IR 05000416/2017013

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EA-17-184 - Grand Gulf Nuclear Station - NRC Supplemental Inspection Report, Assessment Follow-Up Letter 05000416/2017013, and Parallel White Performance Indicator Inspection Finding
ML17342B130
Person / Time
Site: Grand Gulf Entergy icon.png
Issue date: 12/06/2017
From: Kennedy K
NRC Region 4
To: Emily Larson
Entergy Operations
References
EA-17-184 IR 2017013
Download: ML17342B130 (30)


Text

UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION IV

1600 EAST LAMAR BOULEVARD ARLINGTON, TEXAS 76011-4511 December 6, 2017 EA-17-184 Mr. Eric Larson, Site Vice President Entergy Operations, Inc.

Grand Gulf Nuclear Station P.O. Box 756 Port Gibson, MS 39150 SUBJECT: GRAND GULF NUCLEAR STATION-NRG SUPPLEMENTAL INSPECTION REPORT, ASSESSMENT FOLLOW-UP LETTER 05000416/2017013, AND PARALLEL WHITE PERFORMANCE INDICATOR INSPECTION FINDING

Dear Mr. Larson:

On August 24, 2017, the U.S. Nuclear Regulatory Commission (NRC) completed a supplemental inspection using Inspection Procedure 95001, "Supplemental Inspection Response to Action Matrix Column 2 Inputs." On September 19, and November 13, 2017, the NRC inspection team discussed the results of this inspection and the implementation of your corrective actions with you and other members of your staff. The purpose of the supplemental inspection was to review your station's actions in response to a White Unplanned Scrams per 7000 Critical Hours (Initiating Events Cornerstone) performance indicator, which you reported for the third quarter of 2016. The NRC also closed three licensee event reports associated with the events reviewed as part of this inspection. On June 28, 2017, you informed the NRC that your station was ready for the supplemental inspection. The results of this inspection are documented in the enclosed report.

Based on two significant weaknesses identified in this inspection, one parallel White performance indicator inspection finding will be opened retroactively to the first quarter of 2017 and will continue to receive consideration as an Action Matrix input. Grand Gulf Nuclear Station will remain in the regulatory response column of the Action Matrix until the NRC verifies, by inspection, that the objectives of the inspection procedure have been met.

NRC Inspection Manual Chapter 0305, "Operating Reactor Assessment Program," dated November 17, 2016, Section 11.02.b states "If the supplemental inspection (iP 95001) for a safety-significant Pl results in the determination that the licensee failed to (1) identify, understand, or adequately evaluate the root causes, contributing causes, extent-of-condition, or extent-of-cause of the safety-significant Pl; or (2) take or plan adequate corrective actions to address the root causes, contributing causes, extent-of-condition, or extent-of-cause and to prevent recurrence of the safety-significant Pl, then a parallel Pl inspection finding will be opened and given the same safety-significance (i.e., color) as the Pl." The supplemental inspection team determined these attributes were not fully satisfied. The NRC identified seven weaknesses in your efforts to address the performance issues associated with the White performance indicator. The NRC determined that the root-cause evaluation performed as a result of the March 29, 2016, reactor scram, did not generate corrective actions that were adequate to preclude repetition of the event as required by your Procedure EN-Ll-118, "Cause Evaluation Process." The NRC also determined that the root-cause evaluation conducted as a result of the June 17, 2016, reactor scram was not performed to a sufficient depth and breadth as required by Procedure EN-Ll-118. Less significant, additional weaknesses involved the failure to identify contributing causes; failure to conduct reviews of operating experience; inadequate extent of cause evaluation; insufficient corrective actions; and inadequate effectiveness review criteria. The NRC determined that Procedure EN-Ll-118 was not fully implemented to adequately address the performance issues within the scope of this inspection.

The cause evaluations, the extent of condition, the extent of cause, and corrective actions should be revised to address the weaknesses described in the enclosed report. An assessment of any new actions developed by your staff will be performed during the re-inspection. We request that you notify the NRC of your readiness for a re-inspection.

In addition to the parallel White performance indicator inspection finding, the NRC inspectors documented two findings of very low safety significance (Green) in this report. One of these findings involved a violation of NRC requirements. The NRC is treating this violation as a non-cited violation (NCV) consistent with Section 2.3.2.a of the Enforcement Policy.

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

If you disagree with a cross-cutting aspect assignment, or a 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 U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region IV; and the NRC resident inspector at the Grand Gulf Nuclear Station. In accordance with 1O CFR 2.390 of the NRC's "Agency Rules of Practice and Procedure," a copy of this letter, its enclosure, and your response (if any) will be made available electronically for public inspection in the NRC Public Document Room and in the NRC's Agencywide *

Documents Access and Management System (ADAMS), accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams. html .

Sincerely, Kriss M. Kennedy Regional Administrator Docket No. 50-416 License No. NPF-29 Enclosure:

Inspection Report 05000416/2017013 w/Attachment: Supplemental Information

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket: 05000416 License: NPF-29 Report: 05000416/2017013 EA No.: EA-17-184 Licensee: Entergy Operations, Inc.

Facility: Grand Gulf Nuclear Station, Unit 1 Location: 7003 Baldhill Road Port Gibson, MS 39150 Dates: August 21 through November 13, 2017 Inspectors: Christopher Newport, Senior Resident Inspector Michael Bloodgood, Emergency Response Specialist James McHugh, Senior Instructor Rayomand Kumana, Resident Inspector Approved By: Jason Kozal Branch Chief Enclosure

SUMMARY

IR 05000416/2017013; 08/21/2017 - 11/13/2017; Grand Gulf Nuclear Station; Follow-up of

Events and Notices of Enforcement Discretion, Supplemental Inspection - Inspection Procedure 95001.

This supplemental inspection was conducted by a senior resident inspector from the Diablo Canyon Power Plant, a resident inspector from Comanche Peak Nuclear Power Plant, an emergency preparedness specialist from the Region IV office, and a senior instructor from the Technical Training Center. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process. "

Cornerstone: Initiating Events

The NRC inspectors performed this supplemental inspection in accordance with Inspection Procedure 95001, "Supplemental Inspection Response to Action Matrix Column 2 Inputs," dated August 24, 2016, to review the station's actions in response to a White Unplanned Scrams per 7000 Critical Hours (Initiating Events Cornerstone) performance indicator, reported for the third quarter of 2016. Specifically, the inspectors assessed four root-cause evaluations and one common-cause evaluation associated with three reactor scram events occurring on March 29,

June 17, and June 25, 2016. Additionally, the root-cause evaluation associated with the April 4, 2017, manual scram, caused by a condensate leak and subsequent lowering of condensate storage tank level, was reviewed.

NRC Inspection Manual Chapter 0305, "Operating Reactor Assessment Program," dated November 17, 2016, states "If the supplemental inspection (IP 95001) for a safety-significant Pl results in the determination that the licensee failed to (1) identify, understand, or adequately evaluate the root causes, contributing causes, extent-of-condition, or extent-of-cause of the safety-significant Pl, or (2) take or plan adequate corrective actions to address the root causes, contributing causes, extent-of-condition, or extent-of-cause and to prevent recurrence of the safety-significant Pl, then a parallel Pl inspection finding will be opened and given the same safety-significance (i.e., color) as the Pl." The supplemental inspection team determined these attributes were not fully satisfied. Therefore, the White performance indicator input will be held open by assignment of a parallel White performance indicator inspection finding and will continue to be considered in assessing plant performance until you notify the NRC of your readiness for an additional inspection on this issue and the NRC concludes, by inspection, that the objectives of the inspection procedure have been met.

Findings

Green.

The inspectors documented a self-revealed, non-cited violation of 1O CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings, " associated with the licensee's use of an inappropriate procedure to test turbine stop and control valves. Specifically, the licensee's procedure for testing the turbine stop and control valves allowed the use of a nonstandard tool that directly caused the system to fail, resulting in inadvertent closure of two of four stop valves and subsequent reactor pressure and power oscillations leading to a reactor scram.

