IR 05000461/2013009

IR 05000461-13-009, 12/12-18/2013, Clinton Power Station

ML14031A463
Person / Time
Site:	Clinton
Issue date:	01/31/2014
From:	Boland A Division Reactor Projects III
To:	Pacilio M Exelon Generation Co, Exelon Nuclear
References
IR-13-009
Download: ML14031A463 (32)

Text

UNITED STATES ary 31, 2014

SUBJECT:

CLINTON POWER STATION NRC SPECIAL INSPECTION TEAM REPORT 05000461/2013009

Dear Mr. Pacilio:

On December 18, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed a special inspection at your Clinton Power Station. The special inspection evaluated the facts and circumstances surrounding the unexpected opening of the 1A1 4160V bus breaker due to the events of December 8 and the electrical failure of the step down transformer supplying the bus.

The breaker normally powered the 1A and A1 480V buses and the associated loss of power to the Division 1 components resulted in closure of the outboard instrument air containment isolation valve and loss of instrument air to containment. Operators responded to the resultant loss of air pressure to containment air loads by initiating a reactor scram in accordance with station operating procedures. The enclosed report documents the results of this inspection, which were discussed on December 18, 2013, with Mr. B. Taber and other members of your staff.

Based on the results of this inspection, one NRC-identified finding and one self-revealed finding of very low safety significance were identified. Both findings involved violations of NRC requirements. However, because of their very low safety significance, and because the issues were entered into your corrective action program, the NRC is treating the issues as non-cited violations (NCVs) in accordance with Section 2.3.2 of the NRC Enforcement Policy.

If you contest the subject or severity of these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at the Clinton Power Station. In addition, if you disagree with the cross-cutting aspect assigned to any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region III, and the NRC Resident Inspector at the Clinton Power Station. In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records System (PARS)

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

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

Sincerely,

/RA by K. OBrien for/

Anne T. Boland, Director Division of Reactor Projects Docket No. 50-461 License No. NPF-62

Enclosure:

Inspection Report 05000461/2013009 w/Attachments: Supplemental Information

REGION III==

Docket No: 50-461 License No: NPF-62 Report No: 05000461/2013009 Licensee: Exelon Generation Company, LLC Facility: Clinton Power Station Location: Clinton, IL Dates: December 12 through 18, 2013 Inspectors: J. McGhee, Byron Senior Resident Inspector (Lead)

C. Phillips, Project Engineer, A. Dahbur, Reactor Inspector B. Boston, Reactor Engineer Approved by: Anne T. Boland, Director Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

This report covers a special inspection performed by four NRC Region III inspectors in

December 2013. The inspection was conducted in accordance with Inspection Procedure (IP) 93812. Two Green findings were identified by the inspectors. The findings were considered non-cited violations (NCV) of NRC regulations. The significance of inspection findings is indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) and determined using Inspection Manual Chapter (IMC) 0609, Significance Determination Process dated June 2, 2011. Cross-cutting aspects are determined using IMC 0310, Components Within the Cross Cutting Areas dated October 28, 2011. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy dated January 28, 2013. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process Revision 4, dated December 2006.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Mitigating Systems

Green.

A finding of very low safety significance (Green) and associated non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was self-revealed from an event that resulted in a reactor scram.

Specifically, during troubleshooting of the Unit Substation A transformer failure on December 08, 2013, it was identified that the licensee incorrectly measured the resistance between the three phases of the transformer windings instead of measuring the resistance between the phase windings and ground. The licensee entered this concern into its Corrective Action Program as IR 01594794, and satisfactorily re-measured the insulation resistance for the un-faulted transformer 1AP11E.

The performance deficiency was determined to be more than minor because it was associated with the Mitigating Systems cornerstone attribute of equipment performance and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding screened as very low safety significance (Green), because the inspectors answered No to all Mitigating Systems Screening questions in Exhibit 2 of Appendix A of IMC 0609. The finding was determined to have a cross-cutting aspect in the area of human performance, associated with the work control component, in that the licensee failed to ensure supervisory and management oversight of work activities, including contractors, such that nuclear safety is supported. H.4(c).

[Section 4OA3.2.b (1)]

Green.

The inspectors identified a finding of very low safety significance (Green) and associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure to have adequate acceptance criteria in a testing procedure. Specifically, the minimum acceptable insulation resistance for transformers as specified in Procedure CPS 8440.01 did not meet the minimum vendor recommended values in accordance with the vendor manual. The licensee entered this concern into its Corrective Action Program as IR 01596730 and IR 01598375.

