ML18194A413

NRC Baseline Inspection Report 05000458/2018012

ML18194A413
Person / Time
Site:	River Bend
Issue date:	07/18/2018
From:	Jason Kozal NRC/RGN-IV/DRP/RPB-C
To:	Maguire W Entergy Operations
Kozal J
References
IR 2018012
Download: ML18194A413 (32)

See also: IR 05000458/2018012

Text

July 18, 2018

Mr. William F. Maguire, Site Vice President

Entergy Operations, Inc.

River Bend Station

5485 U.S. Highway 61N

St. Francisville, LA 70775

SUBJECT: RIVER BEND STATION - NRC BASELINE INSPECTION REPORT

05000458/2018012

Dear Mr. Maguire:

On July 16, 2018, the U.S. Nuclear Regulatory Commission (NRC) completed a baseline

inspection at your River Bend Station, Unit 1. On May 31 and July 16, 2018, the NRC

inspection team discussed the results of this inspection with you and other members of your

staff. The results of this inspection are documented in the enclosed report.

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

Four of these findings involved violations of NRC requirements. Additionally, NRC inspectors

documented two violations that were determined to be Severity Level IV under the traditional

enforcement process. The NRC is treating these violations as non-cited violations (NCVs)

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

If you contest the violations or significance of these NCVs, you should provide a response within

30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear

Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with

copies to the Regional Administrator, Region IV; the Director, Office of Enforcement; 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 U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk,

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

NRC resident inspector at the River Bend Station.

W. Maguire 2

This letter, its enclosure, and your response (if any) will be made available for public inspection

and copying at http://www.nrc.gov/reading-rm/adams.html and at the NRC Public Document

Room in accordance with 10 CFR 2.390, Public Inspections, Exemptions, Requests for

Withholding.

Sincerely,

/RA/

Jason W. Kozal, Chief

Project Branch C

Division of Reactor Projects

Docket No. 50-458

License No. NPF-47

Enclosure:

Inspection Report 05000458/2018012

w/ Attachment: Documents Reviewed

U.S. NUCLEAR REGULATORY COMMISSION

Inspection Report

Docket Number: 05000458

License Number: NPF-47

Report Number: 05000458/2018012

Licensee: Entergy Operations, Inc.

Facility: River Bend Station

Location: Saint Francisville, Louisiana

Inspection Dates: February 1, 2018 to July 16, 2018.

Inspectors: J. Sowa, Senior Resident Inspector

J. Drake, Senior Reactor Inspector

C. Young, Senior Project Engineer

M. OBanion, Resident Inspector (Acting)

B. Parks, Resident Inspector

Approved By: J. Kozal, Chief, Branch C

Division of Reactor Projects

Enclosure

SUMMARY

The U.S. Nuclear Regulatory Commission (NRC) continued monitoring the licensees

performance by conducting a baseline inspection at River Bend Station in accordance with the

Reactor Oversight Process. The Reactor Oversight Process is the NRCs program for

overseeing the safe operation of commercial nuclear power reactors. Refer to

https://www.nrc.gov/reactors/operating/oversight.html for more information. Findings and

violations being considered in the NRCs assessment are summarized in the tables below.

List of Findings and Violations

Failure to Identify and Correct a Broken Feedwater Chemistry Probe

Cornerstone Significance Cross-cutting Report

Aspect Section

Barrier Green None 71152 -

Integrity NCV 05000458/2018012-02 Problem

Closed Identification

and

Resolution

Two examples of a self-revealed non-cited violation (NCV) of 10 CFR Part 50, Appendix B,

Criterion XVI, Corrective Action, were identified for the licensees failure to identify that a

broken chemistry probe in the feedwater system had the potential to cause an adverse impact

on plant safety, and promptly implement appropriate measures to address that condition.

Failure to Provide Adequate Procedures for Post-Scram Recovery

Cornerstone Significance Cross-cutting Report

Aspect Section

Mitigating Green None 71111.18 -

Systems NCV 05000458/2018012-06 Plant

Closed Modifications

The inspectors reviewed a self-revealed, 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, dated February 1978. 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 main feedwater regulating valve as part of the post-

scram actions. This resulted in the main feedwater regulating valves being operated outside

their design limits. This resulted in catastrophic failure of the main feedwater regulating valve

variseals and subsequent damage to multiple fuel assemblies.

2

Failure to Develop an Adequate Operational Decision-Making Issue for Compensatory Measures

Related to a Degraded Condition of the Feedwater System Sparger Nozzles

Cornerstone Significance Cross-cutting Report Section

Aspect

Mitigating Green [H.9] - 71111.15 -

Systems NCV 05000458/2018012-05 Human Operability

Closed Performance, Determinations

Training and

Functionality

Assessment

The inspectors identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion V,

Instructions, Procedures, and Drawings, for the failure to develop an adequate Operational

Decision-Making Issue (ODMI) document per Procedure EN-OP-111, Operational Decision-

Making Issue Process. Specifically, the licensee failed to develop an ODMI that provided

adequate guidance to the operators for safely operating the plant with degraded feedwater

sparger nozzles.

Failure to Establish Procedural Guidance for Determining Core Flow During Unanticipated

Single Loop Operations

Cornerstone Significance Cross-cutting Report

Aspect Section

Initiating Green [P.3] - 71153 -

Events NCV 05000458/2018012-03 Problem Follow-up of

Closed Identification Events and

and Notices of

Resolution, Enforcement

Resolution Discretion

The inspectors reviewed a self-revealed, non-cited violation of 10 CFR Part 50 Appendix B,

Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to establish

appropriate instructions in the abnormal operating procedure for thermal hydraulic instabilities.

Specifically, the procedural step for determining core flow when in single loop operations at low

power did not provide appropriate instructions to operators. As a result, station personnel could

not conclusively determine core flow and inserted a manual reactor scram.

Failure to Perform 10 CFR 50.59 Evaluation for Main Feedwater System Sparger Nozzle

Damage

Cornerstone Significance Cross-cutting Report

Aspect Section

None SL-IV None 71111.18 -

NCV 05000458/2018012-07 Plant

Closed Modifications

The inspectors identified a Severity Level IV non-cited violation of 10 CFR 50.59, Changes,

Tests, and Experiments, for the licensees failure to provide a written safety evaluation for the

determination that operation with compensatory measures for damaged feedwater sparger

nozzles did not require a license amendment pursuant to 10 CFR 50.90, Application for

amendment of license, construction permit, or early site permit. Specifically, the licensee failed

to recognize that compensatory measures prohibiting operation in single loop conditions

required technical specification changes, and as such required prior NRC approval.

3

Failure to Conduct Adequate Transient Snap Shot Assessment Following Recirculation Pump

Trip

Cornerstone Significance Cross-cutting Report

Aspect Section

Initiating Green None 71152 -

Events FIN 05000458/2018012-01 Problem

Closed Identification

and

Resolution

The inspectors identified a finding for the licensees failure to adequately validate simulator

response during a transient snap shot assessment following an unexpected trip of reactor

recirculation pump A on December 19, 2012.

Failure to Submit a Licensee Event Report for a Manual Scram

Cornerstone Significance Cross-cutting Report

Aspect Section

None SL-IV None 71153 -

NCV 05000458/2018012-04 Follow-up of

Closed Events and

Notices of

Enforcement

Discretion

The inspectors identified a Severity Level IV non-cited violation of 10 CFR 50.73, Licensee

Event Report System, for the licensees failure to submit a required licensee event report (LER).

Specifically, on February 1, 2018, after an unexpected trip of the recirculation pump B, the

licensee initiated a manual scram of the reactor that was not part of a preplanned sequence and

failed to submit an LER within 60 days.

4

INSPECTION SCOPES

Inspections were conducted using the appropriate portions of the inspection procedures (IPs) in

effect at the beginning of the inspection unless otherwise noted. Currently approved IPs with

their attached revision histories are located on the public website at http://www.nrc.gov/reading-

rm/doc-collections/insp-manual/inspection-procedure/index.html. Samples were declared

complete when the IP requirements most appropriate to the inspection activity were met

consistent with Inspection Manual Chapter (IMC) 2515, Light-Water Reactor Inspection

Program - Operations Phase. The inspectors reviewed selected procedures and records,

observed activities, and interviewed personnel to assess licensee performance and compliance

with Commission rules and regulations, license conditions, site procedures, and standards.