The licensee's failure to prescribe adequate instructions for performing main turbine valve testing was a performance deficiency. The performance deficiency is more than minor, and therefore, a finding because it is associated with the procedure quality attribute of the Initiating Events Cornerstone and affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown, as well as power operations. Specifically, the failure to provide an adequate procedure resulted in an inadvertent closure of the two test valves, which upset plant stability resulting in a scram. Using NRC Inspection Manual Chapter 0609, Attachment 04, "Initial Characterization of Findings," dated October 7, 2016, and NRC Inspection Manual Chapter 0609, Appendix A, "Significance Determination Process for Findings At-Power," Exhibit 1, "Initiating Events Screening Questions," the inspectors determined the finding was of very low safety significance (Green) because, although the finding resulted in a reactor scram, it did not result in the loss of mitigation equipment relied upon to transition the plant to a stable shutdown condition. The finding did not have a cross-cutting aspect assigned because the finding is not indicative of current performance. (Section 40A3.01)

Green.

The inspectors documented a self-revealed finding for the licensee's failure to follow plant Procedure EN-Ll-102, "Corrective Action Program," Revision 28, that ensures adverse conditions were identified and corrected. Specifically, licensee staff failed to appropriately disposition and troubleshoot multiple condensate system alarms and indications. This resulted in a degraded condition being unaddressed, which led to the separation of a 2-inch condensate line, lowering condensate storage tank level, and the necessity to trip the reactor.

The licensee's failure to ensure that degraded conditions were identified and corrected was a performance deficiency. The performance deficiency is more than minor, and therefore, a finding because it is associated with the human performance attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown, as well as power operations. Specifically, the failure to appropriately disposition and troubleshoot multiple condensate system alarms and indications led to the separation of a 2-inch condensate line, lowering condensate storage tank level, and the necessity to take the plant off-line. Using NRC Inspection Manual Chapter 0609,

Attachment 04, "Initial Characterization of Findings," dated October 7, 2016, and NRC Inspection Manual Chapter 0609, Appendix A, "Significance Determination Process for Findings At-Power," Exhibit 1, "Initiating Events Screening Questions," the inspectors determined that a detailed risk evaluation was required.

The senior reactor analyst used the Grand Gulf Nuclear Station Standardized Plant Analysis Risk model to perform the detailed risk evaluation. In accordance with Risk Assessment of Operational Events Handbook guidance, the initiating event, "Loss of Main Feedwater," was set to 1.0 using the events and condition assessment module of the Systems Analysis Program for Hands-On Integrated Reliability Evaluations,

Version 8. The calculated conditional core damage probability for the event was 8.2E-7, which represents a finding of very low safety significance (Green).

The inspectors determined that the finding had a human performance cross-cutting aspect associated with conservative bias, individuals use decision making-practices that emphasize prudent choices over those that are simply allowable. Specifically, the licensee did not take actions in accordance with applicable decision making procedures that could have corrected the source of the valve oscillations prior to the pipe break occurring [H.14). (Section 40A3.03)

White.

The NRC assigned one parallel White performance indicator inspection finding involving two significant and multiple general weaknesses identified in the Grand Gulf Nuclear Station's causal evaluations and corrective actions for the White Unplanned Scrams per 7000 Critical Hours performance indicator. This finding takes the color (White) of the performance indicator. (Section 40A4.02.04)

REPORT DETAILS

OTHER ACTIVITIES

Cornerstones: Initiating Events 40A3 Follow-up of Events and Notices of Enforcement Discretion

.01. {Closed} Licensee Event Report (LER} 05000416/2016-004-00 and

05000416/2016-004-01, "Automatic Reactor SCRAM during Turbine Stop and Control Valve Surveillance Due to Reactor Pressure and Power Oscillations"

a. Inspection Scope

On June 17, 2016, Grand Gulf Nuclear Station experienced an automatic reactor scram while operating at approximately 65 percent rated thermal power during turbine stop and control valve surveillance testing. During the testing, licensee staff inadvertently closed and were unable to reopen two of the four stop valves. The closure resulted in oscillations of reactor pressure and power. While attempting to restore the system, an automatic reactor scram was received on a neutron monitoring system oscillation power range monitoring trip. The event was initiated by a reset solenoid valve being actuated per the surveillance procedure by a nonstandard tool using excessive force, causing the solenoid valve to remain in the tripped position. The solenoid valve was replaced prior to startup. The licensee revised the procedure to remove the nonstandard tool used to apply the excessive force.

This licensee event report is closed.

b. Findings

Introduction.

The inspectors documented a self-revealed, Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings,"

associated with the licensee's use of an inappropriate procedure to test turbine stop and control valves. Specifically, the licensee's procedure for testing the turbine stop and control valves allowed the use of a nonstandard tool that directly caused the system to fail, resulting in inadvertent closure of two of four stop valves and subsequent ieactor pressure and power oscillations leading to a reactor scram.

Description.

On June 17, 2016, Grand Gulf Nuclear Station was at approximately 65 percent power after a planned power reduction to compiete Surveillance Procedure 06-0P-1 N32-V-0001, "Turbine Stop and Control Valve Operability,"

Revision 122. While performing the main turbine stop and control valve operability surveillance procedure, the 'B' turbine stop valve (TSV) was closed in accordance with the procedure. When the licensee attempted to reset the 'B' TSV, the 'D' TSV unexpectedly closed. With the two TSVs closed, the 'A' and 'C' turbine control valves (TCVs) were unable to precisely control turbine load and reactor pressure, resulting in oscillating reactor pressure and power of approximately 20 psig and 20 percent power. The oscillations on reactor power, pressure, and level lasted for approximately 39 minutes before an automatic reactor scram occurred when operations personnel attempted to reduce power to dampen the oscillations.

The licensee allowed several methods of performing the turbine stop and control valve testing. The system was designed with an automatic turbine test module to perform the testing by electronically actuating the turbine valve solenoid valves. The licensee's procedure also allowed two methods of manual testing, using either test valves or by manually actuating the test solenoid valves. The licensee had been manually actuating the solenoid valves for the 2 years prior to the trip due to the automatic turbine test system not functioning properly.

The licensee determined that the cause of the failure of the test solenoid valve was the use of a nonstandard tool to operate the system. The tool consisted of a modified wooden dowel that was used to provide additional force and leverage to depress the retest solenoid valve operator. The tool allowed more force to be applied than was possible with just hand operation. The excessive force caused the solenoid valve operator to stick, resulting in a trip of both the 'B' and 'D' TSVs and prevented either TSV from being opened. The licensee concluded that the procedure was inadequate because the test solenoid valve was not designed to be operated by the nonstandard tool and the potential for damage to the valve had not been addressed.

The inadequate procedure first included the use of the nonstandard tool in 1998. The licensee had subsequently modified their procedure review process to evaluate the use of nonstandard tools in procedures. Because. the procedure was revised in 1998, the inspectors determined that the performance deficiency was not reflective of current performance.

Analysis.

The licensee's failure to prescribe adequate instructions for performing main turbine valve testing was a performance deficiency. The performance deficiency is more than minor, and therefore a finding, because it is associated with the procedure quality attribute of the Initiating Events Cornerstone and affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations.

Specifically, the failure to provide an adequate procedure resulted in an inadvertent closure of the two test valves, which upset plant stability resulting in a scram. Using NRC Inspection Manual Chapter 0609, Attachment 04, "Initial Characterization of Findings," dated October 7, 2016, and NRC Inspection Manual Chapter 0609, Appendix A, "Significance Determination Process for Findings At-Power," Exhibit 1, "Initiating Events Screening Questions," the inspectors determined the finding was of very low safety significance (Green) because, although the finding resulted in a reactor scram, it did not result in the loss of mitigation equipment relied upon to transition the plant to a stable shutdown condition. The finding did not have a cross-cutting aspect assigned because the performance deficiency was introduced in 1998 and is not indicative of current performance.

Enforcement.