The performance deficiency was determined to be more than minor because it was associated with the Mitigating Systems cornerstone attribute of design control and affected the cornerstone objective of ensuring capability and reliability of systems that respond to initiating events to prevent undesirable consequences. The finding screened as very low safety significance (Green), because the inspectors answered No to all

Mitigating Systems Screening questions in Exhibit 2 of Appendix A of IMC 0609. The inspectors identified the finding had a cross-cutting aspect in the area of problem identification and resolution, associated with the corrective action program component because the licensee failed to ensure issues potentially impacting nuclear safety are promptly identified. P.1(a). [Section 4OA3.2.b (2)]

Licensee-Identified Violations

No findings were identified

REPORT DETAILS

Summary of Plant Event On Sunday, December 8, 2013, Control Room operators inserted a manual reactor scram from 100 percent power, following an electrical system perturbation. The operators had received multiple alarms in the control room upon the unexpected opening of the 1A1 4160V bus breaker 1AP07EJ, which feeds both 480V Unit Substation A (0AP05E) and 480V Unit Substation A1 (1AP11E). Operators determined that the breaker opened as designed due to a fault on a 4160/480V step-down transformer that feeds the A1 480V substation. Operators noted that the outboard containment isolation valve for instrument air to containment had closed with the loss of 480 VAC power. Ten minutes after the breaker opened, the alarm came in for low scram pilot air header pressure. The control room operators then inserted a manual scram by taking the Mode Switch to Shutdown.

Operators began the cooldown to the main condenser through main steam line drains and auxiliary steam equipment. Reactor pressure lowered quickly due to low decay heat since the unit had been refueled in October and had only been operating for about two months.

Operators were able to maintain the cooldown rate within Technical Specification (TS) limits and normal water makeup systems (i.e. condensate and feedwater) remained available throughout the event. The partial loss of Division 1 480 VAC power de-energized the Division 1 containment isolation solenoid valves and isolated instrument air (IA) to the containment when the outboard containment isolation valve, 1IA005, closed. In addition to isolating the air supply to the scram air header, closure of 1IA005 resulted in a loss of air supply to all containment loads including the inboard main steam isolation valves (MSIVs). The inboard MSIVs began to drift closed about an hour after the transformer fault. The last valve indicated full closed about 90 minutes after the containment isolation valve closed. While this isolated main steam lines (MSLs) to the main condenser, the non-safety related main steam line drain valves remained available to the operators and were used to continue to cooldown to Mode 4 within the time limits required by TS. After instrument air pressure was restored to containment, operators augmented pressure and level control using the control rod drive pumps as the makeup supply and reactor water cleanup (RWCU) in the reject mode until the shutdown cooling system could be placed in service.

The partial loss of Division 1 480 VAC power rendered several components inoperable. Low pressure core spray (LPCS) and the A train of residual heat removal were inoperable and unavailable. Reactor Core Isolation Cooling (RCIC) was also declared inoperable because the AC powered RCIC water leg pump could not function, so the licensee could not be assured that the system was free of voids. The Division 1 battery charger lost power and an operator had to align the Class 1E swing charger to supply the Division 1 Battery. Fuel Building Ventilation (VF)fans lost power resulting in the loss of secondary containment when differential pressure did not meet the TS required values for approximately 15 minutes until Standby Gas Treatment (VG)was manually aligned to the Fuel building and differential pressure was restored.

Based on the deterministic criteria provided in Management Directive (MD) 8.3, NRC Incident Investigation Program, the event met MD 8.3 criterion (d), in that there was a loss of LPCS, a single train safety system, and there was a loss of the secondary containment for 15 minutes.

The initial risk assessment resulted in an estimated Conditional Core Damage Probability (CCDP) range of 9.0 E-5 to 1.2 E-4. The Special Inspection Team (SIT) was dispatched to the site and arrived on December 12, 2013.

The SIT charter is included with this report in the Supplemental Information.

4OA3 Special Inspection

.1 Establish a historical sequence of events related to the transformer failure, reactor

scram, and plant recovery actions. Review related licensee actions with respect to monitoring of plant conditions, procedure usage and decision-making.

a. Inspection Scope

The Special Inspection charter charged the team with independently establishing the sequence of events during the December 8, 2013, event and any applicable historical information. To that end, inspectors reviewed operating logs, plant parameter recordings, testing and trend information, and other maintenance records. Inspectors conducted interviews with control room operators, maintenance technicians, and engineering staff. In addition, the inspectors compared the resulting sequence of events to the licensee generated sequence of events to ensure completeness and accuracy of both documents. Pertinent historical information and the timing of those activities such as previous preventative maintenance dates and inspections performed are discussed in the following sections of the report.

