IR 05000458/2007003
Download: ML072190346
Text
August 7, 2007
Joseph E. VenableSenior Vice President, Operations Entergy Operations, Inc.
River Bend Station 5485 US Highway 61N St. Francisville, LA 70775
SUBJECT: RIVER BEND STATION - NRC INTEGRATED INSPECTIONREPORT 05000458/2007003
Dear Mr. Venable:
On June 30, 2007, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection atyour River Bend Station. The enclosed integrated inspection report documents the inspection findings, which were discussed on July 9, 2007, with you and other members of your staff.The inspection examined activities conducted under your license as they relate to safety andcompliance with the Commission's rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.This report documents one NRC-identified finding and three self-revealing findings of very lowsafety significance (Green). Two of these findings were determined to involve violations of NRC requirements. Additionally, a licensee-identified violation which was determined to be of very low safety significance is listed in this report. However, because of the very low safety significance and because they are entered into your corrective action program, the NRC is treating these findings as noncited violations (NCVs) consistent with Section VI.A.1 of the NRC Enforcement Policy. If you contest any NCV in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, U.S. Nuclear Regulatory Commission, Region IV, 611 Ryan Plaza Drive, Suite 400, Arlington, Texas 76011-4005; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at River Bend Station.
Entergy Operations, Inc.-2-In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, itsenclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).Should you have any questions concerning this inspection, we will be pleased to discuss themwith you.
Sincerely,/RA/Michael C. Hay, ChiefProject Branch C Division of Reactor ProjectsDocket: 50-458License: NPF-47
Enclosure:
NRC Inspection Report 05000458/2007003
w/Attachment:
Supplemental Informationcc w/enclosure:Executive Vice President and Chief Operating Officer Entergy Operations, Inc.
P.O. Box 31995 Jackson, MS 39286-1995Vice President Operations Support Entergy Operations, Inc.
P.O. Box 31995 Jackson, MS 39286-1995General ManagerPlant Operations Entergy Operations, Inc.
River Bend Station 5485 US Highway 61N St. Francisville, LA 70775Director, Nuclear Safety & LicensingEntergy Operations, Inc.
1340 Echelon Parkway Jackson, MS 39213-8298Manager, LicensingEntergy Operations, Inc.
River Bend Station 5485 US Highway 61N St. Francisville, LA 70775The Honorable Charles C. Foti, Jr.Attorney General Department of Justice State of Louisiana P.O. Box 94095 Baton Rouge, LA 70804-9005H. Anne Plettinger3456 Villa Rose Drive Baton Rouge, LA 70806 Entergy Operations, Inc.-3-Bert Babers, PresidentWest Feliciana Parish Police Jury P.O. Box 1921 St. Francisville, LA 70775Richard Penrod, Senior Environmental Scientist, State Liaison Officer Office of Environmental Services Northwestern State University Russell Hall, Room 201 Natchitoches, LA 71497Brian AlmonPublic Utility Commission William B. Travis Building P.O. Box 13326 1701 North Congress Avenue Austin, TX 78701-3326Jim CallowayPublic Utility Commission of Texas 1701 N. Congress Avenue Austin, TX 78711-3326Lisa R. Hammond, ChiefTechnological Hazards Branch National Preparedness Division FEMA Region VI 800 N. Loop 288 Denton, TX 76209 Entergy Operations, Inc.-4-Electronic distribution by RIV:Regional Administrator (BSM1)DRP Director (ATH)DRS Director (DDC)DRS Deputy Director (RJC1)DRS Deputy Director (WBJ)Senior Resident Inspector (MOM)Branch Chief, DRP/C (MCH2)Senior Project Engineer, DRP/C (WCW)Team Leader, DRP/TSS (CJP)RITS Coordinator (MSH3)DRS STA (DAP)M. Kunowski, OEDO RIV Coordinator (MAK3)D. Pelton, OEDO RIV Coordinator (DLP1)ROPreports RBS Site Secretary (LGD)W. A. Maier, RSLO (WAM)R. E. Kahler, NSIR (REK)SUNSI Review Completed: WCW_ADAMS: G YesG No Initials: _WCW_____ G Publicly Available G Non-Publicly Available G SensitiveG Non-SensitiveR:\_REACTORS\_RB\RB2007-03RP-MOM.wpdRIV:SRI:DRP/CSRI:DRP/CSPE:DRP/CC:DRS/EB1C:DRS/PSBMOMillerPJAlterWCWalkerDAPowersMPShannonT-WCWalker forE-WCWalker for /RA/ /RA/ /RA/08/03/0708/03/0708/02/0707/31/0708/01/07C:DRS/EB2C:DRS/OBC:DRP/CLJSmithATGodyMCHay /RA//RA KDClayton for/ /RA/08/01/0708/01/0708/07/07OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax Enclosure-1-U.S. NUCLEAR REGULATORY COMMISSIONREGION IVDocket:50-458License:NPF-47 Report:05000458/2007003 Licensee:Entergy Operations, Inc.