Title 1O CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," requires, in part, that activities affecting quality shall be prescribed by procedures of a type appropriate to the circumstances. Contrary to the above, from 1998 through June 2017, the licensee failed to prescribe procedures of a type appropriate to the circumstances for quality related activities. Specifically, the licensee's procedure for testing the turbine stop and control valves allowed the use of a nonstandard tool that directly caused the system to fail, resulting in inadvertent closure of two of four stop valves and subsequent reactor pressure and power oscillations leading to a reactor scram. In response to this issue, the licensee revised their procedure to eliminate the use of a tool to operate the solenoid test valves. Since this violation was of very low safety significance (Green) and has been entered into the corrective action program as Condition Report CR-GGN-2016-04776, it is being treated as a non-cited violation (NCV) consistent with Section 2.3.2.a of the NRC Enforcement Policy. (NCV 05000416/2017013-01, "Inadequate Procedure for Turbine Stop Valve Testing")

.02. (C!osed) LER 05000416/2016-005-00 and LER 05000416/2016-005-01, "Automatic

Reactor SCRAM"

a. Inspection Scope

On June 25, 2016, the reactor automatically scrammed from 99 percent power following the fast closure of the turbine control valves. The fast closure resulted in actuation of the Division A and B reactor protection system which caused an automatic scram. The event was reportable in accordance with 10 CFR 50. 73(a)(2)(iv)(A) for an automatic actuation of the reactor protection system. The licensee identified that a random failure of an operational amplifier installed on a circuit card that provides input to the turbine control system Channel 1 caused the rapid closure of the throttle control valves and the automatic reactor scram. Plant technicians replaced the circuit card with a refurbished card and completed testing on the component. The licensee is currently planning to replace the current analog system with a digital control system.

This licensee event report is closed.

b. Findings

No findings were identified .

.03. (Closed) LER 05000416/2017-003-00 and LER 05000416/2017-003-01, "Reactor

Shutdown Because of Condensation System Inventory Depletion and a Manual Reactor Core Isolation Cooling (RCIC) Initiation Because of Feedwater System Shutdown"

a. Inspection Scope

On April 4, 2017, the reactor was manually scrammed from approximately 75 percent power when condensate storage tank (CST) level lowered to 24 feet. The reactor core isolation cooling reactor core isolation cooling was manually initiated to maintain reactor level control following the required shutdown of the feedwater system. Following the scram, the reactor core isolation cooling pump was aligned to take suction from the suppression pool instead of the normal suction source from the CST in an effort to prevent the control rod drive pumps from tripping on low suction pressure. Decay heat was removed via steam discharge to the condenser and to the suppression pool via reactor core isolation cooling.

Subsequent investigations revealed that a 2-inch line in the condensate system had separated due to vibrations from excessive valve cycling caused by a failed turbine controls circuit card, leading to a loss of condensate inventory and CST level decrease. The licensee replaced the failed circuit card and damaged piping and ensured that similar piping in the other two trains of condensate were not susceptible to a similar failure mechanism.

The licensee also completed a root-cause evaluation (Condition Report CR-GGN-2017-03333).

This licensee event report is closed.

b. Findings

Introduction.

The inspectors documented a self-revealed, Green, finding for the licensee's failure to follow plant Procedure EN-Ll-102, "Corrective Action Program, "

Revision 28, that ensures adverse conditions were identified and corrected. Specifically, licensee staff failed to appropriately disposition and troubleshoot multiple condensate system alarms and indications which led to the separation of a 2-inch condensate line, lowering CST level, and the necessity to trip the reactor.

Description.

On February 13, 2017, control room staff initiated a condition report documenting receipt of the "TURB BCU CAB FAIL" alarm. This alarm receives inputs from three separate cabinets associated with the condensate system bypass control unit indication and control. Additional troubleshooting was required to identify the source of the alarm. Between February 13, and March 16, 2017, the "TURB BCU CAB FAIL" alarm was repeatedly received in the control room and documented in the licensee's corrective action program. Actions to correct the issue included the installation of recorders at various test points in the bypass control unit cabinets to attempt to troubleshoot and isolate the source of the fault. During this time period, control room and engineering staff identified perturbations in condensate system hotwell levels and surmised that the changes in level were likely caused by condensate water injection valves 1N37-F1 OOA, B, and C intermittently cycling.

System engineering staff proposed multiple options for additional troubleshooting and resolution of the water injection valve cycling to station leadership. According to the licensee's root cause evaluation, station management "elected to manage regulatory risk by delaying performance of work activities that could cause a reactor scram until after April 1, 2017," due to being at risk for exceeding a regulatory performance indicator threshold associated with unplanned reactor scrams. Therefore, permission for system engineering to continue their troubleshooting and resolution efforts was denied.

On March 28, 2017, increased use of water from the CST and a "larger than usual" influx of hot water into turbine building drain sumps were identified by licensee staff (Condition Report CR-GGN-2017-03072). During the disposition of the condition report, the licensee did not take any appreciable immediate corrective actions or enter the Procedures EN-OP-111, "Operational Decision Making" or EN-MA-125, "Troubleshooting Control of Maintenance Activities" processes. The licensee noted that by delaying entry into these processes, its response was fragmented and did not accurately assess the risk to the station.

On April 3, 2017, licensee staff again identified increased use of water from the CST and excessive turbine building drain pump downs. Water was also identified coming from a 4-inch ventilation pipe in the condensate pump room. Operations personnel made a locked high radiation area entry to attempt to identify the source of the leakage.

On April 4, 2017, in order to preserve inventory in the CST for use by the contra! rod drive pumps, operations personnel inserted a manual scram. Additional investigation after the event determined the source of the leakage and lowering CST level to be from the separation of a 2-inch condensate line caused by vibrations from the excessive cycling of water injection valves 1N37-F1 ODA, B, and C due to the failure in the condensate bypass control unit. The licensee placed the reactor in a cold shutdown condition and repaired the damaged equipment.

Licensee Procedure EN-Ll-102, "Corrective Action Program," Revision 28, defines "Adverse Condition," in part, as undesirable conditions related to design basis, licensing basis, and equipment required to support safety related equipment as defined by the functionality assessment process in Procedure EN-OP-104.

Procedure EN-Ll-102 provides additional examples of adverse conditions including, "abnormal plant conditions or indications that cannot be readily explained or long-term, unexplained plant conditions." Procedure EN-Ll-102 states that "adverse conditions are required to be corrected in the Corrective Action Program and are subject to the rigor necessary to evaluate and thoroughly resolve important and significant issues." The inspectors determined that the licensee failed to ensure that adverse conditions were evaluated and thoroughly resolved in accordance with plant procedures. Specifically, licensee staff failed to appropriately disposition and troubleshoot multiple condensate system alarms and indications. This resulted in a degraded condition being unaddressed, which led to the separation of a 2-inch condensate line, lowering CST level, and the necessity to trip the reactor.

Additionally, during review of the associated root cause (Condition Report CR-GGN-2017-00333), the inspectors noted that the licensee failed to appropriately identify the root cause(s) of the event. The licensee's evaluation determined the root cause to be "operations department failed to avoid complacency and continuously challenge conditions when faced with unidentified conditions. The failure to identify the leak (troubleshooting) and the worst possible outcome (ODMI) resulted in a lack of timely action to address CST leakage and the subsequent complicated scram."

While the inspectors agree that failure to enter the troubleshooting and the operational decision making instruction (ODMI) process did result in a lack of timely actions to address the CST leakage and a failure to drive the operations department to perform a controlled shutdown of the plant versus a complicated manual scram, it did not represent the actual root cause of the event, which is associated with the fault in the bypass control unit and subsequent failure of the condensate line. Had an appropriate root cause(s) been determined, organizational and programmatic causes associated with why the bypass control unit fault occurred, and the condensate line failed, may have been developed. These organizational and programmatic causes would have also required the development of corresponding corrective actions, extent of condition, extent of cause, and effectiveness measures associated with the equipment failures in the condensate system.

Analysis.

The licensee's failure to follow plant Procedure EN-Ll-102, to ensure that adverse conditions were identified and appropriately dispositioned by the corrective action process, was a performance deficiency. The performance deficiency was more than minor, and therefore, a finding because it is associated with the human performance attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown, as well as power operations.

