IR 05000416/2021040

NRC Supplemental Inspection Report 05000416/2021040 and Assessment Follow-Up Letter

ML21306A311
Person / Time
Site:	Grand Gulf
Issue date:	11/18/2021
From:	Scott(Ois) Morris NRC Region 4
To:	Franssen R Entergy Operations
Vossmar P
References
IR 2021040
Download: ML21306A311 (50)

Text

November 18, 2021

SUBJECT:

GRAND GULF NUCLEAR STATION - NRC SUPPLEMENTAL INSPECTION REPORT 05000416/2021040 AND ASSESSMENT FOLLOW-UP LETTER

Dear Mr. Franssen:

On September 17, 2021, the U.S. Nuclear Regulatory Commission (NRC) completed a supplemental inspection at your Grand Gulf Nuclear Station (GGNS) using Inspection Procedure (IP) 95002, Supplemental Inspection Response to Action Matrix Column 3 (Degraded Performance) Inputs. The NRC performed IP 95002 to review your stations actions in response to a Yellow performance indicator (PI) for Unplanned Scrams per 7,000 Critical Hours (Initiating Events Cornerstone), which GGNS reported for the fourth quarter of 2020. On October 4, 2021, the NRC inspection team discussed the results of this inspection with you and other members of your staff in a public meeting. The results of this inspection are documented in the enclosed report. Based on the results of this inspection, the NRC concluded that the objectives of IP 95002 were met.

The NRC conducted the IP 95002 supplemental inspection to ensure that your staff understood the root and contributing causes of the events that resulted in the Yellow PI, to assess the extent of condition of these identified causes, to ensure that your planned and completed corrective actions would be effective in precluding repetition of the identified problem(s), and to determine if any adverse safety culture traits caused or significantly contributed to the performance issues.

In addition to specific causal factors identified following each of the five unplanned scram events, your staffs evaluation identified one common root cause for the scrams that led to the Yellow PI. Specifically, the GGNS staff determined the common root cause to be that engineering leadership missed an opportunity to provide appropriate levels of technical rigor and management review during the development and implementation of the turbine control system modification. Corrective actions for this common root cause included enhancing accountability for individual and organizational performance, providing more effective supervisory oversight, and improving the engineering design change process.

Based on the inspection teams independent review of the above activities, the NRC determined that your completed and planned future corrective actions at GGNS were sufficient to address the performance decline that led to the Yellow PI. Notwithstanding the above, the inspection team did identify some general weaknesses in the stations root and common cause evaluations and associated corrective actions. These weaknesses involved the implementation of the operating experience program, the evaluation and resolution of certain issues in the corrective action program, the scope and veracity of some extent-of-cause and extent-of-condition reviews, and the applicability of corrective actions to preclude repetition (CAPRs) to some safety-related, high-risk systems and components. Your staff acknowledged and appropriately addressed these weaknesses following interactions with the NRC inspectors. A discussion of these issues is also included in the enclosed report.

Additionally, the NRC determined that the Unplanned Scrams per 7,000 Critical Hours PI had returned to Green in the third quarter of 2021. Based on the guidance in NRC Inspection Manual Chapter 0305, Operating Reactor Assessment Program, and the results of the IP 95002 inspection, the actions necessary to close the Yellow PI are complete and GGNS will transition from the Degraded Performance Column (i.e., Column 3) of the NRCs Reactor Oversight Process Action Matrix to the Licensee Response Column (i.e., Column 1) as of the date of this letter. Please note that this letter supplements, but does not supersede, the NRCs mid-cycle assessment letter, issued on September 1, 2021 (ADAMS Accession No.

ML21232A225).

In accordance with Inspection Manual Chapter 2515, Appendix B, Supplemental Inspection Program, dated October 21, 2020, the NRC plans to conduct follow-up inspection activities for all of the planned CAPRs that were not yet complete at the time of this supplemental inspection and may include an evaluation of the associated effectiveness review actions. This inspection activity will be scheduled consistent with your NRC-accepted CAPR completion date as part of a future baseline inspection sample to verify that GGNS completed these actions in accordance with the established plan.

The NRC inspection team also documented three findings of very low safety significance (i.e.,

Green) in this report. Two of these findings involved violations of NRC requirements. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2 of the Enforcement Policy.

If you contest the violations or the significance or severity of the violations documented in this inspection report, you should provide a response within 30 days of the date of this letter, 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 Grand Gulf Nuclear Station.

If you disagree with a cross-cutting aspect assignment, or the finding not associated with a regulatory requirement in this report, you should provide a response within 30 days of the date of this letter, 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 GGNS. In accordance with 10 CFR 2.390 of the NRCs Agency Rules of Practice and Procedure, a copy of this letter will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Please contact Mr. Jason Kozal at 817-200-1144 with any questions you may have regarding this letter.

Sincerely, Scott A. Morris Regional Administrator NRC Region IV Docket No. 05000416 License No. NPF-29

Enclosure:

As stated

Inspection Report

Docket Number: 05000416

License Number: NPF-29

Report Number: 05000416/2021040

Licensee: Entergy Operations, Inc.

Facility: Grand Gulf Nuclear Station

Location: Port Gibson, MS

Inspection Dates: August 23, 2021, to September 17, 2021

Inspectors: A. Nguyen, Inspection Team Leader B. Bergeon, Operations Engineer J. Ellegood, Senior Resident Inspector L. Flores, Reactor Inspector (Observer)

M. Keefe-Forsyth, Human Factors Specialist R. Kumana, Senior Resident Inspector R. Sigmon, Reactor Systems Engineer (Observer)

J. Vazquez, Reactor Operations Engineer J. Vera, Resident Inspector P. Zurawski, Senior Resident Inspector

Approved By: Jason W. Kozal, Chief Reactor Projects Branch C Division of Reactor Projects

Enclosure

SUMMARY

The U.S. Nuclear Regulatory Commission (NRC) evaluated the Entergy Operations (Entergys)

actions to address a Yellow performance indicator by conducting a supplemental inspection at Grand Gulf Nuclear Station, in accordance with the Reactor Oversight Process Inspection Procedure (IP) 95002. Additionally, the NRC conducted baseline inspection activities in accordance with IP 71153 to review and assess the licensee event reports issued following each of the reactor scrams that led to the Yellow performance indicator. The Reactor Oversight Process is the NRCs program for overseeing the safe operation of commercial nuclear power reactors. Refer to https://www.nrc.gov /reactors/operating/oversight.html for more information.

The NRC determined that the licensees problem identification, causal analyses, and corrective actions sufficiently addressed the performance issues that led to the Yellow performance indicator. The inspectors concluded that all inspection objectives, as described in IP 95002, were Met. Assessments, findings, violations, and inspector-identified weaknesses in the licensees evaluations are detailed below.

List of Findings and Violations

Failure to Verify Appropriate Design Inputs per the Engineering Change Process Cornerstone Significance Cross-Cutting Report Aspect Section Initiating Events Green [H.3] - Change 71153 FIN 05000416/2021040-01 Management Open/Closed The inspectors identified a self-revealed Green finding when the licensee failed to verify appropriate design inputs per Procedure EN-DC-115, Engineering Change Process,

Revision 31, for the turbine control digital system upgrade project. Specifically, in three instances, the licensee failed to identify the following during the Design Review and Owner Acceptance Review of the engineering change:

1. An incorrect air gap setting for the new turbine speed monitoring probes which resulted in an automatic turbine trip and reactor scram on May 25, 2020.

2. The effect of vibration on the hydraulic actuator for a main turbine control valve, a critical aspect of the design, which resulted in operators having to initiate a manual reactor scram on August 8, 2020.

3. Incorrect design for primary water bushing flow transmitter sensing lines, which led to an automatic turbine trip and reactor scram on November 6, 2020.

Failure to Follow the System Operating Instruction for the Primary Water System Cornerstone Significance Cross-Cutting Report Aspect Section Initiating Events Green [H.11] - 71153 NCV 05000416/2021040-02 Challenge the Open/Closed Unknown The inspectors identified a self-revealed Green finding and associated non-cited violation of Technical Specification 5.4.1(a) when the licensee failed to implement Procedure 04-1-01-N43-1, Primary Water System Operating Instruction, Revision 62.

Specifically, while performing Section 5.2.2, Filling and Venting to Raise System Water Tank Level to Normal, an operator inappropriately applied a caution statement associated with step 5.2.2.f after misdiagnosing that valve 1N43-FD01, the primary water system leakage water return valve, was stuck open. The operator incorrectly took manual action to close the valve, causing the primary water system head tank level to lower, resulting in an automatic turbine trip and reactor scram.

Failure to Prevent Recurrence of Multiple Scrams Related to the Turbine Control System Cornerstone Significance Cross-Cutting Report Aspect Section Initiating Events Green [H.12] - Avoid 95002 NCV 05000416/2021040-03 Complacency Open/Closed The inspectors identified a self-revealed Green finding and associated non-cited violation of 10 CFR 50, Appendix B, Criterion XVI, when the licensee failed to preclude repetition of recurrent plant scrams related to the turbine control system, a significant condition adverse to quality. Specifically, the licensees actions to correct the causes of scrams that occurred prior to calendar year 2020 (and which resulted in the Unplanned Scrams per 7000 critical hours performance indicator crossing an elevated threshold in 2018), were ineffective. As a result, in 2020, four additional plant scrams related to turbine control system deficiencies caused the same performance indicator (Unplanned Scrams) to cross an elevated threshold.

Additional Tracking Items

Type Issue Number Title Report Section Status LER 05000416/2020-002-02 Reactor Scram Due to Main 71153 Closed Turbine Trip LER 05000416/2020-002-01 Reactor Scram Due to Main 71153 Closed Turbine Trip LER 05000416/2020-002-00 Reactor Scram Due to Main 71153 Closed Turbine Trip LER 05000416/2020-003-00 Manual Reactor Scram Due 71153 Closed to Turbine High Pressure Control Valve Malfunction and Automatic Reactor Water Level Scram LER 05000416/2020-003-01 Manual Reactor Scram Due 71153 Closed to Turbine High Pressure Control Valve Malfunction and Automatic Reactor Water Level Scram LER 05000416/2020-004-00 Automatic Reactor Scram 71153 Closed Due to Reactor Feed Pump Trip LER 05000416/2020-004-01 Automatic Reactor Scram 71153 Closed Due to Reactor Feed Pump Trip LER 05000416/2020-005-00 Primary Water System Flow 71153 Closed Lowered Causing Turbine Trip and Subsequent Reactor Scram LER 05000416/2020-005-01 Primary Water System Flow 71153 Closed Lowered Causing Turbine

Type Issue Number Title Report Section Status Trip and Subsequent Reactor Scram LER 05000416/2020-005-02 Primary Water System Flow 71153 Closed Lowered Causing Turbine Trip and Subsequent Reactor Scram LER 05000416/2020-006-00 Primary Water Tank Low 71153 Closed Level Causing Turbine Trip and Subsequent Reactor Scram LER 05000416/2020-006-01 Primary Water Tank Low 71153 Closed Level Causing Turbine Trip and Subsequent Reactor Scram LER 05000416/2020-006-02 Primary Water Tank Low 71153 Closed Level Causing Turbine Trip and Subsequent Reactor Scram

INSPECTION SCOPE

AND CONDUCT

Inspections were conducted using the appropriate portions of the inspection procedures (IPs) in effect at the beginning of the inspection unless otherwise noted. Currently approved IPs with their attached revision histories are located on the public website at http://www.nrc.gov/reading-rm/doc-collections/insp-manual/inspection-procedure/index.html. The NRC staff determined that inspection samples were complete when the IP requirements most appropriate to the inspection activity were met consistent with Inspection Manual Chapter (IMC) 2515, Light-Water Reactor Inspection Program - Operations Phase. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel to assess licensee performance and compliance with Commission rules and regulations, license conditions, site procedures, and standards.

On March 20, 2020, in response to the National Emergency declared by the President of the United States regarding the public health risks of the coronavirus (COVID-19), inspectors were directed to begin teleworking. In addition, regional baseline inspections were evaluated to determine if all or a portion of the objectives and requirements stated in the associated IPs could be performed remotely. If the inspections could be performed remotely, they were conducted per the applicable IP. In some cases, portions of an IP were completed both remotely and on site. All of the inspections documented below met the objectives and requirements for completion of the IPs.

OTHER ACTIVITIES - BASELINE

71153 - Follow Up of Events and Notices of Enforcement Discretion Event Report (IP Section 03.02)

The inspectors evaluated the following licensee event reports (LERs):

(1) LER 05000416/2020-002-02, Reactor Scram Due to Main Turbine Trip (ADAMS Accession No. ML21231A135). The inspection conclusions associated with this LER are documented in this report under Inspection Results Section 71153.

(2) LER 05000416/2020-003-01, Manual Reactor Scram Due to Turbine High Pressure Control Valve Malfunction and Automatic Reactor Water Level Scram (ADAMS Accession No. ML21231A136). The inspection conclusions associated with this LER are documented in this report under Inspection Results Section 71153.

(3) LER 05000416/2020-004-01, Automatic Reactor Scram Due to Reactor Feed Pump Trip (ADAMS Accession No. ML21231A137). The inspectors determined that it was not reasonable to foresee or correct the cause discussed in the LER; therefore, no performance deficiency was identified. The inspectors did not identify a violation of NRC requirements.

(4) LER 05000416/2020-005-02, Primary Water System Flow Lowered Causing Turbine Trip and Subsequent Reactor Scram (ADAMS Accession No. ML21231A138). The inspection conclusions associated with this LER are documented in this report under Inspection Results Section 71153.

(5) LER 05000416/2020-006-02, Primary Water Tank Low Level Causing Turbine Trip and Subsequent Reactor Scram (ADAMS Accession No. ML21231A139). The inspection conclusions associated with this LER are documented in this report under Inspection Results Section

OTHER ACTIVITIES

- TEMPORARY INSTRUCTIONS, INFREQUENT AND ABNORMAL

===95002 - Supplemental Inspection Response to Action Matrix Column 3 (Degraded Performance) Inputs

This inspection fulfills the requirements to perform a supplemental inspection in response to degraded performance that led to the Grand Gulf facility being moved into Column 3 of the Action Matrix for the Unplanned Scrams per 7000 Critical Hours performance indicator crossing into the Yellow threshold. The inspection objectives are to:

Ensure that the root and contributing causes of significant individual and collective performance issues are understood; Independently assess and ensure that the extent-of-condition and the extent-of-cause for significant individual and collective performance issues are identified; Ensure that completed corrective actions to address and preclude repetition of performance issues are timely and effective; Ensure that planned corrective actions to preclude repetition direct timely and effective actions to address and preclude repetition of significant individual and collective performance issues; and Independently determine if safety culture traits caused or significantly contributed to the individual and collective performance issues.

