IR 05000321/2014004

IR 05000321/2014004; and 05000366/2014004, on July 1, 2014 Through September 30, 2014; Edwin I. Hatch, Units 1 and 2, Maintenance Effectiveness, Problem Identification and Resolution, Follow-up of Events and Notices of Enforcement Discretio

ML14316A446
Person / Time
Site:	Hatch, 07200036
Issue date:	11/12/2014
From:	Mark Franke NRC/RGN-II/DRP/RPB2
To:	Vineyard D Southern Nuclear Operating Co
References
IR 2014004
Download: ML14316A446 (28)

Text

UNITED STATES ember 12, 2014

SUBJECT:

EDWIN I. HATCH NUCLEAR PLANT - NRC INTEGRATED INSPECTION REPORT 05000321/2014004 AND 05000366/2014004

Dear Mr. Vineyard:

On September 30, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Edwin I. Hatch Nuclear Plant Units 1 and 2. On October 24, 2014, the NRC inspectors discussed the results of this inspection with you and other members of your staff.

Inspectors documented the results of this inspection in the enclosed inspection report.

NRC inspectors documented three findings of very low safety significance (Green) in this report.

Two of these findings involved violations of NRC requirements. Further, inspectors documented three licensee-identified violations which were determined to be of very low safety significance in this report. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2.a of the Enforcement Policy.

If you contest the violations or significance of the 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 copies to the Regional Administrator, Region II; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC resident inspector at Hatch. If you disagree with a cross-cutting aspect assignment or the finding not associated with a regulatory requirement 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 II; and the NRC resident inspector at Hatch. In accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding, of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRCs Public Document Room or from the Publicly Available Records (PARS) component of the NRC's Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Mark Franke, Chief Reactor Projects Branch 2 Division of Reactor Projects Docket Nos.: 50-321, 50-366 License Nos.: DPR-57 and NPF-5

Enclosures:

Inspection Report 05000321/2014004, 05000366/2014004 w/Attachment: Supplemental Information

REGION II==

Docket Nos.: 50-321, 50-366,72-036 License Nos.: DPR-57 and NPF-5 Report No.: 05000321/2014004; and 05000366/2014004 Licensee: Southern Nuclear Operating Company, Inc.

Facility: Edwin I. Hatch Nuclear Plant Location: Baxley, Georgia 31513 Dates: July 1 through September 30, 2014 Inspectors: D. Hardage, Senior Resident Inspector D. Retterer, Resident Inspector T. Su, Reactor Inspector (1R18)

Approved by: Mark Franke, Chief Reactor Projects Branch 2 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000321/2014004; and 05000366/2014004, July 1, 2014 through September 30, 2014;

Edwin I. Hatch, Units 1 and 2, Maintenance Effectiveness, Problem Identification and Resolution, Follow-up of Events and Notices of Enforcement Discretion.

The report covered a three-month period of inspection by resident inspectors and a regional inspector. One NRC-identified violation, one self-revealing violation and one self-revealing finding are documented in this report. The significance of inspection findings are 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 (SDP) dated June 2, 2011. The cross-cutting aspects are determined using IMC 0310, Aspects within the Cross-Cutting Areas dated December 19, 2013. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy dated January 28, 2013 and revised July 9, 2013. The NRCs program for overseeing the safe operations of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 5.

Cornerstone: Initiating Events

Green.

A self-revealing finding was identified when the opening of the 8th stage feedwater heater relief valves due to improper set point adjustment necessitated a Unit 1 downpower.

Failure to verify the 8th stage feedwater heater shell side relief valve set point was greater than normal system operating pressure as required by 52IT-MME-006-0 was a performance deficiency. This performance deficiency was more than minor because it was associated with the Equipment Performance attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective in that a manual reactor power reduction was required from 93 percent to 25 percent. The inspectors screened this finding as Green because the finding did not cause a reactor trip and the loss of mitigation equipment, a high energy line-break, internal flood, or a fire. The finding had a cross cutting aspect of training in the human performance area because the engineer performing the work order review and approval was newly qualified and did not know how to determine system operating pressures. [H.9] (Section 1R12)

Cornerstone: Mitigating Systems

Green.

The inspectors identified a Green non-cited violation (NCV) of Technical Specification 5.4, Procedures, for the licensees failure to properly implement a valve lineup in a surveillance procedure for the fire protection system. On July 17, 2014 Hatch personnel isolated all fire suppression water during the performance of a valve lineup in accordance with surveillance procedure 42SV-FPX-015-0, System Flush Fire Protection Water. The licensee restored the fire protection system by implementing the correct valve lineup and suspended the use of the procedure until revisions can be made to enhance the procedures usability. The violation was entered into the licensees corrective action program as condition report 841493.

The licensees failure to implement the correct valve lineup in accordance with procedure 42SV-FPX-015-0, System Flush Fire Protection Water, was a performance deficiency.

This performance deficiency was more than minor because the performance deficiency was associated with the Protection Against External Factors (Fire) attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective in that the failure to implement the correct valve lineup of 42SV-FPX-015-0 resulted in total fire suppression water isolation. The inspectors screened this finding using IMC 0609, Appendix F,

Attachment 1, dated September 20, 2013. In Part 1: Fire Protection SDP Phase 1 Worksheet, this finding screened as requiring a Phase 3 analysis. The regional Senior Reactor Analyst performed a Phase 3 analysis using licensee input from their fire PRA.

