments. The inspectors reviewed the most recent self-assessment performed on the CAP; found no issues, and generally agreed with the overall results and conclusions drawn.

The inspectors determined that plant staff were aware of the importance of having a strong safety-conscious work environment and expressed a willingness to raise safety issues. No one interviewed had experienced retaliation for raising safety issues or knew of anyone who had failed to raise issues. All plant staff interviewed had an adequate knowledge of the CAP process. Based on these limited interviews, the inspectors concluded that there was no evidence of an unacceptable safety-conscience work environment.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Mitigating Systems

Green.

The inspectors identified a finding of very low safety significance associated with the licensees failure to appropriately evaluate the functionality of the B Diesel Fire Pump (DFP) after identifying a degraded/non-conforming crankcase pressure condition while performing testing on June 13, 2011, and on numerous occasions thereafter, that could have affected the ability of the system to perform a function important to safety.

An associated NCV of Clinton Power Station License Condition 2.F was identified. The License Condition required the licensee to implement and maintain in effect all provisions of the approved Fire Protection program as described in the Updated Final Safety Analysis Report (UFSAR). Appendix E, Section 4.0.C.8 of the UFSAR stated that the Clinton Power Station Quality Assurance Program establishes measures for corrective action on conditions adverse to fire protection. Quality Assurance Topical Report (QATR), Chapter 16, Section 2.4 stated that personnel performing the evaluation function of conditions adverse to quality are responsible for considering the cause and the feasibility of corrective action to assure that the necessary quality of an item is not deteriorated. The licensee entered the issues into the CAP and initiated corrective actions to evaluate the functionality of the B DFP.

The failure to correctly evaluate a degraded/non-conforming condition potentially affecting the functionality of structures, systems, and components (SSCs) important to safety would become a more significant safety concern if left uncorrected because it could reasonably result in an unrecognized condition of an SSC failing to fulfill a function important to safety. In addition, the finding 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. Specifically, the degraded condition of high crankcase pressure resulted in repeat operational equipment challenges and extended periods of unavailability of the B DFP. Therefore the finding was of more than minor significance. The finding was a licensee performance deficiency of very low safety significance (Green) because it involved only a low degradation of the protection against external factors function due to a redundant train that could supply water. The inspectors concluded that this finding affected the cross-cutting area of problem identification and resolution. Specifically, the licensee failed to thoroughly evaluate problems such that the resolutions addressed causes and extent of condition as necessary for an SSC important to safety when a degraded/non-conforming condition was identified. P.1(c) (Section 4OA2.1.b.(2))

Licensee-Identified Violations

No violations of significance were identified.

REPORT DETAILS

4OA2 Problem Identification and Resolution

The activities documented in Sections

.1 through .4 constituted one biennial sample of

Problem Identification and Resolution (PI&R) as defined in Inspection Procedure (IP) 71152.

.1 Assessment of the Corrective Action Program Effectiveness

a. Inspection Scope

The inspectors reviewed the licensees CAP implementing procedure LS-AA-125, Corrective Action Program (CAP) Procedure, Revision 17, and other implementing procedures for compliance with the requirements of Title 10 Code of Federal Regulations (CFR) Part 50, Appendix B, Criterion XVI, Corrective Action, were met. The inspectors observed meetings related to the CAP, such as the Station Oversight Committee (SOC) and Management Review Committee (MRC) meetings, to obtain insights into the licensees oversight of the CAP. Additionally, several licensee personnel were interviewed to assess their understanding of and their involvement in the CAP at Clinton Power Station (CPS).

The inspectors reviewed selected condition reports (CRs) across all seven Reactor Oversight Process cornerstones to determine if problems were being properly identified and entered into the licensees CAP. The inspectors used issues identified through NRC generic communications, department self-assessments, licensee audits, OE reports, and NRC-documented findings as sources to select items to review. Additionally, the inspectors reviewed CAP items generated as a result of facility personnel performance in daily plant activities, and reviewed a selection of completed investigations from the licensees various investigation methods, including root, apparent, and common cause evaluations. The majority of risk-informed samples of CRs reviewed were issued after the last NRC biennial PI&R inspection completed in early June of 2011.

The inspectors performed a more extensive review of the safety-related service water (SX) system. This review consisted of a five year search of related issues identified in the CAP and discussions with appropriate licensee staff to assess the licensees efforts in addressing identified concerns.

During their reviews, the inspectors evaluated whether the licensees actions were in compliance with the facilitys CAP and Title 10 CFR Part 50, Appendix B requirements.

