IR 05000416/2014003

IR 05000416-14-003; 04/01/2014 - 06/30/2014; Grand Gulf Nuclear Station; Operability Determinations and Functionality

ML14226A998
Person / Time
Site:	Grand Gulf
Issue date:	08/14/2014
From:	Allen D NRC/RGN-IV/DRP/RPB-C
To:	Kevin Mulligan Entergy Operations
R. Smith
References
IR-14-003
Download: ML14226A998 (55)

Text

UNITED STATES ust 14, 2014

SUBJECT:

GRAND GULF NUCLEAR STATION - NRC INSPECTION REPORT 05000416/2014003

Dear Mr. Mulligan:

On June 30, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at the Grand Gulf Nuclear Station, Unit 1. On July 17, 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 one finding of very low safety significance (Green) in this report.

This finding involved a violation of NRC requirements. Further, inspectors documented a licensee-identified violation, which was determined to be of very low safety significance, in this report. The NRC is treating these violations as non-cited violations consistent with Section 2.3.2.a of the NRC Enforcement Policy.

If you contest the violations or significance of these non-cited violations, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region IV; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC resident inspectors at the Grand Gulf Nuclear Station.

If you disagree with a cross-cutting aspect assignment in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region IV; and the NRC resident inspectors at the Grand Gulf Nuclear Station. In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public Inspections, Exemptions, Requests for Withholding, 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 NRCs 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/

Don Allen, Branch Chief Project Branch C Division of Reactor Projects Docket No.: 50-416 License No.: NPF-29 Enclosure:

Inspection Report 05000416/2014003 w/Attachment: Supplemental Information Electronic Distribution to Grand Gulf Nuclear Station

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket: 05000416 License: NPF-29 Report: 05000416/2014003 Licensee: Entergy Operations, Inc.

Facility: Grand Gulf Nuclear Station, Unit 1 Location: 7003 Baldhill Road Port Gibson, MS 39150 Dates: April 1 through June 30, 2014 Inspectors: R. Smith, Senior Resident Inspector B. Rice, Senior Resident Inspector Approved Don Allen By: Chief, Project Branch C Division of Reactor Projects Enclosure

SUMMARY

IR 05000416/2014003; 04/01/2014 - 06/30/2014; Grand Gulf Nuclear Station; Operability

Determinations and Functionality The inspection activities described in this report were performed between April 1 and June 30, 2014, by the resident inspectors at the Grand Gulf Nuclear Station. One finding of very low safety significance (Green) is documented in this report. This finding involved a violation of Nuclear Regulatory Commission requirements. Additionally, NRC inspectors documented in this report one licensee-identified violation of very low safety significance. The significance of inspection findings is indicated by their color (Green, White, Yellow, or Red),

which is determined using Inspection Manual Chapter 0609, Significance Determination Process. Their cross-cutting aspects are determined using Inspection Manual Chapter 0310,

Components Within the Cross-Cutting Areas. Violations of Nuclear Regulatory Commission requirements are dispositioned in accordance with the NRC Enforcement Policy. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG 1649, Reactor Oversight Process.

Cornerstone: Mitigating Systems

Green.

The inspectors reviewed a self-revealing non-cited violation of 10 CFR Part 50,

Appendix B, Criterion XVI, Corrective Action, for the failure to promptly reinstate an essential-critical preventative maintenance task after they identified that it had been improperly retired. Specifically, the licensee did not reinstate and complete Preventive Maintenance Task PMRQ 50024451-04 prior to the failure of diode CR6 on May 21, 2013, which resulted in the division 2 diesel generator failing its monthly functional test and the licensee declaring it inoperable. The operators secured the diesel generator and wrote Condition Report CR-GGN-2013-03423 documenting the issue. The licensee performed a Failure Modes Analysis evaluation to determine the possible cause for the observed conditions. During troubleshooting efforts, the licensee addressed the potential transformer (PT1), the potential transformers fuses, inline fuses, and the voltage regulator circuit bridge diodes. The Failure Modes Analysis evaluation showed that all of the listed components were in satisfactory condition, except that one of the six diodes used in the voltage regulator circuit diode bridge, Diode CR6, had shorted. The licensee replaced the shorted diode and returned the diesel generator to operational status on May 24, 2013.

The licensees failure to implement PMRQ 50024451-04 after discovering it had been improperly retired was a performance deficiency, in that it represented a failure to promptly correct a condition adverse to quality. The performance deficiency is more than minor and therefore a finding because it is associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstones objective of ensuring the availability, reliability, and capability of systems that respond to prevent undesirable consequences. Specifically, Diode CR6 remained in the voltage regulator circuit bridge until it failed, thereby triggering a failure of the division 2 diesel generator, which caused the diesel generator to be inoperable. Using NRC Inspection Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, dated June 19, 2012, the inspectors determined that the issue affected the Mitigating Systems Cornerstone. In accordance with NRC Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, dated June 19, 2012, the inspectors determined that the issue required a detailed risk evaluation because the finding represents an actual loss of function of a single train for greater than its Technical Specification allowed outage time. The total exposure period was 15 days. The allowed outage time was 14 days. The senior reactor analyst performed a detailed risk analysis and determined the delta-CDF was less than 1.0 x 10-6 and the delta-LERF was less than 1.0 x 10-7, therefore this finding was of very low safety significance (Green). The apparent cause of this finding was that the licensee did not recognize the risk of not performing the preventive maintenance task, which led to the decision to exclude the task from the division 2 allowed outage time schedule. Therefore, the finding has a cross-cutting aspect in the human performance area associated with conservative bias because the licensee did not use decision-making practices that emphasize prudent choices over those that are simply allowable [H.14]. (Section 1R15)

Licensee-Identified Violations

A violation of very low safety significance that was identified by the licensee has been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. This violation and associated corrective action tracking numbers are listed in Section 4OA7 of this report.

PLANT STATUS

The Grand Gulf Nuclear Station began the inspection period at approximately 20 percent thermal power. The operators continued in power ascension activities until 100 percent thermal power was reached on April 19, 2014.

On April 23, 2014, the operators reduced power to 87 percent thermal power due to elevated vibration readings on heater drain pump B.

On April 27, 2014, the operators further reduced power to 70 percent thermal power due to the loss of group two cooling on the main transformer A.

On April 28, 2014, the operators reduced power to 52 percent thermal power to remove heater drain pump B from service and to place heater drain pump A in service. The station also restored group two cooling on the main transformer A. The operators then commenced power ascension activities and reached 100 percent thermal power on May 4, 2014.

On June 6, 2014, the operators reduced power to 85 percent thermal power to perform a monthly control rod exercise. Upon completion, they commenced power ascension activities and reached 100 percent thermal power on June 7, 2014.

On June 20, 2014, the operators commenced a planned down power to 42 percent thermal power for a control rod sequence exchange, and after completion, they continued power ascension activities through the end of the inspection period.

REPORT DETAILS

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Summer Readiness for Offsite and Alternate AC Power Systems

a. Inspection Scope

On May 15, 2014, the inspectors completed an inspection of the stations off-site and alternate-ac power systems. The inspectors inspected the material condition of these systems, including transformers and other switchyard equipment to verify that plant features and procedures were appropriate for operation and continued availability of off-site and alternate-ac power systems. The inspectors reviewed outstanding work orders and open condition reports for these systems. The inspectors walked down the switchyard to observe the material condition of equipment providing off-site power sources. The inspectors assessed corrective actions for identified degraded conditions and verified that the licensee had considered the degraded conditions in its risk evaluations and had established appropriate compensatory measures. The inspectors verified that the licensees procedures included appropriate measures to monitor and maintain availability and reliability of the off-site and alternate-ac power systems.