REACTOR SAFETY

71111.15Operability Determinations and Functionality Assessments (1 Sample)

The inspectors evaluated the following operability determinations and functionality

assessments:

(1) Review of Operational Decision-Making Issue (ODMI) associated with damaged

feedwater sparger on February 8, 2018

71111.18Plant Modifications (2 Samples)

The inspectors evaluated the following temporary or permanent modifications:

(1) OSP-0053, Emergency And Transient Response Support Procedure, following

decision to control reactor vessel level with main feedwater regulating valves during

post-scram operations

(2) Review of plant operation following modification to feedwater sparger nozzles 7 and 8

OTHER ACTIVITIES - BASELINE

71152Problem Identification and Resolution

Annual Follow-up of Selected Issues (3 Samples)

The inspectors reviewed the licensees implementation of its corrective action program

related to the following issues:

(1) Review of 1) simulator modelling of core parameters during a recirculation pump trip at

low power and 2) licensed operator training associated with single loop operations at low

power

(2) Actions to address a broken isokinetic chemistry sampling probe in the feedwater

system

(3) Actions to address fuel failures caused by debris material in the reactor vessel

5

71153Follow-up of Events and Notices of Enforcement Discretion

Personnel Performance (1 Sample)

(1) The inspectors evaluated operator response to the unexpected trip of the reactor

recirculation pump B on February 1, 2018.

INSPECTION RESULTS

Failure to Identify and Correct a Broken Feedwater System Chemistry Probe

Cornerstone Significance Cross-cutting Report

Aspect Section

Barrier Green None 71152 -

Integrity NCV 05000458/2018012-02 Problem

Closed Identification

and

Resolution

Two examples of a self-revealed Green finding and associated NCV of 10 CFR Part 50,

Appendix B, Criterion XVI, were identified for the licensees failure to identify that a broken

chemistry probe in the feedwater system had the potential to cause an adverse impact on

plant safety, and promptly implement appropriate measures to address that condition.

Description:

In 1999, the licensee initiated Condition Report CR-RBS-1999-1011 to document that an

isokinetic chemistry sample probe was found to be missing from its installed location in the

feedwater system, having broken off in the system. Following unsuccessful attempts to

locate and remove the missing probe, the licensee performed evaluation ER-99-0539 to

evaluate the potential impact of the missing probe on the continued operation and function of

feedwater system components. This evaluation concluded that the missing probe remaining

in the system would not present any hazard to any feedwater system components, and would

have no adverse effect on continued operation. This conclusion was based, in part, on a

calculation showing that feedwater flow would not have enough energy to levitate the probe

past a 20-foot vertical riser portion of the system, and therefore would not have the potential

to enter a feedwater sparger in the reactor vessel downstream of the vertical riser. Another

calculation showed that the impact energy of the loose probe on any feedwater components

would be negligible.

In March 2004, the NRC issued Information Notice (IN) 2004-06, Loss of Feedwater

Isokinetic Sampling Probes at Dresden Units 2 and 3 (ADAMS Accession No.

ML040711214). The IN discussed that broken probes had been discovered at five other

stations from 1990 to 2001, and further described the conditions discovered at Dresden

Nuclear Power Station (Dresden), Units 2 and 3. In 2003, three holes in a feedwater sparger

at Dresden Unit 2 were discovered, along with the missing feedwater probe in the sparger,

which had apparently caused the damage. Two probes were discovered to be in a feedwater

sparger in Dresden Unit 3, with no damage to the sparger having occurred yet. These

conditions demonstrated that not only could the probes be transported to the feedwater

spargers in the reactor vessel, but that they could potentially damage the spargers. The

licensees evaluation of this operating experience concluded that, since the broken probe at

River Bend had been replaced with a probe of a design not susceptible to the same failure,

no further action was needed. The licensee failed to address the potential impacts of the

adverse condition of the broken probe that remained loose in the feedwater system.

6

In 2011, the licensee documented an evaluation of a similar condition that had been

discovered at Brunswick Steam Electric Plant, Unit 2, where a feedwater sample probe was

discovered inside a feedwater sparger. The licensees evaluation of this operating

experience concluded that the current design (i.e. the probe that replaced the previous

broken probe) was not susceptible to this kind of failure. The licensee again failed to address

the impact of the previous broken probe that remained in the system, given that its potential

to be transported into a feedwater sparger in the reactor vessel had been shown.

In January 2018, the licensee discovered damage in the form of two holes in feedwater

sparger nozzles in the reactor vessel, with the broken probe protruding from one of the holes

in the direction of the other. The broken probe remaining in the feedwater system resulted in

potential adverse impacts on the reactor vessel wall due to impingement of feedwater flow

through the holes in the damaged sparger, as well as potential adverse impacts on the

integrity of fuel cladding due to the introduction of foreign material (pieces of the feedwater

sparger and chemistry probe) in the reactor vessel.

Corrective Actions: The broken probe was removed from the system. The licensee

performed evaluations to identify plant operational limitations to ensure that adverse impacts

to reactor pressure vessel wall integrity from additional holes in a feedwater sparger are

minimized. The licensee also issued an action to perform a review of historical loose parts

evaluations to add to tracking mechanisms and ensure adequacy of previous evaluations.

Corrective Action Reference: CR-RBS-2018-0294, CR-RBS-2018-0613, and

CR-RBS-2017-2828.

Performance Assessment:

Performance Deficiency: The licensees failure on two occasions to identify a broken

chemistry probe in the feedwater system had the potential to cause an adverse impact on

plant safety and to promptly implement appropriate measures to address that condition was a

performance deficiency.

Screening: The inspectors determined the performance deficiency was more than minor

because it was associated with the Cladding Performance, as well as the RCS Equipment

and Barrier Performance, attributes of the Barrier Integrity Cornerstone, and adversely

impacted the cornerstone objective to provide reasonable assurance that physical design

barriers (fuel cladding, reactor coolant system, and containment) protect the public from

radionuclide releases caused by accidents or events. Specifically, the unaddressed condition

of the broken probe remaining in the feedwater system resulted in damage to the feedwater

sparger, which resulted in thermal stresses to the reactor pressure vessel due to feedwater

impingement on the inner reactor pressure vessel wall, as well as the introduction of foreign

material inside the reactor vessel having the potential to result in damaged fuel. The licensee

performed an evaluation to determine what plant operational limitations were necessary in

order to ensure that additional thermal stresses on the reactor pressure vessel inner wall

remained below a threshold that would challenge the structural integrity of the vessel.

Significance: In accordance with Inspection Manual Chapter 0609, Appendix A, Section 5.0,

RCS boundary issues other than pressurized thermal shock are evaluated under the Initiating

Events Cornerstone. Using Inspection Manual Chapter 0609, Appendix A, The Significance

Determination Process for Findings At-Power, Exhibit 1, Initiating Events Screening

Questions, the finding was screened, as a potential loss of coolant accident (LOCA) initiator,

as having very low safety significance (Green) because, after a reasonable assessment of

7

degradation, the finding could not result in exceeding the RCS leak rate for a small LOCA and

could not have likely affected other systems used to mitigate a LOCA.

Cross-cutting Aspect: A cross-cutting aspect of P.5, Operating Experience, was determined

to be applicable to the performance deficiencies; however, no cross-cutting aspect was

assigned since the performance deficiencies occurred in 2004 and 2011, and are not

indicative of current licensee performance.

Enforcement:

Violation: Title 10 CFR Part 50, Appendix B, Criterion XVI, 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

nonconformances are promptly identified and corrected. Contrary to the above, from

June 2004 to January 2018, the licensee failed to establish measures to assure that a

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

failed to identify and correct a condition involving a broken sampling probe inside the

feedwater system. The uncorrected condition resulted in damage to a feedwater sparger,

with the potential to impact the available margin for integrity of the reactor vessel.

Disposition: This violation is being treated as a non-cited violation, consistent with

Section 2.3.2.a of the Enforcement Policy.

Failure to Provide Adequate Procedures for Post-Scram Recovery

Cornerstone Significance Cross-cutting Report

Aspect Section

Mitigating Green None 71111.18 -

Systems NCV 05000458/2018012-06 Plant

Closed Modifications

The inspectors 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, dated February 1978. 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 main feedwater

regulating valve (MFRV) as part of the post-scram actions. This resulted in the MFRVs being

operated outside their design limits. This resulted in catastrophic failure of the MFRV

variseals and subsequent damage to multiple fuel assemblies.

Description:

In January 2015, the licensee revised Procedure OSP-0053, Emergency And Transient

Response Support Procedure, to use one of the three MFRVs to control reactor water level

following a scram event, and not use C33-LVF002, Start-Up FRV, which is designed to be

used for this application. This resulted in proceduralizing the use of a MFRV in circumstances

below the minimum controllable flow for the MFRV of 209,000 lbs/hr that the Main FRV

Copes Vulcan sizing datasheet provides as the a minimum controllable flow condition. As a

result of this change to the procedure to use a MFRV, the valves cycled numerous times in

the process of controlling level at low flow post-scram when feedwater flow demand was

below the MFRV minimum controllable flow volume. This repeated cycling of the valve led to

excessive open/close cycling of the MFRVs and caused the catastrophic failure of the

variseals.

8

As a result, foreign material parts of the variseal were introduced into the core. It is

suspected that this material resulted in six nuclear fuel cladding failures caused by debris

fretting.