Specifically, the inspectors evaluated if licensee personnel were identifying plant issues at the proper threshold, entering the plant issues into the stations CAP in a timely manner, and assigning the appropriate prioritization for resolution of the issues. The inspectors also assessed whether licensee staff had assigned appropriate investigation methods to ensure the proper determination of root, apparent, and contributing causes.

The inspectors also reviewed the timeliness and effectiveness of corrective actions for selected CRs, completed investigations, and NRC findings, including NCVs.

b. Assessment

(1) Identification of Issues Based on the results of the inspection, the inspectors concluded that, in general, the licensee was effective in identifying issues at a low threshold and entering them into the CAP. The inspectors determined that problems were generally identified and captured in a complete and accurate manner in the CAP. The licensee appropriately screened issues from both NRC generic communications and industry OE at an appropriate level and entered them into the CAP when applicable. The inspectors also noted that deficiencies that were identified by external organizations (including the NRC) that had not been previously identified by licensee personnel were entered into the CAP for resolution.

Workers were familiar with the CAP and felt comfortable raising concerns. This was evident by the large number of CAP items generated annually; which were reasonably distributed across the various departments. Based on the interviews of licensee personnel, some individuals expressed confusion regarding station CAP engagement indicators. The confusion related to the perception from some individuals that intermittent declining CR generation rates per person or per department had led to management expecting higher CAP engagement. For example, some individuals stated that they were expected to document at least one issue in the CAP per month. License management informed the inspectors that there was no specific expectation for individuals to document a certain number of issues in the CAP. Although the inspectors recognized the importance of reinforcing engagement in the CAP by all station personnel, they noted that management expectations were not consistent, clear, or well understood. The licensee captured this inspector observation in CR 01555073.

The inspectors determined that the licensee was generally effective at trending low level issues to prevent larger issues from developing. The licensee also used the CAP to document instances where previous corrective actions were ineffective or were inappropriately closed.

The inspectors performed a five year extensive review of the SX system. As part of this review, the inspectors interviewed the system engineer, reviewed a sample of SX system CRs, operating experience, and causal evaluations. The inspectors reviewed the CAP procedures that provided trending guidance and walked down various portions of the SX system area to visually inspect equipment condition. The inspectors concluded that SX system-related concerns were identified and entered into the CAP at a low threshold, and concerns were resolved in a timely manner commensurate with their safety significance. An observation related to the adequacy of documenting the decision making regarding a declining discharge pressure trend on the Division 3 SX pump is documented in Section 4OA2.1.b.(2) below.

Findings No findings were identified.

(2) Effectiveness of Prioritization and Evaluation of Issues Based on the results of the inspection, the inspectors concluded that, overall, the licensee was effective in prioritizing and evaluating issues commensurate with the safety significance of the identified issue, including an appropriate consideration of risk. The inspectors determined that issues were being appropriately screened by both the SOC and MRC, and issues identified of higher significance were assigned root or apparent cause evaluations. Notably, the inspectors concluded that the licensees prioritization and evaluation of issues had improved since the prior biennial PI&R inspection considering the documented observations of a declining trend in this area in June of 2011.

The inspectors performed a detailed review of issues entered into the Maintenance Rule (a)(1) category over the last two years. The review included the main control room ventilation (VC) system which had experienced a repeat maintenance preventive functional failure. The inspectors reviewed action plans approved by the maintenance rule expert panel, associated causal evaluations, Maintenance Rule evaluations, and other associated CRs. The inspectors noted that the licensee generally showed no reluctance in placing SSCs into Maintenance Rule (a)(1) status if appropriate.

Corrective actions to address the deficiencies were prescribed and in progress.

Additionally, detailed reviews of the SSCs generally occurred before returning SSCs to Maintenance Rule (a)(2) status.

The inspectors determined that the licensee usually evaluated equipment operability and functionality requirements adequately after a degraded or non-conforming condition was identified. In general, appropriate actions were assigned to correct degraded or non-conforming conditions.

However, the inspectors noted vulnerabilities and deficiencies in the licensees evaluations of operability, functionality, and reportability for some conditions. These vulnerabilities and deficiencies led to several NRC findings and NCVs over the prior two years.

Observations Common Cause Analyses The inspectors reviewed licensee procedure LS-AA-125-1002, Common Cause Analysis Manual, Revision 7, to determine what criteria were being used to initiate a Common Cause Analysis (CCA). The inspectors noted that the procedure did not contain prescriptive criteria to determine when a CCA was warranted, but rather cognitive trending and/or SOC or MRC requests. Although the inspectors did not identify any significant quantitative trends that warranted a CCA, they were concerned that the lack of more prescriptive criteria could allow for an adverse trend to not be analyzed.

