ML15188A532

IR 05000458/2015009; on 01/26/2015 - 06/29/2015; River Bend Station; Special Inspection for the Scram with Complications That Occurred on December 25, 2014

ML15188A532
Person / Time
Site:	River Bend
Issue date:	07/07/2015
From:	Troy Pruett NRC/RGN-IV/DRP
To:	Olson E Entergy Operations
Greg Warnick
References
EA-15-043 EA-15-043, IR 2015009
Download: ML15188A532 (43)

See also: IR 05000458/2015009

Text

UNITED STATES

NUCLEAR REGULATORY COMMISSION

REGION IV

1600 E. LAMAR BLVD

ARLINGTON, TX 76011-4511

July 7, 2015

EA-15-043

Mr. Eric W. Olson, Site Vice President

Entergy Operations, Inc.

River Bend Station

5485 U.S. Highway 61N

St. Francisville, LA 70775

SUBJECT: RIVER BEND STATION - NRC SPECIAL INSPECTION

REPORT 05000458/2015009; PRELIMINARY WHITE FINDING

Dear Mr. Olson:

On June 29, 2015, the U.S. Nuclear Regulatory Commission (NRC) completed a Special

Inspection at the River Bend Station to evaluate the facts and circumstances surrounding an

unplanned reactor trip. Based upon the risk and deterministic criteria specified in NRC

Management Directive 8.3, NRC Incident Investigation Program, the NRC initiated a Special

Inspection in accordance with Inspection Procedure 93812, Special Inspection. The basis for

initiating the special inspection and the focus areas for review are detailed in the Special

Inspection Charter (Attachment 2). The NRC determined the need to perform a Special

Inspection on January 15, 2015, and the onsite inspection started on January 26, 2015. The

enclosed report documents the inspection findings that were discussed on May 21 and

June 29, 2015, with you and members of your staff. The team documented the results of this

inspection in the enclosed inspection report.

The enclosed inspection report documents a finding that has preliminarily been determined to

be White, a finding with low to moderate safety significance that may require additional NRC

inspections, regulatory actions, and oversight. The team identified an apparent violation for

failure to maintain the simulator so it would accurately reproduce the operating characteristics of

the facility. Specifically, the River Bend Station simulator failed to accurately model feedwater

flow and reactor vessel level response following a scram, failed to provide the correct alarm

response for loss of a reactor protection system motor generator set, and failed to correctly

model the operation of the startup feedwater regulating valve. As a result of the simulator

deficiencies, operations personnel were presented with additional challenges to control the plant

and maintain plant parameters following a reactor scram on December 25, 2014. Because

actions have been taken to initiate discrepancy reports, to investigate and resolve the potential

fidelity issues and to provide training to operations personnel, the simulator deficiencies do not

represent a continuing safety concern. The NRC assessed this finding using the best available

information, and Manual Chapter 0609, Significance Determination Process. The basis for the

NRCs preliminary significance determination is described in the enclosed report. The finding is

also an apparent violation of NRC requirements and is being considered for escalated

enforcement action in accordance with the Enforcement Policy, which can be found on the

E. Olson -2-

NRCs website at http://www.nrc.gov/about-nrc/regulatory/enforcement/enforce-pol.html.

The NRC will inform you in writing when the final significance has been determined.

Before we make a final decision on this matter, we are providing you with an opportunity to

(1) attend a Regulatory Conference where you can present your perspective on the facts and

assumptions used to arrive at the finding and assess its significance, or (2) submit your position

on the finding to the NRC in writing. If you request a Regulatory Conference, it should be held

within 30 days of your receipt of this letter. We encourage you to submit supporting

documentation at least one week prior to the conference in an effort to make the conference

more efficient and effective. The focus of the Regulatory Conference is to discuss the

significance of the finding and not necessarily the root cause(s) or corrective action(s)

associated with the finding. If you choose to attend a Regulatory Conference, it will be open for

public observation. The NRC will issue a public meeting notice and press release to announce

the conference. If you decide to submit only a written response, it should be sent to the NRC

within 30 days of your receipt of this letter. If you decline to request a Regulatory Conference or

to submit a written response, you relinquish your right to appeal the NRCs final significance

determination, in that by not choosing an option, you fail to meet the appeal requirements stated

in the Prerequisites and Limitations sections of Attachment 2, Process for Appealing NRC

Characterization of Inspection Findings (SDP Appeal Process), of NRC Inspection Manual

Chapter 0609.

Please contact Greg Warnick at (817) 200-1144, and in writing, within 10 days from the issue

date of this letter to notify us of your intentions. If we have not heard from you within 10 days,

we will continue with our final significance determination and enforcement decision. The final

resolution of this matter will be conveyed in separate correspondence.

Because the NRC has not made a final determination in this matter, no Notice of Violation is

being issued for this inspection finding at this time. In addition, please be advised that the

number and characterization of the apparent violation described in the enclosed inspection

report may change based on further NRC review.

In addition, the NRC inspectors documented four findings of very low safety significance

(Green) in this report. Three of these findings were determined to involve violations of NRC

requirements. The NRC is treating these violations as non-cited violations consistent with

Section 2.3.2.a of the Enforcement Policy.

If you contest the violations or significance of these non-cited violations, you should provide a

response within 30 days of the date of this inspection report, with the basis for your denial, to

the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk,

Washington, DC 20555-0001; with copies to the Regional Administrator, Region IV; the

Director, Office of Enforcement, U.S. Nuclear Regulatory Commission,

Washington, DC 20555-0001; and the NRC resident inspector at the River Bend Station.

If you disagree with a cross-cutting aspect assignment in this report, you should provide a

response within 30 days of the date of this inspection report, with the basis for your

disagreement, to the Regional Administrator, Region IV; and the NRC resident inspector at the

River Bend Station.

E. Olson -3-

In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public

Inspections, Exemptions, Requests for Withholding, a copy of this letter, its enclosure, and your

response (if any) will be available electronically for public inspection in the NRC's Public

Document Room or from the Publicly Available Records (PARS) component of the NRC's

Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible

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

Reading Room).

Sincerely,

/RA/

Troy W. Pruett

Director

Division of Reactor Projects

Docket No. 50-458

License No. NPF-47

Enclosure:

Inspection Report 05000458/2015009

w/ Attachments:

1. Supplemental Information

2. Special Inspection Charter

SUNSI Review ADAMS Non-Sensitive Publicly Available

By: RVA Yes No Sensitive Non-Publicly Available

OFFICE SRI:DRP/B SRI:DRS/PSB2 RI:DRP/A BC:DRS/OB SES:ACES TL:ACES BC:DRP/C

NAME THartman JDrake DBradley VGaddy RBrowder MHay GWarnick

SIGNATURE /RA/ /RA/ /RA/ /RA/ /RA/ /RA/ /RA/

DATE 06/04/15 06/04/15 06/05/15 06/30/15 06/04/15 06/04/15 06/04/15

OFFICE D:DRP

NAME TPruett

SIGNATURE /RA/

DATE 7/7/15

Letter to Eric Olson from Troy Pruett dated July 7, 2015.

SUBJECT: RIVER BEND STATION - NRC SPECIAL INSPECTION

REPORT 05000458/2015009; PRELIMINARY WHITE FINDING

DISTRIBUTION:

Regional Administrator (Marc.Dapas@nrc.gov)

Deputy Regional Administrator (Kriss.Kennedy@nrc.gov)

DRP Director (Troy.Pruett@nrc.gov)

DRP Deputy Director (Ryan.Lantz@nrc.gov)

DRS Director (Anton.Vegel@nrc.gov)

DRS Deputy Director (Jeff.Clark@nrc.gov)

Senior Resident Inspector (Jeffrey.Sowa@nrc.gov)

Resident Inspector (Andy.Barrett@nrc.gov)

RBS Administrative Assistant (Lisa.Day@nrc.gov)

Branch Chief, DRP/C (Greg.Warnick@nrc.gov)

Senior Project Engineer (Ray.Azua@nrc.gov)

Project Engineer (Michael.Stafford@nrc.gov)

Project Engineer (Paul.Nizov@nrc.gov)

Public Affairs Officer (Victor.Dricks@nrc.gov)

Public Affairs Officer (Lara.Uselding@nrc.gov)

RIV RSLO (Bill.Maier@nrc.gov)

Project Manager (Alan.Wang@nrc.gov)

Team Leader, DRS/TSS (Don.Allen@nrc.gov)

RITS Coordinator (Marisa.Herrera@nrc.gov)

ACES (R4Enforcement.Resource@nrc.gov)

Regional Counsel (Karla.Fuller@nrc.gov)

Technical Support Assistant (Loretta.Williams@nrc.gov)

Congressional Affairs Officer (Jenny.Weil@nrc.gov)

RIV Congressional Affairs Officer (Angel.Moreno@nrc.gov)

RIV/ETA: OEDO (Michael.Waters@nrc.gov)

Senior Staff Engineer, TSB (Kent.Howard@nrc.gov)

Enforcement Specialist, OE/EB (Robert.Carpenter@nrc.gov)

Senior Enforcement Specialist, OE/EB (John.Wray@nrc.gov)

Branch Chief, OE (Nick.Hilton@nrc.gov)

Enforcement Coordinator, NRR/DIRS/IPAB/IAET (Lauren.Casey@nrc.gov)

Branch Chief, Operations and Training Branch (Scott.Sloan@nrc.gov)

NRREnforcement.Resource@nrc.gov

RidsOEMailCenterResource

ROPreports

Electronic Distribution via Listserv for River Bend Station

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket: 05000458

License: NPF-47

Report: 05000458/2015009

Licensee: Entergy Operations, Inc.

Facility: River Bend Station, Unit 1

Location: 5485 U.S. Highway 61N

St. Francisville, LA 70775

Dates: January 26 through June 29, 2015

Inspectors: T. Hartman, Senior Resident Inspector

D. Bradley, Resident Inspector

J. Drake, Senior Reactor Inspector

Approved By: T. Pruett, Director

Division of Reactor Projects

Enclosure

SUMMARY OF FINDINGS

IR 05000458/2015009; 01/26/2015 - 06/29/2015; River Bend Station; Special inspection for the

scram with complications that occurred on December 25, 2014.

The report covered one week of onsite inspection and in-office review through June 29, 2015,

by inspectors from the NRCs Region IV office. One preliminary White apparent violation, three

Green non-cited violations, and one Green finding were identified. The significance of most

findings is indicated by their color (Green, White, Yellow, or Red) using Inspection Manual

Chapter 0609, Significance Determination Process. Findings for which the significance

determination process does not apply may be Green or be assigned a severity level after NRC

management review. The NRCs program for overseeing the safe operation of commercial

nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4,

dated December 2006.

Cornerstone: Initiating Events

• Green. The team reviewed a self-revealing, non-cited violation of Technical

Specification 5.4.1.a for the licensees failure to establish adequate procedures to properly

preplan and perform maintenance that affected the performance of the B reactor protection

system motor generator set. Specifically, due to inadequate procedures for troubleshooting

on the B reactor protection system motor generator set, the licensee failed to identify a

degraded capacitor that caused the B reactor protection system motor generator set output

breaker to trip, which resulted in a reactor scram. The licensee entered this issue into their

corrective action program as Condition Report CR-RBS-2014-06605 and replaced the

degraded field flash card capacitor.