Specifically, the failure to appropriately disposition and troubleshoot multiple condensate system alarms and indications resulted in a degraded condition being unaddressed, which led to the separation of a 2-inch condensate line, lowering condensate storage tank level, and the necessity to take the plant off-line. Using NRC Inspection Manual Chapter 0609, Attachment 04, "Initial Characterization of Findings," dated October 7, 2016, and NRC Inspection Manual Chapter 0609, Appendix A, "Significance Determination Process for Findings At-Power," Exhibit 1, "Initiating Events Screening Questions," the inspectors determined that a detailed risk evaluation was required.

The senior reactor analyst used the Grand Gulf Nuclear Station Standardized Plant Analysis Risk (SPAR) model, Revision 8.50, to perform the detailed risk evaluation of this performance deficiency. In accordance with Risk Assessment of Operational Events Handbook guidance, for findings that cause initiating events to occur, the initiating event that was observed is set to 1.0 or "True" and the conditional core damage probability is calculated.

The conditional core damage probability is equivalent to the change in core damage frequency for a performance deficiency that results in one new initiating event. For the subject finding, the analyst determined that the "Loss of Main Feedwater initiating event best represented the conditions in the plant because the failure of condensate piping resulted in operations personnel tripping the reactor and ultimately isolating the main feedwater system. The events and condition assessment module of the Systems Analysis Program for Hands-On Integrated Reliability Evaluations, Version 8 software was used for the quantification.

The calculated conditional core damage probability for a loss of main feedwater initiating event was 8.2E-7, which represents a finding of very low safety significance (Green).

The dominant core damage sequence was a loss of main feedwater with a loss of high pressure core spray; a loss of reactor core isolation cooling; and the failure of operations personnel to depressurize the reactor.

The analyst used Inspection Manual Chapter 0609, Appendix H, "Containment Integrity Significance Determination Process," dated May 6, 2004, to evaluate the potential risk contribution due to large early release frequency. The finding was a "Type A" finding, in which, the finding had an impact on core damage frequency. In accordance with Tabie 5.1, "Phase 1 Screening-Type A Findings at Full Power," the analyst performed a Phase 2 approximation because Grand Gulf Nuclear Station has a Mark Ill containment and the dominant sequences were transients that went to core damage with high reactor coolant system pressure.

Using Table 5.2, "Phase 2 Assessment Factors-Type A Findings at Full Power," the analyst applied the screening value of 0.2 for the 62.2 percent of core damage sequences that proceeded to core damage while the reactor coolant system pressure was high. This resulted in an estimated large, early release frequency of 1.0E-7, which is at the Green,White threshold. As stated in Appendix H, Section 2.0, "Limitations and Precautions," the Phase 2 generates a "reasonably conservative, order-of-magnitude assessment." Given the value obtained from the Phase 2, and the conservatism in the 0.2 assessment factor, the analyst determined, qualitatively, that any conservatism would reduce the result below the threshold. Therefore, based on quantitative and qualitative evaluation, this finding is of very low safety significance (Green).

The inspectors determined that the finding had a human performance cross-cutting aspect associated with conservative bias, individuals use decision making-practices that emphasize prudent choices over those that are simply allowable. Specifically, the licensee did not take actions in accordance with applicable decision making procedures that could have corrected the source of the valve oscillations prior to the pipe break occurring [H.14].

Enforcement.

This finding does not involve enforcement action because no violation of a regulatory requirement was identified. In response to this issue, the licensee replaced the failed circuit card and damaged piping, and ensured that similar piping in the other two trains of condensate were not susceptible to a similar failure mechanism. The licensee also completed a root-cause evaluation. The licensee entered the issue into the corrective action program as Condition Report CR-GGN-2017-03333. Because this finding does not involve a violation and isof very low safety significance (Green), it is identified as FIN 05000416/2017013-02, "Inadequate Corrective Action Leads to Reactor Scram."

40A4 Supplemental Inspection (95001)

.01. Inspection Scope

This inspection was conducted in accordance with NRC Inspection Procedure 95001 ,

"Supplemental Inspection Response to Action Matrix Column 2 Inputs," dated August 24, 2016, to assess the licensee's evaluation of a White performance indicator, which affected the Mitigating Systems Cornerstone in the reactor safety strategic performance area. The inspection objectives were to:

  • Assure that the root causes and contributing causes of the significant performance issue are understood;
  • Independently assess and assure that the extent of condition and extent of cause of significant performance issues are identified;
  • Assure that corrective actions taken to address and preclude repetition of significant performance issues are prompt and effective; and
  • Assure that corrective plans direct prompt actions to effectively address and preclude repetition of significant performance issues.

Three scrams caused the Unplanned Scrams per 7000 Critical Hours (Initiating Events Cornerstone) performance indicator to cross the Green-White threshold. On March 29, 2016, the Grand Gulf Nuclear Station scrammed from 37 percent power in response to a 'B' phase current differential relay actuation and subsequent generator lockout and main turbine trip. On June 17, 2016, the Grand Gulf Nuclear Station scrammed from 65 percent power during turbine stop and control valve testing when power oscillations, caused by two of four turbine stop valves closing, exceeded the neutron monitoring system oscillation power range monitoring setpoint. On June 25, 2016, the Grand Gulf Nuclear Station scrammed from 99 percent power due to an unplanned fast closure of all turbine stop valves.

The three unplanned scrams resulted in LERs 2016-002-00, "Automatic Actuation of the Reactor Protection System due to 'B' Main Transformer Wiring," 2016-004-01, "Automatic Reactor Scram During Turbine Stop and Control Valve Surveillance Due to Reactor Pressure and Power Oscillations," and 2016-005-01, "Automatic Reactor Scram." Licensee Event Report 2016-002-00 was inspected with results documented in NRC Integrated Inspection Report 05000416/2016002. Licensee Event Reports 2016-004-01 and 2016-005-01 were inspected and dispositioned in Section 40A3 of this report. Additionally, LER 2017-003-01, associated with a reactor scram occurring on April 4, 2017, was inspected and dispositioned in Section 40A3 of this report.

On June 28, 2017, the licensee informed the NRC that the station was ready for the supplemental inspection. In preparation for the inspection, the licensee performed four root-cause evaluations and one common-cause evaluation associated with the March 29, June 17, and June 25, 2016, scrams. The inspectors interviewed licensee personnel to determine whether the root and contributing causes were understood and whether corrective actions taken or planned were appropriate to address the causes and preclude repetition. Additionally, the root-cause evaluation associated with the April 4, 2017, manual scram, caused by a condensate leak and subsequent lowering of CST level, was reviewed.

A brief summary of each root- and common-cause evaluation follows.

1) CR-GGN-2016-02950, "Startup From RF20 'B' Phase Current Differential Relay Scram," Revision 2 (Unplanned Scram on March 29, 2016)

On March 29, 2016, during a power ascension for a unit startup following a refueling outage, a main generator lockout was received followed by a turbine control valve fast closure, which resulted in an uncomplicated reactor scram. The main generator lockout was the result of the 'B' main transformer current differential relay trip being actuated. Subsequent licensee investigation determined the direct cause of the event to be a mis-wiring of the 'B' main transformer current transformer as a result of work performed during the refueling outage.

2) CR-GGN-2016-04766, "Unintended Oscillating Power Range Monitor (OPRM)

Reactor SCRAM due to Reactor Pressure and Power Oscillations, Equipment Failure Evaluation," Revision 2 (Unplanned Scram on June 17, 2016)

On June 17, 2016, during planned main turbine stop and control valve surveillance testing, the 'B' turbine stop valve was fast closed as procedurally directed. While attempting to reset the 'B' turbine stop valve, the 'D' turbine stop valve unexpectedly closed resulting in a Division 2 reactor protection system half scram. Due to the inability of the remaining two functional turbine control valves to control turbine load; reactor pressure, water level, and power began to oscillate.

Reactor pressure oscillated 20 psig peak-to-peak and reactor power oscillated 10-20 percent peak-to-peak. The oscillations lasted for approximately 39 minutes prior to a neutron monitoring system OPRM trip occurring, resulting in a reactor scram. Subsequent licensee investigation determined the direct cause of the closure of the 'D' turbine stop valve to be a reset solenoid valve within the turbine control system sticking in a position that opened a drain path allowing the depressurization of the trip fluid supply header.