The licensee documented this observation in CR 01555046. For the CCAs that were reviewed by the inspectors, the bases for performing the analyses appeared appropriate as well as the evaluation thoroughness and actions taken.

Division 3 SX Pump Discharge Pressure Trend The inspectors reviewed CR 01049920 regarding a declining discharge pressure trend of the Division 3 SX pump and noted that an Operational Decision Making (ODM) item was created to track the issue; however, the ODM was closed without documenting the basis for closure. After further review, the inspectors verified that the ODM closure was acceptable since actions were completed to obtain a spare pump for eventual replacement, but were concerned that the bases were not documented by the licensee.

The licensee documented the inspectors concern in CR 01550820.

Investigation Class Criteria and Trend Coding Issue The inspectors reviewed NCV 05000461/2011009-01 associated with an unsecured fire door. Following the NRC exit meeting for the preliminary NCV in March of 2011, the licensee documented the potential NCV in the CAP and classified the investigation class as level D. Per LS-AA-120, Issue Identification and Screening Process, Revision 14, a level D investigation class is described as requiring no formal causal evaluation to determine causes or corrective actions. The inspectors noted that NRC Enforcement Policy states, in part, that the NRC will normally issue an NCV following placement of the violation into the CAP to restore compliance and address recurrence. The inspectors were concerned that labeling a preliminary NCV as investigation class D could result in not performing an evaluation to determine causes or corrective actions, as stated in LS-AA-120. The inspectors performed additional reviews of how the licensee dispositioned the violation following receipt of the inspection report documenting the NCV. The inspectors noted that the cause and corrective actions were straightforward for the violation in this case and subsequent evaluations performed by the licensee addressed recurrence. However, the subjective criteria for determining investigation class per LS-AA-120 had the potential to result in not evaluating violations that NRC inspectors were considering as non-cited. The licensee documented the inspectors observation in CR 01551297.

The inspectors also questioned whether the licensee was appropriately applying trend codes to fire door issues when the inability of fire doors to automatically close and/or latch was identified in the CAP. The licensee documented the inspectors question in CR 01550099 to evaluate whether CAP trend coding for fire door issues could be improved to better identify developing adverse trends in human performance aspects versus equipment aspects related to fire door deficiencies.

Operability and Functionality Determinations and OE Assessment Weaknesses The inspectors noted an adverse performance trend for the past five years related to NRC findings involving the licensees evaluation of degraded/non-conforming plant conditions for operability, functionality and/or reportability. While corrective actions were performed to address the adverse trend in accordance with the CAP, the trend appeared to be ongoing. The inspectors reviewed Operations department weaknesses in the areas of Operations ownership of the operability determination process, review and use of OE, and technical oversight.

The inspectors noted Operations ownership weaknesses involving the inadequate operability evaluation for hub cracking of VC return fan 0VC04CB in 2011. This failure, which resulted in NRC-identified NCV 05000461/2011004-04, was evaluated by the licensee to have an apparent cause of Lack of Engineering Judgment and a contributing cause of Lack of Management Rigor for not requiring further equipment inspections. The inspectors noted that the Operations department, the owner of the operability process, was not identified to be a significant part of these corrective actions.

The inspectors also noted that eventual hub failure of VC return fan 0VC04CB (and the subsequent incorrect operability evaluation) was avoidable if OE had been more fully utilized. Specifically, similar failures had occurred at Brunswick as noted in OE in March of 2004; in a root cause evaluation from Three Mile Island in March of 2005; and again at Clinton in October of 2006. Although these OE examples did not specifically identify fan blade replacement as the appropriate preventive maintenance (PM)approach, replacement was ultimately found to be needed after numerous attempts to monitor degradation via vibration monitoring were proved to be ineffective (this was documented in ACE 1225739 as being a Latent Organizational Weakness and corrected by implementing the replacement PM) after the 2011 failure.

Additionally, technical oversight weaknesses were noted for three issues reviewed by the inspectors: hydrogen igniter testing, VC flow oscillations, and reactor coolant system (RCS) pressure isolation valve (PIV) leakage testing. Specifically:

• Hydrogen igniters were to be verified operable every 24 months per Technical Specification (TS) Surveillance Requirement (SR) 3.6.3.2.4. Although the test procedure to perform the SR was not owned by Operations, the results were reviewed by Operations for TS conformance and were found to be incorrect for a period exceeding 10 years. Specifically, several hydrogen igniters specified as accessible were not tested as required by the procedure. When the procedural deficiency was finally identified by the NRC in 2011, five hydrogen igniters were considered inoperable due to missed surveillances and required retesting (reference CR 01164658-02 and NCVs05000461/2011002-02 & -03).