This performance deficiency is more than minor, and therefore a finding, because it is

associated with the procedure quality attribute of the Initiating Events Cornerstone and

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.

Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination

Process (SDP) for Findings At-Power, Exhibit 1, Initiating Event Screening Questions, this

finding is determined to have a very low safety significance (Green) because the transient

initiator did not contribute to both the likelihood of a reactor trip and the likelihood that

mitigation equipment or functions would not have been available. This finding has an

evaluation cross-cutting aspect within the problem identification and resolution area because

the licensee failed to thoroughly evaluate this issue to ensure that the resolution addressed

the cause commensurate with its safety significance. Specifically, the licensee failed to

thoroughly evaluate the condition of the field flash card to ensure that the cause of the trip

had been correctly identified and corrected prior to returning the B reactor protection system

motor generator set to service [P.2]. (Section 2.7.a)

Cornerstone: Mitigating Systems

• Green. The team reviewed a self-revealing, non-cited violation of Technical

Specification 5.4.1.a for the licensees failure to establish, implement and maintain a

procedure required by Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.

-2-

Specifically, Procedure OSP-0053, Emergency and Transient Response Support

Procedure, Revision 22, which is required by Regulatory Guide 1.33, inappropriately

directed operations personnel to establish feedwater flow to the reactor pressure vessel

using the startup feedwater regulating valve as part of the post-scram actions. The startup

feedwater regulating valve operator characteristics are non-linear and not designed to

operate in the dynamic conditions immediately following a reactor scram. To correct the

inadequate procedure, the licensee implemented a change to direct operations personnel to

utilize one of the main feedwater regulating valves until the plant is stabilized. This issue

was entered in the licensees corrective action program as Condition

Report CR-RBS-2015-00657.

This performance deficiency is more than minor, and therefore a finding, because it is

associated with the procedure quality attribute of the Mitigating Systems Cornerstone and

adversely affected the cornerstone objective to ensure the availability, reliability, and

capability of systems that respond to initiating events to prevent undesirable consequences.

Specifically, the procedure directed operations personnel to isolate the main feedwater

regulating valves and control reactor pressure vessel level using the startup feedwater

regulating valve, whose operator was not designed to function in the dynamic conditions

associated with a post-scram event from high power, and this challenged the capability of

the system. The team performed an initial screening of the finding in accordance with

Inspection Manual Chapter 0609, Appendix A, The Significance Determination

Process (SDP) for Findings At-Power. Using Inspection Manual Chapter 0609, Appendix A,

Exhibit 2, Mitigating Systems Screening Questions, the team determined that the finding is

of very low safety significance (Green) because it: (1) was not a deficiency affecting the

design or qualification of a mitigating structure, system, or component, and did not result in a

loss of operability or functionality; (2) did not represent a loss of system and/or function;

(3) did not represent an actual loss of function of at least a single train for longer than its

technical specification allowed outage time, or two separate safety systems out-of-service

for longer than their technical specification allowed outage time; and (4) did not represent an

actual loss of function of one or more non-technical specification trains of equipment

designated as high safety-significant in accordance with the licensees maintenance rule

program. This finding has an evaluation cross-cutting aspect within the problem

identification and resolution area because the licensee failed to thoroughly evaluate this

issue to ensure that the resolution addressed the cause commensurate with its safety

significance. Specifically, the licensee failed to properly evaluate the design characteristics

of the startup feedwater regulating valve operator before implementing the procedure to use

the valve for post-scram recovery actions [P.2]. (Section 2.7.b)

• Green. The team identified a non-cited violation of 10 CFR Part 50, Appendix B,

Criterion XVI, Corrective Action, for the licensees failure to assure a condition adverse to

quality was promptly identified. Specifically, the licensee failed to identify, that reaching the

reactor pressure vessel water Level 8 (high) setpoint, on December 25, 2014, was an

adverse condition, and as a result, failed to enter it into the corrective action program. To

restore compliance, the licensee entered this issue into their corrective action program as

Condition Report CR-RBS-2015-00620 and commenced a causal analysis for Level 8 (high)

trips.

-3-

This performance deficiency is more than minor, and therefore a finding, because it is

associated with the equipment performance attribute of the Mitigating Systems Cornerstone

and adversely affected the cornerstone objective to ensure the availability, reliability, and

capability of systems that respond to initiating events to prevent undesirable consequences.

Specifically, failure to identify Level 8 (high) conditions and unplanned automatic actuations

as conditions adverse to quality, would continue to result in the undesired isolation of

mitigating equipment including reactor feedwater pumps, the high pressure core spray

pump, and the reactor core isolation cooling pump. The team performed an initial screening

of the finding in accordance with Inspection Manual Chapter 0609, Appendix A, The

Significance Determination Process (SDP) for Findings At-Power. Using Inspection Manual

Chapter 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, the team

determined that the finding is of very low safety significance (Green) because it: (1) was not

a deficiency affecting the design or qualification of a mitigating structure, system, or

component, and did not result in a loss of operability or functionality; (2) did not represent a

loss of system and/or function; (3) did not represent an actual loss of function of at least a

single train for longer than its technical specification allowed outage time, or two separate

safety systems out-of-service for longer than their technical specification allowed outage

time; and (4) did not represent an actual loss of function of one or more non-technical

specification trains of equipment designated as high safety-significant in accordance with

the licensees maintenance rule program. This finding has an avoid complacency

cross-cutting aspect within the human performance area because the licensee failed to

recognize and plan for the possibility of mistakes, latent issues, and inherent risk, even while

expecting successful outcomes. Specifically, the licensee tolerated leakage past the

feedwater regulating valves, did not plan for further degradation, and the condition ultimately

resulted in the Level 8 (high) trip of the running reactor feedwater pump on December 25,

2014 [H.12]. (Section 2.7.c)

• TBD. The team identified an apparent violation of 10 CFR 55.46(c)(1), Plant-Referenced

Simulators, for the licensees failure to maintain the simulator so it would demonstrate

expected plant response to operator input and to normal, transient, and accident conditions

to which the simulator has been designed to respond. As of January 30, 2015, the licensee

failed to maintain the simulator consistent with actual plant response for normal and

transient conditions related to feedwater flows, alarm response, and behavior of the startup

feedwater regulating valve controller. Specifically, the River Bend Station simulator failed to

correctly model feedwater flows and resulting reactor vessel level response following a

scram, failed to provide the correct alarm response for a loss of a reactor protection system

motor generator set, and failed to correctly model the behavior of the startup feedwater

regulating valve controller. As a result, operations personnel were challenged in their

control of the plant during a reactor scram that occurred on December 25, 2014. This issue

has been entered into the corrective action program as Condition

Report RBS-CR-2015-01261, which includes actions to initiate simulator discrepancy

reports, investigate and resolve the potential fidelity issues, and provide training to

operations personnel on simulator differences.

This performance deficiency is more than minor, and therefore a finding, because it is

associated with the human performance attribute of the Mitigating Systems Cornerstone and

adversely affected the cornerstone objective of ensuring availability, reliability, and capability

-4-

of systems needed to respond to initiating events to prevent undesired consequences.

Specifically, the incorrect simulator response adversely affected the operations personnels

ability to assess plant conditions and take actions in accordance with approved procedures

during the December 25, 2014, scram. The team performed an initial screening of the

finding in accordance with inspection Manual Chapter 0609, Appendix A, The Significance

Determination Process (SDP) for Findings At-Power, Attachment 4, Initial Characterization

of Findings. Using Inspection Manual Chapter 0609, Attachment 4, Table 3, SDP

Appendix Router, the team answered yes to the following question: Does the finding

involve the operator licensing requalification program or simulator fidelity? As a result, the

team used Inspection Manual Chapter 0609, Appendix I, Licensed Operator Requalification

Significance Determination Process (SDP), and preliminarily determined the finding was of

low to moderate safety significance (White) because the deficient simulator performance

negatively impacted operations personnel performance in the actual plant during a

reportable event (reactor scram). This finding has an evaluation cross-cutting aspect within

the problem identification and resolution cross-cutting area because the licensee failed to

thoroughly evaluate this issue to ensure that the resolution addressed the extent of condition

commensurate with its safety significance. Specifically, the licensees evaluation of the

fidelity issue identified by the NRC in March 2014, focused on other training areas that used

simulation, rather than evaluating the simulator modelling for additional fidelity

discrepancies [P.2]. (Section 2.7.d)

• Green. The team identified a finding for the licensees failure to follow written procedures for

classifying deficient plant conditions as operator workarounds and providing compensatory

measures or training in accordance with fleet Procedure EN-OP-117, Operations

Assessment Resources, Revision 8. A misclassification of these conditions resulted in the

failure of the operations department to fully assess the impact these conditions had during a

plant transient. The failure to identify operator workarounds contributed to complications

experienced during reactor scram recovery on December 25, 2014. The licensee entered

this issue into their corrective action program as Condition Report CR-RBS-2015-00795.

This performance deficiency is more than minor, and therefore a finding, because it had the

potential to lead to a more significant safety concern if left uncorrected. Specifically, the

performance deficiency contributed to complications experienced by the station when

attempting to restore feedwater following a scram on December 25, 2014. The team

performed an initial screening of the finding in accordance with Inspection Manual

Chapter 0609, Appendix A, The Significance Determination Process (SDP) for

Findings At-Power. Using Inspection Manual Chapter 0609, Appendix A, Exhibit 2,

Mitigating Systems Screening Questions, the team determined this finding is of very low

safety significance (Green) because it: (1) was not a deficiency affecting the design or

qualification of a mitigating structure, system, or component, and did not result in a loss of

operability or functionality; (2) did not represent a loss of system and/or function; (3) did not

represent an actual loss of function of at least a single train for longer than its technical

specification allowed outage time, or two separate safety systems out-of-service for longer

than their technical specification allowed outage time; and (4) did not represent an actual

loss of function of one or more non-technical specification trains of equipment designated as

high safety-significant in accordance with the licensees maintenance rule program. This

finding has a consistent process cross-cutting aspect in the area of human performance

-5-

because the licensee failed to use a consistent, systematic approach to making decisions

and failed to incorporate risk insights as appropriate. Specifically, no systematic approach

was enacted in order to properly classify deficient conditions [H.8]. (Section 2.7.e)

-6-

REPORT DETAILS

1. Basis for Special Inspection

On December 25, 2014, at 8:37 a.m., River Bend Station scrammed from 85 percent

power following a trip of the B reactor protection system (RPS) motor generator (MG)

set. At the time of the MG set trip, a Division 1 half scram existed due to an unrelated

equipment issue with a relay for the Number 2 turbine control valve fast closure RPS

function. The combination of the B RPS MG set trip and the Division 1 half scram

resulted in a scram of the reactor.

The following equipment issues occurred during the initial scram response.