Corrective Actions: The licensee revised Procedure OSP-0053, Emergency and Transient

Response Support Procedure, to control reactor vessel level post scram using a startup

feedwater regulating valve and modified the design of the MFRV variseal.

Corrective Action Reference: CR-RBS-2016-00893

Performance Assessment:

Performance Deficiency: The failure to establish adequate procedural guidance for operation

of the main feedwater system was a performance deficiency.

Screening: The performance deficiency was more than minor, and therefore a finding,

because it was 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, 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 MFRV as part of the post-scram

actions. This resulted in the MFRVs being operated outside their design limits.

Significance: The inspectors screened the finding in accordance with Inspection Manual

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

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

Systems Screening Questions, the inspectors determined this finding was of very low safety

significance (Green) because the finding: (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 nontechnical specification trains of equipment designated as high

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

Cross-cutting Aspect: No cross-cutting aspect was assigned since the performance

deficiency occurred in January 2015 and is not indicative of current licensee performance.

Enforcement:

Violation: Technical Specification 5.4.1.a requires 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, dated 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 January 30, 2015, until April 13, 2017, the licensee failed to

maintain adequate written procedures for responding to a reactor trip. Specifically,

Procedure OSP-0053 inappropriately directed operations personnel to establish feedwater

9

flow to the reactor pressure vessel using the MFRV as part of the post-scram actions. The

MFRV operator characteristics are not designed to operate at the low flow conditions

immediately following a reactor scram from high power. As a result, the MFRV variseals

degraded and resulted in damage to multiple fuel assemblies. Subsequent to the event, the

licensee changed the procedure, directing operations personnel to utilize one of the startup

feedwater regulating valves.

Disposition: This violation is being treated as an non-cited violation consistent with

Section 2.3.2.a of the NRC Enforcement Policy.

Failure to Develop an Adequate Operational Decision-Making Issue for Compensatory

Measures Related to a Degraded Condition of the Feedwater System Sparger Nozzles

Cornerstone Significance Cross-cutting Report Section

Aspect

Mitigating Green [H.9] - 71111.15 -

Systems NCV 05000458/2018012-05 Human Operability

Closed Performance, Determinations

Training and

Functionality

Assessments

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

Criterion V, Instructions, Procedures, and Drawings, for the failure to develop an adequate

operational decision-making issue (ODMI) document per Procedure EN-OP-111, Operational

Decision-Making Issue Process. Specifically, the licensee failed to develop an ODMI that

provided adequate guidance to the operators for safely operating the plant with degraded

feedwater sparger nozzles.

Description:

During a reactor startup on February 1, 2018, reactor recirculation pump B unexpectedly

tripped during an attempted upshift to fast speed. As a result, the plant was operating with

recirculation pump A in fast speed and recirculation pump B not running. Prior to this startup,

during an outage that was being conducted to replace failed fuel assemblies, damage to

feedwater sparger nozzles was identified.

Example 1: The evaluation of the damaged feedwater sparger nozzles 7 and 8 on

sparger N4C identified that the damaged sections of the feedwater sparger nozzles had the

potential to adversely affect the vessel cladding by allowing relatively colder water to directly

flow into the relatively hotter vessel wall, thus inducing thermal fatigue. All components of the

reactor coolant system (RCS) are designed to withstand effects of cyclic loads due to system

pressure and temperature changes. These loads are introduced by startup (heatup) and

shutdown (cooldown) operations, power transients, and reactor trips. Limits are established

for pressure and temperature changes during RCS heatup and cooldown, such that plant

systems remain within the design assumptions and the stress limits for cyclic operation.

Limits on RCS pressure, temperature, heatup rate, and cooldown rate define allowable

operating regions and operating cycles to prevent nonductile failure of system components.

Because operation with the sparger nozzle damage was outside the limits originally analyzed,

the licensee requested General Electric-Hitachi (GEH) to provide an operability analysis of

the degraded condition. GEH Report 004N6557, Revision 0, dated January 26, 2018,

Operability Assessment of the River Bend Station Feedwater Sparger Assembly in the

January 2018 As-found Condition, stated, in part, this evaluation does not account for Final

10

Feedwater Temperature Reduction (FFWTR), Feedwater Heater Out-of-Service (FWH OOS)

conditions, nor Single Loop Operation (SLO) operating conditions. Based on this analysis,

the licensees engineering department concluded that the recommended classification of this

condition was OPERABLE-COMP MEAS (operable with compensatory measures), with the

degraded/nonconforming condition being the holes in the feedwater sparger nozzles. Based

on the results of this analysis, one of the operational restrictions/limitations stipulated in the

licensees ODMI was that, RBS will not operate in Single Loop Operation (SLO).

The ODMI developed by the licensee included two trigger points:

Trigger Point 1:

An unexpected operational state below approximately 85 percent power in which the vessel

wall-to-feedwater delta-T stabilizes at less than or equal to 154 degrees Fahrenheit (F), as

detected by periodic monitoring during normal operations, OR due to a transient as defined

above.

Trigger Point 2:

An unexpected operational state in which the vessel wall-to-feedwater delta-T stabilizes at

greater than 154 degrees F, as detected by periodic monitoring during normal operations, OR

due to a transient as defined above.

The ODMI failed to provide adequate guidance to the operators if they found themselves in

any of the conditions that GEH had listed as not being evaluated for continued operation with

the degraded condition. When reactor recirculation pump B failed to shift to fast speed at

9:46 a.m., the operators logged entry into Procedure GOP-004, Single Loop Operations.

The plant was in single loop operating conditions, and remained there until 10:57 a.m. when

the Mode switch was placed in shutdown. The ODMI failed to provide adequate guidance on

the actions required if the plant entered any of the conditions that were not evaluated for the

degraded sparger condition. In addition, the Just In Time Training given to the operators

prior to taking the watch to commence power operations with the degraded condition did not

address these issues either. As a result, rather than take prompt actions to place the plant in

a known safe condition upon entry into single loop operations, the control room supervisor

requested that GEH be contacted to determine if it was acceptable to remain in single loop

operations.

Example 2: The evaluation of the damaged feedwater sparger nozzles 7 and 8 on

sparger N4C identified that the damaged sections of the feedwater sparger nozzles had the

potential to adversely affect the B narrow range level instrument. The damage on feedwater

sparger N4C created unexpected feedwater flow paths in the reactor vessel during plant

operation that had the potential to adversely affect the "B" variable leg reactor water level

instruments. There were two potential impacts of this condition on indicated level from

narrow range level instruments that tap off of the B variable leg. Flow from the holes in the

feedwater sparger nozzle elbows could flow across the variable leg nozzle opening at AZ

200 degrees (B Leg), lowering the pressure on the variable leg side of the differential

pressure measurements, or the flow from the sparger nozzle damage could directly impact

the B variable leg, increasing the pressure on the variable leg side of the differential pressure

measurements.

11

The narrow range RPV level instrumentation supports two reactor water level trips: low level

(Level 3) and high level (Level 8). During a transient or accident event where the RPV water

level is changing, the trip signal from the B narrow range instrument could be affected.

Based on the GE report, during a transient or accident event where the RPV water level is

increasing, the high level (Level 8) trips (RPS trip and Feedwater Pump trip) in the affected

channel may occur later than the trips in the unaffected channels. This may delay the overall

Level 8 trips. For the Level 8 RPS trip, the margin between the calculated nominal trip

setpoint and the technical specification allowable value is 0.77 inches. For the Level 3 RPS

trip, the margin between the calculated nominal trip setpoint and the technical specification

allowable value is 0.67 inches. An operability determination of the narrow range level

instruments was performed under CR-RBS-2018-00633 CA-01.

The ODMI developed by the licensee included two trigger points:

Trigger Point 1:

Action: Refer to applicable SRs as specified by STP-000-0001, Att. 9.2

Step 30 in STP-000-0001 not within 4 inches

Step 71 in STP-000-0001 not within 6 inches

Notify the Duty Manager and the Ops Duty Manager

Trigger Point 2:

The magnitude of the B channel deviation is 1.5 inches in either direction from the average

of the A, C and D channel average + 1.1 inches.

Notify the Duty Manager and the Engineering Duty Manager.

The ODMI implemented by the licensee allowed level indication deviation in the affected

channel for the B21-LTN080 instruments to be monitored to ensure it remained within the

allowable margin to ensure the technical specification trip limit is not exceeded. It stated in

part that, If the deviation exceeds a change of 1.5 inches from historical deviation of

1.1 inches above the average of the A, C, and D channels in either an increasing or

decreasing direction, then condition will be evaluated by engineering. The monitored trigger

point of +1.5 inches will provide adequate margin for both the Level 3 and Level 8 trips.

