ML15188A532
| ML15188A532 | |
| Person / Time | |
|---|---|
| Site: | River Bend  |
| Issue date: | 07/07/2015 |
| From: | Troy Pruett NRC/RGN-IV/DRP |
| To: | Olson E Entergy Operations |
| Greg Warnick | |
| References | |
| EA-15-043 EA-15-043, IR 2015009 | |
| Download: ML15188A532 (43) | |
See also: IR 05000458/2015009
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION IV
1600 E. LAMAR BLVD
ARLINGTON, TX 76011-4511
July 7, 2015
Mr. Eric W. Olson, Site Vice President
Entergy Operations, Inc.
River Bend Station
5485 U.S. Highway 61N
St. Francisville, LA 70775
SUBJECT: RIVER BEND STATION - NRC SPECIAL INSPECTION
REPORT 05000458/2015009; PRELIMINARY WHITE FINDING
Dear Mr. Olson:
On June 29, 2015, the U.S. Nuclear Regulatory Commission (NRC) completed a Special
Inspection at the River Bend Station to evaluate the facts and circumstances surrounding an
unplanned reactor trip. Based upon the risk and deterministic criteria specified in NRC
Management Directive 8.3, NRC Incident Investigation Program, the NRC initiated a Special
Inspection in accordance with Inspection Procedure 93812, Special Inspection. The basis for
initiating the special inspection and the focus areas for review are detailed in the Special
Inspection Charter (Attachment 2). The NRC determined the need to perform a Special
Inspection on January 15, 2015, and the onsite inspection started on January 26, 2015. The
enclosed report documents the inspection findings that were discussed on May 21 and
June 29, 2015, with you and members of your staff. The team documented the results of this
inspection in the enclosed inspection report.
The enclosed inspection report documents a finding that has preliminarily been determined to
be White, a finding with low to moderate safety significance that may require additional NRC
inspections, regulatory actions, and oversight. The team identified an apparent violation for
failure to maintain the simulator so it would accurately reproduce the operating characteristics of
the facility. Specifically, the River Bend Station simulator failed to accurately model feedwater
flow and reactor vessel level response following a scram, failed to provide the correct alarm
response for loss of a reactor protection system motor generator set, and failed to correctly
model the operation of the startup feedwater regulating valve. As a result of the simulator
deficiencies, operations personnel were presented with additional challenges to control the plant
and maintain plant parameters following a reactor scram on December 25, 2014. Because
actions have been taken to initiate discrepancy reports, to investigate and resolve the potential
fidelity issues and to provide training to operations personnel, the simulator deficiencies do not
represent a continuing safety concern. The NRC assessed this finding using the best available
information, and Manual Chapter 0609, Significance Determination Process. The basis for the
NRCs preliminary significance determination is described in the enclosed report. The finding is
also an apparent violation of NRC requirements and is being considered for escalated
enforcement action in accordance with the Enforcement Policy, which can be found on the
E. Olson
- 2 -
NRCs website at http://www.nrc.gov/about-nrc/regulatory/enforcement/enforce-pol.html.
The NRC will inform you in writing when the final significance has been determined.
Before we make a final decision on this matter, we are providing you with an opportunity to
(1) attend a Regulatory Conference where you can present your perspective on the facts and
assumptions used to arrive at the finding and assess its significance, or (2) submit your position
on the finding to the NRC in writing. If you request a Regulatory Conference, it should be held
within 30 days of your receipt of this letter. We encourage you to submit supporting
documentation at least one week prior to the conference in an effort to make the conference
more efficient and effective. The focus of the Regulatory Conference is to discuss the
significance of the finding and not necessarily the root cause(s) or corrective action(s)
associated with the finding. If you choose to attend a Regulatory Conference, it will be open for
public observation. The NRC will issue a public meeting notice and press release to announce
the conference. If you decide to submit only a written response, it should be sent to the NRC
within 30 days of your receipt of this letter. If you decline to request a Regulatory Conference or
to submit a written response, you relinquish your right to appeal the NRCs final significance
determination, in that by not choosing an option, you fail to meet the appeal requirements stated
in the Prerequisites and Limitations sections of Attachment 2, Process for Appealing NRC
Characterization of Inspection Findings (SDP Appeal Process), of NRC Inspection Manual
Chapter 0609.
Please contact Greg Warnick at (817) 200-1144, and in writing, within 10 days from the issue
date of this letter to notify us of your intentions. If we have not heard from you within 10 days,
we will continue with our final significance determination and enforcement decision. The final
resolution of this matter will be conveyed in separate correspondence.
Because the NRC has not made a final determination in this matter, no Notice of Violation is
being issued for this inspection finding at this time. In addition, please be advised that the
number and characterization of the apparent violation described in the enclosed inspection
report may change based on further NRC review.
In addition, the NRC inspectors documented four findings of very low safety significance
(Green) in this report. Three of these findings were determined to involve violations of NRC
requirements. The NRC is treating these violations as non-cited violations consistent with
Section 2.3.2.a of the Enforcement Policy.
If you contest the violations or significance of these non-cited violations, you should provide a
response within 30 days of the date of this inspection report, with the basis for your denial, to
the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk,
Washington, DC 20555-0001; with copies to the Regional Administrator, Region IV; the
Director, Office of Enforcement, U.S. Nuclear Regulatory Commission,
Washington, DC 20555-0001; and the NRC resident inspector at the River Bend Station.
If you disagree with a cross-cutting aspect assignment in this report, you should provide a
response within 30 days of the date of this inspection report, with the basis for your
disagreement, to the Regional Administrator, Region IV; and the NRC resident inspector at the
River Bend Station.
E. Olson
- 3 -
In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public
Inspections, Exemptions, Requests for Withholding, a copy of this letter, its enclosure, and your
response (if any) will be available electronically for public inspection in the NRC's Public
Document Room or from the Publicly Available Records (PARS) component of the NRC's
Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible
from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic
Reading Room).
Sincerely,
/RA/
Troy W. Pruett
Director
Division of Reactor Projects
Docket No. 50-458
License No. NPF-47
Enclosure:
Inspection Report 05000458/2015009
w/ Attachments:
1. Supplemental Information
2. Special Inspection Charter
SUNSI Review
By: RVA
Yes No
Non-Sensitive
Sensitive
Publicly Available
Non-Publicly Available
OFFICE
SRI:DRP/B
SRI:DRS/PSB2
RI:DRP/A
BC:DRS/OB
SES:ACES
TL:ACES
BC:DRP/C
NAME
THartman
JDrake
DBradley
VGaddy
RBrowder
MHay
GWarnick
SIGNATURE
/RA/
/RA/
/RA/
/RA/
/RA/
/RA/
/RA/
DATE
06/04/15
06/04/15
06/05/15
06/30/15
06/04/15
06/04/15
06/04/15
OFFICE
D:DRP
NAME
TPruett
SIGNATURE
/RA/
DATE
7/7/15
Letter to Eric Olson from Troy Pruett dated July 7, 2015.
SUBJECT: RIVER BEND STATION - NRC SPECIAL INSPECTION
REPORT 05000458/2015009; PRELIMINARY WHITE FINDING
DISTRIBUTION:
Regional Administrator (Marc.Dapas@nrc.gov)
Deputy Regional Administrator (Kriss.Kennedy@nrc.gov)
DRP Director (Troy.Pruett@nrc.gov)
DRP Deputy Director (Ryan.Lantz@nrc.gov)
DRS Director (Anton.Vegel@nrc.gov)
DRS Deputy Director (Jeff.Clark@nrc.gov)
Senior Resident Inspector (Jeffrey.Sowa@nrc.gov)
Resident Inspector (Andy.Barrett@nrc.gov)
RBS Administrative Assistant (Lisa.Day@nrc.gov)
Branch Chief, DRP/C (Greg.Warnick@nrc.gov)
Senior Project Engineer (Ray.Azua@nrc.gov)
Project Engineer (Michael.Stafford@nrc.gov)
Project Engineer (Paul.Nizov@nrc.gov)
Public Affairs Officer (Victor.Dricks@nrc.gov)
Public Affairs Officer (Lara.Uselding@nrc.gov)
RIV RSLO (Bill.Maier@nrc.gov)
Project Manager (Alan.Wang@nrc.gov)
Team Leader, DRS/TSS (Don.Allen@nrc.gov)
RITS Coordinator (Marisa.Herrera@nrc.gov)
ACES (R4Enforcement.Resource@nrc.gov)
Regional Counsel (Karla.Fuller@nrc.gov)
Technical Support Assistant (Loretta.Williams@nrc.gov)
Congressional Affairs Officer (Jenny.Weil@nrc.gov)
RIV Congressional Affairs Officer (Angel.Moreno@nrc.gov)
RIV/ETA: OEDO (Michael.Waters@nrc.gov)
Senior Staff Engineer, TSB (Kent.Howard@nrc.gov)
Enforcement Specialist, OE/EB (Robert.Carpenter@nrc.gov)
Senior Enforcement Specialist, OE/EB (John.Wray@nrc.gov)
Branch Chief, OE (Nick.Hilton@nrc.gov)
Enforcement Coordinator, NRR/DIRS/IPAB/IAET (Lauren.Casey@nrc.gov)
Branch Chief, Operations and Training Branch (Scott.Sloan@nrc.gov)
NRREnforcement.Resource@nrc.gov
RidsOEMailCenterResource
ROPreports
Electronic Distribution via Listserv for River Bend Station
Enclosure
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket:
05000458
License:
Report:
Licensee:
Entergy Operations, Inc.
Facility:
River Bend Station, Unit 1
Location:
5485 U.S. Highway 61N
St. Francisville, LA 70775
Dates:
January 26 through June 29, 2015
Inspectors:
T. Hartman, Senior Resident Inspector
D. Bradley, Resident Inspector
J. Drake, Senior Reactor Inspector
Approved By:
T. Pruett, Director
Division of Reactor Projects
-2-
SUMMARY OF FINDINGS
IR 05000458/2015009; 01/26/2015 - 06/29/2015; River Bend Station; Special inspection for the
scram with complications that occurred on December 25, 2014.
The report covered one week of onsite inspection and in-office review through June 29, 2015,
by inspectors from the NRCs Region IV office. One preliminary White apparent violation, three
Green non-cited violations, and one Green finding were identified. The significance of most
findings is indicated by their color (Green, White, Yellow, or Red) using Inspection Manual
Chapter 0609, Significance Determination Process. Findings for which the significance
determination process does not apply may be Green or be assigned a severity level after NRC
management review. The NRCs program for overseeing the safe operation of commercial
nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4,
dated December 2006.