• An unexpected Level 8 (high) reactor water level signal at +51 was received which

resulted in tripping the running reactor feedwater pumps (RFPs).

• Following reset of the Level 8 (high) reactor water level signal, operations personnel

were unable to start RFP C. They responded by starting RFP A at a vessel level of

+25. The licensee subsequently determined that the circuit breaker (Magne Blast

type) for RFP C did not close.

• Following the start of RFP A, the licensee attempted to open the startup feedwater

regulating valve (SFRV) but was unsuccessful prior to the Level 3 (low) reactor water

level trip setpoint at +9.7. The licensee then opened main feedwater regulating

valve (FRV) C to restore reactor vessel water level. The lowest level reached

was +8.1. Subsequent troubleshooting revealed a faulty manual function control

card. The card was replaced by the licensee and the SFRV was used on the

subsequent plant startup.

Following restoration of reactor vessel water level, the plant was stabilized in Mode 3. A

plant startup was conducted on December 27, 2014, with RPS bus B being supplied by

its alternate power source. During power ascension following startup, RFP B did not

start. The licensee re-racked its associated circuit breaker and successfully started

RFP B. The licensee did not investigate the cause of RFP B failing to start.

Management Directive 8.3, NRC Incident Investigation Program, was used to evaluate

the level of NRC response for this event. In evaluating the deterministic criteria of

Management Directive 8.3, it was determined that the event: (1) included multiple

failures in the feedwater system which is a short term decay heat removal mitigating

system; (2) involved two Magne Blast circuit breaker issues which could possibly have

generic implications regarding the licensees maintenance, testing, and operating

practices for these components including safety-related breakers in the high pressure

core spray system; and (3) involved several issues related to the ability of operations to

control reactor vessel level between the Level 3 (low) and Level 8 (high) trip setpoints

following a reactor scram. Since the deterministic criteria were met, the trip was

evaluated for risk. The preliminary Estimated Conditional Core Damage Probability was

determined to be 1.2E-6.

-7-

Based on the deterministic criteria and risk insights related to the multiple failures of the

feedwater system, the potential generic concern with the Magne Blast circuit breakers,

and the issues related to the licensees operations departments inability to control

reactor vessel level between the Level 3 (low) and Level 8 (high) setpoints following a

reactor scram, Region IV determined that the appropriate level of NRC response was to

conduct a Special Inspection.

This Special Inspection is chartered to identify the circumstances surrounding this event,

determine if there are adverse generic implications, and review the licensees actions to

address the causes of the event.

The team used NRC Inspection Procedure 93812, Special Inspection Procedure, to

conduct the inspection. The inspections included field walkdowns of equipment,

interviews with station personnel, and reviews of procedures, corrective action

documents, and design documentation. A list of documents reviewed is provided in

Attachment 1 of this report; the Special Inspection Charter is included as Attachment 2.

2. Inspection Results

2.1 Charter Item 2: Develop a complete sequence of events related to the reactor scram

that occurred on December 25, 2014.

a. Inspection Scope

The team developed and evaluated a timeline of the events leading up to, during, and

after the reactor scram. This includes troubleshooting activities and plant startup. The

team developed the timeline, in part, through a review of work orders, action requests,

station logs, and interviews with station personnel. The team created the following

timeline during their review of the events related to the reactor trip that occurred on

December 25, 2014.

Date/Time Activity

December 6, 2014

10:12 a.m. A Division 2 half-scram was received from loss of the

B RPS MG set, licensee initiated Condition

Report CR-RBS-2014-06233

10:17 a.m. The RPS bus B was transferred to the alternate power

supply, Division 2 half-scram was reset

-8-

Date/Time Activity

December 13, 2014

12:35 p.m. The B RPS MG set was restored

December 16, 2014

9:30 p.m. The RPS bus B was placed on B RPS MG set

December 23, 2014

7:59 a.m. The licensee commenced a reactor downpower to

85 percent to support maintenance on RFP B

08:30 a.m. The RFP B was secured to support maintenance

10:28 a.m. A Division 1 half-scram signal from the turbine control

valve 2 fast closure relay was received, licensee initiated

Condition Report CR-RBS-2014-06581

2:21 p.m. The Division 1 half-scram signal was reset by bypassing the

turbine control valve fast closure signal

10:00 p.m. RPS channel A placed in trip condition to satisfy Technical

Specification 3.3.1.1

December 25, 2014

8:37 a.m. Reactor scram due to loss of RPS bus B

8:39 a.m. Feedwater master controller signal caused all FRVs to close,

feedwater continued injecting at 520,000 lbm/hr (leakby

through valves), reactor pressure vessel (RPV) water level at

27.8

8:40 a.m. RFP A was secured per procedure, RPV water level ~ 43,

feedwater flow lowered to 426,400 lbm/hr (leakby through

valves)

-9-

Date/Time Activity

8:41 a.m. Reactor water level reached Level 8 (high) condition, RFP C

(only running RFP) trips

8:42 a.m. All FRVs and associated isolation valves were closed by

operations personnel and the SFRV placed in AUTO with a

setpoint at 18 per procedure

8:45 a.m. Reactor water level dropped below 51 allowing reset of

Level 8 (high) signal and restart of RFPs

8:50 a.m. RFP C failed to start, no trip flags on RFP breaker, RPV

water level ~ 33 and lowering, licensee initiated Condition

Report CR-RBS-2014-06601

8:52 a.m. Operations personnel started RFP A

8:54 a.m. Operations personnel reset the reactor scram signal on

Division 2 of RPS only, RPV water level ~ 17 and lowering

8:54 a.m. The SFRV did not respond as expected in the automatic

mode. Operations personnel attempted to control the SFRV

in Manual, however it did not respond. As a result,

operations personnel began placing the FRV C in service,

licensee initiated Condition Report CR-RBS-2014-06602

8:56 a.m. Water level reached Level 3 (low) and actuated a second

reactor scram signal, RPV water level reached ~ 8.1,

operations personnel completed placing FRV C in service

and reactor water level began to rise

8:57 a.m. RPV water level rose above 9.7, reactor scram signal clear

8:58 a.m. Operations personnel reset the reactor scram signal on

Division 2 of RPS only, RPV water level ~ 15.7

December 27, 2014

12:53 a.m. The plant entered Mode 2 and commenced a reactor startup

-10-

Date/Time Activity

10:00 a.m. RFP C failed to start due to the associated minimum flow

valve not fully opening, licensee initiated Condition

Report CR-RBS-2014-06653

10:18 a.m. Operations personnel started RFP A

5:41 p.m. The plant entered Mode 1

December 28, 2014

7:23 p.m. RFP B failed to start, licensee initiated Condition

Report CR-RBS-2014-06649

8:43 p.m. The RFP B breaker was racked out and then racked back in

8:49 p.m. RFP B was successfully started

b. Findings and Observations

In reviewing the sequence of events and developing the timeline, the team reviewed the

licensees maintenance and troubleshooting activities associated with the B RPS MG set

failure on December 6, 2014. Additionally, the team reviewed the operability

determination to evaluate the licensees basis for returning the B RPS MG set to service.

The licensees troubleshooting practices lacked the technical rigor and attention to detail

necessary to identify and correct the deficient B RPS MG set conditions. On several

occasions, the team noted that the licensee chose the expedient solution rather than

complete an evaluation to determine that corrective actions resolved the deficient

condition. Specifically, the licensee chose to restore the B RPS MG set to service

without fully understanding the failure mechanism. Other examples included the

licensees choice to have operations personnel rack in and out breakers, and have

maintenance personnel manually operate a limit switch, on the makeup and start logic

for the RFP C minimum flow valve, when the RFP did not start. As indicated above, the

licensee performed these compensatory actions instead of evaluating and correcting the

issue.

Based upon a review of the events leading up to the reactor scram, the team determined

the licensee failed to properly preplan and perform maintenance on the B RPS MG set

after the failure that occurred on December 6, 2014. Further discussion involving the

licensees failure to adequately troubleshoot, identify, and correct degraded components

on the B RPS MG set, prior to returning it to service, is included in Section 2.7.a. of this

report.

-11-

Additionally, the team reviewed the procedures that operations personnel used to

respond to the reactor scram and determined the licensee failed to provide adequate

procedures to respond to a post-trip transient. Further discussion on the procedure

prescribing activities affecting quality not being appropriate for the circumstances is

included in Section 2.7.b. of this report.

2.2 Charter Items 3 and 8: Review the licensees root cause analysis and corrective actions

from the current and previous scrams with complications.

a. Inspection Scope

At the time of the inspection, the root cause report for the December 25, 2014, scram

had not been completed. To ensure the licensee was conducting the cause evaluation

at a level of detail commensurate with the significance of the problem, the team

reviewed corrective action procedures, met with members of the root cause team, and

reviewed prior related corrective actions.

The procedures reviewed by the team included quality related Procedure EN-LI-118,

Cause Evaluation Process, Revision 21, and quality related Procedure EN-LI-102,

Corrective Action Program, Revision 24.

The licensees approach for the December 25, 2014, scram causal evaluation was to

use several detailed evaluations as input to the overall root cause. Specifically, the

licensee performed an apparent cause evaluation, under Condition

Report CR-RBS-2014-06696, to understand the failure of Division 2 RPS equipment.

The licensee performed an apparent cause evaluation under Condition

Report CR-RBS-2014-06602, to review the conditions that resulted in the additional

reactor water Level 3 (low) trip, after the initial scram. The licensee also performed an

apparent cause evaluation, under Condition Report CR-RBS-2014-06581, to review the

turbine control valve fast closure circuit failure that resulted in the Division 1 half-scram

signal. All of these evaluations were reviewed under the parent root cause Condition

Report CR-RBS-2014-06605.

The licensee used multiple methods in their causal evaluations that included: event and

causal factor charting, barrier analysis, and organizational and programmatic failure

mode trees. The licensees charter for the root cause evaluation required several

periodic meetings with the members of the different causal analysis teams. It also

required a pre-corrective action review board update and review, a formal corrective

action review board approval, and an external challenge review of the approved root

cause report.

The NRC team also reviewed corrective actions to address complications encountered

during previous reactor scrams. Specifically, the following NRC inspection reports were

reviewed and the related licensee corrective actions were assessed:

• 05000458/2002002, Integrated Inspection Report, July 24, 2002, ML022050206

-12-

• 05000458/2006013, Special Inspection Team Report, March 1, 2007,

ML070640396

• 05000458/2012009, Augmented Inspection Team Report, August 7, 2012,

ML12221A233

• 05000458/2012012, Supplemental Inspection Report, December 28, 2012,

ML12363A170

b. Findings and Observations

The NRC team found the licensees root cause team members had met the

organizational diversity and experience requirements of their procedures. The team

reviewed the qualifications of the members of the root cause team and determined they

were within the correct periodicity.

At the time of the inspection, there were 4 root cause and 10 apparent cause evaluations

in progress. The team determined the root cause analyses were conducted at a level of

detail commensurate with the significance of the problems.