Because of the short exposure time of approximately one hour, the change in risk was below 1E-6. Therefore, this finding is

Green.

The finding had a cross-cutting aspect of resources in the human performance area, because the licensee did not ensure that procedure 42SV-FPX-015-0 was adequate to support nuclear safety. [H.1] (Section 4OA2.2)

Green.

A self-revealing Green NCV of Title 10 of the Code of Federal Regulations (10 CFR)

Part 50, Appendix B, Criterion XVI, Corrective Actions, was identified on May 1, 2014 when a control room annunciator and subsequent investigation of the high pressure coolant injection (HPCI) system led to the discovery that on March 4, 2014 the licensee failed to identify that a blown fuse was preventing the HPCI turbine exhaust drain pot from performing its automatic level control function. The licensee restored HPCI operability by replacing the fuse and draining the accumulated condensation from the HPCI turbine. The violation was entered into the licensees corrective action program as condition report 807394.

The failure to promptly identify and correct the failure of the exhaust drain pot level instrumentation, as required by 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions, was a performance deficiency. This performance deficiency was determined to be more than minor because it was associated with the Equipment Performance - Reliability attribute of the Mitigating Systems cornerstone and it adversely affected the cornerstone objective in that the failure to promptly identify and replace the blown fuse resulted in the HPCI system inoperability from April 24 to May 1, 2014. The inspectors assessed this finding using IMC 0609, Appendix A, The Significance Determination Process For Findings At-Power, dated July 1, 2012. The inspectors determined in accordance with Exhibit 2 that the finding was of very low safety significance (Green) because there was no loss of function. The inspectors determined the finding had a cross cutting aspect of avoid complacency in the human performance area because the licensee did not recognize the possibility of latent issues and inherent risk when evaluating CR 782581. [H.12] (Section 4OA3.1)

Violations of very low safety significance that were identified by the licensee have been reviewed by the NRC. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. These violations and corrective action tracking numbers are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at or near 100 percent rated thermal power (RTP) for the duration of the inspection period.

Unit 2 operated at or near 100 percent RTP for the duration of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

a. Inspection Scope

Readiness to Cope with External Flooding: The inspectors conducted walkdowns of the following plant areas to evaluate the licensees implementation of flood protection procedures and compensatory measures during impending conditions of flooding or heavy rains. The inspectors reviewed the updated final safety analysis report and related flood analysis documents to identify those areas containing safety related equipment that could be affected by external flooding and their design flood levels. The inspectors walked down flood protection barriers, reviewed procedures for coping with external flooding, and reviewed corrective actions for past flooding events. The inspectors verified that the procedures for coping with flooding could reasonably be used to achieve the desired results. For those areas where operator actions are credited, the inspectors assessed whether the flooding event could limit or preclude the required actions. Documents reviewed are listed in the Attachment.

• Unit 1 Intake Area

• Unit 2 Intake Area

b. Findings

No findings were identified.

1R04 Equipment Alignment

a. Inspection Scope

Partial Walkdown: The inspectors verified that critical portions of the following selected systems or trains were correctly aligned by performing partial walkdowns. The inspectors selected systems for assessment because they were a redundant or backup system or train, were important for mitigating risk for the current plant conditions, had been recently realigned, or were a single-train system. The inspectors determined the correct system lineup by reviewing plant procedures and drawings. Documents reviewed are listed in the Attachment.

• Unit 2 A standby gas treatment system train while Unit 1 B standby gas treatment system train was out of service for maintenance, August 11, 2014

• Unit 1 C emergency diesel generator while the Unit 1 B emergency diesel generator was out of service for surveillance testing, August 14, 2014

• Unit 1 and Unit 2 fire protection system pump-house and yard following restoration from surveillance testing, September 2, 2014 Complete Walkdown: The inspectors verified the alignment of the Unit 1 high pressure coolant injection system. The inspectors selected this system for assessment because it is a risk-significant mitigating system. The inspectors determined the correct system lineup by reviewing plant procedures, drawings, the updated final safety analysis report, and other documents. The inspectors reviewed records related to the system outstanding design issues, maintenance work requests, and deficiencies. The inspectors verified that the selected system was correctly aligned by performing a complete walkdown of accessible components.

To verify the licensee was identifying and resolving equipment alignment discrepancies, the inspectors reviewed corrective action documents, including condition reports and outstanding work orders. The inspectors also reviewed periodic reports containing information on the status of risk-significant systems, including maintenance rule reports and system health reports. Documents reviewed are listed in the attachment.

b. Findings

No findings were identified.

1R05 Fire Protection

a. Inspection Scope

Quarterly Inspection: The inspectors evaluated the adequacy of selected fire plans by comparing the fire plans to the defined hazards and defense-in-depth features specified in the fire protection program. In evaluating the fire plans, the inspectors assessed the following items:

• control of transient combustibles and ignition sources

• fire detection systems

• water-based and gaseous fire suppression systems

• manual firefighting equipment and capability

• passive fire protection features

• compensatory measures and fire watches

• issues related to fire protection contained in the licensees corrective action program The inspectors toured the following fire areas to assess material condition and operational status of fire protection equipment. Documents reviewed are listed in the

.