Cornerstone: Initiating Events
Green. The team reviewed a self-revealing, non-cited violation of Technical
Specification 5.4.1.a for the licensees failure to establish adequate procedures to properly
preplan and perform maintenance that affected the performance of the B reactor protection
system motor generator set. Specifically, due to inadequate procedures for troubleshooting
on the B reactor protection system motor generator set, the licensee failed to identify a
degraded capacitor that caused the B reactor protection system motor generator set output
breaker to trip, which resulted in a reactor scram. The licensee entered this issue into their
corrective action program as Condition Report CR-RBS-2014-06605 and replaced the
degraded field flash card capacitor.
This performance deficiency is more than minor, and therefore a finding, because it is
associated with the procedure quality attribute of the Initiating Events Cornerstone and
adversely affected the cornerstone objective to limit the likelihood of events that upset plant
stability and challenge critical safety functions during shutdown as well as power operations.
Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination
Process (SDP) for Findings At-Power, Exhibit 1, Initiating Event Screening Questions, this
finding is determined to have a very low safety significance (Green) because the transient
initiator did not contribute to both the likelihood of a reactor trip and the likelihood that
mitigation equipment or functions would not have been available. This finding has an
evaluation cross-cutting aspect within the problem identification and resolution area because
the licensee failed to thoroughly evaluate this issue to ensure that the resolution addressed
the cause commensurate with its safety significance. Specifically, the licensee failed to
thoroughly evaluate the condition of the field flash card to ensure that the cause of the trip
had been correctly identified and corrected prior to returning the B reactor protection system
motor generator set to service [P.2]. (Section 2.7.a)
Cornerstone: Mitigating Systems
Green. The team reviewed a self-revealing, non-cited violation of Technical
Specification 5.4.1.a for the licensees failure to establish, implement and maintain a
procedure required by Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.
-3-
Specifically, Procedure OSP-0053, Emergency and Transient Response Support
Procedure, Revision 22, which is required by Regulatory Guide 1.33, inappropriately
directed operations personnel to establish feedwater flow to the reactor pressure vessel
using the startup feedwater regulating valve as part of the post-scram actions. The startup
feedwater regulating valve operator characteristics are non-linear and not designed to
operate in the dynamic conditions immediately following a reactor scram. To correct the
inadequate procedure, the licensee implemented a change to direct operations personnel to
utilize one of the main feedwater regulating valves until the plant is stabilized. This issue
was entered in the licensees corrective action program as Condition
Report CR-RBS-2015-00657.
This performance deficiency is more than minor, and therefore a finding, because it is
associated with the procedure quality attribute of the Mitigating Systems Cornerstone and
adversely affected the cornerstone objective to ensure the availability, reliability, and
capability of systems that respond to initiating events to prevent undesirable consequences.
Specifically, the procedure directed operations personnel to isolate the main feedwater
regulating valves and control reactor pressure vessel level using the startup feedwater
regulating valve, whose operator was not designed to function in the dynamic conditions
associated with a post-scram event from high power, and this challenged the capability of
the system. The team performed an initial screening of the finding in accordance with
Inspection Manual Chapter 0609, Appendix A, The Significance Determination
Process (SDP) for Findings At-Power. Using Inspection Manual Chapter 0609, Appendix A,
Exhibit 2, Mitigating Systems Screening Questions, the team determined that the finding is
of very low safety significance (Green) because it: (1) was not a deficiency affecting the
design or qualification of a mitigating structure, system, or component, and did not result in a
loss of operability or functionality; (2) did not represent a loss of system and/or function;
(3) did not represent an actual loss of function of at least a single train for longer than its
technical specification allowed outage time, or two separate safety systems out-of-service
for longer than their technical specification allowed outage time; and (4) did not represent an
actual loss of function of one or more non-technical specification trains of equipment
designated as high safety-significant in accordance with the licensees maintenance rule
program. This finding has an evaluation cross-cutting aspect within the problem
identification and resolution area because the licensee failed to thoroughly evaluate this
issue to ensure that the resolution addressed the cause commensurate with its safety
significance. Specifically, the licensee failed to properly evaluate the design characteristics
of the startup feedwater regulating valve operator before implementing the procedure to use
the valve for post-scram recovery actions [P.2]. (Section 2.7.b)
Green. The team identified a non-cited violation of 10 CFR Part 50, Appendix B,
Criterion XVI, Corrective Action, for the licensees failure to assure a condition adverse to
quality was promptly identified. Specifically, the licensee failed to identify, that reaching the
reactor pressure vessel water Level 8 (high) setpoint, on December 25, 2014, was an
adverse condition, and as a result, failed to enter it into the corrective action program. To
restore compliance, the licensee entered this issue into their corrective action program as
Condition Report CR-RBS-2015-00620 and commenced a causal analysis for Level 8 (high)
trips.
-4-
This performance deficiency is more than minor, and therefore a finding, because it is
associated with the equipment performance attribute of the Mitigating Systems Cornerstone
and adversely affected the cornerstone objective to ensure the availability, reliability, and
capability of systems that respond to initiating events to prevent undesirable consequences.
Specifically, failure to identify Level 8 (high) conditions and unplanned automatic actuations
as conditions adverse to quality, would continue to result in the undesired isolation of
mitigating equipment including reactor feedwater pumps, the high pressure core spray
pump, and the reactor core isolation cooling pump. The team performed an initial screening
of the finding in accordance with Inspection Manual Chapter 0609, Appendix A, The
Significance Determination Process (SDP) for Findings At-Power. Using Inspection Manual
Chapter 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, the team
determined that the finding is of very low safety significance (Green) because it: (1) was not
a deficiency affecting the design or qualification of a mitigating structure, system, or
component, and did not result in a loss of operability or functionality; (2) did not represent a
loss of system and/or function; (3) did not represent an actual loss of function of at least a
single train for longer than its technical specification allowed outage time, or two separate
safety systems out-of-service for longer than their technical specification allowed outage
time; and (4) did not represent an actual loss of function of one or more non-technical
specification trains of equipment designated as high safety-significant in accordance with
the licensees maintenance rule program. This finding has an avoid complacency
cross-cutting aspect within the human performance area because the licensee failed to
recognize and plan for the possibility of mistakes, latent issues, and inherent risk, even while
expecting successful outcomes. Specifically, the licensee tolerated leakage past the
feedwater regulating valves, did not plan for further degradation, and the condition ultimately
resulted in the Level 8 (high) trip of the running reactor feedwater pump on December 25,
2014 [H.12]. (Section 2.7.c)
TBD. The team identified an apparent violation of 10 CFR 55.46(c)(1), Plant-Referenced
Simulators, for the licensees failure to maintain the simulator so it would demonstrate
expected plant response to operator input and to normal, transient, and accident conditions
to which the simulator has been designed to respond. As of January 30, 2015, the licensee
failed to maintain the simulator consistent with actual plant response for normal and
transient conditions related to feedwater flows, alarm response, and behavior of the startup
feedwater regulating valve controller. Specifically, the River Bend Station simulator failed to
correctly model feedwater flows and resulting reactor vessel level response following a
scram, failed to provide the correct alarm response for a loss of a reactor protection system
motor generator set, and failed to correctly model the behavior of the startup feedwater
regulating valve controller. As a result, operations personnel were challenged in their
control of the plant during a reactor scram that occurred on December 25, 2014. This issue
has been entered into the corrective action program as Condition
Report RBS-CR-2015-01261, which includes actions to initiate simulator discrepancy
reports, investigate and resolve the potential fidelity issues, and provide training to
operations personnel on simulator differences.
This performance deficiency is more than minor, and therefore a finding, because it is
associated with the human performance attribute of the Mitigating Systems Cornerstone and
adversely affected the cornerstone objective of ensuring availability, reliability, and capability
-5-
of systems needed to respond to initiating events to prevent undesired consequences.
Specifically, the incorrect simulator response adversely affected the operations personnels
ability to assess plant conditions and take actions in accordance with approved procedures
during the December 25, 2014, scram. The team performed an initial screening of the
finding in accordance with inspection Manual Chapter 0609, Appendix A, The Significance
Determination Process (SDP) for Findings At-Power, Attachment 4, Initial Characterization
of Findings. Using Inspection Manual Chapter 0609, Attachment 4, Table 3, SDP
Appendix Router, the team answered yes to the following question: Does the finding
involve the operator licensing requalification program or simulator fidelity? As a result, the
team used Inspection Manual Chapter 0609, Appendix I, Licensed Operator Requalification
Significance Determination Process (SDP), and preliminarily determined the finding was of
low to moderate safety significance (White) because the deficient simulator performance
negatively impacted operations personnel performance in the actual plant during a
reportable event (reactor scram). This finding has an evaluation cross-cutting aspect within
the problem identification and resolution cross-cutting area because the licensee failed to
thoroughly evaluate this issue to ensure that the resolution addressed the extent of condition
commensurate with its safety significance. Specifically, the licensees evaluation of the
fidelity issue identified by the NRC in March 2014, focused on other training areas that used
simulation, rather than evaluating the simulator modelling for additional fidelity
discrepancies [P.2]. (Section 2.7.d)
Green. The team identified a finding for the licensees failure to follow written procedures for
classifying deficient plant conditions as operator workarounds and providing compensatory
measures or training in accordance with fleet Procedure EN-OP-117, Operations
Assessment Resources, Revision 8. A misclassification of these conditions resulted in the
failure of the operations department to fully assess the impact these conditions had during a
plant transient. The failure to identify operator workarounds contributed to complications
experienced during reactor scram recovery on December 25, 2014. The licensee entered
this issue into their corrective action program as Condition Report CR-RBS-2015-00795.
This performance deficiency is more than minor, and therefore a finding, because it had the
potential to lead to a more significant safety concern if left uncorrected. Specifically, the
performance deficiency contributed to complications experienced by the station when
attempting to restore feedwater following a scram on December 25, 2014. The team
performed an initial screening of the finding in accordance with Inspection Manual
Chapter 0609, Appendix A, The Significance Determination Process (SDP) for
Findings At-Power. Using Inspection Manual Chapter 0609, Appendix A, Exhibit 2,
Mitigating Systems Screening Questions, the team determined this finding is of very low
safety significance (Green) because it: (1) was not a deficiency affecting the design or
qualification of a mitigating structure, system, or component, and did not result in a loss of
operability or functionality; (2) did not represent a loss of system and/or function; (3) did not
represent an actual loss of function of at least a single train for longer than its technical
specification allowed outage time, or two separate safety systems out-of-service for longer
than their technical specification allowed outage time; and (4) did not represent an actual
loss of function of one or more non-technical specification trains of equipment designated as
high safety-significant in accordance with the licensees maintenance rule program. This
finding has a consistent process cross-cutting aspect in the area of human performance
-6-
because the licensee failed to use a consistent, systematic approach to making decisions
and failed to incorporate risk insights as appropriate. Specifically, no systematic approach
was enacted in order to properly classify deficient conditions [H.8]. (Section 2.7.e)
-7-
REPORT DETAILS
1.