In reviewing corrective actions for prior scrams, the team noted that there have been five

unplanned reactor scrams in the past five years, including the December 25, 2014,

event. Of those five scrams, two involved Level 8 (high) reactor water level signal trips

of all running feedwater pumps. Based upon a review of prior scrams and associated

corrective actions, the team determined that the licensee does not have an appropriately

low threshold for recognizing Level 8 (high) reactor water level signal trips as an adverse

condition, and entering that adverse condition into their corrective action program.

Otherwise, the team determined that the licensees corrective actions to address

complications, encountered during previous reactor scrams, were adequate. Further

discussion involving the licensees failure to identify Level 8 (high) reactor water level

signal trips as adverse conditions is included in Section 2.7.c of this report.

2.3 Charter Item 4: Determine the cause of the unexpected Level 8 (high) water level trip

signal.

a. Inspection Scope

To determine the cause of the unexpected Level 8 (high) reactor water level trip on

December 25, 2014, the NRC team reviewed control room logs and graphs of key

reactor parameters to assess the plants response to transient conditions. This

information was then compared to the actions taken by operations personnel in the

control room per abnormal and emergency operating procedure requirements.

Section 5.1 of Procedure AOP-0001, Reactor Scram, Revision 30, required operations

personnel to verify that the feedwater system was operating to restore reactor water

level. This was accomplished using an attachment of Procedure OSP-0053,

Emergency and Transient Response Support Procedure, Revision 22. Specifically,

Attachment 16, Post Scram Feedwater/Condensate Manipulations Below 5% Reactor

-13-

Power, required transferring reactor water level control to the startup feedwater system

after reactor water level had been stabilized in the prescribed band.

Only four minutes elapsed from the time of the scram until the time the Level 8 (high)

reactor water level isolation signal was reached. Consequently, operations personnel

did not have sufficient time to gain control and stabilize reactor vessel level in the

required band.

To gain an understanding of issues affecting systems at the time of the scram, the NRC

team met with system engineers for the feedwater system, feedwater level control

system, and remotely operated valves. Discussions with engineering included system

health reports, open corrective actions from condition reports, licensee event reports,

design data for systems, startup testing and exceptions, post-trip reactor water level

setpoint setdown parameters, open engineering change packages, and requirements for

engineering to analyze post-transient plant data.

b. Findings and Observations

Operations personnel responded to the events in accordance with procedure

requirements. The NRC did not identify any performance deficiencies related to

immediate or supplemental actions taken by control room staff during the transient.

However, operations personnel stated that the plant did not respond in a manner

consistent with their simulator training.

Based on review of operations personnel response to the event and the training received

from the simulator, the NRC team determined that the licensee did not maintain the

simulator in a condition that accurately represented actual plant response. On April 10,

2015, the licensee provided a white paper with additional information related to the

modeling of the plant-referenced simulator. Further discussion involving the licensees

failure to maintain the simulator is included in Section 2.7.d of this report.

The NRC team determined that the plant did not respond per the design as described in

the final safety analysis report. Specifically, the feedwater level control system and

feedwater systems were designed to automatically control reactor water level in the

programmed band post-scram. During the December 25, 2014 scram, reactor water

level quickly (within 4 minutes) rose to a Level 8 (high) trip. By design, reactor water

level should rapidly lower after the initial level transient from core void collapse, rise as

feedwater compensates for the level change, and then return to the programed

setpoint. A Level 8 (high) trip should not occur. The team determined that significant

leakage past the feedwater isolation valves caused the rapid rise in reactor water level.

Operations personnel were unable to compensate for the rapid change in reactor vessel

level. The licensee initially discovered the adverse condition during startup testing in

1986, and allowed the condition to degrade without effective corrective actions.

The team noted that significant post-trip or post-transient plant performance data was

available to system engineers, but review of this data was not prioritized by the licensee.

The review of plant transient data was primarily driven by the licensees root cause team

-14-

charter or by self-assigned good engineering practices. At the time of this inspection,

the licensee had not quantified the amount of leakage past the FRVs, although the

scram and subsequent startup had occurred one month earlier. The NRC team

observed that there was a potential to miss important trends in plant performance

without a more timely review.

2.4 Charter Item 5: Review the effectiveness of licensee actions to address known

equipment degradations that could complicate post-scram response by operations

personnel.

a. Inspection Scope

The NRC team reviewed licensee procedures for classifying and addressing plant

conditions that may challenge operations personnel while performing required actions

per procedures during normal and off-normal conditions.

The team reviewed the licensees current list of operator workarounds and operator

burdens. Specifically, the team was looking for any known equipment issues that could

complicate post-scram response by operations personnel.

b. Findings and Observations

The team determined the licensee did not properly classify several deficient plant

conditions as operator workarounds in accordance with fleet Procedure EN-OP-117,

Operations Assessment Resources, Revision 8. Further discussion related to the

failure to classify plant deficiencies as operator workarounds is included in Section 2.7.e

of this report.

2.5 Charter Items 6 and 7: Review the licensees maintenance, testing and operating

practices for Magne Blast circuit breakers including the causes and corrective actions

taken to address the failure of the RFPs to start.

a. Inspection Scope

The team reviewed the final safety analysis report, system description, the current

system health report, selected drawings, maintenance and test procedures, and

condition reports associated with Magne Blast breakers. The team also performed

walkdowns and conducted interviews with system engineering and design engineering

personnel to ensure circuit breakers were capable of performing their design basis

safety functions. Specifically, the team reviewed:

• Vendor and plant single line, schematic, wiring, and layout drawings

• Circuit breaker preventive maintenance inspection and testing procedures

• Vendor installation and maintenance manuals

• Preventive maintenance and surveillance test procedures

• Completed surveillance test and preventive maintenance results

• Corrective actions and modifications

-15-

b. Findings and Observations

Unresolved Item (URI) - Vendor and Industry Recommended Testing Adequacy on

Safety-related and Safety-significant Circuit Breakers

Introduction. The team identified an unresolved item related to the licensees breaker

maintenance and troubleshooting programs for safety-related and safety-significant

circuit breakers. The charter tasked the team with inspecting the issues associated with

Magne Blast breaker problems that occurred during and after the December 25, 2014,

scram. The NRC team determined that breaker maintenance and troubleshooting

practices extended beyond the Magne Blast breakers. The team identified that there

were potential issues with safety-related Master Pact breakers and determined that

maintenance procedures used to ensure that 4160 V and 13.8 kV safety-related and

safety-significant breakers were being maintained and overhauled in a timely manner

may not conform to industry recommended standards.

Description. The team identified that the licensees maintenance programs for Division I,

II, III, and non-safety 4160 V and 13.8 kV breakers installed in the plant may not meet

the standards recommended by the vendor, corporate, or Electric Power Research

Institute (EPRI) guidelines. The licensees programs were based on EPRI

documents TR-106857-V2 and TR-106857-V3, which were preventive maintenance

program bases for low and medium voltage switchgear. However, the licensee

appeared to only implement portions of the recommended maintenance program, and

were not able to provide the team with engineering analyses or technical bases to justify

the changes. The EPRI guidance was developed specifically for Magne Blast breakers

based on industry operating experience, NRC Information Notices, and General Electric

SILs/SALs. The NRC team was concerned that the licensee may not have performed

the entire vendor or EPRI recommended tests, inspections, and refurbishments on the

breakers since they were installed. The aggregate impact of missing these preventive

maintenance tasks needs to be evaluated to determine if the reliability of the affected

breakers has been degraded.

Pending further evaluation of the above issue by the licensee and subsequent review by

NRC inspectors, this issue will be tracked as URI 05000458/2015009-01, Vendor and

Industry Recommended Testing Adequacy on Safety-related and Safety-significant

Circuit Breakers.

2.6 Charter Item 9: Evaluate pertinent industry operating experience and potential

precursors to the event, including the effectiveness of any action taken in response to

the operating experience.

a. Inspection Scope

The team evaluated the licensees application of industry operating experience related to

this event. The team reviewed applicable operating experience and generic NRC

communications with a specific emphasis on Magne Blast breaker maintenance

practices, to assess whether the licensee had appropriately evaluated the notifications

-16-

for relevance to the facility and incorporated applicable lessons learned into station

programs and procedures.

b. Findings and Observations

Other than the URI described in Section 2.5, of this report, no additional findings or

observations were identified.

2.7 Specific findings identified during this inspection.

a. Failure to Establish Adequate Procedures to Perform Maintenance on Equipment that

can Affect Safety-Related Equipment

Introduction. The team reviewed a Green, self-revealing, non-cited violation of Technical

Specification 5.4.1 for the licensees failure to establish adequate procedures to properly

preplan and perform maintenance that affected the performance of the B RPS MG set.

Specifically, due to inadequate procedures for troubleshooting on the B RPS MG set, the

licensee failed to identify a degraded capacitor that caused the B RPS MG set output

breaker to trip, which resulted in a reactor scram.

Description. On December 6, 2014, during normal plant operations, RPS bus B

unexpectedly lost power because of a B RPS MG set failure, which resulted in a

Division 2 half scram and a containment isolation signal. The RPS system is designed

to cause rapid insertion of control rods (scram) to shut down the reactor when specific

variables exceed predetermined limits. The RPS power system, of which the B RPS MG

set is a component, is designed to provide power to the logic system that is part of the

reactor protection system.

The licensees troubleshooting teams identified both the super spike suppressor card

and the field flash card as the possible causes of the B RPS MG set failure. The

licensee replaced the super spike suppressor card. While inspecting the field flash card,

a strand of wire from one of the attached leads was found nearly touching a trace on the

circuit board. A continuity test was performed while the field flash card was being

tapped and no ground was observed. A ground was observed when forcibly pushing

down on the wire. The licensee believed that the wire strand most likely caused the

B RPS MG set trip. The licensee removed the wire strand and re-installed the field flash

card without any further troubleshooting. Operations personnel returned the B RPS MG

set to service on December 16, 2014.

On December 25, 2014, while operating at 85 percent power, a reactor scram occurred

due to a Division 2 RPS trip concurrent with a Division 1 RPS half-scram signal that was

present at the time. The Division 1 half-scram signal was received on December 23,

2014, because of a turbine control valve fast closure signal. Troubleshooting for the

cause of the Division 1 half-scram was ongoing when the Division 2 RPS trip occurred.

This resulted in a full RPS actuation and an automatic reactor scram. Electrical

protection assembly breakers 3B/3D and the B RPS MG set output breaker were found

tripped, similar to the conditions noted following the loss of the B RPS MG set on

December 6, 2014. The subsequent failure modes analysis and troubleshooting teams

-17-

identified the probable cause of the failure of the B RPS MG set output breaker was an

intermittent failure of the field flash card. A more detailed inspection of the field flash

card revealed that a 10 microfarad capacitor had been subjected to minor heating over a

long period of time. As a result, the degraded component contributed to a reactor

scram. The capacitor on the field flash card in the Division 2 RPS MG set was replaced.

Analysis. Failure to establish and implement procedures to perform maintenance to

correct adverse conditions on B RPS MG set equipment that can affect the performance

of the safety-related reactor protection system was a performance deficiency. This

performance deficiency is more than minor, and therefore a finding, because it is

associated with the procedure quality attribute of the Initiating Events Cornerstone and

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.