3) CR-GGN-2016-04834, "OPRM Reactor SCRAM, Operator Response to Equipment Failure Evaluation," Revision 3 (Unplanned Scram on June 17, 2016)

On June 17, 2016, during main turbine stop valve testing, reactor power, pressure, and level oscillations occurred for approximately 39 minutes without operator action until an automatic OPRM initiated reactor scram occurred arresting the oscillations.

The operations shift crew did not manually scram the reactor when reactor power, pressure, and level were oscillating abnormally, resulting in an automatic scram.

4) CR-GGN-2016-04998, "Turbine Control Valve Fast Closure Reactor Scram,"

Revision 2 (Unplanned Scram on June 25, 2016)

On June 25, 2016, the main turbine control valves experienced a complete fast closure resulting in an automatic reactor scram. Subsequent licensee investigation determined the direct cause to be a main turbine control system Channel 1 valve lift controller signaling a main turbine control valve fast closure due to a failed operational amplifier on a control circuit logic card. The failed operational amplifier resulted in the control circuit logic sensing an instantaneous full open signal to the valve lift controller, which resulted in the fast closure of all turbine stop valves.

5) CR-GGN-2016-05488, "Common Cause Review for the Three Unplanned 2016 Scrams," Revision 1 Root-cause evaluations were performed for the three unplanned scram events that input into the Unplanned Scrams per 7000 Critical Hours performance indicator. For the June 17, 2016, scram, an additional root-cause evaluation was performed to evaluate the performance of the operations crew during the event. The licensee conducted a common cause analysis to review the four root-cause evaluations to determine if commonality exists between the events and to identify any underlying causes of trends of similar repetitive events .

===.02.

  • Evaluation of the Inspection Requirements===

.02.0 1 Problem Identification

a. Determine that the evaluation documented who identified the issue(s) (1.e.,

licensee-identified, self-revealed, or NRG-identified) and under what conditions the issue(s) were identified.

Each of the events described in Section 40A4.01 were the result of self-revealed issues.

The inspectors determined that the licensee's evaluations documented who identified the issues and under what conditions the issues were identified.

b. Determine that the evaluation documented how long the issue(s) existed and prior opportunities for identification.

The licensee's evaluations of the events documented when the issues originated, the circumstances in which each issue could have been previously identified, and documented the conditions, when applicable, involving similar events that had occurred at the station. For the June 17, 2016, scram event, the inspectors identified that the evaluation did not document how long the licensee had been using a "nonstandard tool" to operate solenoid valves during turbine stop and control valve testing. The inspectors determined that the licensee had been using the tools since 1998, based on records of procedure changes. The licensee confirmed this determination. For the remainder of the evaluations, the inspectors determined that the licensee's evaluations were adequate with respect to identifying how long the issues existed and if there were any prior opportunities for identification.

c.

Determine that the evaluation documented significant plant-specific consequence, as applicable, and compliance concerns associated with the issue.

The licensee's evaluations included a plant-specific, risk-informed safety significance evaluation of the issues. In each safety evaluation, the licensee discussed the consequences of each event with respect to the plant, as well as the consequences to the general public's safety, nuclear safety, industrial safety, and radiological safety. The inspectors concluded that the licensee appropriately documented the risk consequences and compliance concerns associated with each issue.

d. Findings

No findings were identified .

.02.0 2 Root Cause, Extent of Condition, and Extent of Cause Evaluation

a. Determine that the problem was evaluated using a systematic methodology to identify the root and contributing causes.

The inspectors determined that the licensee's root-cause evaluations (RCEs) employed a combination of the following evaluation techniques: Event and Causal Factors Charts, Barrier Analysis, Comparative Timelines, Failure Modes Analysis, Taproot', Why Staircase, Equipment Troubleshooting, and Organization and Programmatic evaluations.

The inspectors determined that the licensee selected appropriate analysis methods to ensure thorough and complete evaluations. However, the inspectors identified one significant weakness (as defined in Inspection Procedure 95001, Section 95001-02) and one general weakness associated with the adequacy of the licensee's evaluation of each issue using these systematic methodologies to identify the contributing and root causes.

Significant Weakness 1: CR-GGN-2016-04766, "Unintended OPRM Reactor SCRAM due to Reactor Pressure and Power Oscillations. Equipment Failure Evaluation,"

Revision 2 (Unplanned Scram on June 17, 2016)

For Condition Report CR-GGN-2016-04766, the inspectors determined that the RCE conducted as a resuit of the june 17, 2016, reactor scram did not perform root-cause determinations to a depth commensurate with Entergy Procedure EN-Ll-118, which requires that a root cause represent "the most basic reason for the failure, problem, or deficiency which, if corrected, would preclude repetition." Had an adequate root-cause determination been completed, additional organizational and programmatic causes may have been developed associated with

(1) why procedures were developed allowing for the use of nonstandard tools for main turbine valve testing; and
(2) why the use of nonstandard tools and alternative test methods were accepted for long term use. The additional organizational and programmatic causes would also have required the development of corrective actions and effectiveness measures. Therefore, the adequacy of the extent of condition, extent of cause, and corrective actions required to prevent recurrence cannot be assessed until the depth and breadth of the root-cause evaluation is fully developed.

General Weakness 1: CR-GGN-2016-02950, "Startup from RF 20 "B" Phase Current Differential Relay SCRAM" (Reactor Scram on March 29, 2016)

The inspectors identified that the licensee failed to identify potential contributing causes to the reactor scram event on March 29, 2016. Specifically, the licensee failed to identify a lack of clear work order instructions and retest requirements as a contributing cause.

The licensee did not identify that the work instructions did not include, within the body of the work instruction package, guidance for documenting the installation and removal of jumpers (lead lifting and landing sheets), which is an optional standard of their work order wiring instruction. The inspectors also noted that the licensee's cause evaluation stated that the workers assigned to the transformer wiring tasks did not use shorting screws despite them being available. However, the inspectors concluded, based on their inspections and interviews, that while some shorting screws were available, the required number of shorting screws necessary to perform the work order tasks were not available, contrary to the root-cause evaluation write-up.

The evaluation also did not identify that the decision to limit the scope of the testing of the transformer work removed an opportunity to identify the mistake prior to restoring the transformer to service. Procedure EN-DC-115, "Engineering Chang*e Process,"

Revision 18, requires a testing plan to be developed in accordance with Procedure EN-DC-117, "Post Modification Testing and Special Instructions," Revision 8, for "Nuclear Change Engineering Changes," but not for "Equivalent Change Engineering Changes." If the licensee had included a wiring scheme verification on the complete terminal board as part of a post modification testing plan in accordance with Procedure EN-DC-117, the licensee would likely have identified the incorrect wiring prior to restoring the transformer to service. Because the licensee's procedures did not explicitly require this testing, the responsible engineer chose not to perform this test.

b. Determine that the root-cause evaluation was conducted to a level of detail commensurate with the significance of the problem.

The licensee's RCEs included sufficient information for each event regarding event timelines, event descriptions, previous occurrences, missed opportunities, and analysis discussion. Each RCE used multiple evaluation methodologies, as discussed in Section 02.02.a, to ensure the level of detail matched the significance of each event.

The inspectors determined that the RCEs were conducted to a level of detail commensurate with the significance of the problems discussed.

c. Determine that the root-cause evaluation included a consideration of prior occurrences of the problem and knowledge of prior operating experience.

The licensee's RCEs included a review of internal and external operating experience.

The licensee conducted a fleet-wide search of Entergy's corrective action program for any previously documented conditions related to the event documented in each RCE, conducted a search of the Institute of Nuclear Power Operations (INPO) integrated civil engineering system (ICES) operating experience database, and conducted searches of NRC event reports, safety evaluation reports, information notices, generic letters, and bulletins. For each event, the licensee documented applicable operating experience from these searches. The inspectors identified one general weakness associated with this objective.