These activities constituted one sample of summer readiness of off-site and alternate-ac power systems, as defined in Inspection Procedure 71111.01.

b. Findings

No findings were identified.

.2 Readiness to Cope with External Flooding

a. Inspection Scope

On April 13, 2014, the inspectors completed an inspection of the stations readiness to cope with external flooding. After reviewing the licensees flooding analysis, the inspectors chose five plant areas that were susceptible to flooding:

• Culvert 1

• Culvert 8A

• Culvert 9A

• Diesel generator breezeway

• Control building and auxiliary building roofs The inspectors reviewed plant design features and licensee procedures for coping with flooding. The inspectors walked down the selected areas to inspect the design features, including the material condition of seals, drains, and flood barriers. The inspectors evaluated whether credited operator actions could be successfully accomplished.

These activities constituted one sample of readiness to cope with external flooding, as defined in Inspection Procedure 71111.01.

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Partial Walkdown

a. Inspection Scope

The inspectors performed partial system walk-downs of the following risk-significant systems:

• April 9, 2014, standby gas treatment system A following a surveillance

• April 28, 2014, control room air conditioner A and standby fresh air A while maintenance was being performed on the train B equipment

• May 13, 2014, high pressure core spray system with the reactor core isolation cooling system in a maintenance outage

• June 25, 2014, division 1 diesel generator during division 2 diesel generator scheduled maintenance The inspectors reviewed the licensees procedures and system design information to determine the correct lineup for the systems. They visually verified that critical portions of the systems or trains were correctly aligned for the existing plant configuration.

These activities constituted four partial system walk-down samples as defined in Inspection Procedure 71111.04.

b. Findings

No findings were identified.

.2 Complete Walkdown

a. Inspection Scope

On April 16, 2014, the inspectors performed a complete system walk-down inspection of the reactor core isolation cooling system (RCIC). The inspectors reviewed the licensees procedures and system design information to determine the correct RCIC system lineup for the existing plant configuration. The inspectors also reviewed outstanding work orders, open condition reports, and other open items tracked by the licensees operations and engineering departments. The inspectors then visually verified that the system was correctly aligned for the existing plant configuration.

These activities constituted one complete system walk-down sample, as defined in Inspection Procedure 71111.04.

b. Findings

No findings were identified.

1R05 Fire Protection

Quarterly Inspection

a. Inspection Scope

The inspectors evaluated the licensees fire protection program for operational status and material condition. The inspectors focused their inspection on five plant areas important to safety:

• April 9, 2014, division 1 electrical switch gear room 1A309

• April 9, 2014, division 2 electrical switch gear room 1A308

• May 6, 2014, division 1 electrical switch gear room 1A219

• May 6, 2014, division 2 electrical switch gear room 1A221

• June 24, 2014, division 2 diesel generator room 1D303 For each area, the inspectors evaluated the fire plan against defined hazards and defense-in-depth features in the licensees fire protection program. The inspectors evaluated control of transient combustibles and ignition sources, fire detection and suppression systems, manual firefighting equipment and capability, passive fire protection features, and compensatory measures for degraded conditions.

These activities constituted five quarterly inspection samples, as defined in Inspection Procedure 71111.05.

b. Findings

No findings were identified.

1R06 Flood Protection Measures

a. Inspection Scope

On April 24, 2014, the inspectors completed an inspection of the stations ability to mitigate flooding due to internal causes. After reviewing the licensees flooding analysis, the inspectors chose four plant areas containing risk-significant structures, systems, and components that were susceptible to flooding. During Refueling Outage RF18, which was completed in the spring of 2012, the station installed a condensate full flow filtration (CFFF) system in the turbine building. The inspectors evaluated the impact that the addition of the CFFF system to the turbine building had on the stations internal flooding analysis. The inspectors identified safety-related valves and instrumentation that were in the vicinity of the CFFF piping. The areas assessed were:

• 166 foot elevation of the turbine building

• 133 foot elevation of the turbine building

• 113 foot elevation of the turbine building

• 93 foot elevation of the turbine building The inspectors reviewed plant design features and licensee procedures for coping with internal flooding. The inspectors walked down the selected areas to inspect the design features, including the material condition of seals, drains, and flood barriers. The inspectors evaluated whether operator actions credited for flood mitigation could be successfully accomplished.

These activities constitute completion of one flood protection measures sample, as defined in Inspection Procedure 71111.06.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program and Licensed Operator Performance

.1 Review of Licensed Operator Requalification

a. Inspection Scope

On April 23, 2014, the inspectors observed a crew of licensed operators in the plants simulator during requalification as left evaluation. The inspectors assessed the performance of the operators and the evaluators critique of their performance. The inspectors assessed the following areas:

• Licensed operator performance

• The ability of the licensee to administer evaluations

• The modeling and performance of the control room simulator

• The quality of post-scenario critiques

• Follow-up actions taken by the licensee for identified discrepancies These activities constitute completion of one quarterly licensed operator requalification program sample, as defined in Inspection Procedure 71111.11.

b. Findings

No findings were identified.

.2 Review of Licensed Operator Performance

a. Inspection Scope

On April 1 and 2, 2014, the inspectors observed the performance of on-shift licensed operators in the plants main control room. At the time of the observations, the plant was in a period of heightened activity due to plant startup following a reactor scram. The inspectors observed the operators performance of the following activities:

• On April 1, 2014, the inspectors observed the operating crew operating the turbine at 1800 revolutions per minute in preparation for synchronizing the main generator to the grid.

• On April 2, 2014, the inspectors observed the coordination of local actions to open valve 1N21F009B, the feedwater heater 6B discharge valve that would not open automatically from the main control room. This was to allow the operating crew to shift reactor water level control from startup level control to master level control.

• On April 2, 2014, the inspectors observed the operating crew placing feedwater level control into master level control and withdrawing control rods to increase power to 26 percent rated thermal power in preparation for recirculation pump upshift, including a reactivity pre-job brief.

• On April 2, 2014, the inspectors observed the operating crew upshift reactor recirculation pumps to fast speed, including raising reactor water level to approximately 40 inches narrow range in anticipation of level decrease on pump upshift. During the upshift of recirculation pumps, the inspectors observed the crew respond to HI-HI level in the 6A feedwater heater.

In addition, the inspectors assessed the operators adherence to plant procedures, including conduct of operations procedure and other operations department policies.

These activities constitute completion of one quarterly licensed operator performance sample, as defined in Inspection Procedure 71111.11.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed two instances of degraded performance or condition of safety-related structures, systems, and components (SSCs):

• April 16, 2014, unsuccessful draw down test of the standby gas treatment system

• April 22, 2014, local leak rate test failures of an isolation valve associated with the containment isolation system The inspectors reviewed the extent of condition of possible common cause SSC failures and evaluated the adequacy of the licensees corrective actions. The inspectors reviewed the licensees work practices to evaluate whether these may have played a role in the degradation of the SSCs. The inspectors assessed the licensees characterization of the degradation in accordance with 10 CFR 50.65 (the Maintenance Rule), and verified that the licensee was appropriately tracking degraded performance and conditions in accordance with the Maintenance Rule.