The team performed an initial screening of the finding in accordance with Inspection

Manual Chapter (IMC) 0609, Appendix A, The Significance Determination

Process (SDP) for Findings At-Power. Using IMC 0609, Appendix A, Exhibit 1,

Initiating Event Screening Questions, this finding is determined to have very low safety

significance because the transient initiator did not contribute to both the likelihood of a

reactor trip and the likelihood that mitigation equipment or functions would not have been

available. This finding has an evaluation cross-cutting aspect within the problem

identification and resolution area because the licensee failed to thoroughly evaluate the

failure of the B RPS MG set to ensure that the resolution addressed the cause

commensurate with its safety significance. Specifically, the licensee failed to thoroughly

evaluate the condition of the field flash card to ensure that the cause of the trip had been

correctly identified and corrected prior to returning the B MG set to service [P.2].

Enforcement. Technical Specification 5.4.1.a states, in part, that written procedures

shall be established, implemented, and maintained covering the applicable procedures

recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.

Regulatory Guide 1.33, Appendix A, Section 9.a., states, in part, that, maintenance that

can affect the performance of safety-related equipment should be properly preplanned

and performed in accordance with written procedures, documented instructions, or

drawings appropriate to the circumstances. Contrary to the above, on December 6,

2014, the licensee failed to establish adequate procedures to properly preplan and

perform maintenance on the B RPS MG set that ultimately affected the performance of

safety-related B RPS equipment. Specifically, due to inadequate procedures for

troubleshooting on the B RPS MG set, the licensee failed to identify a degraded

capacitor on the B RPS MG set that caused its output breaker to trip, prior to returning it

to service. On December 25, 2014, this degraded capacitor caused the B RPS MG set

breaker to trip causing a loss of power to the B RPS bus which resulted in a reactor

scram. The licensee entered this issue into their corrective action program as Condition

Report CR-RBS-2014-06605 and replaced the degraded field flash card capacitor.

Because this finding is determined to be of very low safety significance and has been

entered into the licensees corrective action program this violation is being treated as a

non-cited violation consistent with Section 2.3.2.a of the NRC Enforcement Policy:

-18-

NCV 05000458/2015009-02, Failure to Establish Adequate Procedures to Perform

Maintenance on Equipment that can Affect Safety-Related Equipment.

b. Failure to Provide Adequate Procedures for Post-Scram Recovery

Introduction. The team reviewed a Green, self-revealing, non-cited violation of Technical

Specification 5.4.1.a for the licensees failure to establish, implement and maintain a

procedure required by Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.

Specifically, Procedure OSP-0053, Emergency and Transient Response Support

Procedure, Revision 22, inappropriately directed operations personnel to establish

feedwater flow to the reactor pressure vessel using the SFRV as part of the post-scram

actions. The SFRV operator characteristics are non-linear and not designed to operate

in the dynamic conditions immediately following a reactor scram from power.

Description. On November 18, 2013, the licensee modified Procedure OSP-0053,

Attachment 16, due to excessive leakage across the main FRVs and verified the

adequacy of the change using the simulator. The licensee did not realize that the

simulator incorrectly modeled the operating characteristics of the SFRV.

On December 25, 2014, following a reactor scram, operations personnel attempted to

implement Procedure OSP-0053, Attachment 16, Post Scram Feedwater/Condensate

Manipulations Below 5% Reactor Power. When the SFRV did not begin to open as

RPV level approached the level setpoint, operations personnel thought the SFRV had

failed in automatic and placed the valve controller in manual. Unknown to operations

personnel, the manual control of the valve was inoperable due to a faulty card. Unable

to control the SFRV, operations personnel then began placing one of the main FRVs

back in service. The isolation valves for the FRV are motor-operated and take

approximately 90 seconds to reposition. Because of the delay in restoring feedwater to

the RPV, a second Level 3 (low) water level reactor scram signal occurred.

The NRC team determined that plant data indicated the SFRV does not open on a

slowly decreasing RPV water level until the controller signal reaches approximately

12.5 percent error or about 3 inches below the RPV water level setpoint on the

controller. The SFRV in the simulator opens as soon as the controller open signal is

greater than 0.0 percent error. When the licensee became aware of the SFRV design

operating parameters, they determined that the SFRV was not designed to respond to

the dynamic conditions that exist during post-scram recovery, and revised

Procedure OSP-0053, Attachment 16, to continue using the main FRVs during

post-scram recovery actions.

Analysis. The licensees failure to provide adequate guidance in Procedure OSP-0053

for post-scram recovery actions was a performance deficiency. This performance

deficiency is more than minor, and therefore a finding, because it is associated with the

procedure quality attribute of the Mitigating Systems Cornerstone and adversely affected

the cornerstone objective to ensure the availability, reliability, and capability of systems

that respond to initiating events to prevent undesirable consequences. Specifically, the

procedural guidance that directed operations personnel to establish feedwater flow to

-19-

the RPV using the SFRV as part of the post-scram actions adversely affected the

capability of the feedwater systems that respond to prevent undesirable consequences.

The system capability was adversely affected since the valve operator characteristics

are non-linear and not designed to operate in the dynamic conditions immediately

following a reactor scram from high power levels.

The team performed an initial screening of the finding in accordance with IMC 0609,

Appendix A, The Significance Determination Process (SDP) for Findings At-Power.

Using IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, the

finding was of very low safety significance (Green) because it: (1) was not a deficiency

affecting the design or qualification of a mitigating structure, system, or component, and

did not result in a loss of operability or functionality; (2) did not represent a loss of

system and/or function; (3) did not represent an actual loss of function of at least a single

train for longer than its technical specification allowed outage time, or two separate

safety systems out-of-service for longer than their technical specification allowed outage

time; and (4) did not represent an actual loss of function of one or more non-technical

specification trains of equipment designated as high safety-significant in accordance with

the licensees maintenance rule program.

This finding has an evaluation cross-cutting aspect within the problem identification and

resolution area because the licensee failed to thoroughly evaluate this issue to ensure

that the resolution addressed the cause commensurate with its safety significance.

Specifically, the licensee failed to properly evaluate the design characteristics of the

SFRV operator before implementing procedural guidance for post-scram recovery

actions [P.2].

Enforcement. Technical Specification 5.4.1.a states, in part, that written procedures

shall be established, implemented, and maintained covering the applicable procedures

recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.

Regulatory Guide 1.33, Appendix A, Section 6.u., identifies procedures for responding to

a Reactor Trip as required procedures. Procedure OSP-0053, Attachment 16, Post

Scram Feedwater/Condensate Manipulations Below 5% Reactor Power, was a

procedure established by the licensee for responding to a reactor trip. Contrary to the

above, from March 3, 2010, until January 30, 2015, the licensee failed to establish,

implement and maintain Procedure OSP-0053, which directs operator actions for a

reactor trip. Specifically, Procedure OSP-0053 inappropriately directed operations

personnel to establish feedwater flow to the reactor pressure vessel using the SFRV as

part of the post-scram actions. The SFRV operator characteristics are non-linear and

not designed to operate in the dynamic conditions immediately following a reactor scram

from high power. Subsequent to the event, the licensee changed the procedure,

directing operations personnel to utilize one of the main FRVs until the plant was

stabilized. Because this finding is determined to be of very low safety significance and

has been entered into the licensees corrective action program as Condition

Report CR-RBS-2015-00657, this violation is being treated as a non-cited violation

consistent with Section 2.3.2.a of the NRC Enforcement Policy:

NCV 05000458/2015009-03, Failure to Provide Adequate Procedures for Post-scram

Recovery.

-20-

c. Failure to Identify High Reactor Water Level as a Condition Adverse to Quality

Introduction. The team identified a Green, non-cited violation of 10 CFR Part 50,

Appendix B, Criterion XVI, Corrective Action, for the licensees failure to assure a

condition adverse to quality was promptly identified. Specifically, the licensee failed to

identify that reaching the reactor pressure vessel water Level 8 (high) setpoint, on

December 25, 2014, was an adverse condition and enter it into the corrective action

program.

Description. On December 25, 2014, the licensee experienced a scram with

complications. The team reviewed the post-scram report as documented in

Procedure GOP-0003, Scram Recovery, Revision 24. During the scram, the licensee

experienced a Level 8 (high) reactor water condition approximately four minutes after the

scram. This high water level condition should not occur for a scram when main steam

isolation valves remain open and safety relief valves do not actuate.

The team noted that operations personnel followed their training and performed the

required post-scram actions. Those actions did not prevent the overfeeding of the

reactor vessel (which reached the Level 8 (high) setpoint), causing the RFPs to trip off

and would have caused isolation of other emergency core cooling systems, if actuated,

such as high pressure core spray and reactor core isolation cooling. The loss of all

feedwater contributed to the RPV water level lowering to a Level 3 (low) condition that

actuated a second reactor scram signal.

The team interviewed control room operations personnel, system engineers, and

corrective action staff regarding the plants response to the scram. Further, the team

reviewed plant parameter graphs, control room logs, alarm logs, design history, and

licensing basis documents, and determined that excessive leakage past the FRVs

caused the Level 8 (high) trip of all RFPs.

In reviewing the feedwater system data from the December 24, 2014, scram, the

licensee estimated 500,000 lbm/hr leaked past the closed FRVs. This represents

approximately 3 percent of the full-power feedwater flow and significantly exceeds the

design specification for leakage of 135,000-150,000 lbm/hr.

The licensee identified excessive leakage past the FRVs during testing in 1986. At the

time of inspection, the licensee could not produce any corrective actions taken to identify

or correct leakage past the FRVs. Further, the licensee had not quantified the amount of

leakage past the FRVs prior to the December 24, 2014, event and NRC Special

Inspection.

Procedure GOP-0003 provided a post-scram checklist to operations personnel to help

identify equipment and procedure problems that should be corrected prior to the reactor

startup. This document was then reviewed by the Offsite Safety Review Committee in

order to understand and confirm that the plant was safe to restart. Step 1.1 stated the

following:

-21-

Following a reactor scram from high power levels, there is an initial RPV level

Shrink of 20 to 40 inches followed by a Swell of approximately 10 to 20 inches.

The Feedwater Level Control System is programmed to ride out this shrink and

swell without overfilling the RPV.

In section 6.7 of Procedure GOP-003, the licensee documented that there was a control

system trip of RFPs due to reaching Level 8 (high). In section 6.12, however, the

licensee failed to document any off-normal trips (Level 8 (high) feed pump trips). In

Attachment 3 of GOP-003 Procedure, Analysis and Evaluations, Level 8 (high) was

mentioned as part of a timeline discussion but was not listed in the final section labeled

Corrective Actions Required Prior to Returning Unit to Service. This final section was

where condition reports were required for all items listed. By omitting Level 8 (high) from

the discussion, no corrective action document was generated for that condition.

The licensee did not identify that reaching reactor water Level 8 (high) was an adverse

condition. Therefore, the unexpected Level 8 (high) trip was not addressed prior to

startup on December 28, 2014.

