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 (N

RC) 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 finding s of very low safety significance (Green) in this report.

Four of these finding s involved violation

s of NRC requirements. Additionally, NRC inspectors documented two

violation s that were determined to be Severity Level

IV under the traditional enforcement

process. The NRC is treating these violation s as non-cited violation

s (NCV s) consistent with Section

2.3.2.a of the

NRC Enforcement

Policy. If you contest the violation

s or significance of

these NCV s , 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 Statio

n.

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

05000 458/2018012 w/ Attachment: Documents Reviewed

Enclosure U.S. NUCLEAR REGULATORY COMMISSION

Inspection Report

Docket Number:

05000458 License Number:

NPF-47 Report Number: 05000458/201801

2 Enterprise Identifier:

I-2018-012-0015 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. O'Banion, Resident Inspector (Acting)

B. Parks, Resident Inspector

Approved By:

J. Kozal , Chief, Branch C Division of Reactor Projects

2 SUMMARY The U.S. Nuclear Regulatory Commission (NRC) continued monitoring the licensee's performance by conducting a

baseline inspection

at River Bend Station

in accordance with the Reactor Oversight Process. The Reactor Oversight Process is the NRC's 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 NRC's assessment are summarized in the table

s below. List of Findings and Violations

Failure to

Identify and

Correct a Broken F eedwater Chemistry Probe Cornerstone

Significance

Cross-cuttin g Aspect Report Section Barrier Integrity Green NCV 05000458/2018012

-0 2 Closed None 71152 - Problem Identification

and Resolution

Two examples of a self

-revealed n on-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," were identified for the licensee's 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 Aspect Report Section Mitigating Systems Green NCV 05000458/2018012

-06 Closed None 71111.18 - Plant Modifications

The inspectors reviewed a self

-reveal ed, non-cited violation of Technical Specification 5.4.1.a for the licensee's 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.

3 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 Aspect Report Section

Mitigating Systems Green NCV 05000458/2018012

-05 Closed [H.9] - Human Performance, Training 71111.15 - Operability Determinations

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 Aspect Report Section Initiating Events Green NCV 05000458/2018012

-0 3 Closed [P.3] - Problem Identification

and Resolution, Resolution

71153 - Follow-up of Events and Notices of Enforcement 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 licensee's 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 Aspect Report Section None SL-IV NCV 05000458/2018012

-07 Closed None 71111.18 -Plant Modifications

The inspectors identified a Severity Level IV

non-cited violation

of 10 CFR 50.59

, "Changes, Tests, and Experiments," for the licensee's 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 condition

s required technical specification changes, and as such required prior

NRC approval.

4 Failure to Conduct Adequate Transient Snap Shot Assessment Following Recirculation Pump Trip Cornerstone

Significance

Cross-cuttin g Aspect Report Section Initiating Events Green FIN 05000458/2018012

-0 1 Closed None 71152 - Problem Identification

and Resolution

The inspectors identified a finding for the licensee's 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 Aspect Report Section None SL-IV NCV 05000458/2018012

-04 Closed None 71153 - Follow-up of 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 licensee's 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.

5 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

71111.15-Operability 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

71111.18-Plant Modifications

(2 Sample s) 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 71152-Problem Identification and Resolution

Annual Follow

-up of Selected Issue s (3 Samples) The inspectors reviewed the licensee's 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

6 71153-Follow-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 Aspect Report Section Barrier Integrity Green NCV 05000458/2018012

-02 Closed None 71152 - Problem 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 licensee's 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 licensee's 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.

7 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 licensee's 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 licensee's 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

8 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 Aspect Report Section Mitigating Systems Green NCV 05000458/2018012

-06 Closed None 71111.18 - Plant Modifications

The inspectors reviewed a self

-revealing, non

-cited violation of Technical Specification 5.4.1.a for the licensee's 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 MFRV

s 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

MFRV s 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 MFRV s and caused the catastrophic failure

of the variseals.

9 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 licensee's maintenance rule program.