These activities constituted completion of two maintenance effectiveness samples, as defined in Inspection Procedure 71111.12.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed two risk assessments performed by the licensee prior to changes in plant configuration and the risk management actions taken by the licensee in response to elevated risk:

• May 12-15, 2014, reactor core isolation cooling system outage

• May 19-23, 2014, ESF 12 transformer maintenance The inspectors verified that these risk assessments were performed timely and in accordance with the requirements of 10 CFR 50.65 (the Maintenance Rule) and plant procedures. The inspectors reviewed the accuracy and completeness of the licensees risk assessments and verified that the licensee implemented appropriate risk management actions based on the result of the assessments.

The inspectors also observed portions of three emergent work activities and severe weather in the area that had the potential to cause an initiating event or to affect the functional capability of mitigating systems:

• April 2, 2014, with increased risk due to severe weather in the area, the licensee entered their off-normal procedure for severe weather and took appropriate actions to ensure the site would be minimally affected due to thunderstorms, high winds, and a tornado watch in the area.

• April 14, 2014, with increased risk due to severe weather in the area, the licensee entered their off-normal procedure for severe weather and took appropriate actions to ensure the site would be minimally affected due to thunderstorms, high winds, and a tornado watch in the area.

• April 28-29, 2014, with increased risk due to severe weather in the area, the licensee entered their off-normal procedure for severe weather and took appropriate actions to ensure the site would be minimally affected due to thunderstorms, high winds, and a tornado watch in the area.

The inspectors verified that the licensee appropriately developed and followed a work plan for these activities. The inspectors verified that the licensee took precautions to minimize the impact of the work activities on unaffected structures, systems, and components (SSCs).

These activities constitute completion of five maintenance risk assessments and emergent work control inspection samples, as defined in Inspection Procedure 71111.13.

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed four operability determinations that the licensee performed for degraded or nonconforming SSCs:

• April 9, 2014, operability determination of standby service water tower A, Condition Report CR-GGN-2014-03320

• May 7, 2014, operability determination of primary and secondary isolation valves in the condensate transfer system, Condition Report CR-GGN-2014-03960

• May 12, 2014, operability determination for an incorrectly sealed drywell electrical penetration, Condition Report CR-GGN-2014-1214

• May 15, 2014, operability determination of RCIC following over-speed testing, Condition Report CR-GGN-2014-04120 The inspectors reviewed the timeliness and technical adequacy of the licensees evaluations. Where the licensee determined the degraded SSC to be operable, the inspectors verified that the licensees compensatory measures were appropriate to provide reasonable assurance of operability. The inspectors verified that the licensee had considered the effect of other degraded conditions on the operability of the degraded SSC.

These activities constitute completion of four operability and functionality review samples, as defined in Inspection Procedure 71111.15.

The inspectors also reviewed Condition Report CR-GGN-2013-03423 as a follow-up inspection to a sample that was documented in NRC Inspection Report 05000416/2013003. The subject of the condition report was the failure of a division 2 diesel generator voltage regulator diode. The finding from this review is documented below.

b. Findings

Introduction.

The inspectors reviewed a self-revealing Green non-cited violation of Title 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for the failure to promptly reinstate an essential-critical preventative maintenance (PM) task after the licensee identified that it had been improperly retired. Specifically, the licensee did not reinstate and complete PM Task PMRQ 50024451-04 prior to the failure of Diode CR6 on May 21, 2013, which resulted in the division 2 diesel generator failing its monthly functional test and the licensee declaring it inoperable.

Description.

On May 21, 2013, during the division 2 standby diesel generator monthly surveillance test per Procedure 06-OP-1P75-M-0002, Standby Diesel Generator (SDG) 12 Functional Test, Revision 133, an UNDERFREQUENCY alarm sounded concurrently with a drop in indicated voltage (from approximately 4220 Volts to approximately 2100 Volts) as seen on the division 2 incoming voltmeter and the division 2 diesel generator AC voltage indicator. This occurred shortly after raising incoming voltage to approximately 50 Volts above running voltage. The operators secured the diesel generator and wrote Condition Report CR-GGN-2013-03423 documenting the issue.

The licensee performed a Failure Modes Analysis (FMA) evaluation to determine the possible cause for the observed conditions. During troubleshooting efforts, the licensee addressed the potential transformer (PT1), the potential transformers fuses, inline fuses, and the voltage regulator circuit bridge diodes. The FMA evaluation showed that all of the listed components were in satisfactory condition, with the exception of one of the six diodes used in the voltage regulator circuit diode bridge Diode, CR6, had shorted.

The licensee replaced the shorted diode and returned the diesel generator to operational status on May 24, 2013.

During the inspectors review of this issue, they found the licensee had experienced similar issues with degraded diodes on the voltage regulator circuit as described in Condition Report CR-GGN-2002-02384. Based on that condition report, the licensee developed a preventative maintenance strategy to begin testing the diodes on all three divisions of diesel generators and to replace any suspect components prior to causing a loss of excitation event.

The inspectors also reviewed Condition Report CR-GGN-2012-10283, which the licensee originated on August 29, 2012. In this condition report, the licensee described an issue in which PM Task PMRQ 50024451-04, used to test the diodes, was retired in 2009 due to the PM task being incorrectly categorized as non-critical. The operability determination for Condition Report CR-GGN-2012-10283 stated the late date of the reinstated PM task, including a 25 percent grace period, was October 29, 2012. The licensee completed actions to administratively reinstate the PM task on October 31, 2012; however, the licensee did not schedule or complete the PM task during the division 2 allowed outage time maintenance period scheduled for October 29, 2012, to November 7, 2012. Furthermore, the licensee did not schedule or complete the PM task prior to the diode failure on May 21, 2013.

The inspectors also reviewed the surveillance history of the diesel generator and determined the following:

• April 25, 2013, - The division 2 diesel generator successfully completed the monthly surveillance run.

• May 21, 2013, - The division 2 diesel generator failed its surveillance due to a failed diode in the voltage regulator circuitry, and the licensee declared it inoperable.

• May 24, 2013, -The licensee replaced the diode, the division 2 diesel generator successfully completed its surveillance test, and the licensee declared it operable.

Analysis.

The licensees failure to implement PMRQ 50024451-04 after discovering it had been improperly retired was a performance deficiency, in that it represented a failure to promptly correct a condition adverse to quality. The performance deficiency is more than minor and therefore a finding because it is associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstones objective of ensuring the availability, reliability, and capability of systems that respond to prevent undesirable consequences. Specifically, Diode CR6 remained in the voltage regulator circuit bridge until it failed, thereby triggering a failure of the division 2 diesel generator, which caused the diesel generator to be inoperable. Using NRC Inspection Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, dated June 19, 2012, the inspectors determined that the issue affected the Mitigating Systems Cornerstone. In accordance with NRC Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, dated June 19, 2012, the inspectors determined that the issue required a detailed risk evaluation because the finding represents an actual loss of function of a single train for greater than its Technical Specification allowed outage time. The senior reactor analyst performed a detailed analysis. The total exposure period was 15 days.

The allowed outage time was 14 days.