Basis for Special Inspection
On December 25, 2014, at 8:37 a.m., River Bend Station scrammed from 85 percent
power following a trip of the B reactor protection system (RPS) motor generator (MG)
set. At the time of the MG set trip, a Division 1 half scram existed due to an unrelated
equipment issue with a relay for the Number 2 turbine control valve fast closure RPS
function. The combination of the B RPS MG set trip and the Division 1 half scram
resulted in a scram of the reactor.
The following equipment issues occurred during the initial scram response.
An unexpected Level 8 (high) reactor water level signal at +51 was received which
resulted in tripping the running reactor feedwater pumps (RFPs).
Following reset of the Level 8 (high) reactor water level signal, operations personnel
were unable to start RFP C. They responded by starting RFP A at a vessel level of
+25. The licensee subsequently determined that the circuit breaker (Magne Blast
type) for RFP C did not close.
Following the start of RFP A, the licensee attempted to open the startup feedwater
regulating valve (SFRV) but was unsuccessful prior to the Level 3 (low) reactor water
level trip setpoint at +9.7. The licensee then opened main feedwater regulating
valve (FRV) C to restore reactor vessel water level. The lowest level reached
was +8.1. Subsequent troubleshooting revealed a faulty manual function control
card. The card was replaced by the licensee and the SFRV was used on the
subsequent plant startup.
Following restoration of reactor vessel water level, the plant was stabilized in Mode 3. A
plant startup was conducted on December 27, 2014, with RPS bus B being supplied by
its alternate power source. During power ascension following startup, RFP B did not
start. The licensee re-racked its associated circuit breaker and successfully started
RFP B. The licensee did not investigate the cause of RFP B failing to start.
Management Directive 8.3, NRC Incident Investigation Program, was used to evaluate
the level of NRC response for this event. In evaluating the deterministic criteria of
Management Directive 8.3, it was determined that the event: (1) included multiple
failures in the feedwater system which is a short term decay heat removal mitigating
system; (2) involved two Magne Blast circuit breaker issues which could possibly have
generic implications regarding the licensees maintenance, testing, and operating
practices for these components including safety-related breakers in the high pressure
core spray system; and (3) involved several issues related to the ability of operations to
control reactor vessel level between the Level 3 (low) and Level 8 (high) trip setpoints
following a reactor scram. Since the deterministic criteria were met, the trip was
evaluated for risk. The preliminary Estimated Conditional Core Damage Probability was
determined to be 1.2E-6.
-8-
Based on the deterministic criteria and risk insights related to the multiple failures of the
feedwater system, the potential generic concern with the Magne Blast circuit breakers,
and the issues related to the licensees operations departments inability to control
reactor vessel level between the Level 3 (low) and Level 8 (high) setpoints following a
reactor scram, Region IV determined that the appropriate level of NRC response was to
conduct a Special Inspection.
This Special Inspection is chartered to identify the circumstances surrounding this event,
determine if there are adverse generic implications, and review the licensees actions to
address the causes of the event.
The team used NRC Inspection Procedure 93812, Special Inspection Procedure, to
conduct the inspection. The inspections included field walkdowns of equipment,
interviews with station personnel, and reviews of procedures, corrective action
documents, and design documentation. A list of documents reviewed is provided in
Attachment 1 of this report; the Special Inspection Charter is included as Attachment 2.
2.
Inspection Results
2.1
Charter Item 2: Develop a complete sequence of events related to the reactor scram
that occurred on December 25, 2014.
a.
Inspection Scope
The team developed and evaluated a timeline of the events leading up to, during, and
after the reactor scram. This includes troubleshooting activities and plant startup. The
team developed the timeline, in part, through a review of work orders, action requests,
station logs, and interviews with station personnel. The team created the following
timeline during their review of the events related to the reactor trip that occurred on
December 25, 2014.
Date/Time
Activity
December 6, 2014
10:12 a.m.
A Division 2 half-scram was received from loss of the
B RPS MG set, licensee initiated Condition
Report CR-RBS-2014-06233
10:17 a.m.
The RPS bus B was transferred to the alternate power
supply, Division 2 half-scram was reset
-9-
Date/Time
Activity
December 13, 2014
12:35 p.m.
December 16, 2014
9:30 p.m.
The RPS bus B was placed on B RPS MG set
December 23, 2014
7:59 a.m.
The licensee commenced a reactor downpower to
85 percent to support maintenance on RFP B
08:30 a.m.
The RFP B was secured to support maintenance
10:28 a.m.
A Division 1 half-scram signal from the turbine control
valve 2 fast closure relay was received, licensee initiated
Condition Report CR-RBS-2014-06581
2:21 p.m.
The Division 1 half-scram signal was reset by bypassing the
turbine control valve fast closure signal
10:00 p.m.
RPS channel A placed in trip condition to satisfy Technical
Specification 3.3.1.1
December 25, 2014
8:37 a.m.
Reactor scram due to loss of RPS bus B
8:39 a.m.
Feedwater master controller signal caused all FRVs to close,
feedwater continued injecting at 520,000 lbm/hr (leakby
through valves), reactor pressure vessel (RPV) water level at
27.8
8:40 a.m.
RFP A was secured per procedure, RPV water level ~ 43,
feedwater flow lowered to 426,400 lbm/hr (leakby through
valves)
-10-
Date/Time
Activity
8:41 a.m.
Reactor water level reached Level 8 (high) condition, RFP C
(only running RFP) trips
8:42 a.m.
All FRVs and associated isolation valves were closed by
operations personnel and the SFRV placed in AUTO with a
setpoint at 18 per procedure
8:45 a.m.
Reactor water level dropped below 51 allowing reset of
Level 8 (high) signal and restart of RFPs
8:50 a.m.
RFP C failed to start, no trip flags on RFP breaker, RPV
water level ~ 33 and lowering, licensee initiated Condition
Report CR-RBS-2014-06601
8:52 a.m.
Operations personnel started RFP A
8:54 a.m.
Operations personnel reset the reactor scram signal on
Division 2 of RPS only, RPV water level ~ 17 and lowering
8:54 a.m.
The SFRV did not respond as expected in the automatic
mode. Operations personnel attempted to control the SFRV
in Manual, however it did not respond. As a result,
operations personnel began placing the FRV C in service,
licensee initiated Condition Report CR-RBS-2014-06602
8:56 a.m.
Water level reached Level 3 (low) and actuated a second
reactor scram signal, RPV water level reached ~ 8.1,
operations personnel completed placing FRV C in service
and reactor water level began to rise
8:57 a.m.
RPV water level rose above 9.7, reactor scram signal clear
8:58 a.m.
Operations personnel reset the reactor scram signal on
Division 2 of RPS only, RPV water level ~ 15.7
December 27, 2014
12:53 a.m.
The plant entered Mode 2 and commenced a reactor startup
-11-
Date/Time
Activity
10:00 a.m.
RFP C failed to start due to the associated minimum flow
valve not fully opening, licensee initiated Condition
Report CR-RBS-2014-06653
10:18 a.m.
Operations personnel started RFP A
5:41 p.m.
The plant entered Mode 1
December 28, 2014
7:23 p.m.
RFP B failed to start, licensee initiated Condition
Report CR-RBS-2014-06649
8:43 p.m.
The RFP B breaker was racked out and then racked back in
8:49 p.m.
RFP B was successfully started
b.
Findings and Observations
In reviewing the sequence of events and developing the timeline, the team reviewed the
licensees maintenance and troubleshooting activities associated with the B RPS MG set
failure on December 6, 2014. Additionally, the team reviewed the operability
determination to evaluate the licensees basis for returning the B RPS MG set to service.
The licensees troubleshooting practices lacked the technical rigor and attention to detail
necessary to identify and correct the deficient B RPS MG set conditions. On several
occasions, the team noted that the licensee chose the expedient solution rather than
complete an evaluation to determine that corrective actions resolved the deficient
condition. Specifically, the licensee chose to restore the B RPS MG set to service
without fully understanding the failure mechanism. Other examples included the
licensees choice to have operations personnel rack in and out breakers, and have
maintenance personnel manually operate a limit switch, on the makeup and start logic
for the RFP C minimum flow valve, when the RFP did not start. As indicated above, the
licensee performed these compensatory actions instead of evaluating and correcting the
issue.
Based upon a review of the events leading up to the reactor scram, the team determined
the licensee failed to properly preplan and perform maintenance on the B RPS MG set
after the failure that occurred on December 6, 2014. Further discussion involving the
licensees failure to adequately troubleshoot, identify, and correct degraded components
on the B RPS MG set, prior to returning it to service, is included in Section 2.7.a. of this
report.
-12-
Additionally, the team reviewed the procedures that operations personnel used to
respond to the reactor scram and determined the licensee failed to provide adequate
procedures to respond to a post-trip transient. Further discussion on the procedure
prescribing activities affecting quality not being appropriate for the circumstances is
included in Section 2.7.b. of this report.
2.2
Charter Items 3 and 8: Review the licensees root cause analysis and corrective actions
from the current and previous scrams with complications.
a.
Inspection Scope
At the time of the inspection, the root cause report for the December 25, 2014, scram
had not been completed. To ensure the licensee was conducting the cause evaluation
at a level of detail commensurate with the significance of the problem, the team
reviewed corrective action procedures, met with members of the root cause team, and
reviewed prior related corrective actions.
The procedures reviewed by the team included quality related Procedure EN-LI-118,
Cause Evaluation Process, Revision 21, and quality related Procedure EN-LI-102,
Corrective Action Program, Revision 24.
The licensees approach for the December 25, 2014, scram causal evaluation was to
use several detailed evaluations as input to the overall root cause. Specifically, the
licensee performed an apparent cause evaluation, under Condition
Report CR-RBS-2014-06696, to understand the failure of Division 2 RPS equipment.
The licensee performed an apparent cause evaluation under Condition
Report CR-RBS-2014-06602, to review the conditions that resulted in the additional
reactor water Level 3 (low) trip, after the initial scram. The licensee also performed an
apparent cause evaluation, under Condition Report CR-RBS-2014-06581, to review the
turbine control valve fast closure circuit failure that resulted in the Division 1 half-scram
signal. All of these evaluations were reviewed under the parent root cause Condition
Report CR-RBS-2014-06605.
The licensee used multiple methods in their causal evaluations that included: event and
causal factor charting, barrier analysis, and organizational and programmatic failure
mode trees. The licensees charter for the root cause evaluation required several
periodic meetings with the members of the different causal analysis teams. It also
required a pre-corrective action review board update and review, a formal corrective
action review board approval, and an external challenge review of the approved root
cause report.
The NRC team also reviewed corrective actions to address complications encountered
during previous reactor scrams. Specifically, the following NRC inspection reports were
reviewed and the related licensee corrective actions were assessed:
05000458/2002002, Integrated Inspection Report, July 24, 2002, ML022050206
-13-
05000458/2006013, Special Inspection Team Report, March 1, 2007,
05000458/2012009, Augmented Inspection Team Report, August 7, 2012,
05000458/2012012, Supplemental Inspection Report, December 28, 2012,
b.