General Weakness 2: CR-GGN-2016-04834, "OPRM Reactor SCRAM, Operator Response to Equipment Failure Evaluation," Revision 3 (Unplanned Scram on June 17, 2016)

The inspectors identified that the RCE for the June 17, 2016, reactor scram event failed to conduct an adequate review of past internal and external operating experience associated with the second root cause. The second root cause identified that operations personnel did not have specific procedural guidance to address operating limits during transients caused by malfunctions of the turbine control system. The search parameters used to obtain prior operating experience were focused on nonconservative decision making, operator fundamentals, and reactor scrams. The search parameters failed to capture lack of procedural guidance, which resulted in the operating experience search missing a previous internal condition report for an NRG-identified, Green non-cited violation issued in October 2015 (Condition Report CR-GGN-2015-07209).

d. Determine that the root-cause evaluation addressed the extent of condition and the extent of cause of the problem.

The inspectors determined that the RCEs addressed the extent of condition and extent of cause. In addition to evaluating the root causes, each RCE assessed the contributing causes when addressing the extent of cause and extent of condition of each event.

However, the inspectors identified one general weakness associated with the extent of cause evaluation performed for the June 17, 2016, scram event.

General Weakness 3: CR-GGN-2016-04766, "Unintended OPRM Reactor SCRAM due to Reactor Pressure and Power Oscillations, Equipment Failure Evaluation." Revision 2 (Unplanned Scram on June 17, 2016)

The inspectors identified that the extent of cause evaluation performed as a result of the June 17, 2016, scram event was inadequate. The RCE determined the extent of cause to be "instructions were developed allowing the use of a force amplifying tool to manually operate automatic turbine test solenoid valves. The adverse effect of tool usage on the solenoid valve and alternate manual testing methods, where use of the tool was not required, were not considered." When the extent of cause evaluation was performed, only the use of "nonstandard tools on plant equipment that can affect reactor pressure, level, and power" was extended. The inspection team concluded that this was an inappropriately narrow extent of cause. A more appropriate bounding condition could serve to identify instances cf nonstandard tcc!s on other equipment with safety and/er risk significance outside of equipment only impacting reactor pressure, level, and power.

e. Determine that the root cause. extent of condition, and extent of cause evaluation appropriately considered the safety culture traits in NUREG-2165, "Safety Culture Common Language," referenced in Inspection Manual Chapter {IMC) 0310, "Aspects within Cross-Cutting Areas."

The licensee's RCEs included a review of whether a weakness in any safety culture component contributed to the issues. The licensee's evaluations identified weaknesses in safety culture components that were related to the identified root causes and contributing causes. The licensee established adequate corrective actions to address the safety culture weaknesses that were identified. The inspectors concluded that the licensee's evaluation appropriately considered safety culture components.

f. Examine the common cause analyses for potential programmatic weaknesses in performance when a licensee has a second White input in the same cornerstone.

The licensee does not have a second White input in the same cornerstone; therefore, this inspection objective is not applicable.

g. Findings

No findings were identified .

.02.0 3 Corrective Actions Taken

a. Determine that appropriate corrective actions are specified for each root and contributing cause or that the licensee has an adequate evaluation for why no corrective actions are necessary.

The licensee's RCEs identified corrective actions to address root and contributing causes. The inspectors reviewed each of the corrective actions and determined they adequately addressed the identified root and contributing causes.

b. Determine that the corrective actions have been prioritized with consideration of significance and regulatory compliance.

The licensee's immediate corrective actions following each event restored the impacted systems to an operable and/or functional condition in order to restore compliance with plant technical specifications and applicable procedures. The inspectors reviewed the prioritization of the corrective actions and verified that actions of a generally higher priority were scheduled for completion ahead of those of a lower priority. Additionally, the inspectors determined that the licensee's evaluations addressed regulatory compliance issues. The inspectors concluded that the licensee adequately prioritized the corrective actions with consideration of the risk significance and regulatory compliance.

c. Determine that corrective actions taken to address and preclude repetition of significant performance issues are prompt and effective.

The licensee's RCEs identified multiple corrective actions to preclude repetition (CAPRs)associated with the significant performance issues. The CAPRs were adequate to addiess the adverse conditions in three of the four RCEs in the scope of the inspection.

For these three RCEs, the licensee's corrective actions also addressed identified gaps associated with extent of condition and extent of cause of the issues. For these RCEs, the inspectors determined that the CAPRs were prompt and effective. However, the inspectors identified one significant weakness associated with the CAPRs identified for the March 29, 2016, scram event RCE.

Significant Weakness 2: CR-GGN-2016-02950, "Startup from RF 20 'B' Phase Current Differential Relay SCRAM" (Reactor Scram on March 29, 2016)

The inspectors determined that for Condition Report CR-GGN-2016-02950, the RCE the licensee staff performed as a result of the March 29, 2016, scram, did not generate corrective actions that were adequate to preclude repetition of the event, which the licensee determined to be caused by inadequacies in supervision and work instruction use and adherence by supplemental personnel.

Entergy Procedure EN-Ll-118 defines a CAPR as "an action that eliminates the root cause of the [significant condition adverse to quality] SCAQ or, when the cause cannot be eliminated, implements barriers to mitigate the consequences to an acceptable levels. At least one CAPR is required for a SCAQ." The assigned CAPRs for CR-GGN-2016-02950 included revising Procedure EN-MA-100, "Maintenance Fundamentals Program," to include an attachment defining the essential knowledge, skills, behaviors, and practices personnel need to apply to conduct their work properly (CAPR-1) and the implementation of a revision to the existing Procedure EN-OM-126, "Qualification of Supplemental Supervisors," to change the supervisor qualification oral board process to ensure maintenance fundamentals and the oversight role of the supervisor are adequately addressed (CAPR-2).

The intent of the CAPRs included, "ensuring that maintenance personnel, supplemental personnel, and oversight and supervisors are aware of and execute the requirements found in Procedure EN-MA-100," as well as to, "ensure supervisors and supplemental oversight personnel for electrical or instrumentation and control maintenance ... are cognizant and proficient with reinforcing the skills and behaviors regarding the fundamentals for lifting and landing of leads and configuration control."

Assigned corrective actions associated with the CAPRs included conducting observations to monitor and reinforce requirements for Procedure EN-OM-126; generating a case study to be presented on a one time basis to personnel and supervisors on site, as well as inclusion in supervisor continuing training for 2016; and holding a one-time site-wide mandatory briefing for personnel on site. The inspectors noted that the one-time site-wide briefing did not address the root causes of inadequacies in supervision and work instruction use and adherence. This was because the briefing contained superseded root causes from a previous revision to Condition Report CR-GGN-2016-02950.

The inspectors also questioned the adequacy of solely adding an attachment to Procedure EN-MA-100, "Maintenance Fundamentals Program," to prevent work instruction use and adherence deficiencies. The inspectors did not identify any corrective actions serving to make nonsupervisory personnel aware of the addition.

Additionally, the inspectors reviewed the assigned case study and noted that it did not contain a discussion of the root causes that led to the reactor scram on March 29, 2016, and was distributed to supervisors on site via e-mail with no actions assigned to determine if the information contained in the case study was reviewed by the targeted supervisors. It was also unclear to the inspectors how this case study would be presented, if at all, to supplementary supervision temporarily on site during refueling outages and other maintenance activities.

In summary, the inspectors determined that the CAPRs and associated corrective actions assigned to preclude repetition of the event did not meet the intent of the two generated CAPRs and were insufficient to preclude repetition of the event.

d. Determine that each Notice of Violation related to the supplemental inspection is adequately addressed, either in corrective actions taken or planned.

The NRG staff did not issue a Notice of Violation to the licensee; therefore, this inspection item was not applicable.

e. Findings

No findings were identified .

.02.0 4 Corrective Action Plans

a. Determine that appropriate corrective action plans are specified for each root and contributing cause or that the licensee has an adequate evaluation for why no corrective actions are necessary. Determine that the corrective action plans have been prioritized with consideration of significance and regulatory compliance.

The inspectors determined that the licensee's corrective action plans adequately addressed each of the root and contributing causes in three of the four RCEs. For these RCEs, the inspectors noted that the corrective action plans were clearly defined and that the licensee had adequately prioritized the plans with due dates. The licensee also accounted for significance of the issues when prioritizing the actions and considered regulatory compliance when applicable. The inspectors did identify one general weakness associated with the corrective action plan for the June 17, 2016, scram.