• When presented with VC makeup flow oscillations below the required minimum value per procedure CPS 9070.01, Control Room HVAC Air Filter Package Operability Test Run, a senior reactor operator (SRO) failed to identify the challenge to VC system operability per TS 3.7.3. In addressing the abnormality, the SRO documented in a CR that there were Possibly problems with OVC114YA.

Investigate and correct issue. When questioned by the NRC in 2011, it was determined that other Operations personnel may have had a similar knowledge deficiency that was ultimately addressed by Read & Sign training (reference apparent cause evaluation (ACE) 01239007 and NCV 05000461/2011004-04).

• Contrary to the guidance of SR 3.4.6.1, RCS PIVs were pressurized to a value exceeding the maximum test pressure of 1025 psig during testing. The procedural guidance of CPS 9843.01, ISI Category A Valve LRT, Revision 35f, had allowed a maximum test pressure of 1025 psig (+25 psig, -0 psig). When the NRC identified this discrepancy in 2011, the licensee found that they had evaluated the procedural error as conservative several years earlier (the error had existed since February of 2002, and was previously evaluated in 2005) (reference NCV 05000461/2011003-02, Clinton Licensee Event Report (LER) 2011-006, and ACE 01212825).

In summary, it was found that while some recent improvements in the operability and functionality determination process were noted, weaknesses in the utilization of OE and technical oversight continued to exist. At the end of this inspection, the inspectors acknowledged that the licensee had improvement initiatives in place to strengthen the operability and functionality determination process and OE assessments, but emphasized continued efforts due to the apparent slow rate of progress.

Effectiveness Review Timeliness The inspectors reviewed root cause report (RCR) 01506929, Manual Scram Due to Loss of Electro-Hydraulic Control (EHC) Fluid, and identified that the effectiveness review (EFR) to verify lock washers installed, work orders revised, and bill of materials corrected had a due date of April 1, 2015. However, the inspectors noted that the corrective action to prevent recurrence (CAPR) to revise work order documents had been completed by June 28, 2013. The inspectors questioned why the EFR had such a late due date since the CAPRs were complete and could be reviewed for effectiveness.

The licensee determined that an administrative change to the CAPR occurred during development of the RCR that removed some actions from the CAPR, but the EFR due date was not changed accordingly. The licensee documented the excessive EFR due date in CR 01549645 to adjust the EFR due date.

Findings Failure to Evaluate a Degraded/Non-conforming Condition

Introduction:

The inspectors identified a finding of very low safety significance (Green) and associated NCV of License Condition 2.F for the licensees failure to appropriately evaluate the functionality of the B diesel fire pump (DFP) after identifying a degraded/non-conforming crankcase pressure condition during testing on June 13, 2011, and on numerous occasions thereafter, which could have affected the ability of the system to perform a function important to safety.

Description:

On June 13, 2011, during a post-maintenance test run of the B DFP, excessive smoke was observed coming from the engine on the pump end as well as coming from underneath the engine on its east end. These issues were documented in the licensees CAP as CR 01228254 that stated the smoke was most likely due to a positive crankcase pressure condition. The CR recommended that Engineering and Mechanical Maintenance departments either determine whether the condition was acceptable, or determine the feasibility of an engine teardown and replacement of the piston compression rings. At that time, the post-maintenance test was considered a failure and the pump remained non-functional pending the successful completion of CPS 9071.01, Diesel Driven Fire Pumps Operability Test, as documented in main control room logs. Subsequently, on June 14, 2011, CPS 9377.04, Battery Operability Test, and a partial performance of CPS 9072.02, Fire Pump Capacity Test, were satisfactorily completed and the pump was declared functional. No maintenance was performed after the failed test of June 13, 2011, and there was no documented evaluation of the degraded crankcase pressure condition for the B DFP.

On July 7, 2011, during the next scheduled surveillance test, the B DFP engine oil dipstick unseated and sprayed four to eight ounces of oil. The issue was documented in CR 01237444, and stated in part, that the same event had occurred during that last time the engine was run. A specific question was asked in CR 0123744: Is there a problem with the 0FP01PB engine that is causing an above normal crankcase pressure? It was also noted that although the pump subsequently passed its surveillance test, the crankcase pressure was neither an observable parameter nor an acceptance criteria during testing. To answer the question posed in CR 0123744, the following response was provided: Dipstick was reinstalled and pump surveillance completed SAT; appears to be no problem with crankcase pressure. The inspectors noted that the licensee performed no further evaluation at that time, and that engine crankcase pressure of the B DFP was only first measured on November 12, 2012 (a year and four months later).