Inspectors also reviewed the licensee actions with respect to monitoring of plant conditions, procedure usage and decision-making. The team concluded that the plant responded as designed to the failure and the resulting transient with only a small number of equipment failures. The licensee staff appropriately identified, evaluated and corrected the equipment failures prior to restarting the unit; including installing a modification to replace the failed transformer and performance of immediately required extent of condition testing. Additionally, the team concluded that operator decisions were appropriate and procedures were implemented correctly in response to the event.

Documents reviewed are included in the Supplemental information.

The inspector-generated sequence of events is included with this report in the Supplemental information.

b. Findings

No findings were identified.

.2 Evaluate if the licensee missed prior opportunities to have identified this transformer

failure at an earlier point in time (e.g. surveillance testing) or prevented by periodic replacement or preventative maintenance.

a. Inspection Scope

Inspectors reviewed maintenance records for the failed transformer including the past two performance tests as well as periodic cleaning and inspection preventative maintenance of the transformer cubicle. Outstanding work requests for the switchgear and related components were also reviewed by the inspectors. Additionally, inspectors reviewed vendor materials and documents from the licensees CAP program.

Documents reviewed are included in the Supplemental information.

Maintenance was performed on the transformer cubicle and testing was performed on both the transformer that failed and the other safety-related transformer supplied by this same feeder breaker during the most recent outage in October of 2013. Inspectors did not identify any information during the maintenance record review that indicated the licensee should have identified the subsequent failure of the transformer. During the review of the October work activity, inspectors did identify performance deficiencies that resulted in findings as discussed in the following section. The inspectors found no indication that these performance deficiencies contributed to or would have identified the problem with the transformer prior to the failure in December 2013.

b. Findings

(1) Insulation Resistance Testing for Unit Substation Transformers Was Incorrectly Performed

Introduction:

A finding of very low safety significance (Green) and associated non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was self-revealed from an event that resulted in a reactor scram.

Specifically, during troubleshooting of the Unit Substation A transformer failure on December 08, 2013, it was identified that the insulation testing performed on 0AP05E and 1AP11E during the C1R14 outage in October 2013 was not performed in accordance with the written work instructions. The licensee incorrectly measured the resistance between the three phases of the transformer windings instead of measuring the resistance from each phase of the winding and ground.

Description:

On December 09, 2013, during troubleshooting of Unit Substation A transformer 0AP05E failure, the licensee reviewed the testing performed on transformer 0AP05E during C1R14 outage on October 15, 2013 per work order 1534761. The licensee noticed that the insulation resistance entered for the transformer high winding side was 1.23 KOhms, and the test points were listed as A-B, A-C, and B-C. The resistance value recorded was well below the minimum acceptance criteria per Clinton Power Station (CPS) procedure 8440.01 and as specified in the work order as 6160 Megohms. Additionally, the documented test points indicated that the technician was reading from the terminal to terminal instead of terminal to ground.

In this manner the only quantity being tested was the windings resistance of the transformer instead of the insulation resistance as required per the test procedure.

This was indicated for both the 4160 VAC High Side and the 480 VAC Low Side of the transformer.

A review by the licensee of the testing performed on transformer 1AP11E (Unit Substation 1A) during the same outage on October 15, 2013 under work order 1534764 also showed the same problem as the latest testing of transformer 0AP05E. The megger was applied between the transformer winding terminals instead of from terminal to ground for both the high and low voltage windings.

These tests for both transformers were performed by contract personnel. The same contract organization provided the supervisory oversight of the work activity and supervisor review of the results. The work in both cases was reviewed and marked as satisfactorily completed.

The faulted transformer was disconnected and abandoned in place awaiting future resolution for repair activities. A spare transformer located in 0AP05E cubical 7 was modified and was used to supply power to 0AP05E per EC 396387 and its associated work orders. The insulation megger test and Transformer Turn Ratio (TTR) test were performed on the spare transformer with acceptable results.

The licensee entered this issue into their corrective action program as IR 01594794 and re-preformed the insulation megger testing of 1AP11E transformer under work order 1695780 subtask 13. The measured insulation resistance between the high voltage windings and the ground were found above the vendor recommended minimum value.

The measured insulation resistance between the low voltage windings and the ground was also found acceptable.

The inspectors reviewed the latest completed insulation megger tests work orders for all safety-related transformers. The inspectors verified that tests were correctly performed and the measured insulation resistance between the high voltage windings and ground were acceptable.