Findings and Observations
The NRC team found the licensees root cause team members had met the
organizational diversity and experience requirements of their procedures. The team
reviewed the qualifications of the members of the root cause team and determined they
were within the correct periodicity.
At the time of the inspection, there were 4 root cause and 10 apparent cause evaluations
in progress. The team determined the root cause analyses were conducted at a level of
detail commensurate with the significance of the problems.
In reviewing corrective actions for prior scrams, the team noted that there have been five
unplanned reactor scrams in the past five years, including the December 25, 2014,
event. Of those five scrams, two involved Level 8 (high) reactor water level signal trips
of all running feedwater pumps. Based upon a review of prior scrams and associated
corrective actions, the team determined that the licensee does not have an appropriately
low threshold for recognizing Level 8 (high) reactor water level signal trips as an adverse
condition, and entering that adverse condition into their corrective action program.
Otherwise, the team determined that the licensees corrective actions to address
complications, encountered during previous reactor scrams, were adequate. Further
discussion involving the licensees failure to identify Level 8 (high) reactor water level
signal trips as adverse conditions is included in Section 2.7.c of this report.
2.3
Charter Item 4: Determine the cause of the unexpected Level 8 (high) water level trip
signal.
a.
Inspection Scope
To determine the cause of the unexpected Level 8 (high) reactor water level trip on
December 25, 2014, the NRC team reviewed control room logs and graphs of key
reactor parameters to assess the plants response to transient conditions. This
information was then compared to the actions taken by operations personnel in the
control room per abnormal and emergency operating procedure requirements.
Section 5.1 of Procedure AOP-0001, Reactor Scram, Revision 30, required operations
personnel to verify that the feedwater system was operating to restore reactor water
level. This was accomplished using an attachment of Procedure OSP-0053,
Emergency and Transient Response Support Procedure, Revision 22. Specifically,
Attachment 16, Post Scram Feedwater/Condensate Manipulations Below 5% Reactor
-14-
Power, required transferring reactor water level control to the startup feedwater system
after reactor water level had been stabilized in the prescribed band.
Only four minutes elapsed from the time of the scram until the time the Level 8 (high)
reactor water level isolation signal was reached. Consequently, operations personnel
did not have sufficient time to gain control and stabilize reactor vessel level in the
required band.
To gain an understanding of issues affecting systems at the time of the scram, the NRC
team met with system engineers for the feedwater system, feedwater level control
system, and remotely operated valves. Discussions with engineering included system
health reports, open corrective actions from condition reports, licensee event reports,
design data for systems, startup testing and exceptions, post-trip reactor water level
setpoint setdown parameters, open engineering change packages, and requirements for
engineering to analyze post-transient plant data.
b.
Findings and Observations
Operations personnel responded to the events in accordance with procedure
requirements. The NRC did not identify any performance deficiencies related to
immediate or supplemental actions taken by control room staff during the transient.
However, operations personnel stated that the plant did not respond in a manner
consistent with their simulator training.
Based on review of operations personnel response to the event and the training received
from the simulator, the NRC team determined that the licensee did not maintain the
simulator in a condition that accurately represented actual plant response. On April 10,
2015, the licensee provided a white paper with additional information related to the
modeling of the plant-referenced simulator. Further discussion involving the licensees
failure to maintain the simulator is included in Section 2.7.d of this report.
The NRC team determined that the plant did not respond per the design as described in
the final safety analysis report. Specifically, the feedwater level control system and
feedwater systems were designed to automatically control reactor water level in the
programmed band post-scram. During the December 25, 2014 scram, reactor water
level quickly (within 4 minutes) rose to a Level 8 (high) trip. By design, reactor water
level should rapidly lower after the initial level transient from core void collapse, rise as
feedwater compensates for the level change, and then return to the programed
setpoint. A Level 8 (high) trip should not occur. The team determined that significant
leakage past the feedwater isolation valves caused the rapid rise in reactor water level.
Operations personnel were unable to compensate for the rapid change in reactor vessel
level. The licensee initially discovered the adverse condition during startup testing in
1986, and allowed the condition to degrade without effective corrective actions.
The team noted that significant post-trip or post-transient plant performance data was
available to system engineers, but review of this data was not prioritized by the licensee.
The review of plant transient data was primarily driven by the licensees root cause team
-15-
charter or by self-assigned good engineering practices. At the time of this inspection,
the licensee had not quantified the amount of leakage past the FRVs, although the
scram and subsequent startup had occurred one month earlier. The NRC team
observed that there was a potential to miss important trends in plant performance
without a more timely review.
2.4
Charter Item 5: Review the effectiveness of licensee actions to address known
equipment degradations that could complicate post-scram response by operations
personnel.
a.
Inspection Scope
The NRC team reviewed licensee procedures for classifying and addressing plant
conditions that may challenge operations personnel while performing required actions
per procedures during normal and off-normal conditions.
The team reviewed the licensees current list of operator workarounds and operator
burdens. Specifically, the team was looking for any known equipment issues that could
complicate post-scram response by operations personnel.
b.
Findings and Observations
The team determined the licensee did not properly classify several deficient plant
conditions as operator workarounds in accordance with fleet Procedure EN-OP-117,
Operations Assessment Resources, Revision 8. Further discussion related to the
failure to classify plant deficiencies as operator workarounds is included in Section 2.7.e
of this report.
2.5
Charter Items 6 and 7: Review the licensees maintenance, testing and operating
practices for Magne Blast circuit breakers including the causes and corrective actions
taken to address the failure of the RFPs to start.
a.
Inspection Scope
The team reviewed the final safety analysis report, system description, the current
system health report, selected drawings, maintenance and test procedures, and
condition reports associated with Magne Blast breakers. The team also performed
walkdowns and conducted interviews with system engineering and design engineering
personnel to ensure circuit breakers were capable of performing their design basis
safety functions. Specifically, the team reviewed:
Vendor and plant single line, schematic, wiring, and layout drawings
Circuit breaker preventive maintenance inspection and testing procedures
Vendor installation and maintenance manuals
Preventive maintenance and surveillance test procedures
Completed surveillance test and preventive maintenance results
Corrective actions and modifications
-16-
b.
Findings and Observations
Unresolved Item (URI) - Vendor and Industry Recommended Testing Adequacy on
Safety-related and Safety-significant Circuit Breakers
Introduction. The team identified an unresolved item related to the licensees breaker
maintenance and troubleshooting programs for safety-related and safety-significant
circuit breakers. The charter tasked the team with inspecting the issues associated with
Magne Blast breaker problems that occurred during and after the December 25, 2014,
scram. The NRC team determined that breaker maintenance and troubleshooting
practices extended beyond the Magne Blast breakers. The team identified that there
were potential issues with safety-related Master Pact breakers and determined that
maintenance procedures used to ensure that 4160 V and 13.8 kV safety-related and
safety-significant breakers were being maintained and overhauled in a timely manner
may not conform to industry recommended standards.
Description. The team identified that the licensees maintenance programs for Division I,
II, III, and non-safety 4160 V and 13.8 kV breakers installed in the plant may not meet
the standards recommended by the vendor, corporate, or Electric Power Research
Institute (EPRI) guidelines. The licensees programs were based on EPRI
documents TR-106857-V2 and TR-106857-V3, which were preventive maintenance
program bases for low and medium voltage switchgear. However, the licensee
appeared to only implement portions of the recommended maintenance program, and
were not able to provide the team with engineering analyses or technical bases to justify
the changes. The EPRI guidance was developed specifically for Magne Blast breakers
based on industry operating experience, NRC Information Notices, and General Electric
SILs/SALs. The NRC team was concerned that the licensee may not have performed
the entire vendor or EPRI recommended tests, inspections, and refurbishments on the
breakers since they were installed. The aggregate impact of missing these preventive
maintenance tasks needs to be evaluated to determine if the reliability of the affected
breakers has been degraded.
Pending further evaluation of the above issue by the licensee and subsequent review by
NRC inspectors, this issue will be tracked as URI 05000458/2015009-01, Vendor and
Industry Recommended Testing Adequacy on Safety-related and Safety-significant
Circuit Breakers.
2.6
Charter Item 9: Evaluate pertinent industry operating experience and potential
precursors to the event, including the effectiveness of any action taken in response to
the operating experience.
a.
Inspection Scope
The team evaluated the licensees application of industry operating experience related to
this event. The team reviewed applicable operating experience and generic NRC
communications with a specific emphasis on Magne Blast breaker maintenance
practices, to assess whether the licensee had appropriately evaluated the notifications
-17-
for relevance to the facility and incorporated applicable lessons learned into station
programs and procedures.
b.
Findings and Observations
Other than the URI described in Section 2.5, of this report, no additional findings or
observations were identified.
2.7
Specific findings identified during this inspection.
a.
Failure to Establish Adequate Procedures to Perform Maintenance on Equipment that
can Affect Safety-Related Equipment
Introduction. The team reviewed a Green, self-revealing, non-cited violation of Technical
Specification 5.4.1 for the licensees failure to establish adequate procedures to properly
preplan and perform maintenance that affected the performance of the B RPS MG set.
Specifically, due to inadequate procedures for troubleshooting on the B RPS MG set, the
licensee failed to identify a degraded capacitor that caused the B RPS MG set output
breaker to trip, which resulted in a reactor scram.
Description. On December 6, 2014, during normal plant operations, RPS bus B
unexpectedly lost power because of a B RPS MG set failure, which resulted in a
Division 2 half scram and a containment isolation signal. The RPS system is designed
to cause rapid insertion of control rods (scram) to shut down the reactor when specific
variables exceed predetermined limits. The RPS power system, of which the B RPS MG
set is a component, is designed to provide power to the logic system that is part of the
The licensees troubleshooting teams identified both the super spike suppressor card
and the field flash card as the possible causes of the B RPS MG set failure. The
licensee replaced the super spike suppressor card. While inspecting the field flash card,
a strand of wire from one of the attached leads was found nearly touching a trace on the
circuit board. A continuity test was performed while the field flash card was being
tapped and no ground was observed. A ground was observed when forcibly pushing
down on the wire. The licensee believed that the wire strand most likely caused the
B RPS MG set trip. The licensee removed the wire strand and re-installed the field flash
card without any further troubleshooting. Operations personnel returned the B RPS MG
set to service on December 16, 2014.
On December 25, 2014, while operating at 85 percent power, a reactor scram occurred
due to a Division 2 RPS trip concurrent with a Division 1 RPS half-scram signal that was
present at the time. The Division 1 half-scram signal was received on December 23,
2014, because of a turbine control valve fast closure signal. Troubleshooting for the
cause of the Division 1 half-scram was ongoing when the Division 2 RPS trip occurred.