On August 3, 2011, during a surveillance test of the B DFP, the engine dipstick again ejected and sprayed one to two quarts of oil onto the engine batteries as documented in CR 01247414. The dipstick was replaced several times and eventually secured in place with a zip-tie. The pump was declared non-functional and the CR stated that the possible blow-by of pistons causing crankcase pressurization was a restraint to declaring the subsystem functional. Subsequently, on August 8, 2011, main control room logs stated that although no work had been completed on the B DFP, the condition identified (ejection of the dipstick) had been resolved and tested satisfactory, and the subsystem was declared functional. No evaluation of crankcase pressure was performed by the licensee, nor was there an explanation why the restraint to declaring the B DFP functional for crankcase pressurization was no longer a concern. The pump subsequently passed 13 surveillance tests. During this time there were numerous documented cases of the degraded condition of high crankcase pressure being masked during these surveillance tests either by repeatedly reinserting the dipstick or using a zip-tie to hold it in place. Crankcase pressure was never observed nor measured during any of these surveillance tests.

On September 3, 2012, the B DFP received an automatic start signal. Upon entering the area, the pump was observed to be spraying oil into the room and onto its batteries.

The engine was secured and left in the OFF position due to no oil level registering on the dipstick when it was reinserted into the engine block. The pump was later placed in AUTO and declared functional due to the addition a quart of oil. Later, on September 5th, 2012, CR 01409202 was written to, again, document the concern of the degraded condition of high crankcase pressure due to leak-by past the piston compression rings. Again, similar to CR 01228254 written on June 13, 2011, the recommended action was for engineering to perform an evaluation of crankcase pressure. This time, in response, Engineering documented on September 12, 2012, that the symptoms were indicative of high crankcase pressure and that the diesel engine vendor representative should be brought on site to measure the crankcase pressure.

Engineering also stated that if the pressure was found to be greater than 22 inches of water, the engine would require a rebuild. On September 20, 2012, the B DFP received another automatic start signal. Once again, the dipstick was ejected and the engine sprayed a quart of oil onto its batteries and other components as documented in CR 01416249. The engine was immediately shut down for personnel safety reasons and declared functional but degraded. Eventually, when B DFP engine crankcase pressure was measured on November 2, 2012, the instrument gauge pegged high greater than 30 inches of water within less than a minute of operation of the engine.

The diesel engine vendor (Cummins) field engineer stated that if the engine crankcase pressure was found to be higher than 22 inches of water, an engine rebuild was required. High diesel engine crankcase pressure was also a concern for a number of other reasons. Notably, CR 01408355 documented an injury suffered by a licensee operator due to a slip while walking around the engine after it sprayed oil which had covered the floor, and CR 01432868 documented on October 29, 2012, that the B DFP engine had to be secured and disabled due to concerns related to the fire hazard created by oil on the exhaust manifold after the dipstick had dislodged and deposited oil from the dipstick tube. The inspectors also noted that high diesel engine crankcase pressures indicated a potentially explosive condition within the engine. Specifically, the possibility for overheated bearings to ignite hot oil vapors if air was allowed to enter a pressurized crankcase with degraded engine piston compression rings.

Analysis:

The inspectors determined that the licensees failure to appropriately evaluate the functionality of the B DFP was contrary to the licensees quality assurance program as described in NO-AA-10, Quality Assurance Topical Report, Appendix A, and was a performance deficiency. Specifically, after first identifying a degraded condition of high crankcase pressure on June 13, 2011, and on numerous occurrences thereafter where identical symptoms existed, the licensee failed to evaluate the functionality of the B DFP with respect to the underlying degraded condition and instead focused on symptoms (i.e. dipstick ejection and possible operator error). The finding was determined to be more than minor because the finding was associated with the Mitigating Systems cornerstone attribute of Protection Against External Factors (Fire)and affected the cornerstone objective of ensuring the reliability of systems that respond to initiating events (i.e., fire) to prevent undesirable consequences (i.e., core damage).

Specifically, although incidents involving dipstick ejections had not resulted in the failure of the B DFP, the inspectors could not rule out the possibility of an engine failure due to either accelerated oil loss or potential ignition of oil with associated fire damage.

In accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, Table 2, the inspectors determined the finding degraded fire protection defense-in-depth strategies. The inspectors also determined, using Table 3, that it could be evaluated using Appendix F, Fire Protection Significance Determination Process. The inspectors determined that this finding constituted a Low Degradation in accordance with the criteria established in IMC 0609 Appendix F, Attachment 2. Therefore in answering yes to question B of Step 1.4 of IMC 0609 Appendix F, Attachment 1, the inspectors determined that the finding was of very low safety significance (i.e., Green) with no further analysis required.

This finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Corrective Action Program, because the licensee did not thoroughly evaluate problems such that the resolutions addressed causes and extent of conditions, as necessary. This included properly classifying, prioritizing, and evaluating for operability (or functionality) conditions adverse to quality. Specifically, the licensee failed to appropriately evaluate the cause of the B DFP dipstick ejections after identifying a degraded/non-conforming crankcase pressure condition while performing testing on June 13, 2011, and on numerous occasions thereafter, which could have affected the ability of the system to perform a function important to safety. P.1(c)

Enforcement:

Clinton Power Station License Condition 2.F requires the licensee to implement and maintain in effect all provisions of the approved Fire Protection program as described in the UFSAR as amended and as approved through Safety Evaluation Report (NUREG-0853) dated February of 1982 and Supplement Nos. 1 thru 8.

Appendix E, Section 4.0.C of the UFSAR as amended states that portions of the Quality Assurance Program, as delineated in Appendix A of the QATR, apply to fire protection.

Appendix A, Section 2.4 of the QATR, states, in part, that the Quality Assurance Program established for fire protection SSCs that protect SSCs important to safety ensures that corrective actions meet the applicable Quality Assurance guidelines as described in the applicable edition of Branch Technical Position 9.5-1 for each Exelon site. The diesel engines for the fire pumps are fire protection SSCs that protect SSCs important to safety. Appendix E, Section 4.0 of the UFSAR provides the applicable edition of Branch Technical Position 9.5-1 for Clinton Power Station. Appendix E, Section 4.0.C.8, states that the Clinton Power Station Quality Assurance Program establishes measures for corrective action of conditions adverse to fire protection.

Chapter 16 of the QATR describes the Company program to identify and correct conditions adverse to quality. Specifically, QATR Chapter 16, Corrective Action, Section 2.4, Evaluation and Qualification, states, Personnel performing the evaluation function are responsible for considering the cause and the feasibility of corrective action to assure that the necessary quality of an item is not deteriorated.

Contrary to the above, on June 13, 2011, and on numerous occasions thereafter, the licensee failed to implement and maintain in effect all provisions of the approved Fire Protection program as described in the UFSAR as amended. Specifically, the licensee failed to appropriately evaluate the functionality of the B DFP after identifying a degraded/non-conforming crankcase pressure condition. This violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy because it was of very low safety significance and was entered into the licensees CAP as CR 01552494.

The licensee replaced the B DFP engine in December of 2012 under work order 1448046. (NCV 05000461/2013007-01, Failure to Evaluate a Degraded/ Non-conforming Condition on Diesel Fire Pump)

(3) Effectiveness of Corrective Action Based on the results of the inspection, the inspectors concluded that the licensee was generally effective in addressing identified issues, and the assigned corrective actions were generally appropriate. The licensee implemented corrective actions in a timely manner, commensurate with their safety significance, including an appropriate consideration of risk. Problems identified using root or apparent cause methodologies were resolved in accordance with CAP procedures and regulatory requirements.

Corrective actions designed to preclude repetition were generally comprehensive, thorough, and timely. For example, at the time of this inspection, only three open operator workarounds/burdens were in place; a particularly low number considering that the station was late in the operating cycle. The inspectors sampled corrective action assignments for selected NRC documented violations and determined that actions assigned were generally effective and timely. The inspectors review going back five years of the licensees efforts to address issues with SX system did not identify any negative trends or the inability by the licensee to address long term issues.

Based on the finding and NCV discussed above associated with the failure to evaluate the functionality of the B DFP, the inspectors noted that interim corrective actions taken by the licensee to address the high crankcase pressure condition since 2011 were generally ineffective to eliminate the cause. The inspectors noted that the performance of testing to measure crankcase pressures of the B DFP engine were not timely to properly assess ongoing degradation of the engine that ultimately led to engine replacement.