The inspectors reviewed and selectively challenged aspects of the licensees problem identification, causal analyses, and corrective actions in response to crossing the Yellow threshold for the Unplanned Scrams per 7000 Critical Hours Performance Indicator in 2020.

The inspectors independently assessed the extent of condition and extent of cause, and whether safety culture components caused or significantly contributed to any significant performance issues.

The inspectors used the criteria in Inspection Procedure (IP) 95002 when evaluating each objective above. The inspectors evaluated any identified gaps (or weaknesses) in the licensees causal analyses and corrective actions to characterize their significance and to drive any additional necessary licensee actions. In accordance with Inspection Manual Chapter (IMC) 2515, Appendix B, a Weakness is defined as a deficiency associated with licensee actions to identify the causes of performance issue(s) and to preclude repetition. There are three levels of weaknesses with increasing significance:

1) Minor Weakness: A weakness or omission that may warrant informal licensee engagement by inspectors but screens as a non-finding and non-violation.

2) General Weakness: A weakness or omission that is of enough importance to

(a) warrant licensee engagement by inspectors;

(b) be screened as an issue of concern using IMC 0612;

(c) be documented using IMC 0611; and

(d) inform NRC licensee Problem Identification and Resolution (PI&R) assessments.

3) Significant Weakness: A weakness or omission associated with licensee actions to identify the causes of performance issue(s) and to preclude repetition which does not provide the level of assurance required to meet supplemental inspection objectives and requirements. Until resolved or sufficiently mitigated, it precludes satisfactory completion of a supplemental inspection. Significant weaknesses warrant prompt licensee and NRC management engagement.

Supplemental Inspection Response to Action Matrix Column 3 (Degraded Performance) Inputs

=

(1) Overall, the inspectors determined that the licensees problem identification, causal analysis, and corrective actions sufficiently addressed the performance issues that led to the Yellow performance indicator. The team concluded that all inspection objectives were Met. Notwithstanding this outcome, the team identified four General Weaknesses which are described later in this report. Any planned corrective actions to preclude repetition (CAPRs) that were not complete at the time of the inspection will be reviewed during follow-up baseline inspection activities.

There were five individual scram events in 2020 that led to the Yellow performance indicator:

1. On May 25, 2020, the plant experienced a turbine trip and reactor scram due to erroneous overspeed signals from two out of three of the active speed probes on the main turbine shaft.

2. On August 8, 2020, operators inserted a manual reactor scram in response to main turbine high pressure control valve oscillations due to a loose threaded connection for the linear variable reluctance transmitter (LVRT) associated with that valve.

3. On August 24, 2020, while operators were starting up the unit from a forced outage, the reactor experienced an automatic scram caused by a low reactor vessel water level. The low water level was due to the reactor feedwater pump B minimum flow valve failing closed as a result of a failure of its valve positioner.

4. On November 6, 2020, an automatic turbine trip and subsequent reactor scram resulted from a low primary water system (PWS) flow to main generator bushing C trip signal due to gas voiding in the PWS that degraded water flow and increased instrumentation noise.

5. On December 11, 2020, an automatic turbine trip and subsequent reactor scram was caused by the PWS tank level lowering below its trip setpoint after an operator improperly controlled the valve used to fill the tank.

Objective 1: Ensure that the root and contributing causes of significant individual and collective performance issues are understood.

The team reviewed the licensees root cause evaluation for each of the five unplanned scram events and the broader common cause evaluation. Evaluation criteria under this objective included: determining when and for how long the identified performance issues existed; assessing prior opportunities to identify these issues; understanding the plant significant consequences of the events; ensuring the causes were determined using a systematic process with a sufficient level of supporting detail; consideration of prior knowledge of operating experience; and identification of any potential programmatic weaknesses in performance.

NRC Assessment: The team concluded that this objective was Met. Overall, the licensee appropriately identified the issues that led to the scram events, how long they existed, what their associated risk and compliance consequences were, and if prior opportunities existed to identify them. In general, the licensee appropriately evaluated the causes of the events using a systematic process with a sufficient level of supporting detail to identify the root and contributing causes and to identify any potential programmatic weaknesses in performance. There were also two General Weaknesses and several observations related to this objective.

General Weakness No. 1: The team identified a General Weakness associated with prior opportunities to implement effective corrective actions to preclude repetition of events. In 2018 and 2019, the licensee implemented corrective actions to prevent recurrence (CAPRs) for the previously identified decline in plant performance that included reviewing engineering changes/modifications to ensure established processes and procedures were followed with a high level of technical rigor. The licensee initially determined that the turbine control system (TCS) modification being implemented in the upcoming refueling outage (Spring 2020) would serve as an opportunity to implement these CAPRs. However, the licensee did not review the TCS modification as part of the 2018/2019 CAPRs at the time they were completed. When the licensees effectiveness review later identified that the station had not applied the CAPRs to the TCS modification, an additional corrective action was generated and completed which applied the CAPR-driven design reviews to the modification.

However, this corrective action was not completed with the appropriate level of rigor to identify the deficiencies associated with the TCS modification that later revealed themselves and resulted in scrams.

The repetition of scram events, effectively due to the same root cause(s), was a significant condition adverse to quality that resulted from a lack of engineering rigor and a failure to ensure the adequacy of a major system design change (i.e., the TCS modification). The previously established CAPRs, as described above, were in place specifically to prevent this outcome, but failed to do so. While the licensees evaluations determined these previously established CAPRs were effective, the NRC inspection team concluded otherwise. Specifically, the TCS modification, a modification intended to correct the causes of prior GGNS scrams (a previous CAPR), was deficient. Further, as noted above, the station inappropriately excluded (screened out) the TCS modification from the CAPR-prompted reviews that would have initiated a reexamination of that engineering change for technical adequacy. Had this reexamination been performed, it may likely have prevented some of the 2020 scrams. The NRC team discussed this General Weakness with the licensee during the inspection activities and it is documented as a non-cited violation in the Results section of this report.

General Weakness No. 2: The team identified a General Weakness associated with the licensees implementation of their Operating Experience (OE) Program. Specifically, the inspectors determined that the licensee did not identify available OE information prior to several of the scrams, and that these missed opportunities to leverage OE to prevent the scrams were potential common and/or individual contributing causes. The inspectors concluded that sufficient information was available for the licensee to have prior knowledge of the conditions that either caused or contributed to some of the events and, more importantly, that actions were not taken or planned to address those conditions.

One example was related to the May 25, 2020, event which resulted from the GGNS staff not identifying changes to the speed sensor air gap setting (a critical parameter) as part of the TCS design modification. As required by Entergy Procedure EN-DC-115, Engineering Design Change Process, Revision 31, engineering change packages needed to include a relevant OE search and applicable actions to ensure similar errors would not occur. In the root cause evaluation for this event, the licensee found OE from Braidwood and San Onofre where turbine control system issues occurred due to similar errors in the speed sensor air gap setting. As such, the licensee determined that the May 25 event was OE preventable (i.e., if the licensee had appropriately evaluated and acted on the identified OE the cause of the scram would not have occurred). However, the licensee did not identify the failure to assess and act upon pertinent OE information as a root or contributing cause in their causal evaluation for this event.

A second example relating to the General Weakness identified for implementation of the OE program involved the August 24, 2020 event. Entergy Procedure EN-MA-106, Work Planning, Revision 1, required that relevant OE be identified and included in work packages to ensure quality-related maintenance activities incorporated applicable lessons learned. The licensee identified in their root cause evaluation for this event that the work order to replace the reactor feedwater pump B minimum flow valve did not contain relevant OE that was found during the post-event OE search. As a corrective action to preclude repetition, the work order was updated with the OE to include more intrusive inspections, testing, and validation of proper worker practices prior to installation and prior to system re-start. This OE came from similar failures that occurred at Byron and Turkey Point in the early 2000s. However, the failure to incorporate available OE was not considered to be a potential root or contributing cause for this event.

In conversations with the licensee staff, the team noted that identifying relevant OE after an event can provide valuable information about appropriate corrective actions but misses a key component of a successful OE program (i.e., to leverage available information prior to events to help preclude them from occurring). An OE program is fully successful when it proactively seeks out and identifies information that is then used to recognize and avoid potential problems before they impact the plant.

The inspectors determined that sufficient information was available for the licensee to have prior knowledge of the conditions that either caused or contributed to the events in the examples above. The inspectors further concluded that the licensee did not fully evaluate the inadequate implementation of their OE program as potential root or contributing causes for either of these events, or more holistically during their common cause review. The inspectors also conducted interviews with the corporate and site OE specialists and identified further areas for enhancement within this program, including targeted training and independent auditing for quality. Therefore, the team concluded that the issues with the OE program were programmatic in nature and that this deficiency was determined to be a General Weakness.

The teams detailed assessment of this inspection objective included the following:

a. Identification. All five of the events were judged to be self-revealing as documented in the individual licensee root cause evaluations. The inspectors determined that this characterization was appropriate based on reviewing the causal evaluations and operations logs. In all five events, the self-revealing equipment deficiencies led to plant scrams.

The inspectors determined that the licensee appropriately assessed the exposure time for the issues associated with the five events. The main turbine control and protection system was upgraded during a scheduled refueling outage in spring 2020. The licensee determined that four of the five events were directly related to this modification and all the events occurred post-installation. The one event not associated with the TCS modification (i.e., the August 24, 2020 feedwater valve failure) was determined to be caused by a faulty positioner installed during a scheduled preventive maintenance activity.

The inspectors determined that the licensee did evaluate for missed opportunities to identify the conditions. However, the team identified an example where the licensee missed opportunities for prior identification, evaluation, and resolution of some issues that caused the scrams. This was determined to be a General Weakness and was related to effectively using the corrective action program (CAP) to preclude repetition of scram events as described above under the NRC Assessment section.

b. Risk and Compliance. The licensees individual event root cause evaluations and the overall common cause analysis included discussions of general safety of the public, nuclear safety, radiological safety, and environmental safety and stated that no actual consequences resulted from the events. The licensee further concluded that the potential risk significance of the individual events was low because the scrams were uncomplicated and sufficient redundancy in mitigating systems was available to ensure safe shutdown and long-term cooling of the reactor. The inspectors determined that the licensee appropriately understood the risk and consequences associated with the individual scram events.

The licensee conducted, as part of their common cause analysis, an aggregate review of the risk associated with the five scram events in 2020. All of these scrams were classified as transients with the main condenser (heat sink) available. As a result, the licensee increased the frequency of those transient initiators in the probabilistic risk assessment (PRA) model from 0.831/reactor year to 5/reactor year. All of the other initiating event frequencies were kept at the frequencies calculated in the PRA model.

Using these inputs, the licensee calculated that the aggregate risk of the five scrams had a change in Core Damage Frequency (CDF) of 7.16E-07 / reactor year. The licensee concluded that this modeling result indicated that, while the overall aggregate risk remained relatively low, the aggregate impact of the events resulted in a change in CDF to approximately double that of the baseline risk.

An NRC senior reactor analyst (SRA) conducted an independent review of the five unplanned scrams that occurred at GGNS and determined that the licensees aggregate risk assessment was appropriate. All plant transients at an operating reactor facility create opportunities for failure of the installed mitigation systems and therefore increase risk. The SRA noted that all GGNS mitigation systems responded as designed following the May 25, 2020, August 24, 2020, November 6, 2020, and December 11, 2020, scrams. Therefore, the increase in risk was represented by the conditional core damage probability of 3.00E-07 as quantified by the GGNS-specific Standardized Plant Analysis Risk (SPAR) model, Version 8.59. On August 8, 2020, licensed operators manually scrammed the plant when a failed high-pressure control valve was causing power oscillations in the reactor. Thirty minutes after the manual scram, the failure of a startup feedwater level control valve resulted in an automatic scram signal when reactor vessel water level went below the low-level scram setpoint. To bound the risk of this event, the analyst quantified the conditional core damage probability of a loss of main feedwater initiating event (1.88E-06).

The analyst noted that the industry average scram rate for boiling water reactors was about 0.8/year with the 95th percentile of about 1.1/year. In contrast, GGNS experienced approximately 7.5 scrams per year during the 8 months following the refueling outage.

To better understand the aggregate risk of the five unplanned scrams, the SRA used the GGNS experience over the 8 months in question and increased the transient initiating event frequency to 6.0/year and the loss of main feedwater initiating event frequency to 1.5/year. The result from the SPAR model was a change in CDF of 4.35E-06/year. Like the licensee, the NRC analyst concluded that this indicated an increase of approximately double the SPAR baseline of 2.43E-06.

During their review for any challenges to regulatory compliance under this objective, the inspectors identified some regulatory compliance concerns associated with the causes of the events which are described in more detail in the Results section of this report.

c.

Methodology. The inspectors concluded that the licensees individual root cause evaluations were conducted at a level of detail commensurate with the significance and complexity of the events. For each of the five individual scram events, the licensee used several methodologies and analytical techniques to identify the root and contributing causes of the events. These techniques included: failure modes analyses, equipment failure evaluations, barrier analyses, why staircases, event and causal factor charting, comparative timelines, human performance evaluations, and organizational and programmatic evaluations. In general, the team determined that the licensee employed a systematic and evidence-based analysis, using the multitude of techniques mentioned above, to consistently determine the root and contributing causes of the performance issues that led to the scrams.

The inspectors noted that in a few of the evaluations the licensee did not describe in sufficient detail why potential causes were eliminated or not fully considered. One example involved the licensees evaluation of August 24, 2020, reactor feedwater pump trip. The licensees final root cause was that the reactor feedwater pump B minimum flow valve positioner experienced an early failure because it was only in service for approximately 29 hours3.356481e-4 days <br />0.00806 hours <br />4.794974e-5 weeks <br />1.10345e-5 months <br /> after a preventive maintenance change-out activity. However, the licensee did create a corrective action to preclude repetition (CAPR) for the event which included revising the work instructions for installation of this and similar valve positioners to conduct a number of inspections and verifications prior to putting the valve back in service. Based on this, the inspectors questioned whether the valve positioner failure was in fact an early failure or if it could have been caused by maintenance work practices. From these questions, the inspectors discovered that the root cause was changed throughout the review and challenge process. The initial root cause was an inadequate replacement of the valve positioner installed during the preventive maintenance activities. Based on the CAPR and other corrective actions, which included enhancing the receipt inspection process, and the post-failure data provided in the failure analysis report, the inspectors determined that this root cause appeared to be more appropriate and better aligned with the actions the licensee was taking to address the event. This issue was determined to be of minor significance because the CAPR and corrective actions taken in response to the event were considered appropriate to address the root cause and prevent recurrence of the issue.