For the internal events portion, the analyst made the following influential assumptions:

1. On May 21, 2013, the division 2 emergency diesel generator failed approximately 10 minutes after starting. The failure was treated as a Failure to Start because it occurred in the first hour of operation.

2. The analyst determined that only the loss of offsite power sequences were affected by the performance deficiency. Therefore, the analyst only solved the loss of offsite power sequences.

3. The total exposure period was 15 days. The analyst used an exposure time of T/2 + repair time, consistent with the Risk Assessment of Operational Events (RASP) Handbook, Volume 1, External Events, Revision 2, Section 2.4, which stated:

For a failure that could have occurred at any time since the component was last operated (e.g., time of actual failure cannot be determined due to the nature of the failure mechanism), the exposure time (T) is equal to one-half of the time period since the last successful functional operation of the component (T/2) plus repair time.

The last successful operation of the component was on April 25, 2013, when the licensee conducted a 24-hour run of the diesel generator. The failure date was May 21, 2013. The T exposure period was 26 days. The T/2 exposure period was 26/2 = 13 days. The repair time was an additional 2 days. Thus, the T/2 plus repair time period was 13 + 2 = 15 days.

4. The analyst assumed that the diode failure made the division 2 emergency diesel generator non-functional and non-recoverable. However, if a failure of either of the division 1 or division 3 emergency diesel generators occurred, these failures could be recovered.

5. The analyst allowed the normal emergency diesel generator recovery events to occur when either (or both) the failure of the division 1 and/or the division 3 emergency diesel generators appeared in the cutsets. The SPAR model assumed that operators would only attempt to recover one emergency diesel generator. As long as the division 1 and/or division 3 emergency diesel generators were also failed, then one of these diesels could be the recovered diesel. The analyst could not justify recovery of the division 2 emergency diesel generator within the 24-hour probabilistic risk assessment mission time. The licensee used over 2 days to troubleshoot and repair the circuit.

6. The analyst ruled out additional consideration of common cause failures and set the basic event for the division 2 emergency diesel generator failure to start (EPS-DGN-FS-DGB) to a probability of 1.0. This allowed the nominal common cause failure probabilities to occur. The common cause events of interest included failure of the other emergency diesel generators because of the same proximate cause within the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The division 3 emergency diesel generator was of a different design (included different subcomponents) and was not vulnerable to the same common cause failure mechanism. For the division 1 emergency diesel generator, the licensee had completed several surveillance tests, since the noted division 2 failure, and had accumulated approximately 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br /> of run time. The failure mechanism did not surface. In addition, the licensee had completed the periodic diode checks on this emergency diesel generator consistent with their original preventive maintenance program.

Note: Had common cause remained a concern, the analyst could have used the True function, which would have increased the common cause failure probability for the remaining diesel generators by approximately a factor of 100.

Quantification 1. The analyst used the NRCs Standardized Plant Analysis Risk (SPAR) Model for Grand Gulf, Revision 8.22, with a truncation limit of 1E-11. The analyst assumed average failure rates as well as average test and maintenance for all non-affected components.

2. The analyst took the following steps to isolate the cutsets into two groups to allow recovery of the division 1 and 3 emergency diesel generators, but not the division 2 emergency diesel generators.

a. The analyst solved the SPAR model, assuming that the division 2 emergency diesel generator failed.

b. The analyst used the slice function to isolate the cutsets that included division 1 and division 3 failures. The analyst allowed the normal emergency diesel generator recoveries to occur for these cutsets. The conditional core damage probability (CCDP) for this set of cutsets was 1.3E-5. This assumed an entire year of exposure. Considering the 15-day exposure period, the CCDP = 1.3E-5

• 15/365 = 5.3E-7.

c. The analyst inverted this set of cutsets. The resultant cutsets included division 2 diesel generator failures but not division 1 or 3 emergency diesel generator failures. This also included other cutsets where none of the emergency diesel generators failed. The analyst allowed these cutsets to remain in the group, which was conservative.

d. The 30-minute, 1-hour, 4-hour, and 8-hour diesel generator recoveries appeared in the dominant cutsets. To adjust the cutsets to remove recovery credit, the analyst would normally multiply each cutset by 1/(applicable non-recovery value). The 8-hour non-recovery value (0.298) was the most conservative to use for this purpose, 1/(8-hour non-recovery) = 3.4. To simplify the calculation, the analyst multiplied all of the applicable cutsets by this factor, which was very conservative. The resultant CCDP for the 15-day exposure period was:

CCDP = 5.1E-6

• 15/365

• 3.4 = 2.1E-7.

e. The total CCDP for both groups of cutsets was 5.3E-7 + 2.1E-7 = 7.4E-7.

3. The nominal case CCDP for the 15-day exposure period was:

1.4E-6

• 15/365 = 5.8E-8.

4. The incremental CCDP (delta-core damage frequency [CDF]) for internal events was: 7.4E-7 - 5.8E-8 = 6.8E-7/year.

External Events. To identify the external event loss of offsite power initiators, the analyst reviewed the Grand Gulf Nuclear Station Individual Plant Examination of External Events (IPEEE), dated November 15, 1995. The IPEEE specified that the 1975 standard review plan criteria were met for high winds, floods, transportation accidents, and nearby facility accidents, so those events were not considered further. The weather related loss of offsite power initiator was already included in the SPAR model. The remaining accident initiators included seismic and fire.

Seismic. The analyst performed a simplified bounding analysis to address seismic contributors. The analyst referenced the NRCs Risk Assessment of Operational Events Handbook, Volume 2, External Events, Revision 1.01, to determine the seismic induced loss of offsite power initiating event frequency. The value was included in Table 1, Frequencies of Seismically-Induced LOOP Events, which was 2.4E-5/year.

Seismic induced loss of offsite power events are not considered recoverable.

The analyst included the following bounding assumptions to determine the delta-CDF for seismic initiators:

• Seismic Initiating event frequency = 2.4E-5/year

• Set grid related loss of offsite power to 1.0.

• Set all offsite power non-recovery probabilities to 1.0.

• Set all emergency diesel generator non-recovery probabilities to 1.0 (very conservative division 1 and three diesels were recoverable).

The analyst solved only the grid related loss of offsite power sequences. The resultant CDF was: 2.5E-5/year

• 3.9E-3

• 15/365 = 4E-9/year. This bounded the delta-CDF.

Therefore, the delta-CDF was less than 4E-9/year.

Fires. The fire events of interest included those that could initiate a loss of offsite power.

The licensees IPEEE screened out most fire areas as being non-risk significant. The IPEEE identified the following potentially important fire compartments where a fire could result in a loss of offsite power:

Compartment Description CA201 Auxiliary Building Corridors - 199 elevation CA301 Auxiliary Building Corridors - 139 elevation CC202 division I Switchgear Room CC210 division 3 Switchgear Room CC215 division 2 Switchgear Room CR Control Room A simplified equation for the change to the core damage from fires is as follows:

CDF = Fire Frequency ()

• non-suppression probability (PNS)

• CCDP*exposure Delta-CDF =

• PNS * (CCDPedg fails - CCDPedg ok)

• 15/365 CCDPedg ok = is the conditional core damage probability assuming the performance deficiency did not exist.

CCDPedg fails = CCDP where the performance deficiency does exist.

Assumptions for Fire Scenarios:

• The analyst did not include fire scenarios that already assumed that the division 2 emergency diesel generator would fail as a consequence of the fire.