• Unit 2, chiller room, fire zone 2205N

• Unit 2, Northeast residual heat removal (RHR) & core spray pump room, fire zone 2203B

• Units 1 and 2, refueling floor, fire zone 0201

• Unit 2 4160 VAC emergency switchgear rooms 2E, 2F, and 2G, fire area 2404, 2408, and 2409

• Unit 1, reactor building 203 working floor, fire zone 1205Y Annual Inspection: The inspectors evaluated the licensees fire brigade performance during a drill on September 30, 2014 and assessed the brigades capability to meet fire protection licensing basis requirements. The inspectors observed the following aspects of fire brigade performance:

• capability of fire brigade members

• leadership ability of the brigade leader

• use of turnout gear and fire-fighting equipment

• team effectiveness

• compliance with site procedures The inspectors also assessed the ability of control room operators to combat potential fires, including identifying the location of the fire, dispatching the fire brigade, and sounding alarms. The inspectors evaluated the licensees ability to declare the appropriate emergency action level and make required notifications in accordance with NUREG 0654, Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants (FEMA-REP-1)and 10 CFR 50, Domestic Licensing of Production and Utilization Facilities.

Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program and Licensed Operator Performance

a. Inspection Scope

Resident Inspector Quarterly Review of Licensed Operator Requalification: The inspectors observed a simulator scenario conducted for training of an operating crew for licensed operator continuing training and assessed the following attributes. Documents reviewed are listed in the Attachment.

• licensed operator performance

• the ability of the licensee to administer the scenario and evaluate the operators

• the quality of the post-scenario critique

• simulator performance Resident Inspector Quarterly Review of Licensed Operator Performance: The inspectors observed licensed operator performance in the main control room during ground isolation activities on the 1B 600 volt bus, troubleshooting of the C main control room air conditioner, and restoration of the Unit 1 reactor core isolation cooling system. The inspectors assessed the following attributes. Documents reviewed are listed in the Attachment.

• use of plant procedures

• control board manipulations

• communications between crew members

• use and interpretation of instruments, indications, and alarms

• use of human error prevention techniques

• documentation of activities

• management and supervision

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors assessed the licensees treatment of the two issues listed below to verify the licensee appropriately addressed equipment problems within the scope of the maintenance rule (10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants). The inspectors reviewed procedures and records to evaluate the licensees identification, assessment, and characterization of the problems as well as their corrective actions for returning the equipment to a satisfactory condition. The inspectors also interviewed system engineers and the maintenance rule coordinator to assess the accuracy of performance deficiencies and extent of condition.

Documents reviewed are listed in the Attachment.

• Unit 1, feedwater drains 1N22F070A and 1N22F070B, unit down power caused by failed feedwater heater relief valves

• Unit 1 and 2, main control room air conditioners 1Z41B008B and 1Z41B008C, condensing units tripped due simultaneous clogging strainer when swapping to Unit 1 supply

b. Findings

Introduction:

A self-revealing Green finding was identified when opening of the 8th stage feedwater heater relief valves due to improper set point necessitated a Unit 1 downpower.

Description:

On May 31, 2014, Unit 1 was operating at 93% RTP following a loss of feedwater heating event. While attempting to stabilize the unit, the operators received a control room alarm indicating increasing condensate temperature and also observed decreasing condenser vacuum. The operators reduced power per 34SO-N71-001-1 6, Main Condenser Vacuum Parameters and Limitations, Ver. 28.1, to 25%

RTP to stabilize condensate temperature and condenser vacuum. The licensee determined that the cause of the increasing condensate temperature was air in-leakage into the main condenser through the 8th stage feedwater heater shell side relief valves 1N22F070A and 1N22F070B. The downstream piping from these relief valves was routed back to the main condenser. The licensee determined that these relief valves were installed in March 2014 with a lift set point of 50 pounds per-square-inch (psig). At 100% RTP, the 8th stage heaters shell side pressure was 58 psig. Consequently, these relief valves would have been partially opened or opening intermittently since plant startup following their installation. Procedure 52IT-MME-006-0, Safety Relief Valve Bench Test, Section 7.4.8 required the licensee to confirm the newly installed relief valve set points are greater than system operating pressure.

These valves have a bellows which minimizes backpressure effects when the valve lifts and seals the valve bonnet from downstream pressure. The valve bonnet has a vent port that would open to atmosphere in the event bellows failed. The licensee determined that the bellows failed due to the intermittent relief valve opening since startup in March 2014. At full power operating conditions, with the bellows failed, the open relief valve would have resulted in steam being admitted through the ruptured bellows to the valve bonnet and exhausted through the vent port. This caused a steam seal preventing air in-leakage through the valve bonnet vent port into the valve discharge piping. With the power reduction to 93%, heater pressure decreased allowing the relief valve to close.

This removed the steam seal resulting in air in-leakage through the bonnet vent port and ruptured bellows to main condenser causing condensate temperature to increase.