Another example was related to the December 11, 2020, event in which the inspectors determined that the licensee did not sufficiently emphasize the human performance aspects associated with the event. Several human performance barriers broke down which caused and/or contributed to the scram. The inappropriate manipulation of plant equipment, outside of procedural guidance, and without utilizing the proper questioning attitude for system operation, greatly exacerbated the event and are described in more detail as a non-cited violation in the Results section of this report. The inspectors determined that the significance of these human performance breakdowns was not sufficiently described or addressed in the root cause evaluation. The actions to address the human performance aspects of this event were narrow in scope, only focusing on the crew that was involved in the event, and only focused on use of the procedure for the primary water system evolution. The lack of detail associated with this aspect of this event was shared as an observation with the licensee, where it was discovered by the inspectors that additional actions were being taken to address a decline in human performance in the operations department. This information, however, was not provided in the root cause evaluation or as part of the supplemental information to the team. It was also discovered that these actions were being taken due to several other human performance issues within the department that had occurred after the December 11, 2020, scram. The fact that additional errors occurred, and subsequent licensee actions were deemed necessary, bolstered the inspectors observation that the licensee had not fully evaluated operator performance deficiencies in their root cause evaluation for the December 11 event.

d. Prior Opportunities and Operating Experience. For the five individual scram events and the common cause analysis, the licensee included an evaluation of internal and external OE. For some of the events, this search yielded multiple examples where the licensee potentially missed opportunities to apply actions from OE throughout the nuclear industry to, at a minimum mitigate, if not prevent, some of the events from occurring. The team determined this was a General Weakness associated with the licensees implementation of their OE program as described under the NRC Assessment section above.

The team also shared an observation with the licensee for prior occurrences of human performance behavior gaps in the operations department that significantly contributed to the December 11 event. This specific human performance issue is documented in the Results section as a non-cited violation. This event, however, was not the only example of a decline in the usage of human performance tools to prevent errors by operators.

Approximately 6 weeks prior to the December 11 event, the operations department experienced a clearance and tagging error, where the wrong valve was tagged for a work activity. The licensee took narrowly scoped actions that primarily involved conducting observations of the clearance and tagging program and did not evaluate or correct the human performance behaviors associated with the event. Also, in July 2020, operations personnel identified that the primary water system (PWS) leakage water return valve, the valve that locked out during the December 11 event, had become stuck closed. Minimal questioning attitude (a human performance behavior attribute)was applied during the CAP response to this issue to determine why it occurred and what the risk impact would be if it malfunctioned again. The condition report was closed as a broke/fix item.

e. Common

Cause.

The licensee conducted a common cause analysis for the five individual scram events in 2020. This analysis reviewed the events in aggregate, the causes of those events, and any potential programmatic weaknesses. The licensee performed a variety of streaming analyses (a common root cause evaluation tool used to align and evaluate data) and evaluation methodologies to determine a common root cause and contributing causes for the 2020 events.

The licensee-established common root cause was identified as Entergy Engineering Leadership (Corporate Projects and Site Engineering) did not fully align the organization around roles and responsibilities for the Turbine Control System modification missing an opportunity to provide greater rigor to the design change. A contributing cause for the common cause was identified as Engineering Leadership has not fully enforced standards for design changes which require validation of technical adequacy, protect design and operating margins, ensure plant interfaces are fully evaluated, and quality of equipment or parts installed perform as expected. Both causes address programmatic issues within the engineering organization associated with the engineering design change process. These causes emphasize the need to properly implement, with a sufficient level of rigor and technical adequacy, the modification process and ensure thorough reviews of the design change products are conducted by licensee supervisory staff.

Another contributing cause was determined to be Station personnel have at times exhibited complacent behaviors related to aspects of generation risk during implementation of the CAP to fully mitigate some precursor incidents. This cause identified programmatic weaknesses in the CAP where significant issues associated with generation risk had not been fully evaluated and resolved - as self-revealed in the five individual scram events in 2020.

While the licensee did document several programmatic weaknesses as part of their analyses, the inspectors identified additional programmatic issues that the licensee did not recognize. These included the effective use and implementation of the OE program and the CAP, specifically as it pertains to comprehensiveness of evaluations and the timely and effective resolution of identified issues. The inspection team also determined that additional licensee emphasis could be placed on improving human performance behaviors, including some of the specific areas mentioned in the Safety Culture section later in this report. The inspectors shared these observations with the licensee to evaluate for any additional actions to implement moving forward.

Objective 2: Independently assess and ensure that the extent-of-condition and extent-of-cause of significant individual and collective performance issues are identified.

The inspectors independently sampled the licensees assessments to ensure they sufficiently and comprehensively addressed extent-of-condition and extent-of-cause. The goal of the extent-of-condition review was to ensure the licensees evaluation was of sufficient breadth and depth to identify issues similar to those for which the supplemental inspection was performed.

The goal of the extent-of-cause review was to ensure that the licensees evaluation was of sufficient breadth and depth to identify other plant equipment, processes, or human performance issue that may have been impacted by the root causes of the performance issues.

NRC Assessment: The team concluded that this objective was Met. Overall, the licensee appropriately identified the extent-of-condition and extent-of-cause for the performance issues.

There was one General Weakness related to this objective.

General Weakness No. 3: The team identified a General Weakness with the scope of the licensees extent-of-condition and cause reviews. The inspectors found that the licensees reviews excluded potentially risk-significant systems and components that could be impacted by the engineering design change process deficiencies and overall organizational gaps revealed through the five individual scram events. In the analyses performed for the individual events and the common cause, many of the extent-of-condition reviews focused on the TCS modification and plant equipment or process issues that would screen as high risk to electrical power generation. The inspectors conducted their independent assessment by applying the licensee-identified condition or cause to other nuclear safety and risk-significant equipment or processes. The inspectors deemed this to be appropriate because the overriding concern of ensuring nuclear safety extends beyond electrical power generation risk significant items. The inspectors also determined that the underlying causes of the decline in licensee performance revealed by the 2020 scram events could also be present in safety-related equipment and processes necessary for transient mitigation.

One example of this weakness was revealed during the inspectors review of recent design changes to the sites emergency diesel generators (EDGs). In the first half of 2021, the licensee replaced sub-covers (EDG cylinder boundary and support components) for both EDG divisions.

These modifications were not screened as being risk significant per the licensees Technical Task Risk and Rigor (Procedure EN-HU-104) process and hence were not included in the licensees extent-of-cause reviews as they related to reviewing in-process or completed engineering changes. The inspectors identified several gaps during their review of the modification packages, including one case in which an EDG modification package was classified as being non-safety related. This was an incorrect classification based on the component classification of the EDGs and the subcover assemblies (all safety-related). Also, there were missing critical parameters from the Division II EDG table that later led to system operation challenges post-installation (discussed in more detail in the corrective actions section). Additionally, the risk calculation, per the Procedure EN-HU-104 process, was incorrect. Finally, none of these issues were identified by the licensees process including their review board.

This General Weakness included several other examples where the inspectors determined that the licensees scope of the extent-of-condition or extent-of-cause reviews was limited. For the August 8, 2020, event, the inspectors identified that the licensee did not evaluate the potential impacts of vibration on equipment already installed in the plant that was unrelated to the TCS.

Instead, the licensee focused on components that could have been affected by the TCS modification. For the November 6, 2020, event, the inspectors determined that the licensees scope of reviewing the alarm response instructions (ARIs) should have been expanded to include systems outside of the PWS. By conducting a small sampling of licensee procedures, the team identified several ARIs that contained instructions of a similar level of detail that was considered deficient in the ARIs for responding to the PWS alarm. These ARIs were associated with other nuclear safety significant systems. The same potential cause existed in these procedures that potentially could lead the operators to respond in a similar manner to a different alarm indication and could cause adverse system impacts. Finally, the inspectors identified that the common root cause (i.e., engineering leadership didnt ensure proper roles and responsibilities) extent-of-cause and extent-of-condition only reviewed major modifications in progress across the Entergy fleet at that time. This was a small sample of only three projects and none of those projects were in-progress at GGNS. The inspectors shared this observation with the licensee for their consideration to expand their sample size.

The teams detailed assessment of this inspection objective included the following:

a. Extent-of-Condition and -Cause. The team reviewed the licensees extent-of-condition evaluations which were performed individually for each of the five scram events and collectively for the common cause analysis. These evaluations involved extending out many of the conditions to other high-risk components within the TCS. For the May 25, 2020, event, the condition of the speed sensor gap setting being inaccurate was reviewed for other components installed as part of the modification to validate their design settings were correct. For the August 8 event, the condition of the main turbine control valve actuator having a loose threaded rod was reviewed for all other hydraulic actuator assemblies installed as part of the upgrade. For the August 24 event, the condition reviewed was foreign material intrusion into similar valve positioners for conditional single point vulnerabilities such as the other reactor feedwater pump minimum flow valves and startup level control valves. For the November 6 event, the condition reviewed was potential design deficiencies with other PWS flow transmitters that could have been impacted by the system modification. Finally, for the December 11 event, the condition reviewed included proper operation and response of other equipment used during a tank fill evolution for the PWS. Corrective actions included performing a TCS modification vulnerability study to identify any additional latent design change issues, reviewing operator single point vulnerabilities within the PWS, and reviewing critical balance of plant systems for generation risks.

The team reviewed the licensees extent-of-cause evaluations which were performed individually for each of the five scram events and collectively for the common cause analysis. These evaluations involved extending many of the causes to examine other major projects underway to ensure the critical parameters were identified, the proper level of oversight and reviews were assigned, and that any latent design issues were found for the TCS upgrade modification. For the two issues related, at least in part, to operations performance, the causes were extended to look at other ARIs for the PWS and other operational challenges that may have previously been captured in the CAP for the PWS. For the August 24 event, the reactor feedwater minimum flow valve failure, there was not an extent-of-cause evaluation performed because the licensee deemed it to be an early failure. Corrective actions included steps to establish, enforce, and monitor the effectiveness of changes to the fleet process for engineering design changes, specifically as they related to major modifications and/or projects involving contractors.

Objective 3: Ensure that completed corrective actions to address and preclude repetition of performance issues are timely and effective.

The inspectors determined if the completed licensee-identified corrective actions to preclude repetition (CAPRs) were appropriate and included a plan for timely implementation. The inspectors then reviewed implementation of those actions to ensure they were completed according to the plan, commensurate with their significance. For those CAPRs that included effectiveness reviews (either interim or final) already completed at the time of the inspection, the inspectors verified that the licensee had established actions which included proper quantitative and/or qualitative measures of success. The inspectors also reviewed a sample of corrective actions taken for contributing causes and extent-of-condition/extent-of-cause actions. These actions were evaluated for appropriate prioritization for implementation and to ensure they adequately addressed the issues identified. The following table details the completed CAPRs:

Cause CAPR May 25, Root Cause 1: CAPR 1 [Revised in response to NRC Entergy Engineering Leadership (Corporate concerns]: Revise Procedure EN-HU-104, Projects and Site Engineering) did not Technical Task Risk & Rigor, to require ensure critical assumptions in the TCS creation of a detailed table listing risk modification were documented or validated parameters (setpoints, settings, for turbine shaft movement during operation dimensions) being revised for engineering where a reduction in margin was present in changes (ECs) with high consequence accordance with Procedure EN-DC-115, generation or multiple train (common mode)roles and responsibilities were not well or single train safety-related system risk.

communicated across organizations, and Table is to list the old parameter, new, and Cause CAPR leadership behaviors were lacking to basis for acceptability. This table would promote sufficient challenge to achieve an then be presented for mitigating actions acceptable result to prevent an unplanned such as Independent Third-Party Reviews scram.

(ITPRs), Engineering Quality Review Team (EQRT), and challenge board.

[Revision 12, Completed 9/13/2021]

Note: inspectors were unable to inspect implementation of the CAPR since it was revised in response to the NRCs questions at the end of the inspection - this action is also in the Planned CAPR section for follow-up August 8, Root Cause 2: CAPR 3: Revise Procedure EN-MP-100, Engineering leadership (Corporate Projects Critical Procurements, to incorporate and Site Engineering) did not ensure full requirements to document and track implementation of Entergy processes as specific methods utilized to verify critical intended to verify vendor quality of the valve characteristics are met. [Complete]

actuator assembly fabrication, installation coordination of work activities, vendor work planning, control of work activities performed by supplemental vendor support on-site through execution phase by supplemental support.

August 24, Root Cause 1: CAPR 4: Implement work instructions Reactor feed pump B minimum flow valve (such as a new maintenance procedure or positioner installed during preventive model work order) for those air operated maintenance activities failed due to infant valves (AOVs) using ABB/Bailey AV1 or mortality within approximately 29 hours3.356481e-4 days <br />0.00806 hours <br />4.794974e-5 weeks <br />1.10345e-5 months <br /> of AV2 series positioners to inspect the service.

positioners prior to installation. [Complete]

November 6, Root Cause 1: CAPR 5: The sensing lines for all primary Entergy engineering leadership (Corporate water flow transmitters were walked down Projects and Site Engineering) made and those that were determined to require changes to the design of the primary water modification to obtain the proper slope bushing flow instrumentation loop without per JS02 were changed appropriately.

fully evaluating the impacts of the changes Replaced tubing to the three bushing flow to the instrumentation feedback quality and transmitters. Added test valves to allow existing operating margins to a generator backfilling the bushing, rotor, and stator trip.

flow instruments. [Complete]

CAPR 6: Increase primary water flow transmitter damping and trip time delay.

[Complete]

CAPR 7: Raised the low bushing flow alarm setpoint from 29.8 to 31.5 gpm to provide advanced notification of a degrading flow. [Complete]

December 11, Root Cause 1: Entergy *Reference CAPR 1 engineering leadership (Corporate Projects and Site Engineering) established a design Cause CAPR for the leakage water return valve control logic which was not fully understood and had impacts that changed the operation which were not desired in the TCS modification resulting in an automatic plant trip.

December 11, Root Cause 2: The CAPR 9: Perform training for licensed and operating crew lacked adequate knowledge non-licensed operators on the operation of of the primary water system to control and valve N43FD01 and how the primary water stabilize the leakage water standpipe level.

system should respond during head tank addition, and on overall operation of the primary water system. [Complete]

Common Cause, Root Cause 1: Entergy CAPR 10: Develop and implement a Roles engineering leadership (Corporate Projects and Responsibility Matrix to be used to and Site Engineering) did not fully align the establish, communicate, and track specific organization around roles and requirements for each participating responsibilities for the turbine control system individual through each portion of the modification missing an opportunity to modification process. [Complete]

provide greater rigor to the design change.