However, if a 1.5-inch bias in the low direction would have been reached, two Technical

Specification (TS) Allowable Values could have been exceeded (by 0.5 inches for TS

Table 3.3.5.2-1, Function 2, Reactor Core Isolation Cooling System Instrumentation, and by

0.49 inches for TS Table 3.3.5.2-1, Function 5, Reactor Protection System Instrumentation).

The 1.5-inch bias in the low direction would have rendered the instrument inoperable based

on 10 CFR 50.36(c)(2)(i), which states, Limiting conditions for operation are the lowest

functional capability or performance levels of equipment required for safe operation of the

facility. Since the limiting conditions for operations (LCOs) include Allowable Values (e.g.,

LCO 3.3.5.2 includes Table 3.3.5.2-1 which has Allowable Values for Functions 2 and 5), the

Allowable Values are understood to be the lowest functional capability or performance levels

of equipment required for safe operation of the facility.

The licensees technical specifications provide the following guidance: Surveillance

Requirement 3.0.1, Failure to meet a Surveillance, whether such failure is experienced

during the performance of the Surveillance or between performances of the Surveillance,

shall be failure to meet the LCO.

12

1.1 Definitions: A CHANNEL CALIBRATION shall be the adjustment, as necessary, of the

channel output such that it responds within the necessary range and accuracy to known

values of the parameter that the channel monitors

In addition, the TS Bases state, SR 3.0.1 through SR 3.0.4 establish the general

requirements applicable to all Specifications and apply at all times, unless otherwise stated.

The OPERABILITY of the RPS (Reactor Protection System) is dependent on the

OPERABILITY of the individual instrumentation channel Functions specified in

Table 3.3.1.1-1. Each Function must have a required number of OPERABLE channels [2 per

RPS trip system for the vessel level function] per RPS trip system, with their setpoints within

the specified Allowable Value, where appropriate. The actual setpoint is calibrated consistent

with applicable setpoint methodology assumptions. Each channel must also respond within

its assumed response time. Allowable Values are specified for each RPS Function specified

in the Table. Nominal trip setpoints are specified in the setpoint calculations. The nominal

setpoints are selected to ensure that the actual setpoints do not exceed the Allowable Value

between successive channel calibrations. Operation with a trip setpoint less conservative

than the nominal trip setpoint, but within its Allowable Value, is acceptable. A channel is

inoperable if its actual trip setpoint is not within its required Allowable Value.

Process effects impact the establishment of the appropriate Nominal Trip Setpoint, which is

determined by addressing all instrument channel uncertainties (including biases) and

offsetting them from the Analytical Limit. The currently licensed Allowable Values are fixed

within the technical specification tables. Nominal Trip Setpoints are established on the basis

of a calculation that identifies all known uncertainties between the Analytical Limit and the

Nominal Trip Setpoint. If a new, unaccounted-for process effect bias in the nonconservative

direction is discovered, this effect needs to be reflected in the calculation of a new Nominal

Trip Setpoint and a corresponding new Allowable Value. However, in this case, the licensee

did not elect to pursue a license amendment or other process to change its currently licensed

Allowable Value, nor did it ask for a temporary enforcement discretion. Therefore, with the

new (unaccounted for) postulated process effect present, this has the effect of making the

existing Nominal Trip Setpoint (calibrated value) offset in the nonconservative direction by the

amount of the new postulated process effect (i.e., up to 1.5 inches), which reduces the margin

between the actual trip setpoint and the existing licensed Allowable Value.

Therefore, to meet the River Bend technical specification requirement that a channel be

considered inoperable if its actual trip setpoint is not within its required Allowable Value

without changing the currently licensed Allowable Value, only approximately a 1/2-inch of the

1.5 inches of new postulated process effect can be accommodated between the existing

calibrated setpoint and the (existing) licensed Allowable Value. Thus, the direction to notify

engineering only if the Rx vessel level indication bias had reached a value of 1.5 inches in

either direction was inadequate direction for the operating staff in order to ensure that the

instruments remained operable.

Corrective Actions: The licensee corrected the condition by revising the ODMI to include

adequate operator guidance and trigger points.

Corrective Action Reference: CR-RBS-2018-03148

13

Performance Assessment:

Performance Deficiency: The failure to establish ODMI guidance per Procedure EN-OP-111

to address the compensatory measures implemented to maintain operability of the plant with

degraded feedwater sparger nozzles was a performance deficiency.

Screening: For Example 1, the performance deficiency was more than minor, and therefore a

finding, because it was associated with the equipment reliability 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 licensee failed to provide adequate guidance to

the operators for actions required if the plant inadvertently entered any of the unanalyzed

conditions for continued operation with the degraded sparger. For Example 2, the

performance deficiency was more than minor, and therefore a finding, because if left

uncorrected it would have the potential to lead to a more significant safety concern.

Specifically, the use of less conservative calculated values than the Allowable Values stated

in the facility TS as a basis for establishing a threshold for operability of TS equipment could

result in the inappropriate evaluation of actual degraded conditions that impact the ability of

components to perform their required safety functions.

Significance: The inspectors screened the finding in accordance with Inspection Manual

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

At-Power. Using Inspection Manual Chapter 0609, Appendix A, Exhibit 1, Initiating Events

Screening Questions, the inspectors determined this finding was of very low safety

significance (Green) because for Example 1, the finding would not result in exceeding the

RCS leak rate for a small LOCA and could not have likely affected other systems used to

mitigate a LOCA. For Example 2, it was not a design/qualification deficiency, did not

represent a loss of system safety function, did not result in a loss of function of a single train

for greater than its TS-allowable outage time, did not result in a loss of function of nonsafety-

related risk-significant equipment and was not risk significant due to external events. In

addition, no actual deviation of the B narrow range level instrument was observed during

plant startup on February 9, 2018.

Cross-cutting Aspect: This finding had a cross-cutting aspect of human performance, change

management H.3: Leaders use a systematic process for evaluating and implementing

change so that nuclear safety remains the overriding priority. Specifically, the licensee did

not use a systematic process to develop and verify the adequacy of the ODMIs associated

with the compensatory measures implemented for the degraded sparger.

Enforcement:

Violation: Title 10 CFR Part 50, Appendix B, Criterion V, requires in part that, activities

affecting quality shall be prescribed by documented instructions, procedures, or drawings, of

a type appropriate to the circumstances. Licensee Procedure EN-OP-111, Operational

Decision-Making Issue (ODMI) Process, Revision 16, an Appendix B quality-related

procedure, provides instructions for developing guidance for plant operation with

compensatory measures in place to maintain plant system operable with degraded

conditions. Procedure EN-OP-111, step 5.2.4, states that Operational Decision-Making

Considerations should ensure that a course of action is selected based upon a critical

consideration of risks and potential consequences, as well as a thorough understanding of

alternate solutions. The final decision should be a deliberate act, providing clear direction,

trigger points, contingencies, and abort criteria. The Action Plans should provide clear

14

guidance in each ODMI which delineate actions to be taken when conditions escalate

unexpectedly, conditions are outside the scope of the ODMI analysis, or actions are not able

to be implemented. Actions that contain recommendations to "consider or evaluate" in

response to triggers should be avoided. When such actions are used, a definite period to

finish the evaluation or consideration should be provided.

Contrary to the above, prior to February 1, 2018, the licensee failed to ensure that the ODMIs

provided a course of action based upon a critical consideration of risks and potential

consequences, as well as a thorough understanding of alternate solutions; and that the final

decision was a deliberate act providing clear direction, trigger points, contingencies, and abort

criteria. Specifically, the licensee failed to develop adequate guidance for the operators to

maintain safe operation of the plant with compensatory measures in place for degraded

feedwater sparger nozzles. The action plans failed to provide clear guidance in each ODMI

to delineate actions to be taken when conditions escalate unexpectedly; instead, the actions

specified directed the operators to consult with offsite contractors regarding the acceptability

of allowing the plant to remain in operation with given conditions.

Disposition: This violation is being treated as a non-cited violation, consistent with

Section 2.3.2.a of the NRC Enforcement Policy.

Failure to Establish Procedural Guidance for Determining Core Flow During Unanticipated

Single Loop Operations

Cornerstone Significance Cross-cutting Report

Aspect Section

Initiating Green [P.3] - 71153 -

Events NCV 05000458/2018012-03 Problem Follow-up of

Closed Identification Events and

and Notices of

Resolution, Enforcement

Resolution Discretion

The inspectors reviewed a self-revealed, non-cited violation of 10 CFR Part 50, Appendix B,

Criterion V, Instructions, Procedures and Drawings, for the licensees failure to establish

appropriate instructions in the abnormal operating procedure for thermal hydraulic

instabilities. Specifically, the procedural step for determining core flow when in single loop

operations at low power did not provide appropriate instructions to operators. As a result,

station personnel could not conclusively determine core flow and inserted a manual reactor

scram.