This resulted in a full RPS actuation and an automatic reactor scram. Electrical
protection assembly breakers 3B/3D and the B RPS MG set output breaker were found
tripped, similar to the conditions noted following the loss of the B RPS MG set on
December 6, 2014. The subsequent failure modes analysis and troubleshooting teams
-18-
identified the probable cause of the failure of the B RPS MG set output breaker was an
intermittent failure of the field flash card. A more detailed inspection of the field flash
card revealed that a 10 microfarad capacitor had been subjected to minor heating over a
long period of time. As a result, the degraded component contributed to a reactor
scram. The capacitor on the field flash card in the Division 2 RPS MG set was replaced.
Analysis. Failure to establish and implement procedures to perform maintenance to
correct adverse conditions on B RPS MG set equipment that can affect the performance
of the safety-related reactor protection system was a performance deficiency. This
performance deficiency is more than minor, and therefore a finding, because it is
associated with the procedure quality attribute of the Initiating Events Cornerstone and
adversely affected the cornerstone objective to limit the likelihood of events that upset
plant stability and challenge critical safety functions during shutdown as well as power
operations.
The team performed an initial screening of the finding in accordance with Inspection
Manual Chapter (IMC) 0609, Appendix A, The Significance Determination
Process (SDP) for Findings At-Power. Using IMC 0609, Appendix A, Exhibit 1,
Initiating Event Screening Questions, this finding is determined to have very low safety
significance because the transient initiator did not contribute to both the likelihood of a
reactor trip and the likelihood that mitigation equipment or functions would not have been
available. This finding has an evaluation cross-cutting aspect within the problem
identification and resolution area because the licensee failed to thoroughly evaluate the
failure of the B RPS MG set to ensure that the resolution addressed the cause
commensurate with its safety significance. Specifically, the licensee failed to thoroughly
evaluate the condition of the field flash card to ensure that the cause of the trip had been
correctly identified and corrected prior to returning the B MG set to service [P.2].
Enforcement. Technical Specification 5.4.1.a states, in part, that written procedures
shall be established, implemented, and maintained covering the applicable procedures
recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.
Regulatory Guide 1.33, Appendix A, Section 9.a., states, in part, that, maintenance that
can affect the performance of safety-related equipment should be properly preplanned
and performed in accordance with written procedures, documented instructions, or
drawings appropriate to the circumstances. Contrary to the above, on December 6,
2014, the licensee failed to establish adequate procedures to properly preplan and
perform maintenance on the B RPS MG set that ultimately affected the performance of
safety-related B RPS equipment. Specifically, due to inadequate procedures for
troubleshooting on the B RPS MG set, the licensee failed to identify a degraded
capacitor on the B RPS MG set that caused its output breaker to trip, prior to returning it
to service. On December 25, 2014, this degraded capacitor caused the B RPS MG set
breaker to trip causing a loss of power to the B RPS bus which resulted in a reactor
scram. The licensee entered this issue into their corrective action program as Condition
Report CR-RBS-2014-06605 and replaced the degraded field flash card capacitor.
Because this finding is determined to be of very low safety significance and has been
entered into the licensees corrective action program this violation is being treated as a
non-cited violation consistent with Section 2.3.2.a of the NRC Enforcement Policy:
-19-
NCV 05000458/2015009-02, Failure to Establish Adequate Procedures to Perform
Maintenance on Equipment that can Affect Safety-Related Equipment.
b.
Failure to Provide Adequate Procedures for Post-Scram Recovery
Introduction. The team reviewed a Green, self-revealing, non-cited violation of Technical
Specification 5.4.1.a for the licensees failure to establish, implement and maintain a
procedure required by Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.
Specifically, Procedure OSP-0053, Emergency and Transient Response Support
Procedure, Revision 22, inappropriately directed operations personnel to establish
feedwater flow to the reactor pressure vessel using the SFRV as part of the post-scram
actions. The SFRV operator characteristics are non-linear and not designed to operate
in the dynamic conditions immediately following a reactor scram from power.
Description. On November 18, 2013, the licensee modified Procedure OSP-0053,
Attachment 16, due to excessive leakage across the main FRVs and verified the
adequacy of the change using the simulator. The licensee did not realize that the
simulator incorrectly modeled the operating characteristics of the SFRV.
On December 25, 2014, following a reactor scram, operations personnel attempted to
implement Procedure OSP-0053, Attachment 16, Post Scram Feedwater/Condensate
Manipulations Below 5% Reactor Power. When the SFRV did not begin to open as
RPV level approached the level setpoint, operations personnel thought the SFRV had
failed in automatic and placed the valve controller in manual. Unknown to operations
personnel, the manual control of the valve was inoperable due to a faulty card. Unable
to control the SFRV, operations personnel then began placing one of the main FRVs
back in service. The isolation valves for the FRV are motor-operated and take
approximately 90 seconds to reposition. Because of the delay in restoring feedwater to
the RPV, a second Level 3 (low) water level reactor scram signal occurred.
The NRC team determined that plant data indicated the SFRV does not open on a
slowly decreasing RPV water level until the controller signal reaches approximately
12.5 percent error or about 3 inches below the RPV water level setpoint on the
controller. The SFRV in the simulator opens as soon as the controller open signal is
greater than 0.0 percent error. When the licensee became aware of the SFRV design
operating parameters, they determined that the SFRV was not designed to respond to
the dynamic conditions that exist during post-scram recovery, and revised
Procedure OSP-0053, Attachment 16, to continue using the main FRVs during
post-scram recovery actions.
Analysis. The licensees failure to provide adequate guidance in Procedure OSP-0053
for post-scram recovery actions was a performance deficiency. This performance
deficiency is more than minor, and therefore a finding, because it is associated with the
procedure quality attribute of the Mitigating Systems Cornerstone and adversely affected
the cornerstone objective to ensure the availability, reliability, and capability of systems
that respond to initiating events to prevent undesirable consequences. Specifically, the
procedural guidance that directed operations personnel to establish feedwater flow to
-20-
the RPV using the SFRV as part of the post-scram actions adversely affected the
capability of the feedwater systems that respond to prevent undesirable consequences.
The system capability was adversely affected since the valve operator characteristics
are non-linear and not designed to operate in the dynamic conditions immediately
following a reactor scram from high power levels.
The team performed an initial screening of the finding in accordance with IMC 0609,
Appendix A, The Significance Determination Process (SDP) for Findings At-Power.
Using IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, the
finding was of very low safety significance (Green) because it: (1) was not a deficiency
affecting the design or qualification of a mitigating structure, system, or component, and
did not result in a loss of operability or functionality; (2) did not represent a loss of
system and/or function; (3) did not represent an actual loss of function of at least a single
train for longer than its technical specification allowed outage time, or two separate
safety systems out-of-service for longer than their technical specification allowed outage
time; and (4) did not represent an actual loss of function of one or more non-technical
specification trains of equipment designated as high safety-significant in accordance with
the licensees maintenance rule program.
This finding has an evaluation cross-cutting aspect within the problem identification and
resolution area because the licensee failed to thoroughly evaluate this issue to ensure
that the resolution addressed the cause commensurate with its safety significance.
Specifically, the licensee failed to properly evaluate the design characteristics of the
SFRV operator before implementing procedural guidance for post-scram recovery
actions [P.2].
Enforcement. Technical Specification 5.4.1.a states, in part, that written procedures
shall be established, implemented, and maintained covering the applicable procedures
recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.
Regulatory Guide 1.33, Appendix A, Section 6.u., identifies procedures for responding to
a Reactor Trip as required procedures. Procedure OSP-0053, Attachment 16, Post
Scram Feedwater/Condensate Manipulations Below 5% Reactor Power, was a
procedure established by the licensee for responding to a reactor trip. Contrary to the
above, from March 3, 2010, until January 30, 2015, the licensee failed to establish,
implement and maintain Procedure OSP-0053, which directs operator actions for a
reactor trip. Specifically, Procedure OSP-0053 inappropriately directed operations
personnel to establish feedwater flow to the reactor pressure vessel using the SFRV as
part of the post-scram actions. The SFRV operator characteristics are non-linear and
not designed to operate in the dynamic conditions immediately following a reactor scram
from high power. Subsequent to the event, the licensee changed the procedure,
directing operations personnel to utilize one of the main FRVs until the plant was
stabilized. Because this finding is determined to be of very low safety significance and
has been entered into the licensees corrective action program as Condition
Report CR-RBS-2015-00657, this violation is being treated as a non-cited violation
consistent with Section 2.3.2.a of the NRC Enforcement Policy:
NCV 05000458/2015009-03, Failure to Provide Adequate Procedures for Post-scram
Recovery.
-21-
c.
Failure to Identify High Reactor Water Level as a Condition Adverse to Quality
Introduction. The team identified a Green, non-cited violation of 10 CFR Part 50,
Appendix B, Criterion XVI, Corrective Action, for the licensees failure to assure a
condition adverse to quality was promptly identified. Specifically, the licensee failed to
identify that reaching the reactor pressure vessel water Level 8 (high) setpoint, on
December 25, 2014, was an adverse condition and enter it into the corrective action
program.
Description. On December 25, 2014, the licensee experienced a scram with
complications. The team reviewed the post-scram report as documented in
Procedure GOP-0003, Scram Recovery, Revision 24. During the scram, the licensee
experienced a Level 8 (high) reactor water condition approximately four minutes after the
scram. This high water level condition should not occur for a scram when main steam
isolation valves remain open and safety relief valves do not actuate.
The team noted that operations personnel followed their training and performed the
required post-scram actions. Those actions did not prevent the overfeeding of the
reactor vessel (which reached the Level 8 (high) setpoint), causing the RFPs to trip off
and would have caused isolation of other emergency core cooling systems, if actuated,
such as high pressure core spray and reactor core isolation cooling. The loss of all
feedwater contributed to the RPV water level lowering to a Level 3 (low) condition that
actuated a second reactor scram signal.
The team interviewed control room operations personnel, system engineers, and
corrective action staff regarding the plants response to the scram. Further, the team
reviewed plant parameter graphs, control room logs, alarm logs, design history, and
licensing basis documents, and determined that excessive leakage past the FRVs
caused the Level 8 (high) trip of all RFPs.
In reviewing the feedwater system data from the December 24, 2014, scram, the
licensee estimated 500,000 lbm/hr leaked past the closed FRVs. This represents
approximately 3 percent of the full-power feedwater flow and significantly exceeds the
design specification for leakage of 135,000-150,000 lbm/hr.
The licensee identified excessive leakage past the FRVs during testing in 1986. At the
time of inspection, the licensee could not produce any corrective actions taken to identify
or correct leakage past the FRVs. Further, the licensee had not quantified the amount of
leakage past the FRVs prior to the December 24, 2014, event and NRC Special
Inspection.