NRC Assessment: The inspection team concluded that this objective was Met. However, the team did identify several gaps in the area of corrective actions associated with programmatic deficiencies identified in the CAPRs, corrective actions, and effectiveness reviews. There was one General Weakness and several observations related to this objective.

General Weakness No. 4: The team identified a General Weakness associated with the licensees CAPRs. Specifically, the inspectors determined that one of the licensees primary CAPRs (Original CAPR 1, not displayed in the table above) would not address process deficiencies in the engineering design change process in systems/components other than those that would be categorized as high risk to electrical power generation. This CAPR made significant revisions to the licensees processes but did not adequately address the root causes of the issues. It excluded nuclear safety and risk-significant equipment from the scope of the CAPR. The licensee could experience a repeat event due to engineering design change gaps that could lead to improper modifications. Additionally, the licensee used this CAPR as a process entry point for other CAPRs and its deficiencies could have led to those CAPRs being ineffective as well.

Based on the initial assessment of CAPR 1 and the potential impact that gaps in that CAPR would have on other CAPRs, the team initially considered this issue to be a Significant Weakness. Specifically, CAPR 1, as originally written, was listed as Revise EN-HU-104, Technical Task Risk & Rigor, to require creation of a detailed table listing generation risk parameters (setpoints, settings, dimensions) being revised for Engineering Changes (ECs) with high generation risk. The inspectors questioned why this CAPR wasnt also applied to nuclear safety and risk-significant engineering changes that didnt contribute to electrical power generation risk (i.e., mitigating systems).

As stated, the changes made to improve Entergy Procedure EN-HU-104 did not apply to most ECs having nuclear safety risk. Although Attachment 9.1 of that procedure acknowledged a nuclear safety risk impact on multiple trains of safety-related systems, the highest consequence risk screening which could be assigned was 'Medium. As a result, CAPR 10, the Roles and Responsibilities Matrix (aka RACI process), to improve accountability and ownership of design changes would not be implemented. This led the inspectors to question the effectiveness of the CAPRs to prevent repeat events that could result in challenges to the reliability of safety-significant equipment and unplanned transients on the plant.

A supporting example for this process observation was identified during the extent-of-condition/cause reviews. The inspectors reviewed EC 83472 and CAPR 1 as it related to the Division II emergency diesel generator (EDG) sub-cover replacement. The inspectors noted during this review that the function of the rocker arm shaft plugs was not identified by engineering personnel as a critical design parameter for the modification. As a result, EDG rocker arm shaft plugs were not procured and installed during the sub-cover modification installation in January 2021. During post-installation and subsequent surveillance testing of the Division II EDG, in March of 2021, a low lube oil pressure alarm was received, and a downward trend in lube oil pressure was noted that extended back to January 2021. The licensee-identified failure mechanism was the absence of rocker arm shaft plugs. While this issue was determined by the inspectors to be of minor safety significance since the EDG maintained its safety function, it highlighted the importance of applying CAPR actions to improve engineering technical rigor to safety-related equipment. This condition, or something similarly missed during the modification, had the potential to cause a higher consequence, especially for this high safety and risk significant equipment. This engineering change was copied and prepared to be installed on the other division EDG not long after the March 2021 event. If this issue hadnt self-revealed, a common mode failure could potentially have resulted.

After discussing this concern with licensee staff, CAPR 1 was revised to the language that is listed in the above table (Revised CAPR 1), which included adding multiple train (common mode) or single train safety-related system risk. This revision was incorporated into Entergy Procedure EN-HU-104 in Revision 12, dated September 13, 2021. After reviewing the revised CAPR and associated corrective actions, the inspectors determined that the new actions would sufficiently address the vulnerability originally identified with implementation of the process.

Specifically, the change to include high risk significant, safety-related systems as high risk items in Procedure EN-HU-104 ensured that the responsible engineer would create the critical parameters table for the associated design change and that the table would be reviewed by the Engineering Quality Review Team. The inspectors concluded that this change would also drive the licensee to utilize the new RACI process (responsibility and accountability tool - CAPR 10)for the same level of high-risk significant modifications. The inspectors determined that this action adequately addressed their concerns that the original CAPRs may not have been fully effective at ensuring individuals understand their roles and responsibilities and capture critical information with the appropriate level of technical rigor for modifications that have the potential to cause significant impacts on the plant (whether they are high electrical power generation or scram risk, or high safety system reliability risk). However, at the conclusion of the inspection activities, the CAPR was not yet implemented (i.e., had not been used for any engineering changes) and the associated effectiveness review plan was still being developed based. As such, the NRC plans to review these items during future follow-up inspection activities. Based on the licensees changes to the CAPR, the team reclassified the gaps identified in the corrective actions area as a General Weakness.

The teams detailed assessment of this inspection objective included the following:

a. Completed Corrective Actions to Preclude Repetition (CAPRs). The licensee, through their causal evaluation process for the five individual scram events and the common cause analysis, identified multiple root causes and CAPRs. The inspectors reviewed the CAPRs to determine if they appropriately addressed the identified root causes and contained a thorough plan for implementation. The inspectors then reviewed implementation of those actions to ensure they were completed according to the plan and done so in a timely manner, commensurate with their significance. For those CAPRs that had effectiveness reviews (either interim or final) already completed, those completed effectiveness reviews were evaluated to ensure the actions had proper quantitative and/or qualitative measures of success, and that they had been completed satisfactorily. The table above lists the identified root causes, the associated CAPR(s),and completion information for those CAPRs already completed at the time of the inspection. The table in the next section lists the open CAPRs that had not yet been completed at the time of the inspection. CAPR 1 is listed in both sections because of the initial completion of the action at the beginning of the NRC inspection; however, based on NRC concerns, it was revised and recategorized as an open item to inspect those revisions and implementation.

As mentioned in the NRC Assessment section above, the team identified one General Weakness for gaps identified in the implementation of some of the CAPRs. The team also shared several observations with the licensee related to this area. For example, the team observed that CAPRs 1, 3, and 10 relied heavily on the knowledge of individuals constructing the procurement table, critical parameters table, and/or the responsibilities matrix. The inspectors noted that there were very few corrective actions to address self-revealed gaps in staff knowledge identified following many of the scram events. Without ensuring the proper information is included and used in these process tools, they may not be effective. The team acknowledged that licensee staff had instituted additional actions for station management review that could help identify errors in the process tools. However, the team observed that more actions could be taken to improve the training and knowledge of the personnel that use these tools to further enhance their effectiveness.

b. Other Key Completed Corrective Actions. In addition to the CAPRs, the licensee created plans for corrective actions to address the contributing causes and extent-of-condition/extent-of-cause for each individual scram event and the common cause analysis. As with the CAPRs, many of these actions spanned multiple causes. One key area the inspectors reviewed was associated with actions related to improvements for the corrective action program (CAP). Corrective action program deficiencies were referenced in the common cause evaluation and the May 25, November 6, and December 11 event evaluations as contributing causes. Corrective actions included:

analyzing the staffs ability to identify high risks and taking action to mitigate those risks; reinforcing risk assessment requirements to the Performance Review Group (PRG) and engineering / operations management; performing independent observations of PRG and pre-PRG meetings using a revised what-it-looks-like (WILL) sheet; reviewing mitigation plans for conditional single point vulnerabilities (SPVs) and eliminate conditional SPVs during maintenance; reviewing condition reports since the 2020 refueling outage for trip risks; and verifying system monitoring plans to identify degrading trends. Another key set of actions was associated with licensee oversight of supplemental workers. The licensee implemented actions to provide a greater level of oversight for supplemental workers prior to their arrival on-site as well as during their work activities. These actions also included more thorough and detailed reviews of third-party work products as part of the Owner Acceptance Review process.

Other important corrective actions the inspectors reviewed included actions for extent-of-condition and extent-of-cause. As previously mentioned, many extent-of-condition actions focused on verifying and/or correcting similar/same conditions within the TCS.

These actions included activities such as valve positioner inspections and enhancements, correcting flow transmitter design issues for the primary water system, performing a vulnerability study and enacting mitigating actions for deficiencies identified within the TCS, and addressing vibration-induced equipment impacts. The extent-of-cause actions related to improving the engineering design change process, implementing the prescribed CAPRs (listed above), and providing additional oversight for engineering change activities. An example of these actions included reviewing in-process and/or completed major modifications throughout the fleet against the new Procedure EN-HU-104 process and identifying any gaps in those design changes prior to implementation. These reviews also included utilizing the new Critical Procurement table and Critical Parameter table as part of those project plans. These same actions to create more detailed and thorough project plans were expanded to include other third-party projects and additional oversight for those projects.

The team evaluated these other key corrective actions to ensure they adequately addressed the issues identified and were appropriately prioritized for implementation. In general, the actions that were already completed appeared to be effective at resolving the associated issues. The inspectors shared some observations with the licensee in this area which focused on ensuring proper supporting documentation for closure of these actions, proper traceability of actions, and timely resolution. One example related to the December 11 event, in which a work order to correct the flawed control system logic was not properly coded as being related to a root cause evaluation and was cancelled and transferred to another work order. This new work order was not coded to track the resolution of this corrective action as it related to the root cause evaluation.

Without proper coding, these work orders could be inappropriately changed or cancelled, and actions that were credited in the corrective action plan for the scram event could potentially not be completed.

Objective 4: Ensure that planned corrective actions to preclude repetition direct timely and effective actions to address and preclude repetition of significant individual and collective performance issues.

The inspectors reviewed the licensees plans for the not-yet-completed CAPRs. These plans were reviewed to ensure appropriate level of detail, timeliness, and their potential for effectiveness. Additionally, the effectiveness review plans associated with each CAPR were reviewed to ensure the planned actions were appropriate and had proper quantitative and/or qualitative measures of success. A follow-up inspection plan will be developed to ensure timely and appropriate implementation of the actions during a future NRC baseline inspection. The table below lists the planned CAPRs:

Cause CAPR May 25, Root Cause 1: CAPR 1: Revise Procedure EN-HU-104, Entergy engineering leadership (Corporate Technical Task Risk & Rigor, to require Projects and Site Engineering) did not ensure creation of a detailed table listing risk critical assumptions in the TCS modification parameters (setpoints, settings, dimensions)were documented or validated for turbine shaft being revised for ECs with high consequence movement during operation where a reduction in generation or multiple train (common mode) or margin was present in accordance with single train safety-related system risk. Table is Procedure EN-DC-115, roles and to list the old parameter, new, and basis for responsibilities were not well communicated acceptability. This table would then be Cause CAPR across organizations, and leadership behaviors presented for mitigating actions such as ITPR, were lacking to promote sufficient challenge to EQRT, and challenge board. [Revision 12, achieve an acceptable result to prevent an Completed 9/13/2021]

unplanned scram.

Note: inspectors were unable to inspect CAPR implementation since it was revised in response to the NRCs questions at the end of the inspection August 8, Root Cause 1: CAPR 2: Implement an EC based on Entergy engineering leadership (Corporate engineering analysis which incorporates design Projects and Site Engineering) did not ensure features to reduce and control the effects of the actuator assembly design was fully vibration on the actuator assembly.

evaluated and the effects of vibration on the Incorporate findings into an engineering equipment in the TCS modification were fully change package and process in accordance evaluated.

with Procedure EN-DC-115. [Due 4/29/2022]

November 6, Root Cause 1: CAPR 8: Complete a permanent design Entergy engineering leadership (Corporate change for the generator bushing primary water Projects and Site Engineering) made changes to flow low trip setpoint to ensure that the proper the design of the primary water bushing flow margin to the trip setpoint is maintained. [Due instrumentation loop without fully evaluating the 6/1/2022]

impacts of the changes to the instrumentation feedback quality and existing operating margins to a generator trip.

NRC Assessment: The team concluded that this objective was Met. Overall, the team concluded that the planned CAPRs appeared to direct the timely implementation of licensee actions to preclude repetition of the events. When complete, the NRC plans to inspect and assess the planned corrective actions to prevent recurrence identified in the table above.

The teams detailed assessment of this inspection objective included the following:

a. Planned Corrective Actions to Preclude Repetition: In general, the team determined these CAPR plans appeared to direct timely implementation and would likely be effective in addressing and precluding repetition of the significant individual and collective performance issues. The inspectors noted that the licensee was planning to implement many of the planned CAPRs during the next refueling outage. For other modifications, the licensee assigned longer due dates because the planned CAPRs would take longer to complete. The inspectors determined this was reasonable based on the conditions and/or processes that caused the five scram events.

The inspectors did not identify any significant deficiencies during their evaluation of the effectiveness review plans. However, the inspectors noted that the effectiveness of the CAPRs are best evaluated after implementation and an appropriate run time. The inspectors also observed that in some cases the licensee had not been sufficiently thorough and critical when assessing CAPR effectiveness. As an example, the inspectors noted that the old interim effectiveness review for the old CAPR 1 (changes to Procedure EN-HU-104), was considered satisfactorily met even though deficiencies were identified with the engineering changes reviewed. In this case, every EC reviewed, where the EC responsible engineer elected to create a critical parameters table (even though not required by procedure), had one or more examples of failure to follow the new process. Since these items were captured in CAP during the review for effectiveness, the licensee considered the CAPR effective. The inspectors disagreed with this assessment of the data based on the process not being effectively used to identify critical parameters and information, as designed.

Objective 5: Independently determine if safety culture traits caused or significantly contributed to the performance issues.

The inspectors independently determined whether the licensees root cause, extent-of-condition, and extent-of-cause evaluations appropriately considered if safety culture components caused or significantly contributed to the performance issues leading to the Yellow PI. The inspectors also reviewed the third-party safety culture assessment that was performed prior to the inspection activities on-site.

NRC Assessment: The team concluded that this objective was Met. Overall, the team concluded that safety culture was appropriately evaluated throughout the licensees causal evaluations and that appropriate actions were taken to address identified gaps. The inspectors also made some observations related to this objective.

The teams detailed assessment of this inspection objective included the following:

a. Safety Culture: The inspectors reviewed the five individual scram root cause evaluations to determine if the licensee appropriately identified the cross-cutting aspects applicable to the causes of each event, as well as the common cause analysis for general licensee performance issues. The inspectors independently assessed the relationship between the safety culture aspects and performance issues identified at GGNS by conducting focus group sessions and individual interviews, observing a Nuclear Safety Culture Monitoring Panel (NSCMP) meeting, evaluating an independent safety culture assessment of the station, and reviewing other causal evaluations, self-assessments, and corrective action documents developed by the licensee.