Analysis:

Failure to verify the 8th stage feedwater heater shell side relief valve set point was greater than normal system operating pressure as required by 52IT-MME-006-0 was a performance deficiency. This performance deficiency was more than minor because it was associated with the Equipment Performance attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective in that a manual reactor power reduction was required from 93 percent to 25 percent. The inspectors screened this finding using IMC 0609, Appendix A, The Significance Determination Process (SDP) For Findings At-Power, dated June 19, 2012. The finding screened as Green per Section B of Exhibit 1, Initiating Events Screening Questions, because the finding did not cause a reactor trip and the loss of mitigation equipment, a high energy line-break, internal flood, or a fire. The finding had a cross cutting aspect of training in the human performance area because the engineer performing the work order review and approval was newly qualified and did not know how to determine system operating pressures. [H.9]

Enforcement:

This finding does not involve enforcement action because no violation of a regulatory requirement was identified. Because this finding does not involve a violation and is of very low safety significance, it is identified as a FIN 05000321/2014004-01, Unit Downpower Caused by Relief Valve Failure.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed the five maintenance activities listed below to verify that the licensee assessed and managed plant risk as required by 10 CFR 50.65(a)(4) and licensee procedures. The inspectors assessed the adequacy of the licensees risk assessments and implementation of risk management actions. The inspectors also verified that the licensee was identifying and resolving problems with assessing and managing maintenance-related risk using the corrective action program. Additionally, for maintenance resulting from unforeseen situations, the inspectors assessed the effectiveness of the licensees planning and control of emergent work activities.

Documents reviewed are listed in the Attachment.

• Unit 1 and Unit 2, week of July 19 - July 25, including scheduled maintenance for the 2D residual heat removal service water (RHRSW) pump and station service battery charger 1R42S028 replacement

• Unit 1 and Unit 2, week of August 2 - August 8, including scheduled maintenance for the 1A RHRSW pump and 2A control rod drive pump

• Unit 1 and Unit 2, week of August 16 - August 22 , including scheduled maintenance for the 2C emergency diesel generator and 2B diesel driven fire pump

• Unit 1 and Unit 2, week of August 23 - August 29 , including scheduled maintenance for the 1C emergency diesel generator and 2C RHR pump

• Unit 1 and 2, week of September 7 - September 13, including scheduled maintenance on 2B core spray pump and 1B main control room environmental control train

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

a. Inspection Scope

The inspectors selected the five operability determinations or functionality evaluations listed below for review based on the risk-significance of the associated components and systems. The inspectors reviewed the technical adequacy of the determinations to ensure that technical specification operability was properly justified and the components or systems remained capable of performing their design functions. To verify whether components or systems were operable, the inspectors compared the operability and design criteria in the appropriate sections of the technical specification and updated final safety analysis report to the licensees evaluations. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. Additionally, the inspectors reviewed a sample of corrective action documents to verify the licensee was identifying and correcting any deficiencies associated with operability evaluations.

Documents reviewed are listed in the Attachment.

• Unit 1 and 2, Non-conforming diesel fuel added to diesel oil storage tanks, CR 834950

• Unit 1, Void detected in A core spray piping, CR 846731

• Unit 1, Cracking in fire rated wall 1A station service battery room, CR 851298

• Unit 2, HPCI inlet drain pot level high alarm will not clear, CR 853475

• Unit 1 and 2, Flow meter 1X43-N310B not responding during performance of 42SV-FPX-008-0, CR 858903

b. Findings

No findings were identified.

1R18 Plant Modifications

a. Inspection Scope

The inspectors verified that the plant modification listed below did not affect the safety functions of important safety systems. The inspectors confirmed the modifications did not degrade the design bases, licensing bases, and performance capability of risk-significant structures, systems and components. The inspectors also verified modifications performed during plant configurations involving increased risk did not place the plant in an unsafe condition. Additionally, the inspectors evaluated whether system operability and availability, configuration control, post-installation test activities, and changes to documents, such as drawings, procedures, and operator training materials, complied with licensee standards and NRC requirements. In addition, the inspectors reviewed a sample of related corrective action documents to verify the licensee was identifying and correcting any deficiencies associated with modifications. Documents reviewed are listed in the Attachment.

• SNC350527, Replace obsolete pan assemblies in MCC 1R24-S009 with Cutler Hammer assemblies

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors either observed post-maintenance testing or reviewed the test results for the six maintenance activities listed below to verify the work performed was completed correctly and the test activities were adequate to verify system operability and functional capability. Additionally, the inspectors reviewed a sample of corrective action documents to verify the licensee was identifying and correcting any deficiencies associated with post-maintenance testing. Documents reviewed are listed in the

.

• SNC578984, Replace overload heaters in 1R24S025, July 23

• SNC417191, Rebuild actuator for 2E11F207D, July 24

• SNC565829, Perform diagnostic testing on 1A RHRSW pump, August 6

• SNC426278, Inspect undervoltage trip attachment for 2C RHR pump breaker, August 26

• SNC427938, Inspect check valve 2E21F003B, September 10

• SNC 99229, 1E51F030 perform check valve inspection, September 25

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the three surveillance tests listed below and either observed the test or reviewed test results to verify testing adequately demonstrated equipment operability and met technical specification and licensee procedural requirements. The inspectors evaluated the test activities to assess for preconditioning of equipment, procedure adherence, and equipment alignment following completion of the surveillance.

Additionally, the inspectors reviewed a sample of related corrective action documents to verify the licensee was identifying and correcting any deficiencies associated with surveillance testing. Documents reviewed are listed in the Attachment.