Procedure GOP-0003 provided a post-scram checklist to operations personnel to help
identify equipment and procedure problems that should be corrected prior to the reactor
startup. This document was then reviewed by the Offsite Safety Review Committee in
order to understand and confirm that the plant was safe to restart. Step 1.1 stated the
following:
-22-
Following a reactor scram from high power levels, there is an initial RPV level
Shrink of 20 to 40 inches followed by a Swell of approximately 10 to 20 inches.
The Feedwater Level Control System is programmed to ride out this shrink and
swell without overfilling the RPV.
In section 6.7 of Procedure GOP-003, the licensee documented that there was a control
system trip of RFPs due to reaching Level 8 (high). In section 6.12, however, the
licensee failed to document any off-normal trips (Level 8 (high) feed pump trips). In
Attachment 3 of GOP-003 Procedure, Analysis and Evaluations, Level 8 (high) was
mentioned as part of a timeline discussion but was not listed in the final section labeled
Corrective Actions Required Prior to Returning Unit to Service. This final section was
where condition reports were required for all items listed. By omitting Level 8 (high) from
the discussion, no corrective action document was generated for that condition.
The licensee did not identify that reaching reactor water Level 8 (high) was an adverse
condition. Therefore, the unexpected Level 8 (high) trip was not addressed prior to
startup on December 28, 2014.
The team reviewed the history of Level 8 (high) RFP trips and noted that similar issues
of concern were raised by the NRC in 2012. Specifically, a Supplemental Inspection,
performed in 2012, for a White performance indicator associated with reactor scrams
with complications documented the failure to recognize a Level 8 (high) trip as an
adverse condition and enter it into the corrective action program. This non-cited
violation was documented in NRC Inspection Report 05000458/2012012.
The team determined that the licensee did not have a sufficiently low threshold for
entering issues into their corrective action program for reactor water level transients.
Specifically, long-standing equipment issues associated with FRV leakage has led to the
licensee reaching reactor water Level 8 (high) during two reactor scrams in a three-year
period.
Analysis. The failure to identify Level 8 (high) reactor water level trips as adverse
conditions was a performance deficiency. This performance deficiency is more than
minor, and therefore a finding, because it is associated with the equipment performance
attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone
objective to ensure the availability, reliability, and capability of systems that respond to
initiating events to prevent undesirable consequences. Specifically, failure to identify
Level 8 (high) conditions and resulting actuations as conditions adverse to quality, would
continue to result in the undesired isolation of mitigating equipment including RFPs, the
high pressure core spray pump, and the reactor core isolation cooling pump.
The team performed an initial screening of the finding in accordance with IMC 0609,
Appendix A, The Significance Determination Process (SDP) for Findings At-Power.
Using IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, the
finding was of very low safety significance (Green) because it: (1) was not a deficiency
affecting the design or qualification of a mitigating structure, system, or component, and
did not result in a loss of operability or functionality; (2) did not represent a loss of
-23-
system and/or function; (3) did not represent an actual loss of function of at least a single
train for longer than its technical specification allowed outage time, or two separate
safety systems out-of-service for longer than their technical specification allowed outage
time; and (4) did not represent an actual loss of function of one or more non-technical
specification trains of equipment designated as high safety-significant in accordance with
the licensees maintenance rule program.
This finding has an avoid complacency cross-cutting aspect within the human
performance area because the licensee failed to recognize and plan for the possibility of
mistakes, latent issues, and inherent risk, even while expecting successful outcomes.
Specifically, the licensee tolerated excessive leakage past the FRVs, did not plan for
further degradation, and the condition ultimately resulted in the Level 8 (high) trip of the
running RFP on December 25, 2014 [H.12].
Enforcement. Title 10 of the Code of Federal Regulations, Part 50, Appendix B,
Criterion XVI, Corrective Action, requires, in part, that measures shall be established to
assure that conditions adverse to quality, such as failures, malfunctions, deficiencies,
deviations, defective material and equipment, and non-conformances are promptly
identified and corrected. Contrary to the above, from December 25, 2014, to
January 29, 2015, the licensee failed to assure that a condition adverse to quality was
promptly identified. Specifically, the licensee failed to identify that reaching the reactor
pressure vessel water Level 8 (high) setpoint, on December 25, 2014, was an adverse
condition and enter it into the corrective action program. To restore compliance, the
licensee entered this issue into their corrective action program as Condition
Report CR-RBS-2015-00620 to perform a causal analysis for Level 8 (high) trips. Since
the violation was of very low safety significance (Green), this violation is being treated as
a non-cited violation, consistent with Section 2.3.2.a of the Enforcement Policy:
NCV 05000458/2015009-04, Failure to Identify High Reactor Water Level as a
d.
Failure of the Plant-Referenced Simulator to Demonstrate Expected Plant Response
Introduction. The team identified an apparent violation of 10 CFR 55.46(c)(1), Plant-
Referenced Simulators, for the licensees failure to maintain the simulator so it would
demonstrate expected plant response to operator input and to normal, transient, and
accident conditions to which the simulator has been designed to respond. As of
January 30, 2015, the licensee failed to maintain the simulator consistent with actual
plant response for normal and transient conditions related to feedwater flows, alarm
response, and behavior of the SFRV controller. As a result, operations personnel were
challenged in their control of the plant during a reactor scram that occurred on
December 25, 2014.
Description. On December 25, 2014, River Bend Station was operating at 85 percent
power when a reactor scram occurred. On January 26, 2015, a Special Inspection was
initiated in response to this event. The Special Inspection team reviewed the event and
identified several simulator fidelity issues. Licensee Procedure EN-TQ-202, Simulator
Configuration Control, Revision 9, provided the process requirements necessary to
-24-
satisfy the guidelines for simulator testing, performance, and configuration control
specified by ANSI/ANS-3.5-2009. Standard ANSI/ANS-3.5-2009, Nuclear Power Plant
Simulators for Use in Operator Training and Examination, provides the simulator testing
requirements, as well as simulator configuration management to ensure simulator
fidelity. Specifically, as of January 30, 2015, the River Bend Station simulator failed to
model feedwater accurately and failed to model resulting reactor vessel level response
following a scram, failed to provide the correct alarm response for a loss of a RPS MG
set, and failed to correctly model the behavior of the SFRV controller. The simulator
modeling discrepancies and how these discrepancies affected plant response during the
plant trip are discussed below:
The licensee stated their simulator modeled zero leakage across the FRV rather
than the actual leakage in the plant. General Electric record 0247.230-000-016,
Feedwater Control Valve Assembly - Purchase Specification, described the
total design leakage across all the FRVs was approximately 135,000 lbm/hr.
This is equal to approximately 1.1 percent full feedwater flow. The flow rate
across the FRVs measured in the plant on December 25, 2014, was
approximately 500,000 lbm/hr, which is approximately 3 percent full feedwater
flow. The rate of level change of the reactor vessel in the plant was larger than
operations personnel anticipated based on training received in the simulator.
ANSI/ANS-3.5-2009, Section 4.1.4(3), states, The simulator shall not fail to
cause an alarm or automatic action if the reference unit would have caused an
alarm or automatic action under identical circumstances. In this case, the
simulator under similar conditions did not reach the RPV water Level 8 (high)
condition and trip the RFPs, when the actual plant did.
The licensees simulator did not correctly model all alarms that would be received
on a loss of power to the RPS. ANSI/ANS-3.5-2009, Section 4.1.4(3),
states, The simulator shall not fail to cause an alarm or automatic action if the
reference unit would have caused an alarm or automatic action under identical
circumstances. Although the licensee had identified this discrepancy on
December 11, 2014, and implemented a correction in the simulator model,
operations personnel had not received training nor were they notified of the
discrepancy. As a result, during the plant scram on December 25, 2014, the
alarms for drywell high pressure and RPV high pressure annunciated per the
facility design, operations personnel were not expecting the alarms because they
did not alarm in the simulator during training.
The simulator SFRV responded differently than the actual SFRV in the reference
plant. ANSI/ANS-3.5-2009, Section 4.1.4(2) [for malfunctions], stated, Any
observable change in simulated parameters corresponds in direction to the
change expected from actual or best estimate response of the reference unit to
the malfunction. Plant data indicated the SFRV does not open on a slowly
decreasing RPV water level until the controller signal reaches approximately
12.5 percent or about 3 inches below the RPV water level setpoint of the
controller. The SFRV in the simulator opens as soon as the controller open
signal is greater than 0.0. Because the SFRV did not respond as expected,
-25-
operations personnel incorrectly believed the SFRV had failed in automatic
operation and placed the controller in manual. Due to an unrelated issue, the
manual function of the SFRV was unavailable.
Collectively, these modeling discrepancies negatively impacted licensed operations
personnel performance in the actual control room, during the event of December 25,
2014. Specifically, operations personnel were not able to control reactor vessel water
level during the reactor scram.
The team noted that the licensee similarly stated in Condition Report
CR-RBS-2015-00641 that, During an investigation into the report at the OSRC (Onsite
Safety Review Committee) for the SCRAM on December 25, 2014, that feed regulating
valve leakage (FRV) contributed to the Level 8 received reactor vessel, it was
determined by analysis that there is sufficient evidence that leakage by the Feedwater
Regulating Valves presents a significant challenge to Operations during a scram event.
On April 10, 2015, the licensee provided a white paper with additional information related
to the modeling of the plant-referenced simulator. Specifically, it provided the licensees
perspective with regard to the following issues raised by the NRC:
1. Two unexpected alarms on loss of Division II Reactor Protection System Power
2. Main Feedwater Regulating Valve Seat Leakage
3. Start-up Feedwater Regulating Valve Response
The licensee concluded that although they perceived that there were differences
between the simulator and the actual plant, they were considered to be minor. For each
of the items in question, the paper summarized that operator performance was not
impacted by simulator modeling. The team considered the information in the white
paper, and disagreed with the licensees conclusions. Some of the information provided,
however, did improve the teams understanding of the modeling deficiencies.
Analysis. The failure to maintain the plant-referenced simulator so that it would
demonstrate expected plant response to operator input and to normal and transient
conditions was a performance deficiency. This performance deficiency is more than
minor, and therefore a finding, because it is associated with the human performance
attribute of the Mitigating Systems Cornerstone and adversely affected the objective of
ensuring availability, reliability, and capability of systems needed to respond to initiating
events to prevent undesired consequences. Specifically, the incorrect simulator
response adversely affected the operating crews ability to assess plant conditions and
take actions in accordance with approved procedures during the December 25, 2014,
The team performed an initial screening of the finding in accordance with IMC 0609,
Appendix A, The Significance Determination Process (SDP) for Findings At-Power,
Attachment 4, Initial Characterization of Findings. Using IMC 0609, Attachment 4,
Table 3, SDP Appendix Router, the team answered yes to the following question:
Does the finding involve the operator licensing requalification program or simulator
-26-
fidelity? As a result, the team used IMC 0609, Appendix I, Licensed Operator
Requalification Significance Determination Process (SDP), and preliminarily determined
the finding was of low to moderate safety significance (White) because the deficient
simulator performance negatively impacted operations personnel performance in the
actual plant during a reportable event. This modeling deficiency resulted in actual
impact on operations personnel performance during response to a reactor scram that
occurred on December 25, 2014.