The inspectors interviewed 104 plant employees including staff-level personnel, supervisors, superintendents, and key managers. Focus group and interview participants were selected from various departments throughout the licensee organization. Focus groups did not combine supervisors with staff-level personnel. The inspectors designed the focus groups and interviews to gather information on the safety culture at the station with questions directed toward specific safety culture aspects.

These questions included aspects such as: leadership safety values and actions, problem identification and resolution, personal accountability, work processes, continuous learning environment, safety communication, respectful work environment, and safety conscious work environment (SCWE).

The NRC defines Safety Culture as the core values and behaviors resulting from a collective commitment by leaders and individuals to emphasize safety over competing goals. There are many traits included in Safety Culture that help to better define core values and behaviors. One such value is Safety Conscious Work Environment or SCWE. This is a work environment in which employees feel free to raise nuclear safety concerns through multiple avenues without the fear of retaliation. The team determined that overall, the station exhibited signs of a positive SCWE.

The team also found that the licensee identified several safety culture attributes associated with the causes of each individual scram event, as well as the common cause(s) that contributed to the overall GGNS performance decline. The inspectors determined that most of these licensee-identified attributes were appropriate; however, they also identified a few additional attributes that the licensee should have considered.

One such attribute, as was previously described as a General Weakness, was in the area of operating experience. Operating experience is a safety culture trait within the area of Continuous Learning. As mentioned earlier in this report, the inspectors determined that the licensee was not effectively implementing the OE program to ensure that valuable information was reviewed and leveraged to preclude avoidable events from occurring.

Another safety culture attribute identified by the inspection team was in the area of Benchmarking (also part of the Continuous Learning area). The inspectors determined that overall, the licensee had an appropriate Benchmarking program; however, it was not applied consistently throughout the organization. The team identified that Benchmarking was predominantly performed solely within the Entergy fleet and the inspectors considered this a missed opportunity to leverage the experience of other organizations within the nuclear industry to identify potential process gaps. The inspectors also determined that rather than using Benchmarking as a tool to improve overall plant and organizational performance to identify and address issues before they became problems at the station, the licensee tended to use it in response to events after the condition had manifested itself.

A third safety culture attribute that the inspectors identified, which was missed in the licensees evaluation, was in the area of Training (also part of Continuous Learning).

Specifically, the inspectors identified a performance gap in the licensees implementation of new processes for knowledge retention and transfer across departments. In particular, the inspectors noted a lack of consistency among departments regarding the application of the licensees Knowledge Transfer and Retention Process (KTRP). The team discussed these safety culture observations with senior management at the station. In most cases, the station had some corrective actions in place that addressed portions of the identified gaps. The station took additional actions to address the teams concerns.

The team shared their overall assessment of safety culture with the licensee during briefings while on-site. Overall, the station demonstrated a successful practice of many of the traits that contribute to a healthy Safety Culture - including SCWE, Questioning Attitude, and a Respectful Work Environment. However, the inspectors noted a general lack of understanding among several licensee personnel, both at the staff and management level, regarding the definition of safety culture. When asked to define safety culture most individuals interviewed provided the definition of a safety conscious work environment (SCWE). The inspectors noted that, while a healthy environment for raising concerns is indeed important, it is only one element of a healthy Safety Culture.

The team emphasized that Safety Culture is a complex, integrated structure of traits that permeates throughout the organization. The team shared that consistent and persistent messaging of safety culture components for every activity, every day, will be essential for ensuring that the cultural improvements underway at the site will progress in a sustainable manner.

Conclusion Overall, the inspectors determined that the licensees problem identification, causal analyses, and corrective actions sufficiently addressed the performance issues that led to the Yellow performance indicator. All inspection objectives, as described in IP 95002, were Met and this inspection is therefore closed. Open items such as CAPR follow-up will be inspected as part of the ongoing NRC baseline inspection program.

INSPECTION RESULTS

Failure to Verify Appropriate Design Inputs per the Engineering Change Process Cornerstone Significance Cross-Cutting Report Aspect Section Initiating Events Green [H.3] - Change 71153 FIN 05000416/2021040-01 Management Open/Closed The inspectors identified a self-revealed Green finding when the licensee failed to verify appropriate design inputs per Procedure EN-DC-115, Engineering Change Process, Revision 31, for the turbine control digital system upgrade project. Specifically, in three instances, the licensee failed to identify the following during the Design Review and Owner Acceptance Review of the engineering change:

1. An incorrect air gap setting for the new turbine speed monitoring probes which resulted in an automatic turbine trip and reactor scram on May 25, 2020.

2. The effect of vibration on the hydraulic actuator for a main turbine control valve, a critical aspect of the design, which resulted in operators initiating a manual reactor scram on August 8, 2020.

3. Incorrect design for primary water bushing flow transmitter sensing lines, which led to an automatic turbine trip and reactor scram on November 6, 2020.

Description:

The main turbine control and protection system was upgraded in the spring 2020 during Refueling Outage RF22 to replace the main turbine electro-hydraulic control (EHC) and mechanical-hydraulic control (MHC) system to a high-pressure hydraulic system and digital control system. All non-safety work was performed under one vendor-prepared Engineering Change EC72780.

On May 25, 2020, a reactor scram occurred due to a main turbine trip from approximately 65 percent power during valve testing in the initial power ascension following implementation of the turbine control digital system (TCS) upgrade. The trip was determined to be caused by inadvertent overspeed signals from two active speed probes which contacted the speed wheel installed on the turbine shaft, causing erratic high and low signals that initiated an overspeed trip signal. The contact resulted from movement of the shaft during operation of the turbine and occurred during high-pressure turbine valve stroke testing of valves associated with the high-pressure turbine. The speed sensing probes and speed sensing wheel had been modified as part of the installation of the TCS upgrade per Engineering Change EC72780 with a smaller air gap than required, which reduced operating margin. The air gap is the distance between the speed probe and speed wheel axially and radially. It has an established minimum setting to ensure that the speed wheel on the turbine shaft does not contact the active speed probes. Speed measurement is required for turbine speed control and the overspeed protection functions. The vendor design specification for minimum air gap specified was 0.035 inches, a value that was too small for the configuration of the TCS at GGNS. This specification was based on industry knowledge and not verified to be correct for GGNS equipment. The original speed probe gap at GGN was 0.047 inches, but there was no documentation nor basis for the reduction of the air gap with the new design. Contrary to the Engineering Change process, during the design review, the licensee did not do a complete review of the specific element related to the speed wheel or basis for the original air gap setting nor was the documentation obtained from the vendor. These parameters and supporting documentation were all critical aspects of the design change.

On August 8, 2020, operators manually scrammed the reactor in response to high pressure control valve oscillations greater than 5 percent. The cause of the pressure control valve oscillations was a loose threaded connection for the linear variable reluctance transmitter (LVRT) driver plate on hydraulic actuator for the D main turbine control valve. The hydraulic valve actuator assemblies were installed with a new design of LVRT assembly. The LVRT assembly consists of two LVRTs mounted to a common bracket that is attached to the valve actuator assembly. The LVRT driver plate connects the actuator rod to the LVRT assembly to provide position indication for the valve. This connection became loose and resulted in a scram.

Vibration on equipment had previously been determined to cause equipment issues with alignment, assembly fasteners to loosen, and assembly parts critical to the function of the actuator assembly to back out. The vibration conditions were measured and evaluated as part of Engineering Change EC72780 but were not fully evaluated for the effects of vibration on the entire assembly to identify weaknesses, ultimately leading to an inadequate design.

Contrary to the Engineering Change process, critical aspects of the design were not identified during design reviews and owner acceptance reviews. The vendor design documentation contained vibration data that was obtained in Refueling Outage 21, but the evaluation and review of this data was accepted without analysis of all parts of the assembly, and therefore, not fully understood.

On November 6, 2020, an automatic turbine trip and subsequent scram occurred due to a low-level signal for primary water system (PWS) flow to generator bushing C. The cause of the scram was gas voids developed in the PWS, which degraded generator bushing primary water flow and increased instrumentation noise in the bushing flow transmitters. Cooling flow to the A, B, and C phase generator bushings is supplied from a common PWS supply header that splits into three parallel lines to supply each of the three phase bushings. Flow transmitters for each phase share a common sensing line from a flow element; flows are expected to be the same for all three bushings. A low flow alarm and turbine trip occur for low flow conditions. The primary water flow transmitters were upgraded to digital transmitters and the instrumentation rack design was changed as part of the TCS upgrade per Engineering Change EC72780. This resulted in changing the sensing line configuration to the transmitters that connect them to the system. As a result, the sensing lines were not installed with the proper sloping as required per the sites Standard JS-02, Instrument and Control Standard Installation Notes and Details for Safety and Non-Safety Related Services, Revision 2, as well as the Vendor Manual for the transmitters. The effect of not sloping the instrument lines is that it allows air and/or hydrogen to accumulate in the sensing lines and ultimately can lead to false low flow indication and false trips. Additionally, the new instrument rack design did not include valves necessary to perform proper backfilling of the sensing lines to remove air and/or hydrogen. During the primary water system upgrade design review and owner acceptance review, the licensee failed to verify appropriate design inputs were used and failed to evaluate the impact of the changes on system operation.

Specifically, the design drawing for the instrument rack provided by the vendor showed sensing lines that did not have a slope when installed. Additionally, the primary water transmitter manifolds did not include backfill valves in the new design that had existed on the previous transmitter manifolds to aid in removal of air and/or hydrogen from the sensing lines.

Inspectors identified that licensee Procedure EN-DC-115, Engineering Change Process, Revision 31, step 6.7, discussed the review and approval requirements for engineering changes processed using the standard design process performed per Procedure EN-DC-115-01, Industry Standard Design Process (IP-ENG-001), Revision 1.

Step 3.5.9 of Procedure EN-DC-115-01 required that design team members review the change package to ensure appropriate design inputs/design requirements had been identified and properly evaluated. Further, step 3.5.12 of Procedure EN-DC-115-01 required an owner acceptance review for vendor generated designs or engineering products and stated, in part, that an Owner Acceptance Review should confirm the change package includes the appropriate design inputs. Contrary to these requirements, in the examples noted, the licensee failed to verify appropriate design inputs were used during these reviews.

Corrective Actions: The licensee implemented several actions in their engineering design process to ensure that roles and responsibilities will be clearly established for Corporate and Site functions when approving engineering modifications prepared by outside design organizations or by Entergy engineering organizations to improve procedural compliance and modification quality. Root cause evaluations were also performed for each of these events.

Corrective Action References: CR-GGN-2020-08779, CR-GGN-2020-10715, CR-GGN-2020-11199, CR-GGN-2021-03320

Performance Assessment:

Performance Deficiency: The failure to verify appropriate design inputs per Procedure EN-DC-115, Engineering Change Process, Revision 31, for the turbine control system digital upgrade project was a performance deficiency.

Screening: The inspectors determined the performance deficiency was more than minor because it was associated with the Design Control 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 performance deficiency resulted in three reactor scrams on May 25, 2020, August 8, 2020, and November 6, 2020.

Significance: The inspectors assessed the significance of the finding using Appendix A, The Significance Determination Process (SDP) for Findings At-Power. The finding was determined to be of very low safety significance (Green) because it caused a reactor trip but did not cause a loss of mitigating equipment relied on to transition the plant from the onset of a trip to a stable shutdown condition.

Cross-Cutting Aspect: H.3 - Change Management: Leaders use a systematic process for evaluating and implementing change so that nuclear safety remains the overriding priority.

Specifically, station leadership did not ensure that design reviews and owner acceptance reviews associated with the turbine control system digital upgrade project were sufficiently scoped and detailed to avoid significant, unintended consequences. As a result, the licensee did not identify that the design inputs associated with the 3 different events were incorrect and three reactor scrams occurred.

Enforcement:

Inspectors did not identify a violation of regulatory requirements associated with this finding.

Failure to Follow the System Operating Instruction for the Primary Water System Cornerstone Significance Cross-Cutting Report Aspect Section Initiating Events Green [H.11] - 71153 NCV 05000416/2021040-02 Challenge the Open/Closed Unknown The inspectors identified a self-revealed Green finding and associated non-cited violation of Technical Specification 5.4.1(a) when the licensee failed to implement Procedure 04-1-01-N43-1, Primary Water System Operating Instruction, Revision 62.

Specifically, while performing Section 5.2.2, Filling and Venting to Raise System Water Tank Level to Normal, an operator inappropriately applied a caution statement associated with step 5.2.2.f after misdiagnosing that valve 1N43-FD01, the primary water system leakage water return valve, was stuck open. The operator incorrectly took manual action to close the valve, causing the primary water system head tank level to lower, resulting in an automatic turbine trip and reactor scram.

Description:

On December 11, 2020, during operator rounds, primary water system (PWS)head tank level was found to be low. Operations personnel began filling the tank using Procedure SOI 04-1-N43-1, Primary Water System Operating Instruction, Revision 62, to raise level in the tank to the normal band.

To fill the tank, operators opened a local manual fill valve, which takes water from a demineralized water storage tank and directs it to a standpipe. The PWS leakage water return motor operated valve (MOV) 1N42-FD01 operates automatically to maintain standpipe level, directing excess water in the standpipe back to the primary water tank. Operators aligned the system for filling using Section 5.2.2 of Procedure SOI 04-1-01-N43-1. This procedure had a caution statement prior to performing step 5.2.2.f that stated, in part, filling the PW tank too fast may cause leakage water return valve 1N43-FD01 to stroke full open and stick open. If, while filling the PW tank, the MOV sticks full open, stop filling, and manually move 1N43-FD01 off its full open backseat.

After opening the local manual fill valve, the operator noted that there did not appear to be any movement of valve 1N43-FD01. This was not the expected result, so the operator took local, manual control of the valve to move it in the closed position (per the caution statement).

Prior to taking this action, the operator did not validate that the valve stroked to its full open backseat. The operator then inappropriately acted to close, or move the valve off its full open backseat, which resulted in fully closing valve 1N43-FD01 and isolating makeup water to the tank. PWS level continued to lower, eventually reaching the low level setpoint that resulted in the automatic turbine trip and reactor scram.

Corrective Actions: The licensee issued a revision to the system operating instruction to provide instructions for local manual standpipe control and monitoring standpipe level of the PWS.