• The analyst assumed that offsite power would be lost for each scenario. This was very conservative because the fires would need to be of sufficient size to reach different components (cables etc.). Since these areas also included wet pipe automatic sprinkler systems, the analyst assumed that a failure of the suppression system would also be required. The analyst assumed a 0.02 suppression system failure probability.

• Where the failure of balance of plant equipment was specified, the analyst noted that balance of plant equipment would already be lost as a consequence of the loss of offsite power. The analyst did not make additional adjustments for the balance of plant equipment.

• The analyst used the SPAR model to calculate the CCDPs and only solved the plant centered loss of offsite power sequences. For the CCDP calculations, the plant centered loss of offsite power frequency was 1.0.

• The analyst assumed an exposure period of 15 days.

• When cables from a specific division (1, 2, or 3) were assumed damaged, the analyst failed all of equipment in the applicable division. As a surrogate for divisional cables, the analyst failed the applicable emergency diesel generator.

This would result in a failure of all divisional equipment. In addition, the analyst failed all emergency diesel generator recoveries. This was conservative because it was possible to damage only a few divisional components in the fire and not affect the emergency diesel generator.

• The analyst allowed the normal offsite power recoveries to occur. The failure of offsite power is assumed to occur because of fire induced faults on offsite power cables. Based on the fire locations, the analyst determined that these cables could be isolated and offsite power could be aligned to the secondary systems.

• The analyst used Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process, to determine fire initiation frequencies, non-suppression probabilities, and fire damage times. The following generic information was included in this analysis.

• divisional cable fire frequency = 1.4E-3 (highly loaded)

• Control room cabinet fire frequency = 4.8E-3/cabinet

• Control room fire identification time = 0 minutes

• For control room fires, the analyst assumed that each scenario could be initiated by a fire that started in one of three cabinets. This increased the fire frequency to 4.8E-3.

• For control room fires, the analyst used a non-suppression probability of 0.02.

The control room is a continuously occupied area. Control room fires are expected to be promptly identified and suppressed. Operators have access to fire suppression equipment as well as self-contained breathing apparatus.

• Operators could still operate division 1 equipment from the remote shutdown panel. If all other equipment failed, operators would attempt this action. The analyst credited this action and assumed a nominal human error probability of 2.2E-2 (see NUREG/CR-6883, The SPAR-H Human Reliability Analysis Model). Failure of division 1 equipment required both failure in the control room as well as the failure to complete the action at the remote shutdown panel.

The analyst evaluated the following fire scenarios:

Scenario Assumed Supp CCDe CCDP Control ICCDP*

Failed System dg2 failed edg2 ok Room Fire freq*

equipment Fails or Remote PNS*

PNS or Shutdown 15/365 Panel Credit CA201-1 Division 1 1.4E-3

.02 4.7E-3

2.7E-4 Na 5E-9/yr cables CA201-7 Division 1 1.4E-3

.02 4.7E-3

2.7E-4 Na 5E-9/yr cables CA301-1 Division 1 1.4E-3

.02 4.7E-3

2.7E-4 Na 5E-9/yr cables CA301-3 Division 1 1.4E-3

.02 4.7E-3

2.7E-4 Na 5E-9/yr cables CC202- Division 1 1.4E-3

.02 4.7E-3

2.7E-4 Na 5E-9/yr 1b cables CC202- Division 1 1.4E-3

.02 4.7E-3

2.7E-4 Na 5E-9/yr 2a cables CC202- Division 1 1.4E-3

.02 4.7E-3

2.7E-4 Na 5E-9/yr 2b cables CC202- Division 1 1.4E-3

.02 4.7E-3

2.7E-4 Na 5E-9/yr 2c cables CC210-2 Division 3 1.4E-3

.02 4.8E-3

Na 5E-9/yr cables CR-2 Division 1 4.8E-3

.02 4.7E-3

2.7E-4

.022 4E-10/yr

and Balance of Plant CR-4 Division 3 4.8E-3

.02 4.8E-3

2.8E-4 Na 5E-9/yr and Balance of Plant CR-5 Division 1, 4.8E-3

.02 1.6E-1

5.3E-3

.022 1.3E-8/yr

Division 3, and Balance of plant CR-9 Offsite 4.8E-3

.02 2.8E-4

2.7E-4 Na 1E-9/yr Power Total 6.4E-8/yr Total Delta-CDF = 6.8E-7/year + 4E-9/year + 6.4E-8/year = 7.4E-7/year (Green). The dominant core damage sequences included loss of offsite power events that lead to station blackout. Equipment that helped mitigated the risk included the reactor core isolation cooling system and equipment that could be powered from the remote shutdown panel.

Large Early Release Frequency (LERF): To address the contribution to the LERF, the analyst used NRC Inspection Manual Chapter 0609, Appendix H, Containment Integrity Significance Determination Process. For boiling water reactors (BWR-6 with a Mark 3 containment), the failure of the division 2 emergency diesel generator was a potential LERF contributor. For the LERF analysis, the analyst used the Risk-Informed Inspection Notebook for Grand Gulf Station Unit 1, Revision 2.1a. The analyst noted that the LERF important core damage sequences were limited to those that included the failure of both the division 1 and 2 emergency diesel generators.

The analyst identified the LERF factors for the applicable loss of offsite power sequences. In a few instances the LERF factor was 0, but in most cases the LERF factor was 0.2.

The analyst used the internal events SPAR model and the slice function to identify the cutsets that included the failure of both diesels. The CCDP was 9.6E-6. Assuming a 15-day exposure period and a 0.2 LERF factor, the bounding LERF was 9.6E-6

• 0.2

• 15/365 = 7.8E-8. Therefore, the delta-LERF was less than 7.8E-8/yr.

Since the delta-CDF was less than 1.0 x 10-6 and the delta-LERF was less than 1.0 x 10-7, this finding was of very low safety significance (Green).

The apparent cause of this finding was the licensee did not recognize the risk of not performing the PM task, which led to the decision to exclude the task from the division 2 allowed outage time schedule. Therefore, the finding has a cross-cutting aspect in the human performance area associated with conservative bias because the licensee did not use decision making practices that emphasize prudent choices over those that are simply allowable [H.14].

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, states, in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and non-conformances are promptly identified and corrected. Contrary to this requirement, on or before August 29, 2012, the licensee did not promptly identify and correct a condition adverse to quality. Specifically, the licensee did not reinstate and complete PM Task PMRQ 50024451-04 prior to the failure of Diode CR6 on May 21, 2013, which resulted in the division 2 diesel generator failing its monthly functional test and the licensee declaring it inoperable. This violation is being treated as a non-cited violation (NCV), consistent with Section 2.3.2.a of the Enforcement Policy because it was of very low safety significance (Green) and it was entered into the licensees corrective action program as Condition Report CR-GGN-2014-02141 to address recurrence. (NCV 05000416/2013-3423, Failure to Promptly Reinstate an Essential-Critical Preventative Maintenance Task for a High-Critical Component).

1R18 Plant Modifications

a. Inspection Scope

On June 26, 2014, the inspectors reviewed a permanent plant modification that replaced the use of turbine first stage pressure transmitter signals with power range neutron monitoring system signals to control various functions including low power and high power setpoints, turbine stop valve closure and control valve fast closure SCRAM enable/bypass, end of cycle recirculation pump transfer pump enable/bypass, feedwater low power set-down, and hydrogen water chemistry trips.