Analysis:

The inspectors determined that the licensees failure to correctly perform the insulation resistance testing for Unit Substation transformers during the C1R14 outage was contrary to 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, and was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the Mitigating System Cornerstone attribute of equipment performance and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensees failure to ensure the insulation resistances for these transformers were correctly measured in accordance with the written procedure did not ensure the availability and reliability of the transformers.

The inspectors determined the finding could be evaluated using the Significance Determination Process (SDP) in accordance with Inspection Manual Chapter (IMC) 0609, Significance Determination Process, Attachment 4, Initial Characterization of Findings, and Exhibit 2 of Appendix A, The Significance Determination Process for Findings at Power. The finding was screened against the Mitigating Systems Cornerstone and determined to be of very low safety significance (Green) because the finding: 1) was not a deficiency affecting the design or qualification of a mitigating structure, system or component, 2) did not represent a loss of system and/or function, 3) did not represent an actual loss of function of a single train for greater than its technical specification allowed outage time, 4) did not represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and 5) did not involve the loss or degradation of equipment or function specifically designed to mitigate a seismic, flooding or severe weather event.

The finding was determined to have a cross-cutting aspect in the area of human performance, associated with the work control component, in that the licensee failed to ensure supervisory and management oversight of work activities, including contractors, such that nuclear safety is supported. Specifically, the licensee failed to ensure the contractor measurements obtained during the C1R14 outage for the insulation resistance for unit substation transformers were adequate and met the minimum acceptance criteria. H.4(c).

Enforcement:

10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality be prescribed by documented procedures of a type appropriate to the circumstances and be accomplished in accordance with these procedures.

The licensee established CPS 8440.01 Insulation Testing, dated January 19, 2010 as the implementing procedure for measuring the insulation resistance for the unit substation transformers, an activity affecting quality.

Contrary to the above, on October 15, 2013, the licensee failed to ensure that activities affecting quality were accomplished in accordance with the approved stations procedures. Specifically, during the C1R14 outage, the licensee failed to correctly measure the insulation resistance for Unit Substation transformers 0AP05E and 1AP11E. The licensee measured the resistance between the transformers winding instead of between the winding and ground as required per insulation testing procedure CPS 8440.01. Because this violation was of very low safety significance and it was entered into the licensees Corrective Action Program as IR 01594794, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000461/2013009-01; Insulation Resistance Testing for Unit Substation Transformers Was Incorrectly Performed).

(2) Inadequate Acceptance Criteria in the Insulation Resistance Test Procedure

Introduction:

The inspectors identified a finding of very low safety significance (Green)and associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure to have appropriate acceptance criteria in a testing procedure. Specifically, the minimum acceptable insulation resistance for transformers as specified in Procedure CPS 8440.01 did not meet the minimum vendor recommended values in accordance with the vendor manual.

Description:

CPS Procedure 8440.01 Insulation Testing, dated January 19, 2010, provided a uniform standard for measuring insulation resistance to estimate the suitability of insulation in transformers. The procedure specified a minimum acceptable insulation resistance for transformers as Rmin = Kilovolt (kV) + 2, where kV is the rated terminal voltage of the transformer and Rmin is the minimum acceptable insulation resistance of the transformer in Megohms. This acceptance criterion was depicted in the megger testing data sheet for all work orders associated with the safety-related dry type transformers.

Vendor Manual G-IBXFI-00, Installation / Maintenance Instruction, for indoor dry type transformers indicated that when insulation resistance was used as a maintenance test, it should be performed in accordance with ANSI/IEEE Standard C-57.12.91. The vendor manual also indicated that the reading for the insulation resistance of the high voltage windings to ground should be at least 100 megohms, but never less than 2 megohms per kV of the high voltage rating. This recommendation was depicted as a note only in some work orders associated with transformer megger testing.

The inspectors reviewed the latest megger tests for all safety-related dry type transformers and verified that all final reading for the insulation resistance of the high voltage windings to ground were above 2 megohms per kV of the high voltage rating as specified in the vendor manual. However, the inspectors were concerned that the acceptance criteria specified in the work orders and procedure CPS 8440.01 did not meet the minimum recommended vendor value of 2 megohms per kV of the high voltage rating. Specifically for 4.160 kV high side winding, the Rmin per the acceptance criteria as specified in the procedure would be 6.16 megohms, (4.16 + 2), which is less than the vendor recommended value of 8.32 megohms, (4.16 x 2). Therefore it would be possible to measure an acceptable value using the procedure that would not meet the minimum recommended value.

The licensee entered this concern into the corrective action program as IR 01596730 and IR 01598375 and created an action to revise procedure CPS 8440.01 to correct deficiencies identified in the procedure.