Facility:River Bend Station Location:5485 U.S. Highway 61St. Francisville, LouisianaDates:April 1 through June 30, 2007 Inspectors:M. Miller, Senior Resident Inspector, Project Branch CP. Alter, Senior Resident Inspector, Project Branch C D. Tharp, Resident Inspector, Region III, ClintonW. Sifre, Senior Reactor Inspector, Engineering Branch 1 B. Henderson, Reactor Inspector, Engineering Branch 1 E. Owen, Reactor Inspector, Engineering Branch 1 P. Elkmann, Emergency Preparedness Inspector, Operations BranchApproved By:Michael C. Hay, ChiefProject Branch C Division of Reactor Projects Enclosure-2-CONTENTS
SUMMARY OF FINDINGS
....................................................3
REPORT DETAILS
..........................................................6
REACTOR SAFETY
.........................................................61R01Adverse Weather Protection.......................................61R02Evaluation of Changes, Tests, or Experiments.........................71R04Equipment Alignment.............................................81R05 Fire Protection..................................................91R11Licensed Operator Requalification Program...........................101R13Maintenance Risk Assessments and Emergent Work Control.............101R15Operability Evaluations..........................................121R17Permanent Plant Modifications.....................................131R19Postmaintenance Testing........................................141R20Refueling and Other Outage Activities...............................151R22Surveillance Testing.............................................161R23Temporary Plant Modifications.....................................171EP2Alert and Notification System Testing...............................171EP3Emergency Response Organization Augmentation.....................181EP4Emergency Action Level and Emergency Plan Changes.................181EP5Correction of Emergency Preparedness Weaknesses and Deficiencies.....191EP6Exercise Evaluation.............................................19OTHER ACTIVITIES........................................................204OA1Performance Indicator (PI) Verification..............................204OA2Identification and Resolution of Problems............................204OA3Event Followup................................................224OA4Crosscutting Aspects of Findings...................................274OA6Management Meetings...........................................284OA7Licensee-Identified Violations.....................................28
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
................................................A-1
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
...........................A-1
LIST OF DOCUMENTS REVIEWED
..........................................A-2
LIST OF ACRONYMS
......................................................A-9
Enclosure-3-SUMMARY
- OF [[]]
FINDINGSIR 05000458/2007003; 04/01/2007 - 06/30/2007; River Bend Station; Event Followup.The report covered a 3-month period of routine inspections by resident inspectors andannounced baseline inspections by region-based inspectors. Two Green noncited violations
and two Green findings were identified. The significance of most findings is indicated by theircolor (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
NRC's program for overseeing the safe operation of commercial nuclear power reactors is
described in
NRC-Identified and Self-Revealing FindingsCornerstone: Initiating Events
- Green. A self-revealing noncited violation of Technical Specification 5.4.1.a wasidentified involving the failure to follow a surveillance procedure for scram discharge
instrument volume water level channel calibration. Specifically, on February 9, 2007, an
instrument line plug was not replaced following surveillance testing. As a result, on
May 5, 2007, following a reactor scram, reactor water sprayed out of the scram
discharge instrument volume and contaminated some accessible portions of the
containment building causing three inadvertent personnel contamination events. This
issue was entered into the licensee's corrective action program as condition Report
RBS-2007-01809. The finding was more than minor because it was associated with the initiating eventcornerstone attribute of equipment performance and affected the cornerstone objective
to limit the likelihood of those events that upset plant stability and challenge critical
safety functions during power operations. A Phase 2 estimation was required, asdetermined by the Manual Chapter 0609, Appendix A, Phase 1 Worksheet, "SDP Phase1 Screening Worksheet for Initiating Events, Mitigation Systems, and BarriersCornerstones," because the associated performance deficiency resulted in a reactorcoolant leak greater than the Technical Specification limit for identified reactor coolantsystem leakage. Using the plant-specific Phase 2 risk-informed notebook, this violationwas determined to have very low safety significance because the violation onlyincreased the likelihood of a small-break loss of coolant accident by a very small amountand mitigation capability was unaffected. The cause of the finding was related to the
human performance crosscutting component of work practices because neither self norpeer checking actions identified the failure to replace the vent plug (H.4(a)).