Failure to Take Appropriate Corrective Action for a Condition Adverse to Quality During the review of RCR 01307531, Chemistry Parameters Exceeded Action Level 1 Limits, the inspectors identified that the licensees corrective action to resolve Contributing Cause #2, Reactor Coolant cleanup was not maximized during startup, was to code work order 1498918, Rebuild/Rework reactor water cleanup (RT) filter demineralizer B actuator for 1G36-F006B as a corrective action. This work order for the RT actuator was completed on December 18, 2011. The action level 1 limits for chemistry parameters were exceeded on December 21, 2011. Therefore the corrective action for the contributing cause of not maximizing RT during startup was to repair a valve actuator which was actually repaired prior to the occurrence of the condition adverse to quality. Inspectors observed that repair of the 1G36-F006B did not in fact prevent chemistry parameters from exceeding limits.

Licensee procedure LS-AA-125, Corrective Action Program (CAP) Procedure, Revision 17, defines a corrective action as an action taken or planned that restores a condition adverse to quality to an acceptable condition or capability. In this case, the condition adverse to quality was that reactor coolant cleanup was not maximized during startup. The action assigned to correct this condition (coding the work order to repair the 1G36-F006B valve actuator as a corrective action), did not restore the condition adverse to quality to an acceptable condition. In fact, changing the coding of the work order had no actual plant impact. The work itself was completed long before the coding change occurred, and, completing the work did not prevent chemistry parameters from exceeding limits four days later.

The inspectors determined that the licensees failure to have an appropriate corrective action for a licensee-identified condition adverse to quality is a violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, which requires, in part, that measures shall be established to assure that conditions adverse to quality and non-conformances are promptly identified and corrected. Licensee procedure LS-AA-125 states that corrective action assignments are the method by which the licensee restores a condition adverse to quality. Contrary to the above requirements, the corrective action assigned to re-code the work order to rebuild/rework 1G36-F006B did not restore the condition adverse to quality of failing to maximize use of the reactor water cleanup system during startup.

The licensee generated CR 01550123, PI&R - Challenge to Actions from Root Cause

1. 1307531-06, to revise RCR 01307531 to reference ACE 01313140 corrective actions

1. 18, #20 and #27, as well as action items #19 and #34 that clearly address the condition adverse to quality of failing to maximize the use of the reactor water cleanup system during startup. The inspectors determined that the performance deficiency was minor because it was administrative in nature and did not represent a safety concern.

This failure to comply with the requirements of Title 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, constitutes a violation of minor significance that is not subject to enforcement action in accordance with the NRCs Enforcement Policy.

Findings No findings were identified.

.2 Assessment of the Use of Operating Experience

a. Inspection Scope

The inspectors reviewed the licensees implementation of the facilitys OE program.

Specifically, the inspectors reviewed implementing OE program procedures, observed daily meetings for the use of OE information, and reviewed completed evaluations of OE issues and events. The intent was to determine if the licensee was effectively integrating OE experience into the performance of daily activities, whether evaluations of issues were proper and conducted by qualified personnel, whether the licensees program was sufficient to prevent future occurrences of previous industry events, and whether the licensee effectively used the information in developing departmental assessments and facility audits. The inspectors also assessed if corrective actions, as a result of OE experience, were identified and implemented effectively and in a timely manner.

b. Assessment Based on the results of the inspection, the inspectors concluded that, in general, OE was effectively utilized at the station. The inspectors observed that OE was discussed as part of the daily station and pre-job briefings. Industry OE was effectively disseminated across the various plant departments and no issues were identified during the inspectors review of licensee OE evaluations. During interviews, several licensee personnel commented favorably on the use of OE in their daily activities.

The inspectors identified several examples where OE was identified and documented as part of apparent and root cause evaluations, determined to not apply to the condition being evaluated, but minimal to no discussion was documented as to why the OE was not applicable. For example, RCR 01295617, Automatic Scram on High Pressure During Approach to Unit Shutdown, RCR 01408282, Emergency Reserve Auxiliary Transformer and Emergency Reserve Auxiliary Transformer Static Var Compensator Tripped, and ACE 01258926, NRC Identified Weakness in 0VC04CB Operability Evaluation, each documented OE that was identified as part of a search during the evaluations; however, there was no documentation as to why it did not apply. The inspectors were concerned that the lack of the documented justification for why OE did/did not apply could result in minimizing the importance of reviewing OE when evaluating a condition or event at the station that could have been prevented if OE was considered. The licensee documented the inspectors observation as CR 01555051.

Findings No findings were identified.