Analysis:

The inspectors determined that the licensees failure to have adequate minimum acceptable insulation resistance in the insulation testing procedure CPS 8840.01 was contrary to 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, and was a performance deficiency. The performance deficiency was determined to be more than minor because if left uncorrected, it would become a more significant safety concern. The inspectors concluded that this finding was also associated with the Mitigating System Cornerstone attribute of equipment performance and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the minimum insulation acceptance criteria for transformers as specified in CPS 8840.01 did not assure the safety-related transformers would meet the minimum acceptable insulation value as required per the vendor document.

The inspectors determined the finding could be evaluated using the SDP in accordance with Inspection Manual Chapter (IMC) 0609, Significance Determination Process, 4 Initial Characterization of Findings, and Exhibit 2 of Appendix A The Significance Determination Process for Findings at Power. The finding was screened against the mitigating systems cornerstone and determined to be of very low safety significance (Green) because the finding: 1) was not a deficiency affecting the design or qualification of a mitigating structure, system or component, 2) did not represent a loss of system and/or function, 3) did not represent an actual loss of function of a single train for greater than its technical specification allowed outage time, 4) did not represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and 5) did not involve the loss or degradation of equipment or function specifically designed to mitigate a seismic, flooding or severe weather event.

The finding was determined to have a cross-cutting aspect in the area of problem identification and resolution, associated with the corrective action program component; in that the licensee failed to identify that the minimum acceptable insulation resistance for transformers was inadequate. P.1(a).

Enforcement:

10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality be prescribed by documented procedures of a type appropriate to the circumstances and be accomplished in accordance with these procedures.

The licensee established CPS 8440.01 Insulation Testing, dated January 19, 2010, as the implementing procedure for measuring the insulation resistance for the unit substation transformers, an activity affecting quality.

Contrary to the above, as of December 13, 2013, the licensee failed to ensure that activities affecting quality were prescribed by procedures of a type appropriate to the circumstances. Specifically, the minimum acceptable insulation resistance for transformers as specified in CPS 8840.01 was not appropriate in that it did not meet the minimum vendor value. Because this violation was of very low safety significance and it was entered into the licensees Corrective Action Program as IR 1596730, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000461/2013009-02; Inadequate Acceptance Criteria in the Insulation Resistance Test Procedure).

.3 Review the licensees reportability decisions to confirm necessary notifications were

made per 10 CFR 50.72, including consideration of Emergency Action Levels.

a. Inspection Scope

The inspectors reviewed the licensees operations logs for the time period just prior to the 0AP05E 4KV - 480 VAC transformer failure on December 8, 2013, at 8:36 p.m., to the time that the unit reached Mode 4 at 5:38 a.m. on December 10, 2013. The inspectors also interviewed the senior reactor operator that was the Control Room Supervisor (CRS) during the event. The inspectors determined that no other plant conditions met the criteria for notification of the NRC pursuant to 10 CFR 50.72. In addition, the inspectors reviewed the licensees Emergency Action Level (EAL)procedures, inspected the site of the transformer failure, and interviewed operations and maintenance staff and concluded that entry into an EAL was not required for the event.

During the interview with electrical maintenance staff regarding the removal and reinstallation of the transformer cabinet panel doors, the inspectors noted that electrical maintenance staff personnel had identified that one of several pieces of hardware designed to keep the panel doors in place was missing. Specifically, a panel bolt was not found inside the cabinet. Electrical maintenance staff personnel documented this problem in the work order (WO) 1695780-03, EM Megger/Test 480V Aux Transformer A2, but did not write an issue report. One of the electricians told the inspectors that the hardware was replaced with a bolt that was found in the electrical maintenance shop.

The inspectors inquired whether the new bolt was safety-related. The electrician stated, no and that it was not required to be safety-related. Further discussion with electrical maintenance management determined that the transformer cabinet was seismically qualified and the bolt was in fact required to be safety-related. The licensee documented this discrepancy in Issue Report 1596794, Noticed 0AP05E Panel Bolt Was Missing While Removing Panels. The licensee determined that the Panel remained operable and that the single bolt would not have a significant impact on structural integrity. Inspector follow-up determined that the bolt was replaced with a qualified bolt under WO 1695780 on December 19, 2013.

The inspectors reviewed WO 1534761-01, Unit Sub Cleaning Substation A, that was used to install the 0AP05E panel door after cleaning of the cabinet during the refueling outage in October 2013. The work order required the inspection of the cabinet for missing hardware and the replacement of any missing hardware in steps 4.12 and 4.13 respectively. No missing hardware was noted in the WO which had an additional supervisory review for the hardware inspection. The inspectors concluded that the hardware inspection performed on October 16, 2013, was inadequate based on the statement above that the missing bolt was not found within the cabinet during the inspection after the December event.