Corrective Action Reference: CR-GGN-2020-12131

Performance Assessment:

Performance Deficiency: The licensees failure to follow Procedure SOI 04-1-01-N43-1, Primary Water System Operating Instruction, was a performance deficiency.

Screening: The inspectors determined the performance deficiency was more than minor because it was 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 performance deficiency resulted in an automatic turbine trip and reactor scram.

Significance: The inspectors assessed the significance of the finding using Appendix A, The Significance Determination Process (SDP) for Findings At-Power. The finding was determined to be of very low safety significance (Green) because it caused a reactor trip but did not cause a loss of mitigating equipment relied on to transition the plant from the onset of a trip to a stable shutdown condition.

Cross-Cutting Aspect: H.11 - Challenge the Unknown: Individuals stop when faced with uncertain conditions. Risks are evaluated and managed before proceeding. Specifically, the operator had an unexpected plant response and operated a valve contrary to procedure, which prevented transfer of makeup water from the standpipe to the primary water tank, eventually resulting in an automatic turbine trip and reactor scram.

Enforcement:

Violation: Technical Specification 5.4.1(a), Procedures, requires, in part, that written procedures be implemented as recommended by Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Section 4.m of Regulatory Guide 1.33, Revision 2, Appendix A, recommends procedures governing operation of the turbine-generator system. System Operating Instruction 04-1-01-N43-1, Primary Water System, Revision 62, Section 5.2.2, Filling and Venting to Raise System Water Tank Level to Normal, states, in part, filling the PWS tank too fast may cause leakage water return valve 1N43-FD01, to stroke full open and stick open. If, while filling the PW tank, the MOV sticks full open, stop filling, and manually move N43-FD01 off its full open backseat.

Contrary to the above, on December 11, 2020, while filling the PWS tank, an operator inappropriately determined MOV 1N43-FD01 stuck full open, and therefore stopped filling, and manually moved the MOV in the closed direction to reposition it off its full open backseat.

However, prior to taking this action, the operator did not validate that the valve had stroked to its full open backseat. This resulted in the valve going full closed and the primary water system head tank level lowering to its low level setpoint, resulting in an automatic turbine trip and reactor scram.

Enforcement Action: This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy.

Failure to Prevent Recurrence of Multiple Scrams Related to the Turbine Control System Cornerstone Significance Cross-Cutting Report Aspect Section Initiating Events Green [H.12] - Avoid 95002 NCV 05000416/2021040-03 Complacency Open/Closed The inspectors identified a self-revealed Green finding and associated non-cited violation of 10 CFR 50, Appendix B, Criterion XVI, when the licensee failed to preclude repetition of recurrent plant scrams related to the turbine control system, a significant condition adverse to quality. Specifically, the licensees actions to correct the causes of scrams that occurred prior to calendar year 2020 (and which resulted in the Unplanned Scrams per 7000 critical hours performance indicator crossing an elevated threshold in 2018), were ineffective. As a result, in 2020, four additional plant scrams related to turbine control system deficiencies caused the same performance indicator (Unplanned Scrams) to cross an elevated threshold.

Description:

In 2018, the licensee crossed the threshold for White Performance Indicators (PIs) for both Unplanned Scrams per 7000 Critical Hours, as well as a White Performance Indicator for Unplanned Power Changes per 7000 Critical Hours. The turbine control system that led to the scrams had quality-related instrumentation that supplied trip inputs to the reactor protection system. The PIs crossing the elevated threshold and the root causes identified for the scram events were considered significant conditions adverse to quality (SCAQs). Corrective actions to preclude repetition (CAPRs) were created to address the common root causes identified for the events.

The licensee evaluated the 2018/2019 individual scrams and commonalities under multiple root cause evaluations (RCEs) (2018-9645 - common cause analysis (CCA) for Unplanned power changes and 2018-13042 - CCA for scrams and 2019-1504 - RCE for Auto Scram due to Generator Lockout). CAPRs credited in both common cause documents and the 2019 evaluation included the following:

CR-GGN-2019-01504 CAPR-19 CAPR - Develop and implement a standard for performing Engineering Design Review for Engineering changes. Establish in the standard critical attributes for review, requirements for organizational engagement at key milestones, and requirements for risk ranking for prioritization for review of engineering changes.

Standards shall be developed using attributes for each phase of a modification in accordance with EN-DC-115 Attachment 9.19, Standard Design Process.

CR-GGN-2019-01504 CAPR-20 CAPR - Develop a detailed quality review checklist with attributes required for preparation of an Engineering Change in accordance with EN-DC-115 Attachment 9.19 Stand Design process and incorporate the checklist into EN-DC-213, Engineering Quality Review process used at GGNS.

CR-GGN-2019-01504 CAPR-22 CAPR - Develop a detailed critical attributes list for third party review for engineering changes using criteria for each phase of a modification in accordance with EN-DC-115 Attachment 9.19, Standard Design process. Use the attributes list in conjunction with EN-HU-104, Technical Task Risk & Rigor, to implement these attributes at GGNS.

The licensee implemented these actions in 2019. The licensees effectiveness review for those CAPRs (LO-GLO-2019-00088 CA-01/02) concluded that the actions were effective based on the sampling performed. However, the effectiveness review noted that EC 72780 (TCS upgrade modification) was outside the population of items reviewed based on its approval prior to implementation of the CAPR actions. At the time, the licensee justified the decision not to include EC72780 in the scope of items reviewed, noting it was aligned with standard station practices.

After the licensee identified that the TCS upgrade modification was missed in the initial reviews for the implemented CAPRs, CA-35 of 2019-1504 was created with the intent to identify deficiencies in EC 72780 as specified in the extent-of-cause evaluation under that RCE. This action was completed; however, not to the appropriate level of rigor to identify deficiencies with the modification that later self-revealed after installation, eventually causing/contributing to four out of the five SCRAMs in 2020. Specifically, licensee personnel performed a very limited retroactive sampling of some aspects of the modification and failed to perform an in-depth review that would have met the quality standard that was set by the original CAPR.

During this inspection, the inspectors noted that the licensee performed an internal operating experience review as part of their common cause analysis. While this review identified missed opportunities to address issues with the TCS modification, the licensee concluded that the condition was not a repeat event. However, the inspectors concluded that the causes shared multiple commonalities and, if the CAPRs had been properly applied to the TCS modification, the associated scrams could have been prevented.

Corrective Actions: The licensee took actions to improve the engineering design change process to provide greater levels of accountability, appropriate levels of oversight, and a more rigorous review process. Actions were also taken to improve the quality of engineering design change products to ensure greater technical rigor and proper risk assessment/mitigation.

Corrective Action Reference: CR-GGN-2020-10715

Performance Assessment:

Performance Deficiency: The licensee failed to effectively take corrective actions to preclude repetition of recurrent TCS-related plant scrams, a significant condition adverse to quality, which led to crossing an elevated threshold again in 2020 for the Unplanned Scrams per 7000 Critical Hours Performance Indicator.

Screening: The inspectors determined the performance deficiency was more than minor because it was associated with the Design Control 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, multiple scrams occurred due to the licensees failure to appropriately implement the turbine control system upgrade modification.

Significance: The inspectors assessed the significance of the finding using Appendix A, The Significance Determination Process (SDP) for Findings At-Power. The finding did not include an impact on mitigating systems which resulted in a Green (very low) safety significance. However, since the finding involved multiple scrams, the inspectors consulted with the regional senior risk analyst (SRA). The SRA determined that the finding was of Green significance.

Cross-Cutting Aspect: H.12 - Avoid Complacency: Individuals recognize and plan for the possibility of mistakes, latent issues, and inherent risk, even while expecting successful outcomes. Individuals implement appropriate error reduction tools.

Enforcement:

Violation: 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires, in part, that, for significant conditions adverse to quality, the cause of the condition is determined, and corrective action taken to preclude repetition.

Contrary to the above, between December 12, 2018, and December 11, 2020, the licensee failed to take corrective actions to preclude repetition for significant conditions adverse to quality. Specifically, in response to the elevated PI threshold being crossed in 2018, the licensee took actions to address deficiencies within the engineering design change process that were determined to be the common root causes of the TCS-related 2018 scram events (CR-GGN-2019-01504 CAPR-19, CAPR-20, and CAPR-22). The TCS had quality-related instrumentation that supplied trip inputs to the reactor protection system. On December 11, 2020, the plant scrammed for the fifth time in calendar year 2020, causing the same PI to cross the elevated threshold once again. The NRC determined that the station missed opportunities to correct deficiencies within the TCS upgrade modification when they failed to properly apply CAPR-19, -20, and -22, which led to four out of the five scrams in 2020 due to effectively the same root causes, a repetitive significant condition adverse to quality.

Enforcement Action: This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy.

EXIT MEETINGS AND DEBRIEFS

The inspectors verified that no proprietary information was retained or documented in this report.

On October 4, 2021, the inspectors presented the IP 95002 supplemental inspection results to Mr. R. Franssen, Site Vice President, and other members of the licensee staff.

DOCUMENTS REVIEWED

Inspection Type Designation Description or Title Revision or

Procedure Date

71153 Corrective Action CR-GGN-2020-08779 RCE Manual Plant Scram in Response to Pressure 2

Documents Control Valve Oscillations

71153 Corrective Action CR-GGN-2020-10715 Yellow Performance Indicator for Unplanned Scrams 1

Documents 4Q 2020

71153 Corrective Action CR-GGN-2020-11199 RCE Turbine Trip on Low Primary Water Flow to 2

Documents Generator Bushing 'C' Phase

71153 Corrective Action CR-GGN-2021-03320 RCE Plant Scram on Turbine Overspeed Trip 2

Documents

71153 Drawings F6059EGP001 Electronic Generator Protection 3

71153 Drawings F6059SPD101 Speed Sensing Installation 4

71153 Drawings F6059TPBKTI Thrust Probe Installation 3

71153 Engineering EC 72780 Turbine Control Protection System - non-safety 0

Changes

71153 Engineering EC 87601 Modification to the Speed Probe Bracket 0

Changes

71153 Engineering EC 88018 Replace Air Regulator of 1N21F513 With High 0

Changes Volume Air Regulator and Modify Piping to Regulate

the Associated Volume Boosters with a Common

Supply Line

71153 Miscellaneous GGNS Operations Log 08/08/2020

71153 Miscellaneous 460000043 Alpha line Pressure Transmitters Absolute and Gage 10/07/1994

Models 1151AP and 1151GP Vendor Manual

71153 Miscellaneous LER 2020-002 Reactor Scram due to Main Turbine Trip 2

71153 Miscellaneous LER 2020-003 Manual Reactor Scram Due to Turbine High Pressure 1

Control Valve Malfunction and Automatic Reactor

Water Level Scram

71153 Miscellaneous LER 2020-004 Automatic Reactor Scram Due to Reactor Feed Pump 1

Trip

71153 Miscellaneous LER 2020-005 Primary Water System Flow Lowered Causing 2

Turbine Trip and Subsequent Reactor Scram

71153 Miscellaneous LER 2020-006 Primary Water Tank Low Level Causing Turbine Trip 2

and Subsequent Reactor Scram

Inspection Type Designation Description or Title Revision or

Procedure Date

71153 Procedures 04-1-01-N43-1 System Operating Instruction Primary Water System 62

71153 Procedures EN-DC-115 Engineering Change Process 31

71153 Procedures EN-DC-115-01 Industry Standard Design Process (IP-ENG-001) 1

71153 Procedures EN-DC-149 Acceptance of Vendor Documents 15

71153 Procedures EN-HU-102 Human Performance Traps and Tools 18

71153 Procedures EN-HU-104 Technical Task and Rigor 8

71153 Procedures EN-HU-106 Procedure and Work Instruction Use and Adherence 9

71153 Procedures EN-LI-118 Corrective Action Program 44

71153 Procedures EN-OP-115 Conduct of Operations 30

71153 Procedures JS-02 Instrument and Control Standard Installation Notes 2

and Details for Safety and Non-Safety Related

Services

71153 Work Orders 511784, 511780, 511754, 0

2294

95002 Corrective Action CR-GGN-2018-13042 White Performance Indicator Exceeded: SCRAMs per 2

Documents 7000 Critical Hours-Root Cause Evaluation

95002 Corrective Action CR-GGN-2019-00895 Liquid Penetrant Examination, Cracked Portion of Left 02/05/2019

Documents Bank #1 Seat

95002 Corrective Action CR-GGN-2019-00904 Liqui Penetrant Examination, Hairline Crack Right 02/05/2019

Documents Bank #1 Subcover

95002 Corrective Action CR-GGN-2019-00932 Liquid Penetrant Examination, Linear Indications on 02/06/2019

Documents Rocker Arm Subcovers

95002 Corrective Action CR-GGN-2019-00961 Three of six Division II Subcovers Show Signs of 02/06/2019

Documents Damage

95002 Corrective Action CR-GGN-2019-01504 An automatic reactor scram was initiated by the 06/15/2020

Documents Reactor Protection System.

95002 Corrective Action CR-GGN-2020-06674 Grand Gulf received a Reactor Scram due to a 01/27/2021

Documents turbine trip.

95002 Corrective Action CR-GGN-2020-06674 Reactor SCRAM due to a Turbine Trip 05/25/2020

Documents

95002 Corrective Action CR-GGN-2020-06674 CA-CAPR; Revise EN-HU-104 'Technical Task Risk & 10/14/2020

Documents 15 Rigor'

95002 Corrective Action CR-GGN-2020-06763 During Fleet Maintenance Review of WO 511780 06/01/2020

Documents which installed the Speed probes during GGN outage

Inspection Type Designation Description or Title Revision or

Procedure Date

the following gaps were identified.

95002 Corrective Action CR-GGN-2020-07217 Primary Water System Nuisance Alarm Due to PW 06/11/2020

Documents Tank Level Deviation

95002 Corrective Action CR-GGN-2020-07694 Primary Water System Nuisance Alarm due to PW 06/29/2020

Documents Tank Level Deviation

95002 Corrective Action CR-GGN-2020-07997 1N43FD01 Stuck Closed 07/12/2020

Documents

95002 Corrective Action CR-GGN-2020-08779 At 0127 hours0.00147 days <br />0.0353 hours <br />2.099868e-4 weeks <br />4.83235e-5 months <br /> the control room staff inserted a 08/09/2021

Documents manual reactor SCRAM in response to pressure

control valve oscillations.