The team reviewed the history of Level 8 (high) RFP trips and noted that similar issues

of concern were raised by the NRC in 2012. Specifically, a Supplemental Inspection,

performed in 2012, for a White performance indicator associated with reactor scrams

with complications documented the failure to recognize a Level 8 (high) trip as an

adverse condition and enter it into the corrective action program. This non-cited

violation was documented in NRC Inspection Report 05000458/2012012.

The team determined that the licensee did not have a sufficiently low threshold for

entering issues into their corrective action program for reactor water level transients.

Specifically, long-standing equipment issues associated with FRV leakage has led to the

licensee reaching reactor water Level 8 (high) during two reactor scrams in a three-year

period.

Analysis. The failure to identify Level 8 (high) reactor water level trips as adverse

conditions was a performance deficiency. This performance deficiency is more than

minor, and therefore a finding, because it is associated with the equipment performance

attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone

objective to ensure the availability, reliability, and capability of systems that respond to

initiating events to prevent undesirable consequences. Specifically, failure to identify

Level 8 (high) conditions and resulting actuations as conditions adverse to quality, would

continue to result in the undesired isolation of mitigating equipment including RFPs, the

high pressure core spray pump, and the reactor core isolation cooling pump.

The team performed an initial screening of the finding in accordance with IMC 0609,

Appendix A, The Significance Determination Process (SDP) for Findings At-Power.

Using IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, the

finding was of very low safety significance (Green) because it: (1) was not a deficiency

affecting the design or qualification of a mitigating structure, system, or component, and

did not result in a loss of operability or functionality; (2) did not represent a loss of

-22-

system and/or function; (3) did not represent an actual loss of function of at least a single

train for longer than its technical specification allowed outage time, or two separate

safety systems out-of-service for longer than their technical specification allowed outage

time; and (4) did not represent an actual loss of function of one or more non-technical

specification trains of equipment designated as high safety-significant in accordance with

the licensees maintenance rule program.

This finding has an avoid complacency cross-cutting aspect within the human

performance area because the licensee failed to recognize and plan for the possibility of

mistakes, latent issues, and inherent risk, even while expecting successful outcomes.

Specifically, the licensee tolerated excessive leakage past the FRVs, did not plan for

further degradation, and the condition ultimately resulted in the Level 8 (high) trip of the

running RFP on December 25, 2014 [H.12].

Enforcement. Title 10 of the Code of Federal Regulations, Part 50, Appendix B,

Criterion XVI, Corrective Action, requires, in part, that measures shall be established to

assure that conditions adverse to quality, such as failures, malfunctions, deficiencies,

deviations, defective material and equipment, and non-conformances are promptly

identified and corrected. Contrary to the above, from December 25, 2014, to

January 29, 2015, the licensee failed to assure that a condition adverse to quality was

promptly identified. Specifically, the licensee failed to identify that reaching the reactor

pressure vessel water Level 8 (high) setpoint, on December 25, 2014, was an adverse

condition and enter it into the corrective action program. To restore compliance, the

licensee entered this issue into their corrective action program as Condition

Report CR-RBS-2015-00620 to perform a causal analysis for Level 8 (high) trips. Since

the violation was of very low safety significance (Green), this violation is being treated as

a non-cited violation, consistent with Section 2.3.2.a of the Enforcement Policy:

NCV 05000458/2015009-04, Failure to Identify High Reactor Water Level as a

Condition Adverse to Quality.

d. Failure of the Plant-Referenced Simulator to Demonstrate Expected Plant Response

Introduction. The team identified an apparent violation of 10 CFR 55.46(c)(1), Plant-

Referenced Simulators, for the licensees failure to maintain the simulator so it would

demonstrate expected plant response to operator input and to normal, transient, and

accident conditions to which the simulator has been designed to respond. As of

January 30, 2015, the licensee failed to maintain the simulator consistent with actual

plant response for normal and transient conditions related to feedwater flows, alarm

response, and behavior of the SFRV controller. As a result, operations personnel were

challenged in their control of the plant during a reactor scram that occurred on

December 25, 2014.

Description. On December 25, 2014, River Bend Station was operating at 85 percent

power when a reactor scram occurred. On January 26, 2015, a Special Inspection was

initiated in response to this event. The Special Inspection team reviewed the event and

identified several simulator fidelity issues. Licensee Procedure EN-TQ-202, Simulator

Configuration Control, Revision 9, provided the process requirements necessary to

-23-

satisfy the guidelines for simulator testing, performance, and configuration control

specified by ANSI/ANS-3.5-2009. Standard ANSI/ANS-3.5-2009, Nuclear Power Plant

Simulators for Use in Operator Training and Examination, provides the simulator testing

requirements, as well as simulator configuration management to ensure simulator

fidelity. Specifically, as of January 30, 2015, the River Bend Station simulator failed to

model feedwater accurately and failed to model resulting reactor vessel level response

following a scram, failed to provide the correct alarm response for a loss of a RPS MG

set, and failed to correctly model the behavior of the SFRV controller. The simulator

modeling discrepancies and how these discrepancies affected plant response during the

plant trip are discussed below:

• The licensee stated their simulator modeled zero leakage across the FRV rather

than the actual leakage in the plant. General Electric record 0247.230-000-016,

Feedwater Control Valve Assembly - Purchase Specification, described the

total design leakage across all the FRVs was approximately 135,000 lbm/hr.

This is equal to approximately 1.1 percent full feedwater flow. The flow rate

across the FRVs measured in the plant on December 25, 2014, was

approximately 500,000 lbm/hr, which is approximately 3 percent full feedwater

flow. The rate of level change of the reactor vessel in the plant was larger than

operations personnel anticipated based on training received in the simulator.

ANSI/ANS-3.5-2009, Section 4.1.4(3), states, The simulator shall not fail to

cause an alarm or automatic action if the reference unit would have caused an

alarm or automatic action under identical circumstances. In this case, the

simulator under similar conditions did not reach the RPV water Level 8 (high)

condition and trip the RFPs, when the actual plant did.

• The licensees simulator did not correctly model all alarms that would be received

on a loss of power to the RPS. ANSI/ANS-3.5-2009, Section 4.1.4(3),

states, The simulator shall not fail to cause an alarm or automatic action if the

reference unit would have caused an alarm or automatic action under identical

circumstances. Although the licensee had identified this discrepancy on

December 11, 2014, and implemented a correction in the simulator model,

operations personnel had not received training nor were they notified of the

discrepancy. As a result, during the plant scram on December 25, 2014, the

alarms for drywell high pressure and RPV high pressure annunciated per the

facility design, operations personnel were not expecting the alarms because they

did not alarm in the simulator during training.

• The simulator SFRV responded differently than the actual SFRV in the reference

plant. ANSI/ANS-3.5-2009, Section 4.1.4(2) [for malfunctions], stated, Any

observable change in simulated parameters corresponds in direction to the

change expected from actual or best estimate response of the reference unit to

the malfunction. Plant data indicated the SFRV does not open on a slowly

decreasing RPV water level until the controller signal reaches approximately

12.5 percent or about 3 inches below the RPV water level setpoint of the

controller. The SFRV in the simulator opens as soon as the controller open

signal is greater than 0.0. Because the SFRV did not respond as expected,

-24-

operations personnel incorrectly believed the SFRV had failed in automatic

operation and placed the controller in manual. Due to an unrelated issue, the

manual function of the SFRV was unavailable.

Collectively, these modeling discrepancies negatively impacted licensed operations

personnel performance in the actual control room, during the event of December 25,

2014. Specifically, operations personnel were not able to control reactor vessel water

level during the reactor scram.

The team noted that the licensee similarly stated in Condition Report

CR-RBS-2015-00641 that, During an investigation into the report at the OSRC (Onsite

Safety Review Committee) for the SCRAM on December 25, 2014, that feed regulating

valve leakage (FRV) contributed to the Level 8 received reactor vessel, it was

determined by analysis that there is sufficient evidence that leakage by the Feedwater

Regulating Valves presents a significant challenge to Operations during a scram event.

On April 10, 2015, the licensee provided a white paper with additional information related

to the modeling of the plant-referenced simulator. Specifically, it provided the licensees

perspective with regard to the following issues raised by the NRC:

1. Two unexpected alarms on loss of Division II Reactor Protection System Power

2. Main Feedwater Regulating Valve Seat Leakage

3. Start-up Feedwater Regulating Valve Response

The licensee concluded that although they perceived that there were differences

between the simulator and the actual plant, they were considered to be minor. For each

of the items in question, the paper summarized that operator performance was not

impacted by simulator modeling. The team considered the information in the white

paper, and disagreed with the licensees conclusions. Some of the information provided,

however, did improve the teams understanding of the modeling deficiencies.

Analysis. The failure to maintain the plant-referenced simulator so that it would

demonstrate expected plant response to operator input and to normal and transient

conditions was a performance deficiency. This performance deficiency is more than

minor, and therefore a finding, because it is associated with the human performance

attribute of the Mitigating Systems Cornerstone and adversely affected the objective of

ensuring availability, reliability, and capability of systems needed to respond to initiating

events to prevent undesired consequences. Specifically, the incorrect simulator

response adversely affected the operating crews ability to assess plant conditions and

take actions in accordance with approved procedures during the December 25, 2014,

scram.

The team performed an initial screening of the finding in accordance with IMC 0609,

Appendix A, The Significance Determination Process (SDP) for Findings At-Power,

Attachment 4, Initial Characterization of Findings. Using IMC 0609, Attachment 4,

Table 3, SDP Appendix Router, the team answered yes to the following question:

Does the finding involve the operator licensing requalification program or simulator

-25-

fidelity? As a result, the team used IMC 0609, Appendix I, Licensed Operator

Requalification Significance Determination Process (SDP), and preliminarily determined

the finding was of low to moderate safety significance (White) because the deficient

simulator performance negatively impacted operations personnel performance in the

actual plant during a reportable event. This modeling deficiency resulted in actual

impact on operations personnel performance during response to a reactor scram that

occurred on December 25, 2014.

The NRC recently issued a non-cited violation related to simulator fidelity in March 2014

documented in Inspection Report 05000458/2014301. Since the licensee recently

verified simulator fidelity, this issue is indicative of current plant performance and has an

evaluation cross-cutting aspect within the problem identification and resolution area

because the licensee failed to thoroughly evaluate this issue to ensure that the

resolution addressed the extent of condition commensurate with its safety significance.

Specifically, the licensees evaluation of the fidelity issue focused on other training areas

that used simulation, rather than evaluating the simulator modelling for additional fidelity

discrepancies [P.2].

Enforcement. Title 10 of the Code of Federal Regulations, Part 55.46(c)(1), Plant-

Referenced Simulators, requires in part, that a simulator must demonstrate expected

plant response to operator input and to normal, transient, and accident conditions to

which the simulator has been designed to respond.