Inspectors reviewed procedure non-compliance issues identified in the previous paragraphs and determined that the deficiencies were not more-than-minor using the More-than-Minor screening criteria from IMC 0612 Appendix B, because the non-conformance issues were limited in scope to the single fastener and had no impact on the safety-related equipment. The inspectors determined that the issues and the underlying human performance and safety culture significance of procedural compliance were discussed with the licensee during the inspection exit meeting on December 18, 2013. Documents reviewed are included in the Supplemental information.

b. Findings

No findings were identified.

.4 Review the licensees extent of condition evaluation and related activities to determine if

the repair scope is adequate.

a. Inspection Scope

Based on the licensees field inspection of the failed transformer and discussion with the vendor, ABB, Inc., the licensee determined the fault was most probably caused by a turn to turn failure of the high side windings due to insulation breakdown over time.

Determination of the actual cause will require an inspection of the damaged transformer at the ABB facility. The dry type transformer was built in 1980 and the design worst-case loading was 40 percent of the transformer rating. This type transformer is used in 29 480 VAC substations in the plant (only 5 of the 29 are safety-related). The safety-related transformers are inspected and megger tested at a 6 year frequency aligned with the safety-related bus outage schedule. The non-safety dry type transformers are inspected and megger tested at a 8 year frequency (some have been extended to 16 years based on performance). No degraded condition was found during past performance of the preventative maintenance on dry type transformers. Operating experience review found three dry type transformer failures due to turn to turn failures and the licensee reviewed these issues with the vendor to identify potential common causes. In addition, the vendor supplied failure data on age-related transformer failures.

ABB provided the licensee with a report that concluded there is no testing that can be performed at the site to predict life on existing installed dry type transformers. Pending additional information from the inspection of the damaged transformer and the root cause investigation, the extent of condition and related activities were determined to be acceptable. Documents reviewed are included in the Supplemental Information.

b. Findings

No findings were identified.

.5 Review the repair activities including post-maintenance/modification testing plan to

ensure that the applicable plant procedures, plant instructions, and other requirements are followed. Include in this any procedure changes and temporary modifications to the plant necessary to support operations in Mode 3, to enable attaining Mode 4 within TS limits, and to support restart.

a. Inspection Scope

The inspectors reviewed the licensees repair activities including the modifications and its associated work orders. The licensee implemented a plant modification that altered the routing of the power feed cable to 480V Unit Substation A (0AP05E).

Previously, power was fed from 4160 Bus 1A1 (1AP07E) via the unit substation Aux Transformer A1. Engineering Change 396366 changed the power feed to Bus 1AP07E by disconnecting Aux Transformer A1 and connecting to Aux Trans-former A2. The inspectors verified that the replacement transformer which was originally purchased and installed for future use from Clinton Unit 2 was identical (same size and same electrical parameters as the faulted transformer.) The replacement transformer was originally installed at the opposite side of the substation. The inspectors reviewed the new transformer testing activities including the insulation megger test and Transformer Turn Ratio per work order 1695780 Task 03. Additionally, the engineering change also re-routed the control power to the main feed breaker feeding 0AP05E to main feed breaker 452-400A2 in cubical 6B instead of main feed breaker 452-400A1 in cubical 3B. The inspectors reviewed the modification package and its associated work orders which included review of the installation instructions; breakers wiring and schematic diagrams to ensure that breaker control circuits were not affected; cable re-routing installation and associated calculations to ensure no adverse effect on the seismic calculations; and cable testing to ensure that cable integrity was not affected during the event or during the re-routing activities. The inspectors performed a walk down of the newly installed transformer, including all new power cable routing.

Inspectors also reviewed actions the licensee took to gag open the instrument air containment outboard isolation valve, 1IA005 and to line up the swing battery charger to the Division 1 battery bus. A troubleshooting work order was generated to identify the extent of damage to the transformer and an additional work order was generated to gag open the 1IA005 valve to restore and maintain instrument air pressure to the containment. The inspectors reviewed the work orders and the supporting engineering change documents. Inspectors verified that TS 3.6.1.3, Primary Containment Isolation Valves, was correctly implemented and the containment isolation function was maintained through the inboard isolation valve. After instrument air pressure was restored to containment, the reactor water cleanup (RWCU) air operated reject valve was placed in service per the guidance in EOP-1, RPV Control. Control Rod Drive (CRD) makeup and RWCU reject were then used by the operating crew to augment the RPV cooldown to Mode 4. Operator actions were appropriately considered and taken in accordance with written procedures and work instructions.