95002 Corrective Action CR-GGN-2020-08779 Manual Plant Scram in Response to Pressure Control 2

Documents Valve; Root Cause Evaluation

95002 Corrective Action CR-GGN-2020-08779 CA-CAPR; Implement EC with Design Features to 10/01/2020

Documents 10 Reduce Effects of Vibration on Actuator

95002 Corrective Action CR-GGN-2020-08779 CA-CAPR; Revise EN-MP-100 'Critical Procurements' 12/17/2020

Documents 13

95002 Corrective Action CR-GGN-2020-09257 Reactor Feed Pump 'B' Trip and Reactor SCRAM 08/25/2020

Documents

95002 Corrective Action CR-GGN-2020-09257 CA-Generate and Schedule Work Orders to Inspect Valve 11/13/2020

Documents 10 Positioners

95002 Corrective Action CR-GGN-2020-09257 CA-Develop and Implement a Proper Conditional SPV 01/28/2021

Documents 11 Mitigation Strategy

95002 Corrective Action CR-GGN-2020-09257 CA-Ensure that the Guidance to Perform Pre-Installation 03/28/2021

Documents 12 Inspection is Tied to Affected Valves

95002 Corrective Action CR-GGN-2020-09257 CA-Perform a Review of Expected Conditional SPV 03/29/2021

Documents 13 Components During Normal Power Maneuvers to

Ensure Proper Mitigation

95002 Corrective Action CR-GGN-2020-09257 CA-Track Repair of RFP Low Suction Flow Annunciator 11/13/2020

Documents 14

95002 Corrective Action CR-GGN-2020-09257 CA-Ensure the Finalized Failure Report is Accepted into 11/13/2020

Documents 15 Records

95002 Corrective Action CR-GGN-2020-09257 CA-Review Those Critical or Sensitive Components Fed 02/28/2021

Documents 17 by Instrument Air to Evaluate Filter Efficiency

95002 Corrective Action CR-GGN-2020-09257 CA-Track Work Orders to Completion 12/16/2020

Inspection Type Designation Description or Title Revision or

Procedure Date

Documents 19

95002 Corrective Action CR-GGN-2020-09257 CA-Scram Due to Reactor Feed Pump Trip; Root Cause 1

Documents 2 Evaluation

95002 Corrective Action CR-GGN-2020-09257 CA-Revise ARI 04-1-02-1H13-P680 for Improvements 03/15/2021

Documents 22

95002 Corrective Action CR-GGN-2020-09257 CA-Revise Procedure 07-S-13-67 08/03/2021

Documents 27

95002 Corrective Action CR-GGN-2020-09257 CA-CAPR: Implement Work Instructions for AOV Using 02/25/2021

Documents 8 ABB/Bailey AV1 or AV2 Positioners to Inspect Prior to

Installation

95002 Corrective Action CR-GGN-2020-09300 Failure of Annunciator 1N21-FAL-L602B to alarm 08/26/2020

Documents during Reactor Feed Pump 'B' Trip (CR-GGN-2020-

257)

95002 Corrective Action CR-GGN-2020-09685 FCR 87609; Turbine Valves LVRT Guide Rod 09/09/2020

Documents Fastener Modification

95002 Corrective Action CR-GGN-2020-10715 Yellow Performance Indicator for Unplanned Scrams 1

Documents 4Q 2020; Root Cause Evaluation

95002 Corrective Action CR-GGN-2020-10715 Unplanned SCRAMs per 7,000 Critical Hours is 08/19/2021

Documents WHITE at the end

of the third quarter 2020.

95002 Corrective Action CR-GGN-2020-10715 CA-Review SPVs that Rely on Operator Actions 04/07/2021

Documents 06

95002 Corrective Action CR-GGN-2020-10715 CA-Identify Interim Measures for On-Going Modifications05/28/2021

Documents 08

95002 Corrective Action CR-GGN-2020-10715 CA-Identify Specific Requirements for Each Participant in 05/13/2021

Documents 09 EC Process

95002 Corrective Action CR-GGN-2020-10715 CA-CAPR; Develop and Implement Roles and 07/14/2021

Documents 10 Responsibility Matrix Using Pilot Process

95002 Corrective Action CR-GGN-2020-10715 CA-Determine Training Plan for New Requirements 07/20/2021

Documents 11 Based on Roles and Responsibilities

95002 Corrective Action CR-GGN-2020-10715 CA-Communicate Roles to Engineering Personnel in the 07/28/2021

Documents 12 Modification Process

95002 Corrective Action CR-GGN-2020-10715 CA-Evaluate Effectiveness of Modification Teams 06/17/2021

Documents 13

Inspection Type Designation Description or Title Revision or

Procedure Date

95002 Corrective Action CR-GGN-2020-10715 CA-Perform Recurring Observations and Feedback of 06/17/2021

Documents 14 Modification Teams

95002 Corrective Action CR-GGN-2020-10715 CA-Incorporate CAPR Roles and Responsibilities into 04/07/2021

Documents 15 Fleet Procedures

95002 Corrective Action

Documents

95002 Corrective Action CR-GGN-2020-10715 CA-Determine Fleet Training Plan for New Requirements 04/07/2021

Documents 16

95002 Corrective Action CR-GGN-2020-10715 CA-Communicate Roles to Engineering Personnel in the 04/07/2021

Documents 17 Modification Process

95002 Corrective Action CR-GGN-2020-10715 CA-Evaluate the Effectiveness of Modification Teams 06/17/2021

Documents 18

95002 Corrective Action CR-GGN-2020-10715 CA-Perform Recurring Observations and Feedback of 06/17/2021

Documents 19 Modification Teams

95002 Corrective Action CR-GGN-2020-10715 CA-Implement an Oversight Plan for Supplemental 06/14/2021

Documents 23 Engineering

95002 Corrective Action CR-GGN-2020-10715 CA-Conduct Observations of Field Work Performed by 05/05/2021

Documents 24 Supplemental Personnel

95002 Corrective Action CR-GGN-2020-10715 CA-Eliminate Conditional SPVs during Maintenance 06/12/2021

Documents 26

95002 Corrective Action CR-GGN-2020-10715 CA-Validate Parts Quality Prior to Installation 05/12/2021

Documents 29

95002 Corrective Action CR-GGN-2020-10715 CA-Review Critical BOP Systems for Generation Risks 04/22/2021

Documents 7

95002 Corrective Action CR-GGN-2020-11199 Review Previous Turbine Trips 06/02/2021

Documents

95002 Corrective Action CR-GGN-2020-11199 Root Cause Evaluation; Turbine Trip on Low Primary 02

Documents Water Flow to Generator Bushing 'C' Phase

95002 Corrective Action CR-GGN-2020-11199 At 0239 hours0.00277 days <br />0.0664 hours <br />3.95172e-4 weeks <br />9.09395e-5 months <br /> a Turbine Trip and subsequent Reactor 03/02/2021

Documents Scram were received. Cause of Turbine Trip was low

flow on Primary

Water Bushing 'C' Phase.

95002 Corrective Action CR-GGN-2020-11199 CA-Reinforce CAP Requirements MA-40 and EN-LI-102 02/25/2021

Documents 10 regarding Risk Assessments

Inspection Type Designation Description or Title Revision or

Procedure Date

95002 Corrective Action CR-GGN-2020-11199 CA-Reinforce Extent of Cause Expectations 02/26/2021

Documents 11

95002 Corrective Action CR-GGN-2020-11199 CA-Self-Assessment of EC Process 06/04/2021

Documents 14

95002 Corrective Action CR-GGN-2020-11199 CA-Review CRs Since RF22 for conditions that could 03/24/2021

Documents 15 degrade leading directly to turbine or generator trip

95002 Corrective Action CR-GGN-2020-11199 CA-Review System Monitoring Plans 03/24/2021

Documents 16

95002 Corrective Action CR-GGN-2020-11199 CA-Ongoing CR Review 03/11/2021

Documents 17

95002 Corrective Action CR-GGN-2020-11199 CA-Review Extent of Cause Evaluations 03/23/2021

Documents 18

95002 Corrective Action CR-GGN-2020-11199 CA-Review Turbine Trip ARIs 06/09/2021

Documents 19

95002 Corrective Action CR-GGN-2020-11199 CA-CAPR; Create a List of Generation Risk ECs 04/28/2021

Documents 20

95002 Corrective Action CR-GGN-2020-11199 CA-Ongoing CR Review for Trip Critical or Sensitive 04/11/2021

Documents 21 Systems

95002 Corrective Action CR-GGN-2020-11199 CA-Ongoing CR Review Referencing CA-17 & CA-21 05/12/2021

Documents 22

95002 Corrective Action CR-GGN-2020-11199 CA-Ongoing CR Review Referencing CA-17, 21, and 22 06/16/2021

Documents 25

95002 Corrective Action CR-GGN-2020-11199 CA-CAPR#4; Permanent EC for Trip Setpoint 01/08/2021

Documents 7

95002 Corrective Action CR-GGN-2020-12131 Turbine Trip on Low Primary Water Tank Level 1

Documents

95002 Corrective Action CR-GGN-2020-12131 CA-Revise Primary Water SOI to Monitor Standpipe Level03/10/2021

Documents 10

95002 Corrective Action CR-GGN-2020-12131 CA-Review Head Tank Monitoring & Mitigation 04/28/2021

Documents 11

95002 Corrective Action CR-GGN-2020-12131 CA-Create a List of Generation Risks in ECs 04/08/2021

Documents 12

95002 Corrective Action CR-GGN-2020-12131 CA-Design Change to Valve FD01 Control Logic 06/23/2021

Documents 13

Inspection Type Designation Description or Title Revision or

Procedure Date

95002 Corrective Action CR-GGN-2020-12131 CA-Require FCRs for Significant Issues Found in 04/28/2021

Documents 14 Owner's Acceptance Review Documents

95002 Corrective Action CR-GGN-2020-12131 CA-Communication to Design Engineers on Expectations 03/30/2021

Documents 15 for Owner's Acceptance Reviews

95002 Corrective Action CR-GGN-2020-12131 CA-Review Comments Needed for Evaluations 03/25/2021

Documents 16

95002 Corrective Action CR-GGN-2020-12131 CA-Workshop for Design Engineers on Documentation of 05/14/2021

Documents 17 Generation impacts

95002 Corrective Action

Documents

95002 Corrective Action CR-GGN-2020-12131 CA-Training Needs Analysis 04/21/2021

Documents 19

95002 Corrective Action CR-GGN-2020-12131 CA-Meetings to Reinforce Operator Expectations 03/25/2021

Documents 20

95002 Corrective Action CR-GGN-2020-12131 CA-Observations on Operator Use of Human 03/25/2021

Documents 22 Performance Tools

95002 Corrective Action CR-GGN-2020-12131 CA-Track Completion of CR-GGN-2020-11199 CA10, 15, 04/20/2021

Documents 23 & 17

95002 Corrective Action CR-GGN-2020-12131 CA-Observations on Operator Use of Human 04/28/2021

Documents 25 Performance Tools

95002 Corrective Action CR-GGN-2020-12131 CA-Observations on Operator Use of Human 05/27/2021

Documents 27 Performance Tools

95002 Corrective Action CR-GGN-2020-12131 CA-Observations on Operator Use of Human 06/24/2021

Documents 28 Performance Tools

95002 Corrective Action CR-GGN-2020-12131 CA-Track Actions from CR-GGN-2020-10715 CA08 06/17/2021

Documents 29 through CA19

95002 Corrective Action CR-GGN-2020-12131 CA-LO/NLO Continuing Training on Primary Water 07/29/2021

Documents 31 System Operation

95002 Corrective Action CR-GGN-2020-12131 CA-Track CR-GGN-2020-10715 CA-6 to completion 06/17/2021

Documents 32

95002 Corrective Action CR-GGN-2020-12131 CA-Issue a Learning Clock for Operations 02/25/2021

Documents 9

95002 Corrective Action CR-GGN-2020-12153 1N43FD01 Mechanical Interlock Broken on 42 Device 12/12/2020

Documents

Inspection Type Designation Description or Title Revision or

Procedure Date

95002 Corrective Action CR-GGN-2021-00476 Division II Diesel Generator Lube Oil Pressure Low 01/17/2021

Documents

95002 Corrective Action CR-GGN-2021-00486 Division II Diesel Generator Lube Oil Pressure 39- 01/18/2021

Documents 40psig

95002 Corrective Action CR-GGN-2021-00953 Primary Water System "Leakage Water Level High" 02/02/2021

Documents Alarm Not Functioning

95002 Corrective Action CR-GGN-2021-01105 CFAM Elevation Issued for GGN Operations Due to 02/05/2021

Documents Human Performance

95002 Corrective Action CR-GGN-2021-01261 Division II Diesel Monthly Run Low Lube Oil Pressure02/12/2021

Documents

95002 Corrective Action CR-GGN-2021-01849 Diesel Generator 12 Functional Test - Low Lube Oil 03/07/2021

Documents Pressure

95002 Corrective Action CR-GGN-2021-02018 Division II Low Oil Pressure During Functional Test03/13/2021

Documents

95002 Corrective Action CR-GGN-2021-02093 Division II Subcovers Potentially Missing Rocker 03/16/2021

Documents Shaft Plugs

95002 Corrective Action CR-GGN-2021-03320 Plant Scram on Turbine Overspeed Trip; Root Cause 2

Documents Evaluation

95002 Corrective Action CR-GGN-2021-03320 Pre-inspection Self-Assessment identified the 06/14/2021

Documents following required revisions to the root cause

evaluation for

CR-GG-2020-6674, Turbine Overspeed Trip Plant

SCRAM

95002 Corrective Action CR-GGN-2021-04064 Incorrect Component Classification of 1N21R085B, 05/22/2021

Documents RFP 'B' Recirc Valve

95002 Corrective Action CR-GGN-2021-04101 EN-HU-104 performed was the previous revision and 05/27/2021

Documents did not contain the critical characteristic table required

for the independent station review

95002 Corrective Action CR-GGN-2021-04144 EC 88482 for TDM Solenoid Connectors and EC 07/27/2021

Documents 89184 for Thrust Bearing Wear Detection did not

include a High Consequence Risk Factor Table as

required by EN-HU-104

95002 Corrective Action CR-GGN-2021-04161 Root Cause CR-GGN-2019-01504 CA-035 was not 06/01/2021

Documents implemented effectively.

Inspection Type Designation Description or Title Revision or

Procedure Date

95002 Corrective Action CR-GGN-2021-0469 Division 2 Diesel Generator Run - Operators identified 01/16/2021

Documents 2-inch Crack

95002 Corrective Action CR-GGN-2021-04700 Primary water trips have not been enabled since 12-08/25/2021

Documents 11-2020

95002 Corrective Action CR-GGN-2021-06469 Action Closure Review Board Rejected a Number of 08/21/2021

Documents Corrective Action Closure Packages Prepared for

95002 Inspection

95002 Corrective Action CR-GGN-2021-06696 In EC72780 Section 7.0 the keywords used 08/31/2021

Documents for the Operating Experience search was not

recorded in the OE section.