The inspectors reviewed the design and planned implementation of the modification.

The inspectors verified that work activities involved in implementing the modification would not adversely impact operator actions that may be required in response to an emergency or other unplanned event.

These activities constitute completion of one sample of permanent modifications, as defined in Inspection Procedure 71111.18.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed five post-maintenance testing activities that affected risk-significant SSCs:

• April 30, 2014, control room standby fresh air unit B blower test after fan B replacement

• May 6, 2014, average power range monitor channel one after broadcaster card replacement

• May 12, 2014, control room air conditioner B after compressor replacement

• May 15, 2014, RCIC system following a system outage

• May 15, 2014, steam supply valve (valve E51-F0045), cooling water valve (valve E51-F046), and the condensate storage tank supply valve (valve E51-F010) for the reactor core isolation cooling system following maintenance on the valves The inspectors reviewed licensing- and design-basis documents for the SSCs and the maintenance and post-maintenance test procedures. The inspectors observed the performance of the post-maintenance tests to verify that the licensee performed the tests in accordance with approved procedures, satisfied the established acceptance criteria, and restored the operability of the affected SSCs.

These activities constitute completion of five post-maintenance testing inspection samples, as defined in Inspection Procedure 71111.19.

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors observed five risk-significant surveillance tests and reviewed test results to verify that these tests adequately demonstrated that the SSCs were capable of performing their safety functions:

In-service tests:

• April 11, 2014, residual heat removal system A quarterly motor operated valve (MOV) surveillance Other surveillance tests:

• April 8, 2014, station battery banks 1A3, 1B3, and 1C3 pilot cell surveillance

• May 13, 2014, division 1, 4160 VAC degraded voltage functional test and calibration

• May 23, 2014, ESF transformer 12 deluge test

• June 4, 2014, drywell high pressure emergency core cooling water system (ECCS) functional test channel A The inspectors verified that these tests met technical specification requirements, that the licensee performed the tests in accordance with their procedures, and that the results of the test satisfied appropriate acceptance criteria. The inspectors verified that the licensee restored the operability of the affected SSCs following testing.

These activities constitute completion of five surveillance testing inspection samples, as defined in Inspection Procedure 71111.22.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors observed an emergency preparedness drill on May 7, 2014, to verify the adequacy and capability of the licensees assessment of drill performance. The inspectors reviewed the drill scenario, observed the drill from the simulator control room and the emergency operations facility and attended the post-drill critique. The inspectors verified that the licensees emergency classifications, off-site notifications, and protective action recommendations were appropriate and timely. The inspectors verified that any emergency preparedness weaknesses were appropriately identified by the licensee in the post-drill critique and entered into the corrective action program for resolution.

These activities constitute completion of one emergency preparedness drill observation sample, as defined in Inspection Procedure 71114.06.

b. Findings

No findings were identified.

OTHER ACTIVITIES

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

4OA1 Performance Indicator Verification

.1 Safety System Functional Failures (MS05)

a. Inspection Scope

For the period of April 1, 2013, through March 31, 2014, the inspectors reviewed licensee event reports (LERs), maintenance rule evaluations, and other records that could indicate whether safety system functional failures had occurred. The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, and NUREG-1022, Event Reporting Guidelines: 10 CFR 50.72 and 50.73, Revision 3, to determine the accuracy of the data reported.

These activities constituted verification of the safety system functional failures performance indicator for the site, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.2 Reactor Coolant System Specific Activity (BI01)

a. Inspection Scope

The inspectors reviewed the licensees reactor coolant system chemistry sample analyses for the period of April 1, 2013, through March 31, 2014, to verify the accuracy and completeness of the reported data. The inspectors observed a chemistry technician obtain and analyze a reactor coolant system sample on October 16, 2013. The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the reported data.

These activities constituted verification of the reactor coolant system specific activity performance indicator for the site, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.3 Reactor Coolant System Total Leakage (BI02)

a. Inspection Scope

The inspectors reviewed the licensees records of reactor coolant system total leakage for the period of April 1, 2013, through March 31, 2014, to verify the accuracy and completeness of the reported data. The inspectors observed the performance of reactor coolant system leakage surveillance procedure on April 8, 2013. The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the reported data.

These activities constituted verification of the reactor coolant system leakage performance indicator for the site, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.1 Routine Review

a. Inspection Scope

Throughout the inspection period, the inspectors performed daily reviews of items entered into the licensees corrective action program and periodically attended the licensees condition report screening meetings. The inspectors verified that licensee personnel were identifying problems at an appropriate threshold and entering these problems into the corrective action program for resolution. The inspectors verified that the licensee developed and implemented corrective actions commensurate with the significance of the problems identified. The inspectors also reviewed the licensees problem identification and resolution activities during the performance of the other inspection activities documented in this report.

b. Findings

No findings were identified.

.2 Semiannual Trend Review

a. Inspection Scope

To verify the licensee was taking corrective actions to address apparent adverse trends that might indicate the existence of a more significant safety issue, the inspectors reviewed corrective action program documentation associated with the following issues associated with the division 1 and 2 diesel generator air start systems:

• Multiple occurrences of the divisions 1 and 2 standby diesel generator air dryer malfunctions challenging the motor driven and diesel driven air compressor reliability (Condition Report CR-GGN-2014-00468)

• Multiple occurrences of elevated dew points within the divisions 1 and 2 standby diesel generator air start system which could lead to corrosion of the air start receivers (Condition Report CR-GGN-2012-00273)

Furthermore, the licensee identified an emerging cross-cutting theme in H.5 (Work Management: The organization implements a process of planning, controlling, and executing work activities such that nuclear safety is the overriding priority. The work process includes the identification and management of risk commensurate to the work and the need for coordination with different job groups or job activities) and H.8 (Procedure Adherence: Individuals follow processes, procedures, and work instructions). The inspectors reviewed the licensees response to these themes to verify that the licensee had taken, was taking, and/or planned to take appropriate actions to address them.

The documents reviewed during this trend review are listed in the Attachment.

These activities constitute completion of one semiannual trend review sample, as defined in Inspection Procedure 71152.

b. Observations and Assessments The inspectors review of the trends identified above produced the following observations and assessments:

• For multiple occurrences of air dryer malfunctions, the licensee initiated Condition Report CR-GGN-2014-00468 identifying the reliability of the divisions 1 and 2 air drying towers as unacceptably low. Furthermore, the system engineer identified the air dryer reliability issue as a significant system issue requiring resolution in the standby diesel generator system health report. Immediate corrective actions included enhancing the model work orders to improve the reliability of the components within the air dryer system and evaluating the system configuration to ensure optimum performance. Long term corrective action involved upgrading the air dryer system to a newer more reliable design.

• For multiple occurrences of elevated dew points within the air start system, the licensee initiated Condition Report CR-GGN-2012-00273 and determined that the elevated dew points were directly related to the reliability of the air dry system. In April 2013, the licensee performed visual inspections of the division 1 air receivers and observed minimal corrosion. The resident inspectors also inspected the air receivers and verified the licensees findings. The licensee scheduled inspections of the division 2 air receivers during a planned maintenance window scheduled for June 2014. Furthermore, the licensee performed non-destructive examinations that resulted in no indications of degradation.