Procedure CPS 3503.01C006, Class 1E Swing Battery Charger 1DC11E Feed to Safety-Related DC Bus Checklist, was implemented by the operators to restore charging to the Division 1 battery. Inspectors verified that the activity was implemented in accordance with the design as described in the UFSAR and Technical Specifications.

The power connection between the swing charger 125 VDC output and the class 1E Division 1 125 VDC battery is protected by class 1E shunt trip devices to disconnect the charger from the bus upon receipt of a loss of coolant accident (LOCA) signal.

Technical Specification 3.8.4.A allows 7 days to restore the inoperable charger when the swing battery charger is aligned to the battery and the appropriate verifications are performed. In this instance, both the design and the actions taken were implemented appropriately.

No other procedure changes or temporary modifications to the plant were implemented to support operations in Mode 3, to enable attaining Mode 4 within TS limits, or to support restart. Documents reviewed are included in the Supplemental Information.

b. Findings

No findings were identified.

.6 Review the operation of the plant equipment in response to the transient, including

adequacy of procedures and whether equipment operated in accordance with its design and the regulations. In particular, review the static VAR (volt ampere reactive)compensator trip and its effect on the emergency reserve auxiliary transformer; the closure of containment isolation valves resulting in loss of air to containment; the inoperability of RCIC and the status of its availability for use for decay heat removal; the use of the steam line drains to maintain the condenser as a heat sink when the MSIVs closed.

a. Inspection Scope

The inspectors reviewed anticipated plant response to a manual scram, loss of electrical power, and a loss of instrument air described in the Clinton Power Station UFSAR Chapter 15. Additionally, several procedures were reviewed and compared to the plant response and the actions taken by the operators during the event. The inspectors reviewed the licensees operations narrative logs for the time period just prior to the transformer failure on December 8, 2013, at 8:36 p.m., to the time that the unit reached Mode 4 at 5:38 a.m. on December 10, 2013. The inspectors interviewed the CRS and read statements documented from other operators that were on shift at the time of the event. Inspectors also reviewed copies of the documents used by the control room operators and marked up by them during the event. Inspectors also reviewed plant parameter recordings and the post trip review completed by the licensee. Documents reviewed are in the Supplemental Information. The three issues expressly identified in the charter are addressed below:

• Review of the Static VAR Compensator trip and its effect on the emergency reserve auxiliary transformer: The Static VAR Compensator (SVC) adjusts bus voltage by switching capacitor banks in and out of service as required to compensate for the impact of large inductive loads on bus voltage. When the initial fault on 0AP05E occurred on December 8, the Emergency Reserve Auxiliary Transformer (ERAT) SVC tripped due to thyristor switch capacitor (TSC) overcurrent. Initially the operators did not understand why the SVC tripped and conservatively declared the ERAT (and therefore, the associated offsite Class 1E supply) inoperable. The system engineer determined that the SVC had responded as expected to the large voltage drop caused by the fault condition since the Division 1 bus was being supplied by the ERAT at the time of the fault. When the SVC inserted the TSC bank to raise voltage by adding capacitive resistance, the protective relays detected excessive currents and tripped the SVC. The function of the trip was to keep the SVC from feeding the fault. Following the functional review of the SVC trip and field walkdowns to ensure there was no damage to the SVC, operators reset the overcurrent trip and restarted the SVC. Issue Report 1596771 was written to document the trip and the evaluation. The operators recognized that the Division 1 DG was not operable and in conjunction with the required offsite line being inoperable, TS 3.8.1, AC Sources - Operating, required operators to restore one of those sources to operable within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> or take the unit to Mode 3 within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. However, since the unit was manually shutdown (i.e. placed in Mode 3) and the ERAT continued to supply voltage within the required range to the 4160 VAC bus throughout the event, there was no impact to the calculated risk profile by the trip of the SVC.

• The Instrument air containment isolation valve closure: The inspectors reviewed the operating procedures and design for the instrument air containment isolation valves. The instrument air containment isolation valves are air operated valves.

The instrument air supply to the valves is regulated and aligned to open the valve through AC powered solenoid operated valves. The divisionally separated power supply to the solenoids for the solenoid operated valves air to the valves is safety related. The solenoid for 1IA005, Containment Outboard Isolation Valve, lost power when the Division 1 480 VAC bus was deenergized. Inspectors determined that station procedures correctly anticipated the containment isolation valve closure and the operator correctly focused on the parameters called out in those procedures to identify when the reactor was required to be shutdown. As stated previously, loss of instrument air to containment resulted in a loss of air pressure to the inboard MSIVs, the RWCU system components and the CRD system. Although no reactor pressure vessel (RPV) safety relief valves opened during this event, closure of the MSIVs could have resulted in a greater challenge to RPV pressure control if the event had occurred at a time when more decay heat was present. Since the unit had just started up from a refueling outage two months before, the main steam line drains were able to control pressure and cooldown the unit until air pressure to containment was restored.