Cross-cutting Aspect:

No cross-cutting aspect was assigned since the performance deficienc y 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

10 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 Aspect Report Section

Mitigating Systems Green NCV 05000458/2018012

-05 Closed [H.9] - Human Performance, Training 71111.15 -Operability Determinations

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 nozzle

s 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

11 Feedwater Temperature Reduction (FFWTR), Feedwater Heater Out-of-Service (FWH OOS) conditions, nor Single Loop Operation (SLO) operating conditions." Based on this analysis, the licensee's 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 licensee's 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 delt

a-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 issue

s 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.

T here were two

potential impact

s 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

.

12 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:

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 operation

s (LCO s) 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 licensee's 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."

13 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

14 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 Consideration

s 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

15 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 Aspect Report Section Initiating Events Green NCV 05000458/2018012

-03 Closed [P.3] - Problem Identification

and Resolution, Resolution

71153 - Follow-up of Events and Notices of Enforcement Discretion

The inspectors reviewed a self

-revealed , non-cited violation of

10 CFR Part 50, Appendi

x B, Criterion V, "Instructions, Procedures and Drawings

," for the licensee's 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

M ode 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 ente

r 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

16 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 display

ed 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.

17 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 Aspect Report Section None SL-IV NCV 05000458/2018012

-07 Closed None 71111.18 -Plant Modifications

The inspectors identified

a Severity Level IV NCV of 10 CFR 50.59

, "Changes, Tests, and Experiments," for the licensee's 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

18 failed to recognize that compensatory measures prohibiting operation in single loop condition s 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 nozzle

s 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 licensee's 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 licensee's 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 licensee's 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:

19 "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.

20 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

d id 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 Aspect Report Section Initiating Events

Green FIN 05000458/2018012

-0 1 Closed None 71152 - Problem Identification

and Resolution

The inspectors identified a Green finding for the licensee's 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 c an be observed in both ERIS and the plant process computer) when in a configuration with one recirculation pump in fast speed and one

21 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 plat

e 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.

22 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 defi ciency 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 licensee's 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.

23 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 Aspect Report Section None SLIV NCV 05000458/2018012

-04 Closed None 71153 - Follow-up of 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 licensee's 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 compute

r (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-

24 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 powe

r-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 o

ff-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

25 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-20 18-03953 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.

26 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 licensee's corrective action program as Condition Report

CR-RBS-201 8-0395 3, it is being treated as a non

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

EXIT MEETIN

GS 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 inspector s presented the inspection

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

Attachment

DOCUMENTS REVIEWED 71111.15-Operability 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, Level 3, High, Level 8, Channel Calibration and Logic System Functional Test (B21

-N680B, B21

-N683B, B21

-N080B) 305 STP-051-4227 ECCS/RCIC Actuation Ads Trip System "B" Reactor Vessel Water Level Low, Level 3/High, Level 8 Channel Calibration, and Logic System Functional Test (B21

-N095B, B21

-N695B, B21

-N693B) 20 STP-501-4202 FWS/MAIN Turbine Trip System

- Reactor Vessel Water Level - High Level 8, Channel Calibration and LSFT (C33-N004B, C33

-K624B, C33

-R606B, C33

-K650-3) 15 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 Range 0, 1, 2, & 3

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

- Reactor Vessel Water Level

- High Level 8, Loop Calibration (C33

-LTN006B, C33

-ESN606B) 0 71111.18-Plant 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 N4C Nozzles 7 and 8 Damaged

0 & 1

A-2 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 4221.110-000-043 Operability Assessment of the River Bend Station Feedwater Sparger Assembly in the January 2018 As

-Found Condition

0 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-2004-0 0 008 OE-NOE-2004-00084 Engineering Changes

Number Title Revision EC-75663 Loose Parts Evaluation for Material Lost From Feedwater Spargers Identified During PO

-18-01 Foreign Material FME LPA

-000 0 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 Methodology

0 NEDE-21821-A Boiling Water Reactor Feedwater Nozzle/Sparger Final Report

0 NEI 96-07 Guidelines for 10 CFR 50.59 Implementation

1 OE33308-20110507 Sampling Probe Found in Feedwater Sparger

August 17, 2011

A-3 Miscellaneous

Documents Number Title Revision/Date PO 18-01 BOP Foreign Material Inspection Report

RBS-ER-99-0539 Engineering Response Associated with Loose Part in the Feedwater System

0 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 71153-Follow-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

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 MO'Banion 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