The NRC recently issued a non-cited violation related to simulator fidelity in March 2014
documented in Inspection Report 05000458/2014301. Since the licensee recently
verified simulator fidelity, this issue is indicative of current plant performance and has an
evaluation cross-cutting aspect within the problem identification and resolution area
because the licensee failed to thoroughly evaluate this issue to ensure that the
resolution addressed the extent of condition commensurate with its safety significance.
Specifically, the licensees evaluation of the fidelity issue focused on other training areas
that used simulation, rather than evaluating the simulator modelling for additional fidelity
discrepancies [P.2].
Enforcement. Title 10 of the Code of Federal Regulations, Part 55.46(c)(1), Plant-
Referenced Simulators, requires in part, that a simulator must demonstrate expected
plant response to operator input and to normal, transient, and accident conditions to
which the simulator has been designed to respond.
Contrary to the above, as of January 30, 2015, the simulator failed to demonstrate
expected plant response to operator input and to normal, transient, and accident
conditions to which the simulator has been designed to respond. Specifically, the River
Bend Station simulator failed to correctly model leakage flow rates across the FRVs;
failed to provide the correct alarm response for a loss of a RPS MG set; and failed to
correctly model the behavior of the SFRV controller. These simulator modeling issues
led to negative training of operators. This subsequently complicated the operators
response to a reactor scram in the actual plant on December 25, 2014. This issue has
been entered into the corrective action program as Condition Report
CR-RBS-2015-01261. The licensees condition report included actions to initiate
simulator discrepancy reports, to investigate and resolve the potential fidelity issues, and
to provide training to operations personnel on simulator differences. This is a violation of
10 CFR 55.46(c)(1), Plant-Referenced Simulators: AV 05000458/2015009-05, Failure
of the Plant-Referenced Simulator to Demonstrate Expected Plant Response.
e.
Failure to Identify and Classify Operator Workarounds that Impacted Scram Recovery
Actions
Introduction. The team identified a Green finding for the licensees failure to follow
written procedures for classifying deficient plant conditions as operator workarounds and
providing compensatory measures or training in accordance with fleet
Procedure EN-OP-117. A misclassification of these conditions resulted in the failure of
the operations department to fully assess the impact these conditions had during a plant
-27-
transient. The failure to identify operator workarounds contributed to complications
experienced during reactor scram recovery on December 25, 2014.
Description. The team reviewed the recovery actions taken by the main control room
staff following the reactor scram on December 25, 2014, from 85 percent power. During
the review, the team observed the station had zero conditions identified as operator
workarounds. The team reviewed fleet Procedure EN-FAP-OP-006, Operator
Aggregate Impact Index Performance Indicator, Revision 2. This procedure defined an
operator workaround as:
Any plant condition (equipment or other) that would require compensatory
operator actions in the execution of normal operating procedures, abnormal
operating procedures, emergency operating procedures, or annunciator
response procedures during off-normal conditions. This indicator provided a
measure of plant safety. It provided a measure of the likelihood that a plant
transient may be complicated by equipment and human performance problems.
During their review, the team identified the following three conditions which met the
definition of an operator workaround as described in Procedure EN-FAP-OP-006, and
which were in effect prior to the December 25, 2014, event:
Work Order WO-RBS-00404323: RFP B supply breaker repetitive failures to
close potentially reduces the number of feedwater pumps available to operations
personnel during a transient following reactor pressure vessel water
Level 8 (high). Operations personnel would rack out and then rack the breaker
back in until the breaker would function properly. This work order was initiated
on February 3, 2015, following discussions with the NRC inspection team.
Work Order WO-RBS-00396449: RFP C minimum flow valve does not stroke
fully open which prevents starting the C feed pump. Maintenance personnel
would manually operate a limit switch on the valve to make up the start logic for
the RFP. This work order was initiated on October 10, 2014.
Work Order WO-RBS-00346642: leakage past FRVs when closed complicated
post-scram reactor water level control. Operations personnel proceduralized the
closure of the main feedwater isolation valves to stop the effect of the leakage.
This work order was initiated on March 27, 2013.
The deficient conditions in WO-RBS-00346642 and WO-RBS-00396449 contributed to
complications experienced by the station when attempting to restore feedwater following
a scram and loss of all feedwater pumps on a reactor pressure vessel water
Level 8 (high).
Fleet Procedure EN-OP-117, Attachment 9.4, Operator Aggregate Assessment of Plant
Deficiencies, provides a method to assess and document the impact of plant
deficiencies on operations personnel response during off-normal and emergency
conditions. In order to assess the cumulative impact of outstanding operator aggregate
-28-
impact deficiencies, several deficiency types were evaluated, including operator
workarounds. Following assessment of deficiencies, Attachment 9.4, step 5, directed
the station to provide compensatory measures or training as appropriate until the
deficiencies could be corrected.
The resident inspectors engaged operations department management in January 2015,
and informed the licensee that the three conditions appeared to meet the definition of an
operator workaround as described in Procedure EN-FAP-OP-006. Upon learning of the
misclassification of these issues, the station revised their operator aggregate index on
February 6, 2015, to account for the three operator workaround conditions and the
indicator turned red. As a result, the station issued guidance for post-scram reactor
water level control and required operating crews to attend simulator training on vessel
level control and feedwater system recovery following a Level 8 (high) trip of feedwater
pumps. Additionally, the station wrote Condition Report CR-RBS-2015-00795 to
document the issue.
Analysis. The failure to follow written procedures for classifying deficient plant
conditions as operator workarounds and providing compensatory measures or training in
accordance with fleet Procedure EN-OP-117 was a performance deficiency. This
performance deficiency is more than minor, and therefore a finding, because it had the
potential to lead to a more significant safety concern if left uncorrected. Specifically, the
performance deficiency contributed to complications experienced by the station when
attempting to restore feedwater following a scram on December 25, 2014.
The team performed an initial screening of the finding in accordance with IMC 0609,
Appendix A, The Significance Determination Process (SDP) for Findings At-Power.
Using IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, the
finding was of very low safety significance (Green) because it: (1) was not a deficiency
affecting the design or qualification of a mitigating structure, system, or component, and
did not result in a loss of operability or functionality; (2) did not represent a loss of
system and/or function; (3) did not represent an actual loss of function of at least a single
train for longer than its technical specification allowed outage time, or two separate
safety systems out-of-service for longer than their technical specification allowed outage
time; and (4) did not represent an actual loss of function of one or more non-technical
specification trains of equipment designated as high safety-significant in accordance with
the licensees maintenance rule program.
This finding has a consistent process cross-cutting aspect within the human
performance area because the licensee failed to use a consistent, systematic approach
to making decisions and incorporate risk insights as appropriate. Specifically, no
systematic approach was enacted in order to properly classify deficient conditions [H.8].
Enforcement. Enforcement action does not apply because the performance deficiency
did not involve a violation of regulatory requirements. Because this finding does not
involve a violation and is of very low safety significance, this issue was entered into the
licensees corrective action program as Condition Report CR-RBS-2015-00795: FIN
-29- 05000458/2015001-06, Failure to Identify and Classify Operator Workarounds That
Impacted Scram Recovery Actions.
4OA6 Meetings, Including Exit
Exit Meeting Summary
On January 20, 2015, the team initially debriefed Mr. E. Olson, Site Vice President, and other
members of the licensee's staff. The licensee representatives acknowledged the findings
presented.
On June 29, 2015, the team conducted an exit briefing with Mr. E. Olson, Site Vice President,
and other members of the licensees staff. The licensee representatives acknowledged the
findings presented.