General Weakness 4: CR-GGN-2016-04834, "OPRM Reactor SCRAM, Operator Response to Equipment Failure Evaluation," Revision 3 (Unplanned Scram on June 17, 2016)

The inspectors determined that multiple corrective actions (CAs) associated with Condition Report CR-GGN-2016-04834 have responses that were either insufficient or did not meet the intent statement in the CA These include:

  • The intent statement of CA-32 required Plant Review Group review of Operations Crew Metrics. Operations Guide 50 Crew Metrics, implemented to address CA-32, made this review optional.
  • CA-31 identified training requirements for the reactor engineer position. CA-37 required a performance analysis be completed to identify weaknesses in reactor engineer performance. The performance analysis gaps were not identified in CA-31 as training requirements. In addition, the performance analysis did not address the specific knowledge issue identified in the root cause associated with 3D Monicore use.
  • CA-36 required an engineering self-assessment to be performed associated with engineering fundamentals. The CA was closed to an informal seif-assessment that did not meet the requirements of the licensee's self-assessment Procedure EN-Ll-104.
  • CA-23 was written to compare Grand Gulf Nuclear Station procedures with other non-Entergy boiling water reactors. This was closed to CA-40, which benchmarked the Perry Nuclear Power Plant and Clinton Power Station and identified two gaps. The identified gaps were subsequently closed to CA-45, which provided the option of not addressing the gaps identified from CA-40, at the senior operations manager discretion.
  • There were no CAs generated to incorporate into the initial license operator training program the lessons learned from requalification training provided as a result of Condition Report CR-GGN-2016-04834. Three actions were being tracked outside of the corrective action program; however, these do not have the same rigor as CAs.
  • CA-17 provided training to operations and duty managers to practice their roles during transients in accordance with applicable guidance. There are no corrective actions to train future operations and duty managers to the same standard to prevent recurrence of an issue identified in the contributing cause associated with roles an~ responsibilities during transients.

b. Determine that corrective plans direct prompt actions to effectively address and preclude repetition of significant performance issue.

The licensee's RCEs included numerous corrective action plans to ensure the significant performance issues are effectively addressed. These corrective action plans included multiple CAPRs. The inspectors reviewed the CAPRs and other corrective action plans and determined that the licensee established a formal tracking mechanism for each specific open corrective action. When establishing and prioritizing corrective action plans, the licensee considered the significance assessment results of the different performance issues. As a result, the inspectors determined that the corrective action plans directed prompt actions to effectively address and preclude repetition of significant performance issues.

c. Determine that appropriate quantitative or qualitative measures of success have been developed for determining the effectiveness of planned and completed corrective actions.

The inspectors determined that the licensee developed sufficient effectiveness review plans for the established CAPRs for three of the four RCEs. These plans included quantitative and qualitative measures of success to determine the effectiveness of the corrective actions to prevent recurrence. However, the inspectors did identify one general weakness associated with the June 17, 2016, scram.

General Weakness 5: CR-GGN-2016-04766, "Unintended OPRM Reactor SCRAM due to Reactor Pressure and Power Oscillations, Equipment Failure Evaluation," Revision 2 (Unplanned Scram on June 17, 2016)

The inspectors determined that the effectiveness review criteria developed for the corrective actions taken for Condition Report CR-GGN-2016-04766 were not adequate.

The licensee had developed one measure of success to determine the effectiveness of completed corrective actions. The attribute to measure was, "nonstandard tool use to operate plant equipment causing plant transient greater than 5 percent," with a success criteria of, "No occurrences of plant transient greater than 1O percent caused by use of a nonstandard tool to operate plant equipment." This was to be assessed for 12 months.

The inspectors considered this effectiveness measure to be too narrowly focused, given that the intent of the corrective actions was to eliminate or assess the use of "non-standard tools" in plant procedures. Further, it is unclear why additional instance(s) of non-standard tool use resulting in plant transients would be acceptable (i.e., meet the success criteria for this effectiveness measure) as long as the transient was below 1O percent. Additionally, although the effectiveness review is intended to be completed as early as practicable, when combined with the narrow failure criteria, a review after 12 months is unlikely to detect failure of the corrective actions to prevent recurrence.

d. Determine that each Notice of Violation related to the supplemental inspection is adequately addressed in corrective actions taken or planned.

The NRC staff did not issue a Notice of Violation to the licensee; therefore, this inspection item was not applicable.

e. Findings

Introduction.

The NRC assigned a parallel corrective action (performance indicator)inspection finding of low-to-moderate safety significance (White) for the failure to adequately evaluate the causes and implement corrective actions sufficient to address the root and contributing causes that resulted in the White Unplanned Scrams per 7000 Critical Hours performance indicator.

Description.

The inspectors identified deficiencies regarding the licensee's execution of corrective actions documented in the RCEs, as well as understanding of some of the causes of the issues. Specifically, the NRC supplemental inspection team determined that several of the licensee's cause evaluations did not have sufficient depth and breadth. Additionally, licensee Procedure EN-Ll-118, "Cause Evaluation Process,"

Revision 24, requirements for cause evaluations were not satisfied, as noted below. The NRC supplemental inspection team identified two significant weaknesses, and multiple general weaknesses.

First, the NRC supplemental inspection team determined that for Condition Report CR-GGN-2016-04766, the root-cause evaluation conducted for the June 17, 2016, reactor scram did not perform root-cause determinations to an adequate depth to identify the root cause. Additionally, Entergy Procedure EN-Ll-118, which requires that a root cause represent "the most basic reason for the failure, problem, or deficiency which, if corrected, would preclude repetition," was not satisfied. Had an adequate root-cause determination process been completed, additional or different root causes may have been developed requiring the development of corrective actions and effectiveness measures.

Second, the NRC determined that for Condition Report CR-GGN-2016-02950, the root-cause evaluation of the March 29, 2016, scram did not generate corrective actions that were adequate to preclude repetition of the event, which was determined to be caused by inadequacies in supervision and work instruction use and adherence by supplemental personnel. Additionally, Entergy Procedure EN-Ll-118 defines a CAPR as "an action that eliminates the root cause of the SCAQ or, when the cause cannot be eliminated, implements barriers to mitigate the consequences to an acceptable ieveis.

At least one CAPR is required for a SCAQ."

Additionally, less significant, additional weaknesses involved the failure to identify contributing causes; failure to conduct reviews of operating experience; inadequate extent of cause evaluation; insufficient corrective actions; and inadequate effectiveness review criteria were identified.

The licensee's failure to adequately evaluate these performance issues is indicative of challenges in implementing the site's corrective action program, which is being further evaluated by the NRC with an inspection team conducting a biennial problem identification and resolution inspection. The results of that inspection will be documented in NRC Inspection Report 05000416/2017011.

Analysis.

NRC Inspection Manual Chapter 0305, "Operating Reactor Assessment Program," dated November 17, 2016, states "lfthe supplemental inspection (IP 95001 )

for a safety-significant Pl results in the determination that the licensee failed to

(1) identify, understand, or adequately evaluate the root causes, contributing causes, extent-of-condition, or extent-of-cause of the safety-significant Pl; or
(2) take or plan adequate corrective actions to address the root causes, contributing causes, extent-of-condition, or extent-of-cause and to prevent recurrence of the safety-significant Pl, then a parallel Pl inspection finding will be opened and given the same safety-significance (i.e., color) as the Pl."

The NRC supplemental inspection team determined that for Condition Report CR-GGN-2016-04766, associated with the June 17, 2016, reactor scram, the licensee did not identify, understand, or adequately evaluate a root cause. Additionally, Entergy Procedure EN-Ll-118, which requires that a root cause represent "the most basic reason for the failure, problem, or deficiency which, if corrected, would preclude repetition," was not satisfied.

The NRC supplemental inspection team determined that for Condition Report CR-GGN-2016-02950, the root-cause evaluation of the March 29, 2016, scram the licensee failed to take or plan adequate corrective actions to address the root causes, contributing causes, extent-of-condition, or extent-of-cause and to prevent recurrence of the safety-significant Pl. Additionally, Entergy Procedure EN-Ll-118 defines a CAPR as "an action that eliminates the root cause of the SCAQ or, when the cause cannot be eliminated, implements barriers to mitigate the consequences to an acceptable levels. At least one CAPR is required for a SCAQ." Since the licensee did not generate corrective actions that were adequate to address the identified root cause of the event (as described in Section 02.03.c above), this procedure was not satisfied.