Description:

On February 1, 2018, with the unit in Mode 1 at approximately 27 percent power, reactor

recirculation pump B unexpectedly tripped during an upshift in the speed of the pump. As a

result, the reactor was in a single loop configuration with the recirculation pump A running in

fast speed and the recirculation pump B not running. Operators entered Abnormal Operating

Procedure AOP-0024, Thermal Hydraulic Instability Controls, Revision 30, as a result of the

unplanned entry into single loop operations. Step 5.8 of this procedure directed operators to

determine core flow and enter the General Operating Procedure GOP-004, for single loop

operations. Step 5.8 also instructed operators to determine core flow using process computer

point B33NA01V when in a configuration with one recirculation pump in fast speed and one

recirculation pump off. Control room operators observed the value of this data point as

13.9 Mlbm/hr. The operators concluded that this value was not valid since the indicated flow

15

was much lower than expected with one recirculation pump running in fast speed. The

operators then observed a value of 27.3 Mlbm/hr core flow using the ERIS data point for

B33NA01V. This value appeared to be a valid number based on the single loop operation

power/flow map contained in AOP-0024, Attachment 2. Normal data points are displayed in

ERIS with a white text, but control room operators observed the ERIS data point displayed in

a magenta color. Additionally, the word suspect appeared adjacent to the data point for

core flow. Control room operators contacted information technology personnel and attempted

to understand the magenta color and suspect information associated with the core flow data

point. Concurrently, operators attempted to validate core flow using alternate means but

were unsuccessful as the alternate indications did not provide accurate core flow readings at

low reactor power when in a single loop configuration. After approximately one hour spent

seeking to understand the unfamiliar indication associated with B33NA01V, control room

operators conducted a brief and made the decision to shut down the unit due to the

uncertainties associated with the core flow data point. Following plant shutdown and

subsequent troubleshooting and investigation, licensee personnel concluded that the

magenta text and suspect note associated with ERIS B33NA01V was an expected system

response. Below approximately 40 percent core flow, the plant process computer shifts the

calculation method from the primary means of calculating core flow using the sum of jet pump

flows to an alternate process that uses core plate differential pressure. As a result of shifting

to the alternate calculation of core flow, data point ERIS B33NA01V was programmed to turn

magenta in color and display suspect to alert operators that the method of calculating core

flow had changed.

The inspectors reviewed Condition Report CR-RBS-2012-07759. This condition report was

generated by operations department personnel on December 19, 2012, and identified that

ERIS point B33NA01V indicated suspect and was not available for use. The condition

report also stated that this data point was needed for determining core flow when the plant

configuration consisted of one recirculation pump running in fast speed and another

recirculation pump was off. The inspectors confirmed that this condition report was generated

during a single loop plant configuration that was the result of an unanticipated reactor

recirculation pump A trip on December 19, 2012. The condition report corrective actions

explained the reason for the suspect reading of ERIS point B33NA01V. No corrective

actions were generated to address AOP-0024, which directs licensed operators to validate

core flow in single loop operations. Additionally, no corrective actions were generated to

validate plant simulator response to unanticipated single loop operations.

Corrective Actions: After this information was disseminated to licensed operators, the

licensee implemented procedural changes to AOP-0024 that provided amplifying information

regarding B33NA01V validated core flow. Specifically, the licensee revised the procedure on

February 7, 2018, in order to 1) direct operators to determine core flow using ERIS data point

B33NA01V during single loop operations when core flow is below 40 percent and 2) provide

clear guidance regarding expected system response of the process computer data points

during abnormal flow configurations.

Corrective Action Reference: CR-RBS-2018-00776

Performance Assessment:

Performance Deficiency: The failure to establish appropriate guidance to determine core flow

during single loop operations in quality-related abnormal operating procedure AOP-0024,

Thermal Hydraulic Instability Controls, Revision 30, was a performance deficiency.

16

Screening: The performance deficiency was more than minor, and therefore a finding,

because it was 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. Specifically, the failure to understand core flow data indicated by

plant process computer point B33NA01V and ERIS data point B33NA01V resulted in

confusion and the ultimate decision to insert a manual reactor scram.

Significance: The inspectors screened the finding in accordance with Inspection Manual

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

At-Power. Using Inspection Manual Chapter 0609, Appendix A, Exhibit 1, Initiating Events

Screening Questions, the inspectors determined this finding is of very low safety significance

(Green) because the finding did not cause a reactor trip and the loss of mitigation equipment

relied upon to transition the plant from the onset of the trip to a stable shutdown condition.

Cross-cutting Aspect: This finding has a cross-cutting aspect in the area of problem

identification and resolution, resolution, because the licensee failed to take effective

corrective actions to address issues in a timely manner commensurate with their safety

significance. Specifically, the station failed to implement procedure changes to AOP-0024

after discovering similar confusing indications associated with B33NA01V on

December 19, 2012.

Enforcement:

Violation: Title 10 CFR Part 50, Appendix B, Criterion V, requires in part that, activities

affecting quality shall be prescribed by documented instructions, procedures, or drawings, of

a type appropriate to the circumstances.

Contrary to the above, prior to February 7, 2018, the licensee failed to provide a procedure of

a type appropriate to the circumstances for an activity affecting quality. Specifically,

AOP-0024, Thermal Hydraulic Stability Controls, a quality-related procedure, was not

appropriate to the circumstances. AOP-0024 did not provide accurate and adequate

instruction to operators to determine core flow during single loop operations. The licensee

restored compliance by revising AOP-0024 to include accurate and adequate guidance to

determine core flow during unanticipated single loop operations.

Disposition: This violation is being treated as an non-cited violation consistent with

Section 2.3.2.a of the NRC Enforcement Policy.

Failure to Perform 10 CFR 50.59 Evaluation for Main Feedwater System Sparger Nozzle

Damage

Cornerstone Significance Cross-cutting Report

Aspect Section

None SL-IV None 71111.18 -

NCV 05000458/2018012-07 Plant

Closed Modifications

The inspectors identified a Severity Level IV NCV of 10 CFR 50.59, Changes, Tests, and

Experiments, for the licensees failure to provide a written safety evaluation for the

determination that operation with compensatory measures for damaged feedwater sparger

nozzles did not require a license amendment pursuant to 10 CFR 50.90, Application for

amendment of license, construction permit, or early site permit. Specifically, the licensee

17

failed to recognize that compensatory measures prohibiting operation in single loop

conditions were technical specification changes, and as such required prior NRC approval.

Description:

During an outage that was conducted to replace failed fuel assemblies in January 2018,

damage to feedwater sparger nozzles was identified. The evaluation of the damaged

feedwater sparger nozzles #7 and #8 on sparger N4C identified that the damaged sections of

the feedwater sparger nozzles had the potential to adversely affect the vessel cladding by

allowing relatively colder water to directly flow into the relatively hotter vessel wall, thus

inducing thermal fatigue. All components of the RCS are designed to withstand effects of

cyclic loads due to system pressure and temperature changes. These loads are introduced

by startup (heatup) and shutdown (cooldown) operations, power transients, and reactor trips.

Limits are established for pressure and temperature changes during RCS heatup and

cooldown, such that plant systems remain within the design assumptions and the stress limits

for cyclic operation. Limits on RCS pressure, temperature, heatup rate, and cooldown rate

define allowable operating regions and operating cycles to prevent nonductile failure of

system components. Because operation with the sparger nozzle damage was outside the

limits originally analyzed, the licensee requested General Electric-Hitachi (GEH) to provide an

operability analysis of the degraded condition. GEH Report #004N6557 Revision 0, dated

January 26, 2018, Operability Assessment of the River Bend Station Feedwater Sparger

Assembly in the January 2018 As-found Condition, stated in part, this evaluation does not

account for Final Feedwater Temperature Reduction (FFWTR), Feedwater Heater Out-of-

Service (FWH OOS) conditions, nor Single Loop Operation (SLO) operating conditions.

Based on this analysis, the licensees engineering department concluded that the

recommended classification of this condition was OPERABLE-COMP MEAS (operable with

compensatory measures), with the degraded/nonconforming condition being the holes in the

feedwater sparger nozzles. One of the operational restrictions/limitations was that, RBS will

not operate in Single Loop Operation (SLO). These compensatory measures directly

affected Technical Specification (TS) 3.4.1, Recirculation Loops Operating. The TS limiting

condition for operation (LCO) B, One recirculation loop shall be in operation, which is

applicable when operating in Modes 1 and 2, had the following limitations:

1. THERMAL POWER 77.6% rated thermal power (RTP);

2. Total core flow within limits;

3. LCO 3.2.1,"AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR),"

single loop operation limits specified in the Core Operating Limits Reports (COLR);

4. LCO 3.2.2,"MINIMUM CRITICAL POWER RATIO (MCPR)," single loop operation

limits specified in the COLR; and

5. LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation," Function 2.b

(Average Power Range Monitors Flow Biased Simulated Thermal Power- High), Allowable

Value for single loop operation as specified in the COLR.