The inspectors determined these trends with the diesel generator air dryer assembly and elevated dew points in the air start system represented a weakness in the licensees ability to address reliability issues associated with non-safety related equipment that supports safety related equipment. The inspectors concluded that the licensee had also recognized equipment reliability as an area for improvement and developed corrective actions via a recovery plan to address them.

• For the emerging cross-cutting theme due to receiving three findings with the H.5 cross-cutting aspect, the licensee initiated Condition Report CR-GGN-2014-3006 to perform a common cause analysis. The licensee concluded that although the three findings were assigned the H.5 cross-cutting aspect, the causes were sufficiently diverse such that a common cause did not exist. The inspectors reviewed the causal analysis as well as the original documentation of the findings that were assigned H.5 and determined that the conclusions made by the licensee were reasonable.

• For the emerging cross-cutting theme due to receiving three findings with the H.8 cross-cutting aspect, the licensee initiated Condition Report CR-GGN-2013-07616 to perform a common cause analysis. The licensee concluded that the cause was the same as that of a root cause evaluation performed under Condition Report CR-GGN-2013-3639. The inspectors previously reviewed the root cause as documented in NRC Inspection Report 05000416/2013004 (ML13331B343) and identified no issues. The inspectors reviewed Condition Report CR-GGN-2013-3639 and verified it accurately captured the findings of the causal analysis performed under Condition Report CR-GGN-2013-07616. The inspectors determined the licensees conclusions and corrective actions were reasonable.

For these emerging cross-cutting themes, the inspectors determined that the licensee had entered the emerging themes into the corrective action program in a timely manner, completed an appropriate evaluation of the themes, developed and scheduled corrective actions to address the identified weaknesses and areas for improvement, and had completed/implemented most of the corrective actions at the time of this inspection. Thus, as a result of this inspection, the inspectors concluded that the licensees actions and progress in addressing the emerging trends in H.5 and H.8 have been appropriate.

c. Findings

No findings were identified.

.3 Annual Follow-up of Selected Issues

a. Inspection Scope

The inspectors selected one issue for an in-depth follow-up:

• On April 7, 2014, the inspector reviewed Condition Report CR-GGN-2013-0037, which addressed a non-cited violation that was issued in NRC Inspection Report IR 05000416/2013002 for the failure to maintain design control of set point calculations for instruments required by technical specifications. The inspectors reviewed the associated corrective actions and determined the steps taken by the licensee adequately addressed the violation. The inspectors also reviewed Engineering Changes EC 39554 and EC 39605 to verify the set point calculations were adjusted to account for the change from 18-month cycles to 24-month cycles.

The inspectors assessed the licensees problem identification threshold, cause analyses, extent of condition reviews, and compensatory actions. The inspectors verified that the licensee appropriately prioritized the planned corrective actions and that these actions were adequate to correct the condition.

These activities constitute completion of one annual follow-up sample as defined in Inspection Procedure 71152

b. Findings

No findings were identified.

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

.1 (Closed) Licensee Event Report 05000416/2013-0005-00: Reactor Pressure Vessel

Steam Pressure Less than 0 psig During Six Plant Startups Resulting in a Violation of Technical Specification 3.4.11, RCS Pressure and Temperature (P/T) Limits.

a. Inspection Scope

On December 12, 2013, with the plant operating in Mode 1 at 100 percent thermal power, Grand Gulf Nuclear Station (GGNS) discovered that during the past six startups, the reactor pressure vessel (RPV) steam pressure was below zero

(0) pounds per square inch gage (psig) with the main steam isolation valves open and the mechanical vacuum pumps running without entering Limiting Condition of Operation LCO 3.4.11, RCS Pressure and Temperature Limits. From December 12, 2010, through December 12, 2013, there were six occurrences of reactor pressure being less than 0 psig. The reactor pressure/temperature curves in the GGNS Pressure and Temperature Limits Report have a minimum pressure value of 0 psig referenced on the curve. The lowest pressure identified in the six occurrences was approximately -9.9 psig on December 13, 2013. All systems performed per design during the reactor startups with the RPV pressure below 0 psig during the past 3 years.

The cause of not entering LCO 3.4.11 was the condition was procedurally allowed and aligned with operator training. Corrective actions included revising station procedures and training documents. The licensee also performed an apparent cause evaluation (ACE) and developed corrective actions based on the findings of the ACE. The inspectors reviewed the ACE and associated corrective actions and determined the licensees conclusions and course of action were reasonable. The enforcement aspects of this event were discussed in NRC Inspection Report 05000416/2013005 in Section 1R20. Documents reviewed as part of this inspection are listed in the attachment.

These activities constitute completion of one event follow-up sample, as defined in Inspection Procedure 71153.

b. Findings

No findings were identified.

.2 (Closed) Licensee Event Report 05000416/2013-006-00: Primary Containment

Inoperable Due to an Inadequate Surveillance Procedure Resulting in a Loss of Safety Function

a. Inspection Scope

On December 17, 2013, at approximately 1:22 p.m., with the plant operating in Mode 1 at 100 percent thermal power, Grand Gulf Nuclear Station personnel utilized a procedure that was incorrectly revised. The event was identified at 2:15 p.m. during the performance of the surveillance when valve E51-F063, reactor core isolation cooling (RCIC) steam line drywell inboard isolation valve, was observed unexpectedly going closed when a test signal was applied. This action resulted in the inoperability of primary containment and the RCIC system. The operators immediately halted the surveillance and began troubleshooting the cause of the valve closure. The operators restored RCIC system operability at 2:35 p.m. when valve E51-F063 was reopened.

Primary containment operability was restored at 2:37 p.m. by restoring power to the containment isolation valve (valve E51F064).

The cause of this event was an improper procedure revision that resulted in an inadequate procedure. Corrective actions included restoring the operability of primary containment isolation and the RCIC system. Other corrective actions included correcting the procedural deficiency, performing reviews of other procedures that were recently revised, and conducting a root cause evaluation of the event. The inspectors reviewed the root cause as well as the associated corrective actions and determined the actions taken by the licensee were reasonable. The enforcement aspects of this event were discussed in NRC Inspection Report 05000416/2013005 in Section 1R22. Documents reviewed as part of this inspection are listed in the attachment.

These activities constitute completion of one event follow-up sample, as defined in Inspection Procedure 71153.

b. Findings

No findings were identified.

4OA5 Other Activities

.1 Follow-up on Traditional Enforcement Actions Including Violations, Deviations,

Confirmatory Action Letters, Confirmatory Orders, and Alternative Dispute Resolution Confirmatory Orders (IP 92702)a. Background:

On August 24, 2011, the NRC issued a Confirmatory Order (EA-11-096) to Entergy Operations, Inc., and Entergy Nuclear Operations, Inc. (collectively referred to as Entergy). The Confirmatory Order actions were agreed upon by Entergy and the NRC during an alternative dispute resolution session held on July 18, 2011, to resolve NRC concerns regarding an apparent violation of employee protection requirements at the River Bend Station. The actions focused on reorganizing the Quality Control reporting relationships, ensuring adequate training of 10 CFR 50.7, Employee Protection, and performing an effectiveness review of the Employee Concerns Program procedures at all Entergy facilities.