Routine Surveillance Tests

• 34SV-R43-002-2, Diesel Generator 1B Monthly Test

• 42SV-FPX-008-0, Fire Protection Water Suppression System Flow Test In-Service Tests (IST)

• 34SV-E11-001-2, Residual Heat Removal Pump Operability

b. Findings

No findings were identified.

1EP6 Drill Evaluation

a. Inspection Scope

The inspectors observed the emergency preparedness drill conducted on August 20, 2014. The inspectors observed licensee activities in the simulator and technical support center to evaluate implementation of the emergency plan, including event classification, notification, and protective action recommendations. The inspectors evaluated the licensees performance against criteria established in the licensees procedures.

Additionally, the inspectors attended the post-exercise critique to assess the licensees effectiveness in identifying emergency preparedness weaknesses and verified the identified weaknesses were entered in the corrective action program. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

4OA1 Performance Indicator Verification

a. Inspection Scope

The inspectors reviewed a sample of the performance indicator (PI) data, submitted by the licensee, for the Unit 1 and Unit 2 PIs listed below. The inspectors reviewed plant records compiled between July 2013 and June 2014 to verify the accuracy and completeness of the data reported for the station. The inspectors verified that the PI data complied with guidance contained in Nuclear Energy Institute 99-02, Regulatory Assessment Performance Indicator Guideline, and licensee procedures. The inspectors verified the accuracy of reported data that were used to calculate the value of each PI.

In addition, the inspectors reviewed a sample of related corrective action documents to verify the licensee was identifying and correcting any deficiencies associated with PI data. Documents reviewed are listed in the Attachment.

Cornerstone: Mitigating Systems

• residual heat removal system

• high pressure injection system

• emergency AC power system

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.1 Routine Review

The inspectors screened items entered into the licensees corrective action program in order to identify repetitive equipment failures or specific human performance issues for followup. The inspectors reviewed condition reports, attended screening meetings, or accessed the licensees computerized corrective action database.

.2 Annual Followup of Selected Issues

a. Inspection Scope

The inspectors conducted a detailed review of the following two condition reports to :

• CR 822819, emergency diesel generator 2A room fans failure to operate

• CR 841493, fire header isolated to plant site due to incorrect performance of fire water flush surveillance The inspectors evaluated the following attributes of the licensees actions:

• complete and accurate identification of the problem in a timely manner

• evaluation and disposition of operability and reportability issues

• consideration of extent of condition, generic implications, common cause, and previous occurrences

• classification and prioritization of the problem

• identification of root and contributing causes of the problem

• identification of any additional condition reports

• completion of corrective actions in a timely manner Documents reviewed are listed in the Attachment.

b. Findings

Introduction:

The NRC identified a Green NCV of Technical Specification 5.4, Procedures, for the licensees failure to properly implement a valve lineup in a surveillance procedure for the fire protection system. The licensee inadvertently isolated all fire suppression water during the performance of a valve lineup.

Description:

On July 17, 2014, the licensee performed fire protection surveillance 42SV-FPX-015-0, System Flush of Fire Protection Water. While performing flush point #20, licensee personnel did not properly implement the valve lineup of the procedure and left isolation valve 1Y43F306E in the closed position. The licensee subsequently closed isolation valve 1Y43F306H when performing flush point #21. At this point, the licensee determined additional personnel would be required to complete flush point #21 and decided to stop the surveillance and restore the fire suppression system to its normal line up. The fire suppression water system was a ring header with two supply points.

With both the 1Y43F306E and 1Y43F306H valves closed, a large differential pressure developed across the closed isolation valves and personnel performing the surveillance were unable to re-open the isolation valves. It was then the licensee recognized having the 1Y43F306E and 1Y43F306H valves closed isolated fire suppression water to both units. The licensee personnel went to the fire pump house to open the 1Y43F306E and 1Y43F306H valves. They were unable to open the 1Y43F306E valve, but were able to open the 1Y43F306H. After opening the 1Y43F306H valve, the 1Y43F306E valve was opened restoring fire protection to both units.

Corrective action report (CAR) 211274 identified the apparent cause for the event as unclear or complex guidance, wording, or grammar making the procedure confusing and difficult to use effectively. The inspectors reviewed CAR 211274 and identified the following deficiencies that were not identified by the licensee. These deficiencies were entered into the licensees corrective action program as condition reports 863851 and 860605.

• The inspectors identified that the licensee had also isolated the suppression water to the site in the same manner during the previous test performance on June 10, 2011.

This isolation of fire suppression water was not identified during the apparent cause determination.

• The inspectors noted that if flush point #8 was performed as written, all flow paths to the flush point would have been isolated and personnel performing the procedure would have been unable to flush the header. This was not identified during the apparent cause determination. On August 4, 2014, this test was signed off as being successfully completed.

• On September 2, 2014, the inspectors identified that a 14 main header isolation valve 1Y43F306D was closed, out of the required position. The licensee investigation revealed that the valve was left out of its required position during the performance of the same valve lineup of surveillance procedure 42SV-FPX-015-0 on August 4, 2014. The licensee had omitted a step to open 1Y43F306D upon completion of the procedure and the omission was not identified during the apparent cause determination. On August 28, the licensee was unable to perform loop flow surveillance testing because this valve isolated the test flow path which resulted in the fire header being degraded for 29 days.