The licensees compensatory measures established a more restrictive LCO whereby Single

Loop Operations are limited by more restrictive criteria than those stated in the existing LCO.

Specifically, the licensees compensatory measures stated that the station would not operate

in Single Loop Operation.

NRC Administrative Letter 98-10: Dispositioning of Technical Specifications That Are

Insufficient To Assure Plant Safety, dated December 29, 1988, provides the following

guidance:

18

Title 10 of the Code of Federal Regulations, Section 50.36, Technical Specifications

requires that each TS limiting condition for operation (LCO) specify, at a minimum, the lowest

functional capability or performance level of equipment required for the safe operation of the

facility.

IMC0326 states, in part: Additionally, if a compensatory measure involves a temporary facility

or procedure change, 10 CFR 50.59 should be applied to the temporary change with the

intent to determine whether the temporary change/compensatory measure itself (not the

degraded or nonconforming condition) impacts other aspects of the facility or procedures

described in the UFSAR. In considering whether a temporary facility or procedure change

impacts other aspects of the facility, a licensee should apply 10 CFR 50.59, paying particular

attention to ancillary aspects of the temporary change that result from actions taken to directly

compensate for the degraded condition. Whenever degraded or nonconforming conditions

are discovered, 10 CFR Part 50, Appendix B, requires prompt corrective action to correct or

resolve the condition.

In summary, the discovery of an improper or inadequate TS value or required action is

considered a degraded or nonconforming condition as defined in IMC0326. Imposing

administrative controls in response to an improper or inadequate TS is considered an

acceptable short-term corrective action. The NRC staff expects that, following the imposition

of administrative controls, an amendment to the TS, with appropriate justification and

schedule, will be submitted in a timely fashion. Once any amendment correcting the TS is

approved, the licensee must update the final safety analysis report, as necessary, to comply

with 10 CFR 50.71(e).

Because the licensee did not perform a 50.59 screening for the compensatory measures

associated with the restricted operating conditions, the licensee failed to recognize that the

TSs were now non-conservative and that NRC approval was required.

Corrective Actions: The licensee documented the violation in the corrective action program

and created actions to review 50.59 screening requirements.

Corrective Action Reference: CR-RBS-2018-03147

Performance Assessment:

Performance Deficiency: The failure to perform a written safety evaluation for the effect of

compensatory measures implemented due to degraded feedwater sparger nozzles was a

performance deficiency.

Screening: The performance deficiency was evaluated in accordance with the traditional

enforcement process because it impacted the ability of the NRC to perform its regulatory

oversight function.

Significance: Using example 6.1.d.2 from the NRC Enforcement Policy, the violation was

determined to be a Severity Level IV violation.

Cross-cutting Aspect: Because the violation was dispositioned using the traditional

enforcement process, no cross cutting aspect was assigned.

19

Enforcement:

Violation: Title 10 CFR 50.59(d)(1) requires, in part, that the licensee shall maintain records

of changes in the facility, of changes in procedures, and of tests and experiments as

described in the updated final safety analysis report (UFSAR). These records must include a

written evaluation which provides a basis for the determination that the change, test, or

experiment does not require a license amendment.

Contrary to the above, since January 29, 2018, the licensee failed to maintain records of a

change to the facility, as described in the UFSAR, that include a written evaluation which

provides a basis for the determination that the change did not require a license amendment.

Specifically, the licensee made changes pursuant to 10 CFR 50.59(c) to the plant as

described in the UFSAR and did not provide a written evaluation for the determination that

compensatory measures prohibiting operation in single loop condition were technical

specification changes, and as such required prior NRC approval.

Disposition: This violation is being treated as an non-cited violation consistent with

Section 2.3.2.a of the NRC Enforcement Policy.

Failure to Conduct Adequate Transient Snap Shot Assessment Following Recirculation Pump

Trip

Cornerstone Significance Cross-cutting Report

Aspect Section

Initiating Events Green None 71152 -

FIN 05000458/2018012-01 Problem

Closed Identification

and

Resolution

The inspectors identified a Green finding for the licensees failure to adequately validate

simulator response during a transient snap shot assessment following an unexpected trip of

reactor recirculation pump A on December 19, 2012.

Description:

On December 19, 2012, with the plant operating at 100 percent power, reactor recirculation

pump A unexpectedly tripped off. As a result, the plant configuration consisted of one

recirculation pump running in fast speed and the other recirculation pump secured. During

this single loop configuration, station personnel identified that emergency response

information system (ERIS) point B33NA01V indicated suspect and was not available for

use. The station documented this condition in Condition Report CR-RBS-2012-07759.

On February 1, 2018, with the unit in Mode 1 at approximately 27 percent power, reactor

recirculation pump B unexpectedly tripped during an upshift in the speed of the pump. As a

result, the reactor was in a single loop configuration with the recirculation pump A running in

fast speed and the recirculation pump B not running. Operators entered abnormal operating

procedure AOP-0024, Thermal Hydraulic Instability Controls, Revision 30, as a result of the

unplanned entry into single loop operations. Step 5.8 of this procedure directed operators to

determine core flow and enter general operating procedure GOP-004, Single Loop

Operations. Step 5.8 also instructed operators to determine core flow using process

computer point B33NA01V (which can be observed in both ERIS and the plant process

computer) when in a configuration with one recirculation pump in fast speed and one

20

recirculation pump off. Control room operators observed the value of this data point as

13.9 million pounds mass per hour (Mlbm/hr) of flow through the reactor core. The operators

concluded that this value was not valid since the indicated flow was much lower than

expected with one recirculation pump running in fast speed. The operators then observed a

value of 27.3Mlbm/hr core flow using the ERIS data point for B33NA01V. This value

appeared to be a valid number based on the single loop operation power/flow map contained

in AOP-0024, Attachment 2. Normal data points on ERIS are displayed with a white text, but

control room operators observed the ERIS data point displayed in a magenta color.

Additionally, the word suspect appeared adjacent to the data point for core flow. Control

room operators contacted information technology personnel and attempted to understand the

magenta color and suspect information associated with the core flow data point.

Concurrently, operators attempted to validate core flow using alternate means but were

unsuccessful, as the alternate indications did not provide accurate core flow readings at low

reactor power when in a single loop configuration. After approximately one hour spent

seeking to understand the unfamiliar indication associated with B33NA01V, control room

operators conducted a brief and made the decision to shut down the unit due to the

uncertainties associated with the core flow data point. Following plant shutdown and

subsequent troubleshooting and investigation, licensee personnel concluded that the

magenta text and suspect note associated with ERIS B33NA01V was an expected system

response. Below approximately 40 percent core flow, the plant process computer shifts the

calculation method from the primary means of calculating core flow using the sum of jet pump

flows to an alternate process that uses core plate differential pressure. As a result of shifting

to the alternate calculation of core flow, data point ERIS B33NA01V was programmed to turn

magenta in color and display suspect to alert operators that the method of calculating core

flow had changed. After this information was disseminated to licensed operators, the

licensee implemented procedural changes to AOP-0024 that provided amplifying information

regarding B33NA01V validated core flow. Specifically, the licensee revised the procedure on

February 7, 2018, in order to provide clear guidance regarding expected system response of

the process computer data points during abnormal flow configurations.

The inspectors compared the actual plant response to the simulator response for the trip of a

recirculation pump while at low power. The actual conditions in the main control room during

the event on February 1, 2018, resulted in ERIS point B33NA01V indicating the correct flow

(27.3Mlbm/hr), but the data point turned magenta in color and displayed the warning label

suspect. This was later determined by information technology personnel to be the correct

response and data display, and was the result of the core flow calculation methodology

swapping from the primary method (jet pump flow) to the alternate method (core plate

differential pressure).

In the simulator, the inspectors determined that ERIS point B33NA01V provided erratic

indications of core flow following a simulated trip of the recirculation pump B from an initial

condition of approximately 25 percent. The indicated flow varied, and ultimately stabilized at

approximately 10Mlbm/hr, which is less than half of the expected indication. Additionally,

B33NA01V did not change to a magenta color, and it did not display the word suspect. The

inspectors determined that ERIS B33NA01V was programmed to calculate core flow using

the sum of jet pump flows at all power levels. As a result, the displayed value was inaccurate

below 40 percent core flow, and the data point was not programmed to turn magenta or

indicate suspect since no swap to a backup means of calculation below 40 percent core

flow was modelled.