By letter dated August 23, 2012, Entergy notified the NRC of the actions that had been taken in response to the requirements imposed by the Confirmatory Order. Accordingly, during the week of April 29, 2013, NRC staff from the Office of Enforcement and Region IV performed an inspection at the River Bend Station to assess the specific actions identified in Entergys response letter. NRC staff also verified implementation of the remaining actions required to satisfy the conditions set forth in the Confirmatory Order, for all Entergy sites. Subsequent to this inspection, NRC staff continued to interact with Entergy regarding the adequacy of the corrective and preventive actions related to the underlying discriminatory issue.

b. Findings

and Observation:

During the follow-up inspection, the NRC staff reviewed Entergys Employee Concerns Program supervisory training and general employee training documents, the relevant lessons learned from the facts of this matter and the fleet-wide written communication reinforcing Entergys commitment to maintaining a safety-conscious work environment.

The NRC staff also reviewed the General Employee Training and Supervisory Training modules. Based on these reviews, it was determined that these training modules adequately addressed employee protection and included insights from the underlying discriminatory matter. The NRC staff determined that the supervisory training module appeared complete and included case studies as well as the specific elements from the underlying § 50.7, Employee Protection, violation. However, it was noted that although employees receive General Employee Training on an annual basis, Entergy does not require supervisors to take employee protection refresher training on a recurring basis as a means to reinforce these standards.

Additionally, NRC staff evaluated the results of Entergys effectiveness review of Employee Concerns Program (ECP) enhancements and the associated training that arose from the corrective actions taken to address this matter. Based on the results of this evaluation, it was determined that Entergy had performed the requisite reviews at each station, including examination of selected ECP Case Files, Records Retention, Concerned Individual follow-up, and ECP Coordinator training. Within the areas examined, no findings were identified and in general it was determined that Entergy had adequately performed the effectiveness review of ECP procedural enhancements and the ECP training related to this matter.

During the follow-up review of the Quality Control/Quality Assurance reporting relationship, it was determined that Entergys response did not ensure that persons performing the quality assurance function of receipt inspection reported to a management level sufficient to maintain organizational freedom and independence from cost and schedule are maintained. Subsequent to the identification of this performance issue, which affected the implementation of the QA program at all nine Entergy sites, the condition was entered into the licensees corrective action program as Condition Report CR-HQN-2013-00466.

Following the identification of this issue, additional discussions were held between NRC and Entergy to clarify the intent of the settlement agreement and subsequent Confirmatory Order stemming from the earlier alternate dispute resolution mediation.

As a result of these discussions, Entergys Corporate Licensing organization developed a fleet reconciliation plan to modify Entergys Quality Assurance Program Manual to require that individuals performing inspections in accordance with Quality Assurance Program Manual, Section B.12, Inspection, functionally report to the associated manager responsible for Quality Assurance. As described in the corrective actions associated with Condition Report CR-HQN-2013-00466, the affected individuals were those requiring certification in accordance with Quality Assurance Program Manual, Table 1, Regulatory Commitments, Section G, Regulatory Guide 1.58, Revision 1, Qualification of Nuclear Power Plant Inspection, Examination, and Testing Personnel, dated September 1980. In addition to revising the applicable provisions in the Quality Assurance Program Manual, corrective actions were initiated to revise implementing procedures to reflect the change in reporting relationship during the performance of required inspections as well as providing training to the affected individuals. The NRC staff confirmed that the remaining conditions of the Confirmatory Order were adequately addressed.

c. Conclusion:

Based on the above reviews, the NRC determined that Entergy properly implemented the conditions specified in the Confirmatory Order and the associated actions were adequately implemented.

d. Findings

No findings were identified.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On July 17, 2014, the inspectors presented the inspection results to Mr. K. Mulligan, Site Vice President of Operations, and other members of the licensee staff. The licensee acknowledged the issues presented. The licensee confirmed that any proprietary information reviewed by the inspectors had been returned or destroyed.

4OA7 Licensee-Identified Violations

The following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements, which meets the criteria of the NRC Enforcement Policy for being dispositioned as a non-cited violation.

• Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, states, in part, activities affecting quality shall be prescribed by documented procedures, of a type appropriate to the circumstances and shall be accomplished in accordance with these procedures. Contrary to the above, the licensee failed to assure that activities affecting quality were prescribed by documented instructions of a type appropriate to the circumstances. Specifically, the licensee failed to meet the requirements of Electrical Standard ES03, Electrical Standard for Installation of Cables, Revision 1, in that Chico A potting compound was not used to seal the drywell electrical penetration. As immediate corrective actions, the licensee removed the instrument cables and sealed the penetration. The licensee entered this issue in the corrective action program under Condition Report CR-GGN-2014-02141. Furthermore, the licensee evaluated the potential impact the open 4-inch penetration would have on the suppression pools suppression capability and determined that having an open 4-inch diameter penetration in the drywell did not cause the drywell bypass leakage criteria to be exceeded. Using Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, June 19, 2012, Table 2, Cornerstones Affected by Degraded Condition or Programmatic Weakness, the inspectors determined this issue affected the Barrier Integrity Cornerstone. Using Manual Chapter 0609, Appendix A, Significance Determination Process (SDP) for Findings at Power, June 19, 2012, Exhibit 3, Barrier Integrity Screening Questions, the inspectors determined that this finding represented an actual open pathway in the physical integrity of reactor containment (valves, airlocks, etc.),

containment isolation system (logic and instrumentation), and heat removal components.

Using Manual Chapter 0609, Appendix H, Containment Integrity Significance Determination Process, dated May 6, 2004, the inspectors determined that this finding would not influence the likelihood of accidents leading to core damage. However, since this finding involved components significant to suppression pool integrity/scrubbing that are important to LERF, the inspectors determined a detail risk analysis needed to be performed by a senior risk analyst. The senior risk analyst performed a detailed risk evaluation and determined that since the function of the systems/components did not fail, even with the failed penetration, and there was no failure of the safety function.

Therefore, this finding is of very low safety significance (Green).

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

C. Beschett, Manager, Nuclear Oversight

T. Coutu, Director, Regulatory Compliance and Performance Improvement

J. Dorsey, Security Manager

H. Farris, Assistant Operations Manager

J. Gerard, Manager, Operations

M. Godwin, Assistant Operations Manager

G. Hawkins, Manager, Site Projects

J. Miller, General Manager Plant Operations

R. Miller, Manager, Radiation Protection

M. Milly, Manger, Maintenance

K. Mulligan, Site Vice President

J. Nadeau, Manager, Regulatory Assurance and Performance Improvement

R. Scarbrough, Senior Regulatory Engineer, Licensing

T. Thornton, Manager, Design Engineering

D. Wiles, Director, Engineering

NRC Personnel

D. Loveless, Senior Reactor Analyst

G. Replogle, Senior Reactor Analyst

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000416/2014003-01 NCV Failure to Promptly Reinstate an Essential-Critical Preventative Maintenance Task for a High-Critical Component (Section 1R15)

Closed

05000416/2013-005-00 LER Reactor Pressure Vessel Steam Pressure Less than 0 psig During Six Plant Startups Resulting in a Violation of Technical Specification 3.4.11, RCS Pressure and Temperature (P/T)

Limits (Section 4OA3)

05000416/2013-006-00 LER Primary Containment Inoperable Due to an Inadequate Surveillance Procedure Resulting in a Loss of Safety Function (Section 4OA3)