Analysis:

The licensees failure to implement the correct valve lineup in accordance with procedure 42SV-FPX-015-0, System Flush Fire Protection Water, was a performance deficiency. This performance deficiency was more than minor because the performance deficiency was associated with the Protection Against External Factors (Fire) attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective in that the failure to implement the correct valve lineup of 42SV-FPX-015-0 resulted in total fire suppression water isolation. The inspectors screened this finding using IMC 0609, Appendix F, Attachment 1, dated September 20, 2013. In Part 1: Fire Protection SDP Phase 1 Worksheet, this finding screened as requiring a Phase 3 analysis, because 1)the duration factor was determined to be 0.01 (< 3 Days), 2) the summation of estimated fire frequency for the fire areas was calculated to 1.24E-01, and 3) the delta CDF calculation was greater than 1E-6 in Table 1.5.4. The regional Senior Reactor Analyst performed a Phase 3 analysis for the finding using licensee input from their fire PRA.

Because of the short exposure time of approximately one hour, the change in risk was below 1E-6. Therefore, this finding is of very low safety significance (Green). The finding had a cross-cutting aspect of resources in the human performance area, because the licensee did not ensure that procedure 42SV-FPX-015-0 was adequate to support nuclear safety. [H.1]

Enforcement:

Hatch Unit 1 and Unit 2 Technical Specification 5.4, Procedures requires, in part, that written procedures shall be established, implemented, and maintained covering fire protection program implementation. The fire protection program as contained in the Hatch Fire Hazards Analysis, Section 2.3.1, requires the fire suppression water system flush. Hatch procedure 42SV-FPX-015-0, System Flush of Fire Protection Water is the site procedure which implements Fire Hazards Analysis Section 2.3.1. Contrary to this requirement, on June 17, 2014 during the performance of 42SV-FPX-015-0 personnel failed to implement the procedure resulting in the isolation of the fire suppression water system to the station for greater than one hour. The licensee restored the fire header to operable status July 17, 2014 at 1530. This violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy. The violation was entered into the licensees corrective action program as CR 841493. (NCV 05000321, 366/2014004-02, Failure to Implement Fire Surveillance Procedure Resulted in Isolation of All Fire Water to the Station)

.3 Operator Work-Around Annual Review

a. Inspection Scope

The inspectors performed a detailed review of the licensees operator work-around, operator burden, and control room deficiency lists for the station in effect on September 12, 2014 to verify that the licensee identified operator workarounds at an appropriate threshold and entered them in the corrective action program. The inspectors verified that the licensee identified the full extent of issues, performed appropriate evaluations, and planned appropriate corrective actions. The inspectors also reviewed compensatory actions and their cumulative effects on plant operation. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

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

.1 (CLOSED) LER 05000366/2014-001, Incorrectly Sized Thermal Overloads Result in a

Condition Prohibited by Plant Technical Specifications The inspectors reviewed this LER for potential performance deficiencies and/or violations of regulatory requirements. Additionally, discussions were held with operations, engineering, and licensing staff members to understand the details surrounding this issue. This condition was documented in the licensees corrective action program as CR 822819. The enforcement aspects of this finding are discussed in Section 4OA7.

.2 (CLOSED) LER 05000321/2014-002, HPCI Steam Leak Results in Water in the Turbine

Making HPCI Inoperable

a. Inspection Scope

The inspectors reviewed this LER for potential performance deficiencies and/or violations of regulatory requirements. Additionally, discussions were held with operations, engineering, and licensing staff members to understand the details surrounding this issue. This condition was documented in the licensees corrective action program as CR 807394.

b. Findings

Introduction:

A self-revealing Green NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions, was identified when the licensee failed to identify that the HPCI turbine exhaust drain pot level control was not functional. The licensee did not identify a blown fuse that prevented the automatic level control from maintaining exhaust drain pot level.

Description:

On May 1, 2014, the Unit 1 control room received an annunciator HPCI Room Instrument Sump Level High. Operators investigating the cause of this annunciator discovered water dripping from the HPCI turbine shaft gland seals. The licensee determined that the 1E41-F245 fuse associated with the circuit for the 1E41-N077A, B, C level switches for the HPCI turbine exhaust drain pot level instrumentation and the HPCI inlet drain pot annunciator was blown. The blown fuse prevented drain valve 1E41-F053 from opening on a high exhaust drain pot level which allowed condensate into the HPCI turbine. The accumulation of water in the HPCI turbine has the potential to create a water hammer event in the turbine exhaust piping which rendered the HPCI system inoperable.