.3 Assessment of Self-Assessments and Audits

a. Inspection Scope

The inspectors reviewed selected Nuclear Oversight comparative and departmental audits, check-in assessments, and focused area self-assessments. The inspectors evaluated whether these audits and self-assessments were effectively managed, adequately covered the subject areas, and properly captured identified issues in the CAP. In addition, the inspectors interviewed licensee personnel regarding the implementation of the audit and self-assessment programs.

b. Assessment Based on the results of the inspection, the inspectors concluded that self-assessments and audits were typically accurate, thorough, and effective at identifying issues and enhancement opportunities at an appropriate threshold level. The audits and self-assessments were completed by personnel knowledgeable in the subject area. In many cases, these audits and self-assessments had identified numerous issues that were not previously recognized by the licensee. These issues were entered into condition reports as required by CAP procedures.

The inspectors reviewed the focused area self-assessment that the licensee had performed for the 2013 biennial PI&R inspection. They noted that the self-assessment, while thorough, may not have reviewed all items intended since it did not consider issues that occurred prior to, or during, the 2011 biennial PI&R inspection. For example, the aforementioned NCV 05000461/2011009-01 was not within the scope of the self-assessment. If it had been reviewed, the licensee may have had the opportunity to identify the investigation class concern. The licensee acknowledged this observation as a potential enhancement to their focused self-assessment process.

Findings No findings were identified.

.4 Assessment of Safety-Conscious Work Environment (SCWE)

a. Inspection Scope

The inspectors interviewed selected Clinton Power Station personnel to determine if there were any indications that individuals were reluctant to raise safety concerns to either their management, supervision, the employee concerns program (ECP), or the NRC due to the fear of retaliation. The inspectors reviewed selected ECP activities to identify any emergent issues or potential trends. The inspectors also assessed the SCWE through a review of ECP implementing procedures, discussions with the ECP representative, interviews with personnel from various departments, and reviews of CRs.

The licensees programs to publicize the CAP and ECP were also reviewed. The inspectors reviewed licensee self-assessments and assessments by external organizations of safety culture to determine if there were any organizational issues or trends that could impact the licensees safety performance.

b. Assessment The inspectors did not identify any issues that suggested conditions were not conducive to the establishment and existence of a SCWE. Licensee personnel were aware of and generally familiar with the CAP and other processes, including the ECP, through which concerns could be raised. In addition, a review of the types of issues in the ECP database indicated that personnel were appropriately using the CAP and ECP to identify issues. The staff also indicated that management had been supportive of the CAP by providing time and resources for employees to generate their own condition reports.

The staff also expressed a willingness to challenge actions or decisions that they believed were unsafe. All employees interviewed noted that any safety issue could be freely communicated to supervision and safety significant issues were being corrected.

Some employees indicated a number of low level items were not being corrected in a timely manner. The inspectors determined that the timeliness of the planned corrective actions for the examples given were commensurate with their safety significance.

Various safety culture assessments had been performed by contractors, the licensees staff, and a nuclear plant owner/operators organization. The results indicated that there were no impediments to the identification of nuclear safety issues.

During inspector interviews of station personnel, the inspectors received feedback from several individuals that they had not received feedback emails in the instances where their supervisor (initiator) had submitted a condition report for issues they (originator)had identified. The inspectors questioned whether CAP feedback was provided to the initiators and originators in order for the personnel to review the actions being taken for issues they were involved with. The licensees CAP program was automated such that CAP feedback was emailed to the initiator only and not the originator as well. The inspectors questioned whether the licensee had considered this potential deficiency in the CAP feedback process since the originating individual of a CR would not necessarily receive feedback. The licensee documented this question in CR 01555048.

Findings No findings were identified.

4OA6 Management Meetings

.1 Exit Meeting Summary

On August 30, 2013, the inspectors presented the inspection results to Mr. B. Taber and other members of the licensee staff. The licensee acknowledged the issues presented.

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

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

B. Taber, Site Vice President

T. Stoner, Plant Manager

D. Kemper, Site Engineering Director

J. Stovall, Maintenance Director

J. Cunningham, Operations Director

K. Baker, Regulatory Assurance Manager

R. Frantz, Regulatory Compliance

K. Brown, Regulatory Compliance

F. Perryman, Nuclear Oversight Audit Team Lead

J. Tocco, Engineering Balance of Plant Manager

W. Padgett, Work Management On-Line Manager

J. Peterson, Regulatory Programs

R. Chickering, Corrective Action Process

D. Shelton, Operations Services Manager

E. Rodriguez-Ramos, Engineering Balance of Plant Support

Nuclear Regulatory Commission

C. Lipa, Chief, Branch 1, Division of Reactor Projects

W. Schaup, Senior Resident Inspector, Clinton Power Station

LIST OF ITEMS

Opened/Closed

05000461/2013007-01 NCV Failure to Evaluate a Degraded/Non-conforming Condition on Diesel Fire Pump (Section 40A2.1.b.(2))

Attachment