21

The inspectors reviewed procedure EN-OP-117, Operations Assessments, Version 4,

Section 5.4, which states that transient snap-shot assessments are performed whenever a

plant transient occurs. A plant transient is defined in section 5.4[2] as including any turbine

generator power change in excess of 10 percent of rated power in less than one minute other

than a momentary spike due to a grid disturbance or a manually initiated runback. The

inspectors concluded that the recirculation pump A trip on December 19, 2012, met the

definition of a transient. EN-OP-117, Attachment 9.2, Transient Snap Shot Assessment

Documentation Form, Objective 7, discusses the training preparation aspect of the

assessment. Specifically, the transient snap-shot assessment is performed in order to

validate that the simulator accurately represented the plant characteristics of the transient.

The licensee provided a Post-Event Simulator Test report that was run on February 14, 2013.

The report concluded that the simulator response matched the parameters observed in the

plant. The inspectors determined that although the snap-shot assessment was performed,

station personnel did not validate that ERIS B33NA01V (validated core flow) provided

operators with the same indications seen by operators in the plant during a recirculation

pump trip.

The inspectors determined that no condition report or simulator deficiency report was

generated to document the discrepancy between the plant and the simulator for displaying

ERIS B33NA01V. The simulator ERIS B33NA01V core flow indication did not display the

correct value for core flow and also did not indicate suspect or turn magenta. The

inspectors reviewed training documentation to determine why this discrepancy was not

observed during continuing simulator training scenarios. The inspectors concluded that this

discrepancy was not documented because the station did not conduct training on abnormal

single loop operations during low power operations. The inspectors reviewed industry

standards and guidelines for simulator training and determined that the station is required to

periodically conduct training on abnormal events that occur during low power operations.

Corrective Actions: The station documented the core flow indication simulator deficiency in a

deficiency report and generated actions to incorporate the discrepancy into future licensed

operator training sessions.

Corrective Action Reference: CR-RBS-2018-03145

Performance Assessment:

Performance Deficiency: The licensees failure to validate core flow in the simulator during a

transient snap shot assessment following the trip of the reactor recirculation pump A on

December 19, 2012, was a performance deficiency.

Screening: The performance deficiency was more than minor, and therefore a finding,

because it was associated with the human performance attribute of the Initiating Events

Cornerstone and adversely affected the cornerstone objective to limit the likelihood of events

that upset plant stability and challenge critical safety functions during shutdown as well as

power operations. Specifically, the failure to validate simulator fidelity following a plant

transient prevented the licensee from identifying simulator model discrepancies when

determining core flow during low power, single loop operations.

22

Significance: The inspectors screened the finding in accordance with Inspection Manual

Chapter 0609, Appendix A, The Significance Determination Process for Findings At-Power.

The finding was determined to be of very low safety significance (Green) because the finding

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

equipment would not be available.

Cross-cutting Aspect: No cross cutting aspect was assigned because the performance

deficiency is not indicative of current licensee performance.

Enforcement: Inspectors did not identify a violation of regulatory requirements associated

with this finding.

Failure to Submit a Licensee Event Report for a Manual Scram

Cornerstone Significance Cross-cutting Report

Aspect Section

None SLIV None 71153 -

NCV 05000458/2018012-04 Follow-up of

Closed Events and

Notices of

Enforcement

Discretion

The inspectors identified a Severity Level IV non-cited violation of 10 CFR 50.73, Licensee

Event Report System, for the licensees failure to submit a required licensee event report

(LER). Specifically, on February 1, 2018, after an unexpected trip of the recirculation pump

B, the licensee initiated a manual scram of the reactor that was not part of a preplanned

sequence and failed to submit an LER within 60 days.

Description: At approximately 9:46 a.m. on February 1, 2018, with the unit operating at

approximately 27 percent power, the recirculation pump B unexpectedly tripped during an

attempted transfer from slow to fast speed. The licensee promptly entered AOP-0024,

Thermal Hydraulic Instability, and GOP-0004, Single Loop Operation. Note 5.8 of AOP-

0024 and Precaution 3.6 of GOP-0004 instruct the licensee to use process computer point

B33NA01V to determine core flow while in single loop operation. The plant process computer

(PPC) and emergency response information system (ERIS) readouts showed conflicting

indications for this computer point, with the PPC showing approximately 13,900 Mlbm/hr of

flow and ERIS showing approximately 26,000 Mlbm/hr of flow.

Step 5.1 of AOP-0024 instructs the licensee to determine where on the power-to-flow map the

plant is operating. If the plant is operating in the restricted region, the procedure states to exit

that region by lowering power or raising flow. If the plant is operating in the exclusion region,

the procedure states to verify that a scram has occurred. The indicated PPC value for core

flow put the plant in an unanalyzed region of the power-to-flow map, with less flow than the

minimum amount of flow that defines any region, including the exclusion region. The

indicated ERIS value put the plant in the restricted region, just above the boundary that

delineates the restricted region from the monitoring region.

The licensee initially believed the ERIS value to be the correct value; however, this value was

accompanied by a magenta suspect note on the ERIS screen, which caused the licensee to

question its validity. In an effort to determine the true value of core flow, the licensee

performed a manual calculation using other known inputs. The licensee performed this

calculation incorrectly and wrongly corroborated the PPC value as the correct value. Given

the inability to establish that the plant was operating in any allowed region of the power-to-

23

flow map, the licensee made the decision to manually actuate the reactor protection system

(RPS) by taking the reactor mode switch to shutdown.

During the investigation after the scram, the licensee determined that the ERIS value was, in

fact, a valid indication of core flow at the time of the event. Operators had not been

adequately trained on the meaning of the magenta suspect indication, and were therefore

unable to determine the implications of the indications on the validity of the data point.

Pursuant to the requirements of 10 CFR 50.72(b)(3)(iv), the licensee reported the scram

event to the NRC at 1:23 p.m. as an event that resulted in an actuation of the RPS. On

March 23, 2018, the licensee retracted the report on the grounds that the actuation was part

of a pre-planned sequence during testing or reactor operation. The inspectors concluded that

this retraction was inappropriate and that the event was reportable for the reasons provided

below.

The inspectors reviewed NUREG-1022, Event Report Guidelines 10 CFR 50.72 and 50.73,

revision 3, which provides the following guidance: Actuations that need not be reported are

those initiated for reasons other than to mitigate the consequences of an event (e.g., at the

discretion of the licensee as part of a preplanned procedure). In the case of the February 1,

2018, River Bend scram event, the inspectors determined that the manual RPS actuation was

initiated in order to mitigate the consequences (i.e., uncertainty as to the condition of the plant

with respect to core flow and power-to-flow considerations) of an event (i.e., the unexpected

loss of a reactor recirculation pump).

NUREG-1022 also provides an example of a reportable manual scram that was event driven

and not part of a preplanned sequence during testing or reactor operation:

At a BWR, both recirculation pumps tripped as a result of a breaker problem. This

placed the plant in a condition in which BWRs are typically scrammed to avoid

potential power/flow oscillations. At this plant, for this condition, a written off-normal

procedure required the plant operations staff to scram the reactor. The plant staff

performed a reactor scram, which was uncomplicated. This event is reportable as a

manual RPS actuation. Even though the reactor scram was in response to an existing

written procedure, this event does not involve a preplanned sequence because the

loss of recirculation pumps and the resultant off-normal procedure entry were event

driven, not preplanned. Both an ENS notification and an LER are required. In this

case, the licensee initially retracted the ENS notification, believing that the event was

not reportable. After staff review and further discussion, it was agreed that the event

is reportable for the reasons discussed above.

As with the scram in the above example, the scram that occurred at River Bend Station was

not part of a preplanned sequence during testing or reactor operation, but was instead an

event driven response to a series of unplanned and unexpected adverse occurrences in the

plant. These occurrences included: a trip of the recirculation pump B, entry into an abnormal

operating procedure for thermal hydraulic instability, an inability to determine core flow and

location on the power-to-flow map in accordance with that procedure, a realization that the

PPC indication of core flow put the plant outside of any allowed operating region of the

power-to-flow map, an incorrect manual calculation that wrongly corroborated the accuracy of

the PPC indication, and the presence of a poorly understood suspect indication that

appeared to undermine the validity of the ERIS flow indication. These adverse occurrences

generated uncertainty as to the status of reactor safety. The subsequent decision to perform

24

a manual reactor scram was consistent with general instruction provided in EN-OP-115,

Conduct of Operations, which states: do not hesitate to reduce power or perform an

immediate reactor shutdown when reactor safety is uncertain. As with the scram in the

above example, the February 1, 2018, River Bend scram also involved entry into an off-

normal procedure due to an unexpected plant equipment malfunction that resulted in the

potential for the plant to be in an undesired condition with respect to power-to-flow

considerations.