With the HPCI turbine in its normal standby lineup, the inlet drain pot removes condensation from upstream of the normally closed turbine steam supply valve and the exhaust drain pot collects and removes any leak-by of the turbine steam supply valve preventing condensation from collecting in the HPCI turbine. On March 4, 2014, the licensee noted that HPCI inlet drain pot drain valve 1E41-F054 was cycling, but the HPCI inlet drain pot high level control room annunciator was not received. The licensee generated condition report (CR) 782581 which was closed to a work order to troubleshoot and repair the annunciator. During the review of CR 782581, the licensee did not identify that the exhaust drain pot was also affected and no corrective actions were taken. The licensee performed a HPCI system walkdown on April 19, at which time the HPCI turbine shell was cool to the touch indicating there was no turbine steam supply valve leak-by. On April 24, the licensee performed the HPCI operability surveillance test which involved opening of the turbine steam supply valve. On May 1, the HPCI turbine shell was too hot to touch indicating that the turbine steam supply valve did not completely seat following the April 24 HPCI surveillance resulting in leakage past the valve. The leakage required approximately one week for condensation to build up to the point that it flowed from the HPCI turbine gland seals. On May 1, the licensee replaced 1E41-F245 fuse, drained the accumulated condensation from the HPCI turbine, and restored the HPCI system operability. Additionally, the licensee has put administrative controls in place to manually drain the exhaust drain pot once per shift until the turbine steam supply valve can be replaced during the next refueling outage or the valve is confirmed to be no longer leaking.

Analysis:

The failure to promptly identify and correct the failure of the exhaust drain pot level instrumentation, as required by 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions, was a performance deficiency. This performance deficiency was determined to be more than minor because it was associated with the Equipment Performance - Reliability attribute of the Mitigating Systems cornerstone and it adversely affected the cornerstone objective in that the failure to promptly identify and replace the blown fuse resulted in the HPCI system inoperability from April 24 to May 1, 2014. The inspectors assessed this finding using IMC 0609, Appendix A, The Significance Determination Process For Findings At-Power, dated July 1, 2012. The inspectors determined in accordance with Exhibit 2 that the finding was of very low safety significance (Green) because all the questions in section A were answered no. The inspectors determined the finding had a cross cutting aspect of avoid complacency in the human performance area because the licensee did not recognize the possibility of latent issues and inherent risk when evaluating CR 782581. [H.12]

Enforcement:

10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions, requires, in part, that measures shall be established to assure that conditions adverse to quality are promptly identified. Contrary to the above, from March 4, 2014, to May 1, 2014, the licensee failed to promptly identify the failure of Unit 1 HPCI turbine exhaust drain pot level instrumentation. This resulted in water accumulation in the HPCI turbine and HPCI system inoperability from April 24 to May 1, 2014. On May 1, as part of the immediate corrective actions to restore compliance, the licensee replaced 1E41-F245 fuse, drained the accumulated condensation from the HPCI turbine, and restored the HPCI system operability. The violation was entered into the licensees corrective action program as condition report 807394. This violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy. (NCV 05000321/2014004-03, Failure to Promptly Identify Malfunction of HPCI Exhaust Drain Pot Level Instrumentation.)

.3 (CLOSED) LER 05000321/2014-003, Safety Relief Valves As Found Settings Resulted

in Not Meeting Tech Spec Surveillance Criteria The inspectors reviewed this LER for potential performance deficiencies and/or violations of regulatory requirements. Additionally, discussions were held with operations, engineering, and licensing staff members to understand the details surrounding this issue. This condition was documented in the licensees corrective action program as CR 809721. The enforcement aspects are discussed in Section 4OA7.

.4 (CLOSED) LER 05000321/2014-005, Degraded Diesel Room Fan Flow Switch and

Incorrect Thermal Overload Setting Result in a Condition Prohibited by Technical Specifications The inspectors reviewed this LER for potential performance deficiencies and/or violations of regulatory requirements. Additionally, discussions were held with operations, engineering, and licensing staff members to understand the details surrounding this issue. This condition was documented in the licensees corrective action program as CR 835377. The enforcement aspects are discussed in Section 4OA7.

4OA5 Other Activities

.1 Operation of an Independent Spent Fuel Storage Installation (60855.1)

a. Inspection Scope

The inspectors performed a walkdown of the onsite independent spent fuel storage installation (ISFSI) and monitored the activities associated with the dry fuel storage campaign completed on August 29, 2014. The inspectors reviewed changes made to the ISFSI programs and procedures, including associated 10 CFR 72.48, Changes, Tests, and Experiments, screens and evaluations to verify that changes made were consistent with the license or certificate of compliance. The inspectors reviewed records to verify that the licensee recorded and maintained the location of each fuel assembly placed in the ISFSI. The inspectors also reviewed surveillance records to verify that daily surveillance requirements were performed as required by technical specifications.

Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

4OA6 Meetings, Including Exit

On October 24, 2014, the resident inspectors presented the inspection results to Mr. D.

Vineyard and other members of the licensees staff. The inspectors confirmed that proprietary information was not provided or examined during the inspection period.

4OA7 Licensee-Identified Violations

The following violations of very low safety significance (Green) or Severity Level IV were identified by the licensee and are violations of NRC requirements which meet the criteria of the NRC Enforcement Policy, for being dispositioned as a Non-Cited Violation.