Contrary to the above, as of January 30, 2015, the simulator failed to demonstrate

expected plant response to operator input and to normal, transient, and accident

conditions to which the simulator has been designed to respond. Specifically, the River

Bend Station simulator failed to correctly model leakage flow rates across the FRVs;

failed to provide the correct alarm response for a loss of a RPS MG set; and failed to

correctly model the behavior of the SFRV controller. These simulator modeling issues

led to negative training of operators. This subsequently complicated the operators

response to a reactor scram in the actual plant on December 25, 2014. This issue has

been entered into the corrective action program as Condition Report

CR-RBS-2015-01261. The licensees condition report included actions to initiate

simulator discrepancy reports, to investigate and resolve the potential fidelity issues, and

to provide training to operations personnel on simulator differences. This is a violation of

10 CFR 55.46(c)(1), Plant-Referenced Simulators: AV 05000458/2015009-05, Failure

of the Plant-Referenced Simulator to Demonstrate Expected Plant Response.

e. Failure to Identify and Classify Operator Workarounds that Impacted Scram Recovery

Actions

Introduction. The team identified a Green finding for the licensees failure to follow

written procedures for classifying deficient plant conditions as operator workarounds and

providing compensatory measures or training in accordance with fleet

Procedure EN-OP-117. A misclassification of these conditions resulted in the failure of

the operations department to fully assess the impact these conditions had during a plant

-26-

transient. The failure to identify operator workarounds contributed to complications

experienced during reactor scram recovery on December 25, 2014.

Description. The team reviewed the recovery actions taken by the main control room

staff following the reactor scram on December 25, 2014, from 85 percent power. During

the review, the team observed the station had zero conditions identified as operator

workarounds. The team reviewed fleet Procedure EN-FAP-OP-006, Operator

Aggregate Impact Index Performance Indicator, Revision 2. This procedure defined an

operator workaround as:

Any plant condition (equipment or other) that would require compensatory

operator actions in the execution of normal operating procedures, abnormal

operating procedures, emergency operating procedures, or annunciator

response procedures during off-normal conditions. This indicator provided a

measure of plant safety. It provided a measure of the likelihood that a plant

transient may be complicated by equipment and human performance problems.

During their review, the team identified the following three conditions which met the

definition of an operator workaround as described in Procedure EN-FAP-OP-006, and

which were in effect prior to the December 25, 2014, event:

• Work Order WO-RBS-00404323: RFP B supply breaker repetitive failures to

close potentially reduces the number of feedwater pumps available to operations

personnel during a transient following reactor pressure vessel water

Level 8 (high). Operations personnel would rack out and then rack the breaker

back in until the breaker would function properly. This work order was initiated

on February 3, 2015, following discussions with the NRC inspection team.

• Work Order WO-RBS-00396449: RFP C minimum flow valve does not stroke

fully open which prevents starting the C feed pump. Maintenance personnel

would manually operate a limit switch on the valve to make up the start logic for

the RFP. This work order was initiated on October 10, 2014.

• Work Order WO-RBS-00346642: leakage past FRVs when closed complicated

post-scram reactor water level control. Operations personnel proceduralized the

closure of the main feedwater isolation valves to stop the effect of the leakage.

This work order was initiated on March 27, 2013.

The deficient conditions in WO-RBS-00346642 and WO-RBS-00396449 contributed to

complications experienced by the station when attempting to restore feedwater following

a scram and loss of all feedwater pumps on a reactor pressure vessel water

Level 8 (high).

Fleet Procedure EN-OP-117, Attachment 9.4, Operator Aggregate Assessment of Plant

Deficiencies, provides a method to assess and document the impact of plant

deficiencies on operations personnel response during off-normal and emergency

conditions. In order to assess the cumulative impact of outstanding operator aggregate

-27-

impact deficiencies, several deficiency types were evaluated, including operator

workarounds. Following assessment of deficiencies, Attachment 9.4, step 5, directed

the station to provide compensatory measures or training as appropriate until the

deficiencies could be corrected.

The resident inspectors engaged operations department management in January 2015,

and informed the licensee that the three conditions appeared to meet the definition of an

operator workaround as described in Procedure EN-FAP-OP-006. Upon learning of the

misclassification of these issues, the station revised their operator aggregate index on

February 6, 2015, to account for the three operator workaround conditions and the

indicator turned red. As a result, the station issued guidance for post-scram reactor

water level control and required operating crews to attend simulator training on vessel

level control and feedwater system recovery following a Level 8 (high) trip of feedwater

pumps. Additionally, the station wrote Condition Report CR-RBS-2015-00795 to

document the issue.

Analysis. The failure to follow written procedures for classifying deficient plant

conditions as operator workarounds and providing compensatory measures or training in

accordance with fleet Procedure EN-OP-117 was a performance deficiency. This

performance deficiency is more than minor, and therefore a finding, because it had the

potential to lead to a more significant safety concern if left uncorrected. Specifically, the

performance deficiency contributed to complications experienced by the station when

attempting to restore feedwater following a scram on December 25, 2014.

The team performed an initial screening of the finding in accordance with IMC 0609,

Appendix A, The Significance Determination Process (SDP) for Findings At-Power.

Using IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, the

finding was of very low safety significance (Green) because it: (1) was not a deficiency

affecting the design or qualification of a mitigating structure, system, or component, and

did not result in a loss of operability or functionality; (2) did not represent a loss of

system and/or function; (3) did not represent an actual loss of function of at least a single

train for longer than its technical specification allowed outage time, or two separate

safety systems out-of-service for longer than their technical specification allowed outage

time; and (4) did not represent an actual loss of function of one or more non-technical

specification trains of equipment designated as high safety-significant in accordance with

the licensees maintenance rule program.

This finding has a consistent process cross-cutting aspect within the human

performance area because the licensee failed to use a consistent, systematic approach

to making decisions and incorporate risk insights as appropriate. Specifically, no

systematic approach was enacted in order to properly classify deficient conditions [H.8].

Enforcement. Enforcement action does not apply because the performance deficiency

did not involve a violation of regulatory requirements. Because this finding does not

involve a violation and is of very low safety significance, this issue was entered into the

licensees corrective action program as Condition Report CR-RBS-2015-00795: FIN

-28-

05000458/2015001-06, Failure to Identify and Classify Operator Workarounds That

Impacted Scram Recovery Actions.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On January 20, 2015, the team initially debriefed Mr. E. Olson, Site Vice President, and other

members of the licensee's staff. The licensee representatives acknowledged the findings

presented.

On June 29, 2015, the team conducted an exit briefing with Mr. E. Olson, Site Vice President,

and other members of the licensees staff. The licensee representatives acknowledged the

findings presented.

-29-

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

E. Olson, Site Vice President

D. Bergstrom, Senior Operations Instructor

M. Browning, Senior Operations Instructor

T. Brumfield, Director, Regulatory & Performance Improvement

S. Carter, Manager, Shift Operations

M. Chase, Manager, Training

J. Clark, Manager, Regulatory Assurance

F. Corley, Manager, Design & Program Engineering

T. Creekbaum, Engineer

G. Degraw, Manager, Training

G. Dempsey, Senior Operations Instructor

S. Durbin, Superintendent, Operations Training

R. Gadbois, General Manager, Plant Operations

T. Gates, Manager, Operations Support

J. Henderson, Assistant Manager, Operations

K. Huffstatler, Senior Licensing Specialist, Licensing

K. Jelks, Engineering Supervisor

G. Krause, Assistant Manager, Operations

T. Laporte, Senior Staff Operations Instructor

R. Leasure, Superintendent, Radiation Protection

P. Lucky, Manager, Performance Improvement

J. Maher, Manager, Systems & Components Engineering

W. Mashburn, Director, Engineering

W. Renz, Director, Emergency Planning, Entergy South

J. Reynolds, Senior Manager, Maintenance

T. Shenk, Manager, Operations

T. Schenk, Manager, Operations

S. Vazquez, Director, Engineering

D. Williamson, Senior Licensing Specialist

D. Yoes, Manager, Quality Assurance

NRC Personnel

G. Warnick, Branch Chief

J. Sowa, Senior Resident Inspector

R. Deese, Senior Reactor Analyst

A1-1 Attachment 1

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000458/2015009-01 URI Vendor and Industry Recommended Testing Adequacy on

Safety-related and Safety-significant Circuit Breakers

(Section 2.5.b)

Opened and Closed

05000458/2015009-02 NCV Failure to Establish Adequate Procedures to Perform

Maintenance on Equipment that can Affect Safety-Related

Equipment (Section 2.7.a)05000458/2015009-03 NCV Failure to Provide Adequate Procedures for Post-scram

Recovery (Section 2.7.b)05000458/2015009-04 NCV Failure to Identify High Reactor Water Level as a Condition

Adverse to Quality (Section 2.7.c)05000458/2015009-05 AV Failure of the Plant-Referenced Simulator to Demonstrate

Expected Plant Response (Section 2.7.d)05000458/2015009-06 FIN Failure to Identify and Classify Operator Workarounds that

Impacted Scram Recovery Actions (Section 2.7.e)

LIST OF DOCUMENTS REVIEWED

DRAWINGS

NUMBER TITLE REVISION

GE-828E445AA, Elementary Diagram - Nuclear Steam Supply Shutoff System 34

Sheet 7

GE-828E445AA, Elementary Diagram - Nuclear Steam Supply Shutoff System 33

Sheet 8

GE-828E445AA, Elementary Diagram - Nuclear Steam Supply Shutoff System 31

Sheet 10

GE-828E445AA, Elementary Diagram - Nuclear Steam Supply Shutoff System 30

Sheet 11

GE-828E445AA, Elementary Diagram - Nuclear Steam Supply Shutoff System 30

Sheet 12

GE-828E445AA, Elementary Diagram - Nuclear Steam Supply Shutoff System 37

Sheet 15

GE-944E981 Elementary Diagram - RPS MG Set Control System 11

A1-2

DRAWINGS

NUMBER TITLE REVISION

PID-25-01A Engineering P&I Diagram - System 051, Nuclear Boiling 19

Instrumentation

PID-25-01B Engineering P&I Diagram - System 051, Nuclear Boiling 7

Instrumentation

828E531AA, Elementary Diagram - Reactor Protection System 25

Sheet 4

828E531AA, Elementary Diagram - Reactor Protection System 22

Sheet 4A

828E531AA, Elementary Diagram - Reactor Protection System 27

Sheet 6

PROCEDURES

NUMBER TITLE REVISION

AOP-0001 Reactor Scram 30

AOP-0003 Automatic Isolations 33

AOP-0006 Condensate/Feedwater Failures 19

AOP-0010 Loss of One RPS Bus 19

EN-FAP-OM-004 Fleet and Site Business Plan Process 0

EN-FAP-OM-012 Prompt Investigation, Notifications and Duty Manager 6

Responsibilities

EN-FAP-OP-006 Operator Aggregate Impact Index Performance Indicator 2

EN-LI-102 Corrective Action Program 24

EN-LI-118 Cause Evaluation Process 21

EN-MA-125 Troubleshooting Control of Maintenance Activities 17

EN-OP-104 Operability Determination Process 7

EN-OP-115 Conduct of Operations 15

EN-OP-117 Operations Assessment Resources 8

EN-OP-115-09 Log Keeping 1

EN-TQ-202 Simulator Configuration Control 9

EOP-0001 RPV Control 26

EOP-0003 Secondary Containment and Radioactive Release Control 16

A1-3

PROCEDURES

NUMBER TITLE REVISION

EPSTG-0001 Emergency Operating and Severe Accident Procedures - Plant 16

Specific Technical Guidelines (PSTG)