A1-1
Attachment 1
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
E. Olson, Site Vice President
D. Bergstrom, Senior Operations Instructor
M. Browning, Senior Operations Instructor
T. Brumfield, Director, Regulatory & Performance Improvement
S. Carter, Manager, Shift Operations
M. Chase, Manager, Training
J. Clark, Manager, Regulatory Assurance
F. Corley, Manager, Design & Program Engineering
T. Creekbaum, Engineer
G. Degraw, Manager, Training
G. Dempsey, Senior Operations Instructor
S. Durbin, Superintendent, Operations Training
R. Gadbois, General Manager, Plant Operations
T. Gates, Manager, Operations Support
J. Henderson, Assistant Manager, Operations
K. Huffstatler, Senior Licensing Specialist, Licensing
K. Jelks, Engineering Supervisor
G. Krause, Assistant Manager, Operations
T. Laporte, Senior Staff Operations Instructor
R. Leasure, Superintendent, Radiation Protection
P. Lucky, Manager, Performance Improvement
J. Maher, Manager, Systems & Components Engineering
W. Mashburn, Director, Engineering
W. Renz, Director, Emergency Planning, Entergy South
J. Reynolds, Senior Manager, Maintenance
T. Shenk, Manager, Operations
T. Schenk, Manager, Operations
S. Vazquez, Director, Engineering
D. Williamson, Senior Licensing Specialist
D. Yoes, Manager, Quality Assurance
NRC Personnel
G. Warnick, Branch Chief
J. Sowa, Senior Resident Inspector
R. Deese, Senior Reactor Analyst
A1-2
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened 05000458/2015009-01
Vendor and Industry Recommended Testing Adequacy on
Safety-related and Safety-significant Circuit Breakers
(Section 2.5.b)
Opened and Closed 05000458/2015009-02
Failure to Establish Adequate Procedures to Perform
Maintenance on Equipment that can Affect Safety-Related
Equipment (Section 2.7.a)05000458/2015009-03
Failure to Provide Adequate Procedures for Post-scram
Recovery (Section 2.7.b)05000458/2015009-04
Failure to Identify High Reactor Water Level as a Condition
Adverse to Quality (Section 2.7.c)05000458/2015009-05
Failure of the Plant-Referenced Simulator to Demonstrate
Expected Plant Response (Section 2.7.d)05000458/2015009-06
Failure to Identify and Classify Operator Workarounds that
Impacted Scram Recovery Actions (Section 2.7.e)
LIST OF DOCUMENTS REVIEWED
DRAWINGS
NUMBER
TITLE
REVISION
GE-828E445AA,
Sheet 7
Elementary Diagram - Nuclear Steam Supply Shutoff System
34
GE-828E445AA,
Sheet 8
Elementary Diagram - Nuclear Steam Supply Shutoff System
33
GE-828E445AA,
Sheet 10
Elementary Diagram - Nuclear Steam Supply Shutoff System
31
GE-828E445AA,
Sheet 11
Elementary Diagram - Nuclear Steam Supply Shutoff System
30
GE-828E445AA,
Sheet 12
Elementary Diagram - Nuclear Steam Supply Shutoff System
30
GE-828E445AA,
Sheet 15
Elementary Diagram - Nuclear Steam Supply Shutoff System
37
GE-944E981
Elementary Diagram - RPS MG Set Control System
11
A1-3
DRAWINGS
NUMBER
TITLE
REVISION
PID-25-01A
Engineering P&I Diagram - System 051, Nuclear Boiling
Instrumentation
19
PID-25-01B
Engineering P&I Diagram - System 051, Nuclear Boiling
Instrumentation
7
828E531AA,
Sheet 4
Elementary Diagram - Reactor Protection System
25
828E531AA,
Sheet 4A
Elementary Diagram - Reactor Protection System
22
828E531AA,
Sheet 6
Elementary Diagram - Reactor Protection System
27
PROCEDURES
NUMBER
TITLE
REVISION
Reactor Scram
30
Automatic Isolations
33
Condensate/Feedwater Failures
19
Loss of One RPS Bus
19
EN-FAP-OM-004
Fleet and Site Business Plan Process
0
EN-FAP-OM-012
Prompt Investigation, Notifications and Duty Manager
Responsibilities
6
EN-FAP-OP-006
Operator Aggregate Impact Index Performance Indicator
2
Corrective Action Program
24
Cause Evaluation Process
21
Troubleshooting Control of Maintenance Activities
17
Operability Determination Process
7
Conduct of Operations
15
Operations Assessment Resources
8
EN-OP-115-09
Log Keeping
1
Simulator Configuration Control
9
RPV Control
26
Secondary Containment and Radioactive Release Control
16
A1-4
PROCEDURES
NUMBER
TITLE
REVISION
EPSTG-0001
Emergency Operating and Severe Accident Procedures - Plant
Specific Technical Guidelines (PSTG)
16
EPSTG-0002
EPGs/SAGs to PSTG to EOP/SAP Flowcharts Comparison
16
EPSTG-0002,
Appendix B
Emergency Operating and Severe Accident Procedures -
Bases
16
GOP-0001
Plant Startup
83
GOP-0002
Plant Shutdown
70
GOP-0003
Scram Recovery for December 27, 2014
24
Control of Operator Aids
13
Emergency and Transient Response Support Procedure
22
CONDITION REPORTS
WORK ORDERS
WO-RBS-00346642
WO-RBS-00396449
WO-RBS-00401085
WO-RBS-00404323
A1-5
MISCELLANEOUS DOCUMENT
NUMBER
TITLE
REVISION /
DATE
Engineering Change - Feedwater Level Control Setpoint
Setdown Modification
0
EN-LI-100-ATT-
9.1
Process Applicability Determination Form for AOP-0001,
Reactor Scram, Revision 24
August 6,
2007
LI-101
50.59 Review Form for GOP-0002, Power Decrease/Plant
Shutdown, Revision 30
August 26,
2004
GE-22A3778
Feedwater Control System (Motor Driven Feed Pumps)
Design Specification
4
GE-22A3778AB
Feedwater Control System (Motor Driven Feed Pumps)
Design Specification Data Sheet
7
RLP-LOP-0511
Licensed Operator Requalification - Industry
Events/Operating Experience and Plant Modifications
August 1,
2002
1-ST-27-TC6
Startup Procedure and Results - Turbine Trip and Generator
Load Reject
June 27,
1986
107-Feedwater
System Health Report - Feedwater
Q2 2014
0247.230-000-16 Feedwater Control Valve Assembly - Purchase Specifications 301
List of Actuations/Isolations That Occur From Loss of RPS
Bus B
January 29,
2015
Main Control Room Log
December 6,
2014
Main Control Room Log
December 13,
2014
Main Control Room Log
December 16,
2014
Main Control Room Log
December 27,
2014
Main Control Room Log
December 28,
2014
A2-1
Attachment 2
January 15, 2015
MEMORANDUM TO: Tom Hartman, Senior Resident Inspector
Reactor Projects Branch B
Division of Reactor Projects
FROM:
Troy Pruett, Director /RA/
Division of Reactor Projects
SUBJECT:
SPECIAL INSPECTION CHARTER TO EVALUATE CAUSES OF THE
UNPLANNED REACTOR TRIP WITH COMPLICATIONS AT THE
RIVER BEND STATION
In response to the unplanned reactor trip with complications at the River Bend Station, a special
inspection will be performed. You are hereby designated as the special inspection team leader.
The following members are assigned to your team:
Jim Drake, Senior Reactor Inspector, Division of Reactor Safety
Dan Bradley, Resident Inspector, Division of Reactor Projects
A.
Basis
On December 25, 2014, at 8:37 AM, River Bend Station scrammed from 85 percent power
following a trip of the B reactor protection system (RPS) motor generator (MG) set. At the
time of the MG set trip, a Division 1 half scram existed due to an unrelated equipment
issue with a relay for the No. 2 turbine control valve fast closure RPS function. The
combination of the B RPS MG set trip and the Division 1 half scram resulted in a scram of
the reactor.
The following equipment issues occurred during the initial scram response.
An unexpected Level 8 (high) reactor water level signal was received which resulted in
tripping of all RFPs.
Following reset of the Level 8 high reactor water level signal, plant operators were
unable to start RFP C. Plant operators responded by starting RFP A at a vessel level
of 25. The licensee subsequently determined that the circuit breaker (Magne Blast
type) for RFP C did not close because an interlock lever for a microswitch that controls
the breaker close permissive was not fully engaged in the cubicle.
Following the start of RFP A, the licensee attempted to open the startup feed
regulating valve but was unsuccessful prior the Level 3 low reactor water level trip
setpoint at +9.7. The licensee then opened the C main feedwater regulating valve to
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION IV
1600 E LAMAR BLVD
ARLINGTON, TX 76011-4511
A2-2
restore reactor vessel water level. The lowest level reached was +7.5. Subsequent
troubleshooting revealed a faulty manual function control card. The card was
replaced by the licensee and the startup feedwater regulating valve was used on the
subsequent plant startup.
Following restoration of reactor vessel water level, the plant was stabilized in Mode 3. A
plant startup was conducted on December 27, 2014 with RPS bus B being supplied by
its alternate power source. During power ascension following startup, RFP B did not
start. The licensee re-racked its associated circuit breaker and successfully started
RFP B.
Management Directive 8.3, NRC Incident Investigation Program, was used to evaluate
the level of NRC response for this event. In evaluating the deterministic criteria of
MD 8.3, it was determined that: (1) The event included multiple failures in the feedwater
system which is a short term decay heat removal mitigating system; (2) involved two
Magna Blast circuit breaker issues which could possibly have generic implications
regarding the licensees maintenance, testing, and operating practices for these
components including safety-related breakers in the high pressure core spray system;
and, (3) involved several issues related to the ability of operations to control reactor vessel
level between the Level 3 low and Level 8 high trip set points following a reactor scram.
Since the deterministic criteria was met, the trip was evaluated for risk. The preliminary
Estimated Conditional Core Damage Probability was determined to be 1.2E-6.
Based on the deterministic criteria and risk insights related to the multiple failures of the
feedwater system, the potential generic concern with the Magna Blast circuit breakers,
and the issues related to the licensees Operations departments inability to control reactor
vessel level between the Level 3 and Level 8 setpoints following a reactor scram, Region
IV determined that the appropriate level of NRC response was to conduct a Special
Inspection.
This Special Inspection is chartered to identify the circumstances surrounding this event,
determine if there are adverse generic implications, and review the licensees actions to
address the causes of the event.
B.
Scope
The inspection is expected to perform data gathering and fact-finding in order to address
the following:
1.
Provide a recommendation to Region IV management as to whether the
inspection should be upgraded to an augmented inspection team response. This
recommendation should be provided by the end of the first day on site.
2.
Develop a complete sequence of events related to the reactor scram that
occurred on December 25, 2014. The chronology should include the events
leading to the reactor scram, the licensees immediate scram response and the
licensees post-scram recovery actions including troubleshooting and reactor
startup.
A2-3
3.
Review the licensees root cause analysis and determine if it is being conducted
at a level of detail commensurate with the significance of the problem.
4.
Determine the causes for the unexpected Level 8 high water level trip signal that
was experienced following the reactor scram.
5.
Review the effectiveness of licensee actions to address known equipment
degradations that could complicate post scram operator response.
6.
Review the causes and corrective actions taken to address the failure of RFP C
to start during the initial scram response and RFP B during the subsequent
reactor startup. For issues related to Magne Blast circuit breakers, verify that the
licensees corrective actions have addressed extent of condition and extent of
cause.
7.
Review the licensees maintenance, testing and operating practices for Magne
Blast circuit breakers. Promptly communicate any potential generic issues to
regional management.
8.
Review the licensees corrective actions to address complications encountered
during previous reactor scrams. Reference previously docketed correspondence
regarding complicated reactor scrams in NRC inspection reports
05000458/2002002, 05000458/2006013, 05000458/2012009 and
9.
Evaluate pertinent industry operating experience and potential precursors to the
event, including the effectiveness of any action taken in response to the
operating experience.
10.
Collect data necessary to support completion of the significance determination
process.
C.
Guidance
Inspection Procedure 93812, "Special Inspection," provides additional guidance to be
used by the Special Inspection Team. Your duties will be as described in Inspection
Procedure 93812. The inspection should emphasize fact-finding in its review of the
circumstances surrounding the event. It is not the responsibility of the team to examine
A2-4
the regulatory process. Safety concerns identified that are not directly related to the
event should be reported to the Region IV office for appropriate action.
You will formally begin the special inspection with an entrance meeting to be conducted
no later than January 26, 2015. You should provide a daily briefing to Region IV
management during the course of your inspections and prior to your exit meeting. A
report documenting the results of the inspection should be issued within 45 days of the
completion of the inspection.
This Charter may be modified should you develop significant new information that
warrants review. Should you have any questions concerning this Charter, contact
Jeremy Groom at (817) 200-1144.
cc via E-mail:
M. Dapas
K. Kennedy
T. Pruett
A. Vegel
J. Clark
V. Dricks
W. Maier
J. Groom
J. Sowa
R. Azua
N. Taylor
T. Hartman
J. Drake
D. Bradley
ADAMS ACCESSION NUMBER ML15015A634
SUNSI Rev Compl.
Yes No
Yes No
Reviewer Initials
JRG
Publicly Avail
Yes No
Sensitive
Yes No
Sens. Type Initials
JRG
Keyword
MD 3.4/A.7
RIV/DRP: BC
RIV/DRP: DIR
JRGroom
TWPruett
/RA/RAzua for
/RA/
1/15/15
1/15/15
OFFICIAL RECORD