• Technical Specification 3.4.3 requires 10 of 11 safety relief valves (SRVs) to be operable during Mode 1, 2, and 3. Contrary to the above, the licensee identified during bench testing that five safety relief valves failed to lift at the required technical specification setpoint, and therefore were inoperable when Unit 1 was in Mode 1, 2, and 3. Analysis showed that with the SRVs lifting at the as-found bench test setpoints, the SRVs still would have maintained reactor coolant system pressure below the TS safety limit requirements. The inspectors determined the violation was of very low safety significance (Green) because the SRVs maintained their functionality. This condition was documented in the licensees corrective action program as CR 809721. (Section 4OA3.2)

• 10 CFR Part 50 Appendix B, Criterion V, requires in part that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions. Contrary to the above, on June 6, 2014, the licensee failed to accomplish installation of thermal overload (TOL) heaters for 1X41-C002B using actual fan running current in accordance with procedure 52PM-R24-001-0, Allis Chalmers Low Voltage MCC Inspection. The design group based the TOL heaters on motor name plate data and did not consider actual motor running amps. This violation was determined to require a detailed risk (Phase 3) analysis because there was an actual loss of function for greater than the TS AOT. A Senior Reactor Analyst performed a Phase 3 analysis using the NRCs Hatch PRA model modified to include the EDG room ventilation fan breakers including common cause failure terms. Since the EDG 1B fan breakers were not included in the licensee breaker upgrade program, they were not included in the common cause assumptions. The licensee had performed an analysis that showed the EDGs would remain functional with any one of the three fans operating. The screening analysis conservatively assumed complete failure of one of the large room fans, an increase in the common cause failure rate, and no recovery of the tripped breakers. The dominant sequences involved a Loss of Offsite Power initiator, independent failure of the EDG 1B fans, common cause failure of the EDG 1A and 1C fans, and no recovery of the EDGs or offsite power for 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />. The second EDG 1A room fan breaker was found tripped due to a cause not part of the performance deficiency, and was assumed to fail at its normal rate. Because of the short exposure time and the lack of a common cause failure of fan breakers for the 1B EDG, the finding screened well below the 1E-6 threshold. Therefore, this finding was determined to be of very low safety significance (Green). This condition was documented in the licensees corrective action program as CR 835377. (Section 4OA3.3)

• 10 CFR Part 50 Appendix B, Criterion III, Design Control, requires in part that design changes shall be subject to design control measures commensurate with those applied to the original design. Contrary to the above, during design activities to replace safety related low voltage breaker pan assemblies, the licensee incorrectly classified Cutler Hammer thermal overload blocks as like-for-like replacements of the previous Westinghouse design. The new Cutler Hammer thermal overload blocks had different operating characteristics which resulted in newly installed pan assemblies having incorrectly sized thermal overload heaters. The nonconforming thermal overload heaters tripped the fan motors under normal operating conditions which resulted in the 2A emergency diesel generator being declared inoperable.

The inspectors determined that the violation required a detailed risk (Phase 3)assessment because there was an actual loss of function for greater than the TS AOT. A Senior Reactor Analyst performed a Phase 3 analysis for the finding using the NRCs Hatch PRA model modified to include the EDG room ventilation fan breakers including common cause failure terms. Since the EDG 1B fan breakers were not included in the licensee breaker upgrade program, they were not included in the breaker common cause assumptions. The screening analysis assumed an increase in failure rate of the fan breakers based on actual run data that was applied to the 6 breakers that control the EDG 2A and EDG 2C fans, and also conservatively assumed no recovery of the tripped breakers. The exposure time was assumed to be one year for SDP purposes, in accordance with the program assumptions, since the exposure time exceeded one year. The dominant sequences involved a Loss of Offsite Power initiator, independent failure of the EDG 1B fans, common cause failure of the EDG 2A and 2C fans, and no recovery of the EDGs or offsite power for 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />. Because of the multiple successful operations of the EDG fans prior to failure, and the lack of a common cause failure tie for the fan breakers for the 1B swing EDG, the finding screened well below the 1E-6 threshold. Therefore, this finding was determined to be of very low safety significance (Green). This condition was documented in the licensees corrective action program as CR 822819. (Section 4OA3.4)

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

B. Anderson, Health Physics Manager

G. Brinson, Maintenance Director

B. Duval, Chemistry Manager

A. Giancatarino, Engineering Director

G. Johnson, Site Regulatory Affair Manager

D. Komm, Operations Director

K. Long, Work Management Director

R. Spring, Plant Manager

S. Tipps, Principal Licensing Engineer

M. Torrance, Nuclear Oversight Manager

D. Vineyard, Hatch Vice President

A. Wheeler, Site Projects Manager

LIST OF REPORT ITEMS

Closed

LER

05000366/2014-001 Incorrectly Sized Thermal Overloads Result in a Condition Prohibited by Plant Technical Specifications (Section 4OA3.1)

LER

05000321/2014-002 HPCI Steam Leak Results in Water in the Turbine Making HPCI Inoperable (Section 4OA3.2)

LER

05000321/2014-003 Safety Relief Valves As Found Settings Resulted in Not Meeting Tech Spec Surveillance Criteria (Section 4OA3.3)

LER

05000321/2014-005 Degraded Diesel Room Fan Flow Switch and Incorrect Thermal Overload Setting Result in a Condition Prohibited by Technical Specifications (Section 4OA3.4)

Opened &

Closed

FIN

05000321/2014004-01 Unit Downpower Caused by Relief Valve Failure (Section R12)

NCV

05000321,366/2014004-02 Failure to Implement Fire Surveillance Procedure Resulted in Isolation of All Fire Water to the Station (Section 4OA2.2)

NCV

05000321/2014004-03 Failure to Promptly Identify Malfunction of HPCI Exhaust Drain Pot Level Instrumentation (Section 4OA3.1)