95002 Corrective Action CR-GGN-2021-06734 EC 88268 Division I Diesel Subcover didn't identify 09/01/2021

Documents Risk Category, Risk Rank 4 should have been shown

95002 Corrective Action CR-GGN-2021-0802 Disposition CA to Perform RCE for a Significant 03/02/2021

Documents Condition Adverse to Quality Extended Twice by

Engineering

95002 Corrective Action CR-GGNS-2010-01397 Liquid Penetrant Exam Division II Diesel Sub-cover 03/03/2010

Documents rocker arm

95002 Corrective Action CR-GGNS-2010-01503 Reactor Feed Pump 'A' Trip, Resulting in 'A' Recirc 03/08/2010

Documents FCV failing to close

95002 Corrective Action CR-GGNS-2012-12201 Lube Oil Leaks on SDG 12 11/07/2012

Documents

95002 Corrective Action CR-GGNS-2016-05488 Common Cause Review for the Three Unplanned 3

Documents 12016 Scrams

95002 Corrective Action CR-GGNS-2017-04258 Lube Oil Seepage on Division II Standby Diesel 04/26/2017

Documents Generator

95002 Corrective Action CR-GGNS-2018-01265 Division II Diesel Generator Oil Leak from Cylinder 02/12/2018

Documents Inspection Cover

95002 Corrective Action CR-GGNS-2018-01347 Division II Diesel Generator Oil Leak from Valve 02/13/2018

Documents Covers

95002 Corrective Action CR-GGNS-2018-09645 White Performance Indicator Exceeded: Unplanned 5

Documents Power Changes per 7000 Critical Hours

95002 Corrective Action CR-GGNS-2020-12131 Turbine Trip on Low Primary Water Tank Level; Root 1

Documents Cause Evaluation

95002 Corrective Action CR-HQN-2020-01869 EN-DC-115, Engineering Change Process, for 09/29/2020

Inspection Type Designation Description or Title Revision or

Procedure Date

Documents Operating Experience (OE) appears to have a

weakness in evaluating OE for EC development.

95002 Corrective Action CR-HQN-2021-00879 During development of engineering changes for 05/27/2021

Documents GGNS, there were two examples with use of EN-HU-

104, Technical Task Risk & Rigor, that indicate there

may be confusion with identification of High

Consequence Risk Factor Table.

95002 Corrective Action CR-HQN-2021-01191 The Comparison Tables in the revised Pre-Job Brief 08/19/2021

Documents form were found to lack a detailed description of how

generation could be impacted

95002 Corrective Action CR-HQN-2021-01232 The Comparison Tables developed and utilized 08/24/2021

Documents during reviews as required by EN-HU-104, Technical

Task Risk & Rigor, for ECs 87853 and 88515 were

not included with the ECs documentation.

95002 Corrective Action CR-HQN-2021-01432 95002 Inspector Question - Basis for EN-HU-104 08/26/2021

Documents Attachment 9.1 Consequence Risk Factor Medium

Risk for Operability issue affecting multiple trains of

safety-related system

95002 Corrective Action OE-GGN-2006-00794 Perform OE Impact Evaluation of INPO TR4-41, 02/27/2006

Documents Review of Main Feedwater System Related Events

95002 Corrective Action OE-NOE-2005-00321 TR4-41 Review of Main Feedwater System Related 10/07/2005

Documents Events Requires a Plant Impact Review

95002 Corrective Action OE-NOE-2006-00371 TR4-41 Addendum Review of Main Feedwater 10/11/2006

Documents System Related Events Requires a Plant Impact

Review

95002 Corrective Action OE-NOE-2009-00060 TR4-41 Addendum Review of Main Feedwater 02/11/2009

Documents System Related Events Requires a Plant Impact

Review

95002 Corrective Action CR-GGN-2021-06602 PCRS Access 08/26/2021

Documents

Resulting from

Inspection

95002 Corrective Action CR-GGN-2021-06619 Inappropriate closure of a Work Order tied to a 08/26/2021

Documents Corrective Action

Inspection Type Designation Description or Title Revision or

Procedure Date

Resulting from

Inspection

95002 Corrective Action CR-GGN-2021-06628 95002 Inspection NRC Identified - EC88268 08/26/2021

Documents Incorrectly Classified as Non-Safety Related

Resulting from

Inspection

95002 Corrective Action CR-GGN-2021-06637 Programmatic Weakness in the Application of 08/27/2021

Documents Operating Experience

Resulting from

Inspection

95002 Corrective Action CR-GGN-2021-07033 Due Dates for the Final Effectiveness Review for CR-09/14/2021

Documents GGN-2020-10715 is Incorrect

Resulting from

Inspection

95002 Corrective Action CR-HQN-2021-01456 EN-MA-101-03 Revision Error 09/01/2021

Documents

Resulting from

Inspection

95002 Engineering 0000081856 Reactor Feed Pump Turbine Trip Low Suction Flow 0

Changes Trip Hardening

95002 Engineering EC 0000083472 Diesel Div 1&2 Sub-Cover Replacement 0

Changes

95002 Engineering EC 0000087609 Turbine Valves LVRT Guide Rod Fastener 0

Changes Modification

95002 Engineering

Changes

95002 Engineering EC 0000087660 CR-GGN-2020-11199 CAPR#2; Time Delay for 0

Changes Primary Water Flow Path Trip Signals

95002 Engineering EC 0000088018 Replace Air Regulator of 1N21F513 with High Volume 0

Changes Air Regulator and Modify Piping to Regulate the

Associated Volume Boosters with a Common Supply

Line

95002 Engineering EC 0000088018 EN-HU-Evaluate the Replacement Air Regulator and Piping 09/16/2020

Changes 104 Consequence Configuration for 1N21F513

Inspection Type Designation Description or Title Revision or

Procedure Date

Attachments

95002 Engineering EC 0000088268 Division 1 Diesel Subcover Replacement 0

Changes

95002 Engineering EC 0000088268 Division I Diesel Subcover Replacement Design 0

Changes Verification Checklist

95002 Engineering EC 0000088547 CR-GGN-2020-11199 CAPR#3; Generator Bushing 0

Changes Primary Water Low Flow Alarm Setpoint Change

Increase to 31.5GPM

95002 Engineering EC 0000088572 CAPR#1 CR-GGN-2020-11199; Update Drawing per 0

Changes Work Order 550604

95002 Engineering EC 0000088665 EHC Main Pump Motor Set 1N32C300A&B Replace 0

Changes Magnaloy Motor Dampening Bar Sets with Steel

Mounting Bars

95002 Engineering EC 0000088665 EN-HU-EC-88665, 1N32C300A/B Pump Vibration Reduction 04/15/2021

Changes 104 Consequence Risk EC

Checklist

95002 Engineering EC 0000090361 Cut/Cap 1N11F045B and 1N11F368 Valves and 0

Changes Associated Piping to Eliminate Risk of Flow Induced

Vibration

95002 Engineering EC 0000090618 Replacement 28V Power Supply for RC&IS Obsolete 0

Changes Lambda Model MLGS-EEA-28-OV

95002 Engineering EC 0000072780 Turbine Control Protection System - Non-Safety 0

Changes

95002 Engineering EC 0000087061 Modification to the Speed Bracket 0

Changes

95002 Engineering EC 0000088574 Raise Primary Water Tank Low Level Alarm Setpoint 0

Changes from 85% to 90%

95002 Engineering EC 0000089459 Turbine Control System Actuator Replacements 0

Changes

95002 Engineering EC 0000090618 EN-HU-EC 90618 - Replace 1C11PS28 Obsolete Power 07/14/2021

Changes 104 Consequence Risk Supply with New Equivalent Power Supply

Checklist

95002 Engineering Management Standard Attachment 6; Supervisor Checklist 07/07/2021

Changes No. 51 - EC 0000090361

Inspection Type Designation Description or Title Revision or

Procedure Date

95002 Engineering Management Standard Attachment 6; Supervisor Checklist 05/25/2021

Changes No. 51 Checklist - EC 0000088665

95002 Miscellaneous Grand Gulf Nuclear Station 2021 Business Plan Phase 2,

Revision 0

95002 Miscellaneous Summary of qualifications and experience level of the

Engineers associated with the TCS project.

95002 Miscellaneous Maintenance Guideline - Pre-installation Parts 1

Inspections

95002 Miscellaneous 2021 Grand Gulf Nuclear 2021 Grand Gulf Nuclear Station Operations Action

Station Operations Action Plan

Plan

95002 Miscellaneous 460004254 Nuclear Tandem Compound, Six-Flow Turbine with 2

Two Stages of Reheat

95002 Miscellaneous Contract 10507770-05 Contract Between Entergy and Westinghouse Re: 5

Turbine Control System

95002 Miscellaneous FLP-ESPO-Human Performance for Technical Worker 2

HUPERF4TECHWORKER

95002 Miscellaneous LF201185-R-001 GGNS RFP B Recirc Valve 1N21F503B Positioner 0

Failure Analysis

95002 Miscellaneous Operations Standing 1N43DF01 Leakage Water Return Valve Mitigating 12/13/2020

Order No: 20-021 Actions

95002 Miscellaneous Purchase Order PO 10471355 04/10/2018

95002 Miscellaneous Training Lesson Plan Primary Water System 16

GLP-NLOR-N43-

21CYC09

95002 Miscellaneous Training Lesson Plan Primary Water System 16

GLP-OPS-N4300

95002 Miscellaneous Training Lesson Plan Training Lesson Plan GLP-OPS-TCSU-19CYC1, 0

GLP-OPS-TCSU-19CYC1 Turbine Control System Upgrade

95002 Miscellaneous Vendor Manual Bailey Characterizable Positioners 0

460002831

95002 Procedures

95002 Procedures 04-1-02-1H13-P680 Alarm Response Instruction Panel No: 1H13-P680 261

Inspection Type Designation Description or Title Revision or

Procedure Date

95002 Procedures 07-S-13-67 ABB/Bailey AV1 or AV2 Series Positioner Pre-1

Installation Inspection

95002 Procedures EN-DC-115 Engineering Change Process 31

95002 Procedures EN-DC-141 Design Inputs 18

95002 Procedures EN-DC-149 Acceptance of Vendor Documents 15

95002 Procedures EN-DC-153 Preventative Maintenance Component Classification 21

95002 Procedures EN-FAP-HR-004 Knowledge Transfer and Retention (KT&R) Process 4

95002 Procedures EN-FAP-MP-009 Enhanced Procurement Process for SPV/Critical 5

Spares

95002 Procedures EN-HU-102 Human Performance Traps and Tools 18

95002 Procedures EN-HU-104 Technical Task Risk & Rigor 11

95002 Procedures EN-HU-104 Technical Task Risk & Rigor 9

95002 Procedures EN-HU-104 Technical Task Risk & Rigor 10

95002 Procedures EN-HU-104, Attachment EC 88262; Division 1 Diesel Subcover Replacement 05/27/2021

9.1

95002 Procedures EN-HU-106 Procedure and Work Instruction Use and Adherence 9

95002 Procedures EN-MA-101 Conduct of Maintenance 33

95002 Procedures EN-MA-101-03 Maintenance Work Preparation Process 12

95002 Procedures EN-MA-106 Planning 1

95002 Procedures EN-OE-100 Operating Experience Program 34

95002 Procedures EN-OM-132 Nuclear Risk Management Process 3

95002 Procedures

95002 Procedures EN-WM-100 Work Request Generation, Screening, and 17

Classification

95002 Procedures JA-PI-01 Analysis Manual 13

95002 Procedures Management Standard GGN Design Review Board Guideline 1

No. 50

95002 Procedures Management Standard GGN Technical Product Quality Guideline 8

No. 51

95002 Procedures Management Standard GGN Design Change Roles and Responsibilities 0

No. 57

95002 Procedures SOI 04-1-01-N43-1 Primary Water System 64

95002 Self-Pre-Inspection Assessment Worksheet for IP 95002 04/14/2021

Inspection Type Designation Description or Title Revision or

Procedure Date

Assessments Inspection, CR-GGN-2020-12131, Turbine Trip on

Low Primary Water Tank Level

95002 Self-USA Utilities Services Alliance Grand Gulf Nuclear 1

Assessments Station Nuclear Safety Culture Assessment

95002 Self-Pre-Inspection Assessment Worksheet for IP 95002 04/13/2021

Assessments Inspection, CR-GGN-2020-9257, Automatic SCRAM

due to B Reactor Feed Pump Trip,

95002 Work Orders 00517874-01 1P75E001B Replace Left Bank #1 Subcover 02/14/2019

Assembly

95002 Work Orders 511754 N11F026D-CV Replace HP Actuator with New Design 07/23/2020

per EC-72780

95002 Work Orders 511780 1N30ZEN200 Install New SP & TBWD Detectors per 11/30/2020

EC-72780

95002 Work Orders WO-00547001-01 1N43N066; Add Time Delay for Primary Water Flow 10/15/2020

Transmitters per EC87660

95002 Work Orders WO-00549388-01 1N37F001A/B/C; Install EC-87632 & FCR-87609 on 11/25/2020

Stop Valve Actuator

95002 Work Orders WO-00550604-01 1N43N060 Retube and add Test Valves per JS02 11/23/2020

CR-GGN-2020-09431

95002 Work Orders WO-00554157-01 1N432607: Implement EC-88547 (Increase Setpoint 03/01/2021

to 31.5GPM)

95002 Work Orders WO-GGN-00528791-01 1N21F503B Rework Actuator Per VM, Repack as 02/09/2020

Necessary 07-S-1

95002 Work Orders WO-GGN-00545789-01 1N43N051/1N43N052, T/S and Correct Level 08/14/2020

Discrepancies

95002 Work Orders WO-GGN-00547880-01 1H13P828JC08: Troubleshoot Control System Sheet 11/15/2020

407

95002 Work Orders WO-GGN-00548011-01 1N43DF01 Valve Stuck Close 09/30/2020

95002 Work Orders WO-GGN-00550018-01 1N21F503B T/S and Repair Actuator 11/25/2020

95002 Work Orders WO-GGN-00550137-01 1N21R085A Replace Positioner (Extent of Condition)01/28/2021

95002 Work Orders WO-GGN-00552902-01 1N21R085A Inspect Positioners/Contingency 02/09/2021

Replace

46