The senior resident inspector was present in the control room during the events and was able

to confirm that the shutdown was event driven rather than preplanned. At 10:55 a.m., the

control room briefed that because PPC and ERIS showed conflicting indications of core flow

with ERIS indicating suspect, the mode switch was going to be placed in shutdown. At

10:57 a.m., roughly two minutes after the brief was completed, the reactor operator

scrammed the reactor, and the following station log entry was made: MCR [main control

room] announces placing plant in shut down due to inability to regulate recirculation flow. If

the reactor shutdown had been preplanned, it would not have proceeded at this accelerated

pace. Rather, the licensee would have worked through the relevant steps of the applicable

shutdown procedure, GOP-0004, Single Loop Operation, scramming the reactor only after

those steps had been completed and signed for. Upon review of the copy of GOP-0004 that

was in use by the operators on February 1, 2018, the inspectors noted that no steps of

Attachment 3, Shutdown from Single Loop Operation, were marked as completed, and the

attachment was not signed off as being initiated or completed. The deviation from normal

practice was appropriate because the scram was not being initiated as part of a preplanned

sequence. It was instead being initiated in response to the unanticipated emergence of a

safety concern.

Corrective Actions: The licensee documented the violation in the corrective action program

and generated corrective actions to review reportability requirements.

Corrective Action Reference(s): CR-RBS-2018-03953

Performance Assessment:

Performance Deficiency: The failure to submit a required licensee event report was a

performance deficiency.

Screening: The performance deficiency was evaluated in accordance with the reactor

oversight process and was determined to be minor because it could not be reasonably

viewed as a precursor to a significant event, would not have the potential to lead to a more

significant safety concern, does not relate to a performance indicator that would have caused

the performance indicator to exceed a threshold, and did not adversely affect a cornerstone

objective. The performance deficiency was evaluated in accordance with the traditional

enforcement process because it impacted the ability of the NRC to perform its regulatory

oversight function.

Significance: Using example 6.9.d.9 from the NRC Enforcement Policy, the violation was

determined to be a Severity Level IV violation.

Cross-cutting Aspect: Because the violation was dispositioned using the traditional

enforcement process, no cross-cutting aspect was assigned.

25

Enforcement:

Violation: 10 CFR 50.73(a)(1) requires, in part, that the licensee shall submit a Licensee

Event Report (LER) for any event of the type described in this paragraph within 60 days after

the discovery of the event. 10 CFR 50.73(a)(2)(iv)(A) requires, in part, that the licensee shall

report any event or condition that resulted in manual actuation of the reactor protection

system (RPS) except when the actuation resulted from and was part of a pre-planned

sequence during testing or reactor operation. Contrary to the above, on April 2, 2018, the

licensee failed to submit an LER within 60 days after the discovery of an event or condition

that resulted in manual actuation of the RPS that did not result from and that was not a part of

a pre-planned sequence during testing or reactor operation. Specifically, the licensee failed

to submit an LER within 60 days of a manual reactor scram that occurred on February 1,

2018.

Disposition: Because this SLIV violation was neither repetitive nor willful, and because it was

entered into the licensees corrective action program as Condition Report

CR-RBS-2018-03953, it is being treated as a non-cited violation consistent with

Section 2.3.2.a of the NRC Enforcement Policy.

EXIT MEETINGS AND DEBRIEFS

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

On May 31, 2018, and on July 16, 2018, the inspectors presented the inspection results to

Mr. W. Maguire, Site Vice President, and other members of the licensee staff.

26

DOCUMENTS REVIEWED

71111.15Operability Determinations and Functionality Assessments

Procedures

Number Title Revision

EN-OE-100 Operating Experience Program 12 & 13

STP-051-4206 (RPS Bypassed) RPS/RHR Reactor Vessel Level-Low, 305

Level 3, High, Level 8, Channel Calibration and Logic

System Functional Test (B21-N680B, B21-N683B, B21-

N080B)

STP-051-4227 ECCS/RCIC Actuation Ads Trip System B Reactor 20

Vessel Water Level Low, Level 3/High, Level 8 Channel

Calibration, and Logic System Functional Test (B21-

N095B, B21-N695B, B21-N693B)

STP-501-4202 FWS/MAIN Turbine Trip System - Reactor Vessel Water 15

Level - High Level 8, Channel Calibration and LSFT

(C33-N004B, C33-K624B, C33-R606B, C33-K650-3)

G13.18.6.1.B21 Reactor Vessel Water Level - Low, Level 3 Trip Function 3

G13.18.6.1.B21*003 Reactor Vessel Water Level - Low, Level 3 Trip Function 3

G13.18.6.1.B21*010 Reactor Vessel Water Level - Low, Level 8 Narrow 0, 1, 2, & 3

Range

MCP-IC-501-4202 FWS/FEED Pump Trip System (MSO) - Reactor Vessel 0

Water Level - High Level 8, Loop Calibration (C33-

LTN006B, C33-ESN606B)

71111.18Plant Modifications

Condition Reports (CR-RBS-)

CR-RBS-2014-05194 CR-RBS-2014-06685 CR-RBS-2014-06691 CR-RBS-2015-03253

CR-RBS-2015-03983 CR-RBS-2015-04065 CR-RBS-2015-04117 CR-RBS-2015-08476

CR-RBS-2015-08515 CR-RBS-2016-00791 CR-RBS-2016-00893 CR-RBS-2016-00893

CR-RBS-2016-04351 CR-RBS-2016-04353 CR-RBS-2017-02828 OE-NOE-2004-00008

OE-NOE-2004-00084

Engineering Changes

Number Title Revision

EC-75588 Accept As-Is Evaluation for Remainder of Cycle 20: Sparger 0 & 1

N4C Nozzles 7 and 8 Damaged

Attachment

Procedures

Number Title Revision

OSP-0053 Emergency and Transient Response Support Procedure 20-25

STP-000-0001 Daily Operating Logs 082

DBR-0035279 GEH Comment Resolution Form 0

4221.110-000- Operability Assessment of the River Bend Station 0

043 Feedwater Sparger Assembly in the January 2018 As-

Found Condition

71152 - Problem Identification and Resolution

Condition Reports (CR-RBS-)

CR-RBS-2018-00358 CR-RBS-2018-00613 CR-RBS-2018-00633 CR-RBS-2018-00733

CR-RBS-2018-00895 CR-RBS-2018-00294 OE-NOE-2004-00008 OE-NOE-2004-00084

Engineering Changes

Number Title Revision

EC-75663 Loose Parts Evaluation for Material Lost From 0

Feedwater Spargers Identified During PO-18-01

Foreign Material FME LPA-000

Miscellaneous Documents

Number Title Revision/Date

OSRC Meeting 2018-0001 Minutes

OSRC Meeting 2018-0002 Minutes

Action Item OE33308-20110507-A2-RBS-001

CNR RBS PO-18-01-01 Foreign Material Customer Notification Report 0

ECH-NE-17-00039 River Bend MOC-20a Fuel Inspection Plan 0

NEDC-31336P-A General Electric Instrument Setpoint 0

Methodology

NEDE-21821-A Boiling Water Reactor Feedwater 0

Nozzle/Sparger Final Report

NEI 96-07 Guidelines for 10 CFR 50.59 Implementation 1

OE33308-20110507 Sampling Probe Found in Feedwater Sparger August 17, 2011

A-2

Miscellaneous Documents

Number Title Revision/Date

PO 18-01 BOP Foreign Material Inspection Report

RBS-ER-99-0539 Engineering Response Associated with Loose 0

Part in the Feedwater System

Procedures

Number Title Revision

AOP-0001 Reactor Scram 37

AOP-0024 Thermal Hydraulic Stability Controls 30, 31, & 32

EN-NF-102 Corporate Fuel Reliability 6

EN-OP-104 Operability Determination Process 14

EN-OP-111 Operational Decision Making Issue Process 15

EN-OP-117 Operations Assessments 4

EOP-0001 Emergency Operating Procedure - RPV Control 28

GOP-0001 Plant Startup 99

GOP-0002 Power Decrease/Plant Shutdown 78

GOP-0003 Scram Recovery 31

GOP-0004 Single Loop Operation 25

OE-100 Operating Experience Program 1

R-PL-012 Corrective Action Program 1

STP-000-0001 Daily Operating Logs 082

Work Order 52599498

71153Follow-up of Events and Notices of Enforcement Discretion

Procedures

Number Title Revision

EN-OP-115 Conduct of Operations 23

GOP-0004 Single Loop Operation 23

Condition Reports (CR-RBS-)

2018-03149 2018-03953

A-3

ML18194A413

SUNSI Review: ADAMS: Non-Publicly Available Non-Sensitive Keyword:

By: CHY/RDR Yes No Publicly Available Sensitive NRC-002

OFFICE SRI:DRP/C RI:DRP/C SPE:DRP/C ARI:DRP/C C:DRS/EB2 D:DRP

NAME JSowa BParks CYoung MOBanion JDrake AVegel

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

DATE 6/22/2018 6/21/2018 6/21/2018 6/25/2018 7/10/2018 7/18/18

OFFICE BC:DRP/C

NAME JKozal

SIGNATURE /RA/

DATE 7/18/18