As a result of these determinations, a parallel Pl inspection finding will be opened and given the same safety-significance (i.e., color) as the Pl. Since the initiating performance indicator was White, this parallel inspection finding has been assigned a low to moderate safety significance (White). This parallel performance indicator inspection finding provides for additional NRC review of the licensee's actions to address the weaknesses identified in this report.

  • Because this is a parallel White performance indicator inspection finding, it was not assessed for cross-cutting aspects.
Enforcement.

No violation of regulatory requirements is associated with this finding.

The parallel inspection finding associated with the White Unplanned Scrams per 7000 Critical Hours performance indicator will take effect in the first quarter of 2017, which is the quarter the White performance indicator was no longer considered an Action Matrix input in accordance with Section 11.02.b of Inspection Manual Chapter 0305, "Operating Reactor Assessment Program," dated November 17, 2016. The finding will be removed from consideration of future agency action (per the Action Matrix) in the quarter following successful completion of a follow-up supplemental inspection. The parallel White performance indicator inspection finding will not be double-counted with the performance indicators with which they are associated. (FIN 05000416/2017013-03, "Parallel White Unplanned Scrams per 7000 Critical Hours performance indicator Finding")

.02.0 5 Evaluation of Inspection Manual Chapter 0305 Criteria for Treatment of Old Design

Issues The licensee did not request credit for self-identification of an old design issue; therefore, the risk significant issues were not evaluated against Inspection Manual Chapter 0305, "Operating Reactor Assessment Program," criteria for treatment of an old design issue.

40A6 Meetings, Including Exit

Exit Meeting Summary

On September 19, 2017, and November 13, 2017, the inspectors presented the inspection results to Mr. Eric Larson, Site Vice President, 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.

SUPPLEMENTAL INFORMATION

KEY POINTS OF. CONTACT

Licensee Personnel

D. Bareswelt, Training
T. Chamblee, Operations Reactor Operator
S. Dunfee, Operations Shift Manager
G. Ellis, Operations Unit Supervisor
A. Farrell, Senior Manager, Maintenance
S. Flickinger, Operations Unit Supervisor
R. Gaston, Acting Vice President, Corporate Regulatory Assurance
M. Giacini, General Manager, Plant Operations
K. Haley, Operations Reactor Operator
G. Hawkins, Director, Regulatory Assurance and Performance Improvement
E. Larson, Site Vice President
D. Lauterburg, Training Manager
R. Liddell, Training
D. Lum, Senior Communications
R. Meister, Regulatory Assurance
R. Myers, Operations Superintendent
D. Neve, Manager, Regulatory Assurance
A. Notbohn, Director, Performance Improvement
R. Purdy, Operations Shift Manager
B. Roach, Senior Manager, Site Projects
P. Salgado, Performance Improvement
T. Tharp, Training
T. Vehec, Director, Recovery
B. Wertz, Senior Manager, Operations
P. Williams, Director, Engineering

NRC Personnel

N. Day, Resident Inspector
M. Young, Senior Resident Inspector

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000416/2017013-01 NCV Inadequate Procedure for Turbine Stop Valve Testing

(Section 40A3)05000416/2017013-02 FIN Inadequate Corrective Action Leads to Reactor Scram

(Section 40A3)05000416/2017013-03 FIN Parallel White Unplanned Scrams per 7000 Critical Hours Pl

Finding (Section 40A4)

Closed

05000416/2016-004-01; LER Automatic Reactor Scram during Turbine Stop and Control

05000416/2016-004-00 Valve Surveillance Due to Reactor Pressure and Power

Oscillations (Section 40A3)

05000416/2016-005-01; LER Automatic Reactor Scram (Section 40A3)

05000416/2016-005-00

05000416/2017-003-01; LER Reactor Shutdown Because of Condensation System Inventory

05000416/2017-003-00 Depletion and a Manual Reactor Core Isolation Cooling (RCIC)

Initiation Because of Feedwater System Shutdown

(Section 40A3)

LIST OF DOCUMENTS REVIEWED

Section 40A4: Supplemental Inspection (95001)

Drawings

Number Description Revision

E-1046 Main Generator and Main Transformers C. T. 14

Connections

Miscellaneous Documents

Number Title Revision/Date

2017 Operations Department Action Plan July 24, 2017

Entergy Operations Grand Gulf Nuclear Station/Unit 1

Readiness Assessment for IP95001 2016 Unplanned

Scrams

Grand Gulf Nuclear Station Rebuilding Blueprint 3

Operations High Intensity Oversight Plan July 28, 2016

Turbine Control, System Health Report August 1, 2017

2016-04-00 Licensee Event Report August 12, 2016

2016-04-01 Licensee Event Report August 16, 2017

2016-05-00 Licensee Event Report August 22, 2016

2016-05-01 Licensee Event Report August 16, 2016

JA-Pl-01 Analysis Manual 4

NUREG-2165 Safety Culture Common Language

OPG-12 Operator Workarounds 2

Procedures

Number Title Revision/Date

Grand Gulf Technical Specifications

Grand Gulf UFSAR

01-S-02-9 Procedure Change Process 5

01-S-06-26, Post Trip Analysis Scram No. 140, TCV Fast Closure June 30, 2016

I

01-S-17-42 Trip Critical Program 7

2-S-01-27 Operations Section Procedure - Operations Philosophy 72

06-0P-1 N32-V- Turbine Stop and Control Valve Operability 120

0001

06-0P-1 N32-V- Turbine Stop and Control Valve Operability 122

0001

EN-DC-112 Engineering Change Request Process 9

EN-DC-115 Engineering Change Process 18

EN-DC-117 Post Modification Testing and Special Instructions 8

EN-DC-153 Preventative Maintenance Component Classification 14

EN-DC-159 System and Component Monitoring 9

EN-DC-175 Single Point Vulnerability Review Process 5,6

EN-DC-325 Component Performance Monitoring 9

EN-DC-345 Critical Component Failure Determination 3

EN-FAP-OM-102 Prompt Investigations and Notifications 17

EN-Ll-102 Corrective Action Program 29

EN-Ll-118 Cause Evaluation Process 24

EN-Ll-12*1 Trending and Performance Review Process 22

EN-Ll-123-01 Pre-Inspection Preparation for IP 95001 and IP 95002 6

Supplemental Inspections

EN-MA-100 Maintenance Fundamentals Program 1

EN-OM-126 Management and Oversight of Supplemental Personnel 1

EN-OM-132 Nuclear Risk Management Process 0

EN-OM-133 Entergy Nuclear Risk Governance 0

EN-OP-103 Reactivity Management Program 6

EN-OP-115 Conduct of Operations 19

EN-OP-120 Operator Fundamentals Program 1

Procedures

Number Title Revision/Date

EN-TQ-210 Conduct of Simulator Training 10

EN-TQ-212 Conduct of Training and Qualification 15

EN-WM-105 Planning 16

EN-WM-107 Post Maintenance Testing 5

Condition Re~orts (CR-GGN-l

2005-02446 2007-00773 2007-04972 2010-01935 2010-05889

2011-01565 2011-06292 2012-10929 2013-06384 2013-04414

2013-06549 2015-00801 2015-02061 2015-04301 2015-04324

2015-07209 2016-00275 2016-00572 2016-02686 2016-02876

2016-02950 2016-02973 2016-02989 2016-03794 2016-04766

2016-04834 2016-04998 2016-04999 2016-05004 2016-05008

2016-05015 2016-05153 2016-05488 2016-05844 2016-06359

2016-08090 2017-00854 2017-04834 2017-04998 2017-05883

2017-08019 2017-08020 2017-08021 2017-08253 2017-08256

2017-08267 2017-08287 2017-08295 2017-08296 2017-08297

2017-08304 2017-08305 2017-08311 WT-WTHQN-

2015-0038

Work Order <WO)

194674 358344 397549 397595 411493

2489

A-4