• The inoperability of RCIC and the status of its availability: The inspectors reviewed annunciator procedure CPS 5063.07, Reactor Core Isolation Cooling Water Leg Pump Discharge Pressure Low, Revision 30c, Reactor Core Isolation Cooling (RCIC) operating procedure CPS 3310.01, Reactor Core Isolation Cooling (RI), Revision 29, and CPS 9054.06, RCIC Discharge Header Filled and Flow Path Verification, and Flow Controller Checks, Revision 27a. The inspectors reviewed Engineering Change 396373, Start RCIC System for Pressure Control Without RCIC Water Leg Pump, Revision 0. The inspectors also interviewed the RCIC system manager and two program engineers that perform ultrasonic testing on piping to look for voids. The inspectors also reviewed computer printouts of RCIC suction and discharge pressure from the time of the event until the plant reached Mode 4. The inspectors also reviewed calculations for Net Positive Suction Head for the RCIC pump from both of its suction sources. The inspectors concluded that the RCIC system, although appropriately declared inoperable due to the power loss to the water leg pump, was available for operation if necessary for pressure/inventory control and for decay heat removal.

• The use of steam line drains to maintain the condenser as a heat sink when the MSIVs closed: Procedure CPS EOP-1; RPV Control, lists main steam line drains as one of the systems to be used to control RPV pressure and cooldown rate. Procedure CPS 4100.01; Reactor Scram, directs the operator to use an appropriate cooldown method listed in CPS 9000.06, Unit Shutdown. In CPS 9000.06 Section 8.8, Cooldown With Main Condenser, MSL drain valves were one method listed and included a statement that it is OK to shut MSIVs when using this method. The unit supervisor stated that he considered using RCIC for pressure control, but determined that he did not need to because the main condenser remained available and he was able to control pressure and the cooldown rate using MSL drains to the main condenser.

While performing the preliminary risk analysis for the MD 8.3 Evaluation to determine the risk criteria, the Senior Reactor Analyst used a Loss of Condenser Heat Sink initiating event due to the manual reactor scram and closure of the inboard Main Steam Isolation Valves (MSIVs). The MSL drains were not credited for all such events since the flow path contains nonsafety-related valves and therefore may not have electrical power in all scenarios. However, as demonstrated during this event, the MSL drains removed a significant amount of decay heat and diverted that heat from containment when the main condenser remained available.

b. Findings

No findings were identified.

4OA6 Management Meetings

.1 Exit Meeting

On December 18, 2013, the inspectors presented the inspection results to Mr. B. Taber and other members of the licensee staff. The licensee acknowledged the issues presented. Proprietary information was examined during this inspection and was returned to the licensees representatives. Proprietary information is not specifically discussed in this report.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

B. Taber, Site Vice President

T. Stoner, Plant Manager

J. Smith, Acting Site Engineering Director

R. Schenck, Work Management Director

R. Zacholski, Nuclear Oversight Lead

J. Cunningham, Acting Regulatory Assurance Manager

B. Brooks, Security Manager

D. Shelton, Operations Support Manager

P. Simpson, Exelon Corporate Licensing

W. Harris, Site Communicator

J. Ward, Maintenance

J. Gruber, Maintenance

A. Kulow, Quad Cities Engineering

Nuclear Regulatory Commission

C. Lipa, Chief, Reactor Projects Branch 1

N. Martinez, Reactor Inspector

N. Valos, Senior Reactor Analyst

W. Schaup, Clinton Senior Resident Inspector

D. Lords, Clinton Resident Inspector

Illinois Emergency Management Agency

S. Miscke, IEMA Resident Inspector

Attachment

LIST OF ITEMS

OPENED AND CLOSED

Opened

05000461/2013009-01 NCV Insulation Resistance Testing for Unit Substation Transformers Was Incorrectly Performed (Section 4OA3.2.b(1))

05000461/2013009-02 NCV Inadequate Acceptance Criteria in the Insulation Resistance Test Procedure(Section 4OA3.2.b(2))

Closed

05000461/2013009-01 NCV Insulation Resistance Testing for Unit Substation Transformers Was Incorrectly Performed (Section 4OA3.2.b(1))

05000461/2013009-02 NCV Inadequate Acceptance Criteria in the Insulation Resistance Test Procedure (Section 4OA3.2.b(2))