EPSTG-0002 EPGs/SAGs to PSTG to EOP/SAP Flowcharts Comparison 16

EPSTG-0002, Emergency Operating and Severe Accident Procedures - 16

Appendix B Bases

GOP-0001 Plant Startup 83

GOP-0002 Plant Shutdown 70

GOP-0003 Scram Recovery for December 27, 2014 24

OSP-0001 Control of Operator Aids 13

OSP-0053 Emergency and Transient Response Support Procedure 22

CONDITION REPORTS

CR-RBS-1998-00384 CR-RBS-2002-00672 CR-RBS-2002-00688 CR-RBS-2006-04078

CR-RBS-2011-02209 CR-RBS-2011-09053 CR-RBS-2012-02249 CR-RBS-2012-03434

CR-RBS-2012-03439 CR-RBS-2012-03440 CR-RBS-2012-03665 CR-RBS-2012-03739

CR-RBS-2012-03816 CR-RBS-2012-03817 CR-RBS-2012-05894 CR-RBS-2012-06015

CR-RBS-2012-07249 CR-RBS-2012-07250 CR-RBS-2012-07251 CR-RBS-2012-07253

CR-RBS-2012-07254 CR-RBS-2013-04419 CR-RBS-2014-05200 CR-RBS-2014-05209

CR-RBS-2014-06233 CR-RBS-2014-06357 CR-RBS-2014-06561 CR-RBS-2014-06581

CR-RBS-2014-06602 CR-RBS-2014-06605 CR-RBS-2014-06649 CR-RBS-2014-06696

CR-RBS-2015-00030 CR-RBS-2015-00043 CR-RBS-2015-00153 CR-RBS-2015-00318

CR-RBS-2015-00365 CR-RBS-2015-00480 CR-RBS-2015-00482 CR-RBS-2015-00483

CR-RBS-2015-00484 CR-RBS-2015-00486 CR-RBS-2015-00487 CR-RBS-2015-00579

CR-RBS-2015-00620 CR-RBS-2015-00626 CR-RBS-2015-00641 CR-RBS-2015-00657

CR-RBS-2015-00795 CR-RBS-2015-01261 CR-RBS-2015-02810

WORK ORDERS

WO-RBS-00346642 WO-RBS-00396449 WO-RBS-00401085 WO-RBS-00404323

A1-4

MISCELLANEOUS DOCUMENT

NUMBER TITLE REVISION /

DATE

EC 50374 Engineering Change - Feedwater Level Control Setpoint 0

Setdown Modification

EN-LI-100-ATT- Process Applicability Determination Form for AOP-0001, August 6,

9.1 Reactor Scram, Revision 24 2007

LI-101 50.59 Review Form for GOP-0002, Power Decrease/Plant August 26,

Shutdown, Revision 30 2004

GE-22A3778 Feedwater Control System (Motor Driven Feed Pumps) 4

Design Specification

GE-22A3778AB Feedwater Control System (Motor Driven Feed Pumps) 7

Design Specification Data Sheet

RLP-LOP-0511 Licensed Operator Requalification - Industry August 1,

Events/Operating Experience and Plant Modifications 2002

1-ST-27-TC6 Startup Procedure and Results - Turbine Trip and Generator June 27,

Load Reject 1986

107-Feedwater System Health Report - Feedwater Q2 2014

0247.230-000-16 Feedwater Control Valve Assembly - Purchase Specifications 301

List of Actuations/Isolations That Occur From Loss of RPS January 29,

Bus B 2015

Main Control Room Log December 6,

2014

Main Control Room Log December 13,

2014

Main Control Room Log December 16,

2014

Main Control Room Log December 27,

2014

Main Control Room Log December 28,

2014

A1-5

UNITED STATES

NUCLEAR REGULATORY COMMISSION

REGION IV

1600 E LAMAR BLVD

ARLINGTON, TX 76011-4511

January 15, 2015

MEMORANDUM TO: Tom Hartman, Senior Resident Inspector

Reactor Projects Branch B

Division of Reactor Projects

FROM: Troy Pruett, Director /RA/

Division of Reactor Projects

SUBJECT: SPECIAL INSPECTION CHARTER TO EVALUATE CAUSES OF THE

UNPLANNED REACTOR TRIP WITH COMPLICATIONS AT THE

RIVER BEND STATION

In response to the unplanned reactor trip with complications at the River Bend Station, a special

inspection will be performed. You are hereby designated as the special inspection team leader.

The following members are assigned to your team:

• Jim Drake, Senior Reactor Inspector, Division of Reactor Safety

• Dan Bradley, Resident Inspector, Division of Reactor Projects

A. Basis

On December 25, 2014, at 8:37 AM, River Bend Station scrammed from 85 percent power

following a trip of the B reactor protection system (RPS) motor generator (MG) set. At the

time of the MG set trip, a Division 1 half scram existed due to an unrelated equipment

issue with a relay for the No. 2 turbine control valve fast closure RPS function. The

combination of the B RPS MG set trip and the Division 1 half scram resulted in a scram of

the reactor.

The following equipment issues occurred during the initial scram response.

• An unexpected Level 8 (high) reactor water level signal was received which resulted in

tripping of all RFPs.

• Following reset of the Level 8 high reactor water level signal, plant operators were

unable to start RFP C. Plant operators responded by starting RFP A at a vessel level

of 25. The licensee subsequently determined that the circuit breaker (Magne Blast

type) for RFP C did not close because an interlock lever for a microswitch that controls

the breaker close permissive was not fully engaged in the cubicle.

• Following the start of RFP A, the licensee attempted to open the startup feed

regulating valve but was unsuccessful prior the Level 3 low reactor water level trip

setpoint at +9.7. The licensee then opened the C main feedwater regulating valve to

A2-1 Attachment 2

restore reactor vessel water level. The lowest level reached was +7.5. Subsequent

troubleshooting revealed a faulty manual function control card. The card was

replaced by the licensee and the startup feedwater regulating valve was used on the

subsequent plant startup.

Following restoration of reactor vessel water level, the plant was stabilized in Mode 3. A

plant startup was conducted on December 27, 2014 with RPS bus B being supplied by

its alternate power source. During power ascension following startup, RFP B did not

start. The licensee re-racked its associated circuit breaker and successfully started

RFP B.

Management Directive 8.3, NRC Incident Investigation Program, was used to evaluate

the level of NRC response for this event. In evaluating the deterministic criteria of

MD 8.3, it was determined that: (1) The event included multiple failures in the feedwater

system which is a short term decay heat removal mitigating system; (2) involved two

Magna Blast circuit breaker issues which could possibly have generic implications

regarding the licensees maintenance, testing, and operating practices for these

components including safety-related breakers in the high pressure core spray system;

and, (3) involved several issues related to the ability of operations to control reactor vessel

level between the Level 3 low and Level 8 high trip set points following a reactor scram.

Since the deterministic criteria was met, the trip was evaluated for risk. The preliminary

Estimated Conditional Core Damage Probability was determined to be 1.2E-6.

Based on the deterministic criteria and risk insights related to the multiple failures of the

feedwater system, the potential generic concern with the Magna Blast circuit breakers,

and the issues related to the licensees Operations departments inability to control reactor

vessel level between the Level 3 and Level 8 setpoints following a reactor scram, Region

IV determined that the appropriate level of NRC response was to conduct a Special

Inspection.

This Special Inspection is chartered to identify the circumstances surrounding this event,

determine if there are adverse generic implications, and review the licensees actions to

address the causes of the event.

B. Scope

The inspection is expected to perform data gathering and fact-finding in order to address

the following:

1. Provide a recommendation to Region IV management as to whether the

inspection should be upgraded to an augmented inspection team response. This

recommendation should be provided by the end of the first day on site.

2. Develop a complete sequence of events related to the reactor scram that

occurred on December 25, 2014. The chronology should include the events

leading to the reactor scram, the licensees immediate scram response and the

licensees post-scram recovery actions including troubleshooting and reactor

startup.

A2-2

3. Review the licensees root cause analysis and determine if it is being conducted

at a level of detail commensurate with the significance of the problem.

4. Determine the causes for the unexpected Level 8 high water level trip signal that

was experienced following the reactor scram.

5. Review the effectiveness of licensee actions to address known equipment

degradations that could complicate post scram operator response.

6. Review the causes and corrective actions taken to address the failure of RFP C

to start during the initial scram response and RFP B during the subsequent

reactor startup. For issues related to Magne Blast circuit breakers, verify that the

licensees corrective actions have addressed extent of condition and extent of

cause.

7. Review the licensees maintenance, testing and operating practices for Magne

Blast circuit breakers. Promptly communicate any potential generic issues to

regional management.

8. Review the licensees corrective actions to address complications encountered

during previous reactor scrams. Reference previously docketed correspondence

regarding complicated reactor scrams in NRC inspection reports

05000458/2002002, 05000458/2006013, 05000458/2012009 and

05000458/2012012.

9. Evaluate pertinent industry operating experience and potential precursors to the

event, including the effectiveness of any action taken in response to the

operating experience.

10. Collect data necessary to support completion of the significance determination

process.

C. Guidance

Inspection Procedure 93812, "Special Inspection," provides additional guidance to be

used by the Special Inspection Team. Your duties will be as described in Inspection

Procedure 93812. The inspection should emphasize fact-finding in its review of the

circumstances surrounding the event. It is not the responsibility of the team to examine

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the regulatory process. Safety concerns identified that are not directly related to the

event should be reported to the Region IV office for appropriate action.

You will formally begin the special inspection with an entrance meeting to be conducted

no later than January 26, 2015. You should provide a daily briefing to Region IV

management during the course of your inspections and prior to your exit meeting. A

report documenting the results of the inspection should be issued within 45 days of the

completion of the inspection.

This Charter may be modified should you develop significant new information that

warrants review. Should you have any questions concerning this Charter, contact

Jeremy Groom at (817) 200-1144.

cc via E-mail:

M. Dapas

K. Kennedy

T. Pruett

A. Vegel

J. Clark

V. Dricks

W. Maier

J. Groom

J. Sowa

R. Azua

N. Taylor

T. Hartman

J. Drake

D. Bradley

ADAMS ACCESSION NUMBER ML15015A634

SUNSI Rev Compl. Yes No ADAMS Yes No Reviewer Initials JRG

Publicly Avail Yes No Sensitive Yes No Sens. Type Initials JRG

Keyword MD 3.4/A.7

RIV/DRP: BC RIV/DRP: DIR

JRGroom TWPruett

/RA/RAzua for /RA/

1/15/15 1/15/15

OFFICIAL RECORD

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