(Section 4OA3)*Green. A self-revealing finding was identified involving the failure to implement 1998vendor recommendations associated with the potential for vibration induced degradation
of recirculation loop gate valves. This resulted in the failure to identify and implement
timely corrective actions prior to disk to stem separation of recirculation Pump A
Enclosure-4-discharge gate valve that occurred on May 21, 2007. This issue was entered into thelicensee's corrective action program as condition Report
RBS-2007-02113. The finding was more than minor because it was associated with the initiating eventscornerstone attribute of equipment performance and affected the associated
cornerstone objective to limit the likelihood of those events that upset plant stability and
challenge critical safety functions during power operations. Using the Manual Chapter0609, "Significance Determination Process," Phase 1 Worksheet, the finding wasdetermined to have a very low safety significance because the finding did not contributeto the likelihood that mitigation equipment or functions would not be available following areactor trip. (Section 4OA3) Green. A self-revealing finding was identified involving inadequate maintenanceinstructions for opening a stuck closed feedwater regulating Valve A isolation valve.
Specifically, the instructions failed to account for the system being pressurized resulting
in unexpected valve stem movement while technicians were removing the manual
operator from the valve on June 10, 2007. This deficiency could have resulted in
personnel harm or an unexpected and uncontrolled plant transient. This issue was
entered into the licensee's corrective action program as condition Report
RBS-2007-02576. The finding was more than minor because it could become a more significant safetyconcern if left uncorrected. Using the Manual Chapter 0609, "SignificanceDetermination Process," Phase 1 Worksheet, the finding was determined to have very
low safety significance because the deficiency did not contribute to both the likelihood of
a reactor trip and the likelihood that mitigation equipment or functions would not be
available. No violation of NRC requirements occurred. The cause of this finding wasrelated to the human performance crosscutting component of resources because thelicensee did not ensure a complete and accurate work package was available prior to
the start of the job (H.2(c)). (Section 4OA3)Cornerstone: Barrier Integrity
Green. A self-revealing noncited violation of Technical Specification 5.4.1.a wasidentified involving the failure to follow procedure. Specifically, during control rod
withdrawal a reactor engineer noted that reactor power, as calculated by a heat balance,
was inconsistent with predicted power. Although this inconsistency was identified the
reactor engineers and operators failed to fully evaluate this condition, as required by
procedure, and continued with power ascension resulting in an automatic rod withdrawal
block. Upon further review the event was caused from feed flow and temperature data
not automatically updating resulting in calculated power being less than actual power.
This issue was entered into the licensee's corrective action program as condition Report
RBS-2007-01691.The finding was more than minor because it was associated with the barrier integritycornerstone attribute of configuration control and it affected the cornerstone objective to
provide reasonable assurance that physical design barriers, such as fuel cladding,
protect the public from radio-nuclide releases caused by accidents or events. Using the
Enclosure-5-Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheet, thefinding was determined to have a very low safety significance because it did not have
the potential to affect the integrity of the RCS barrier. The cause of this finding is
related to the human performance cross cutting component of work practices because
neither self nor peer checking actions prevented the automatic rod withdrawal block
(H.4(a)). (Section 4OA3)B.Licensee-Identified ViolationsOne violation of very low safety significance, which was identified by the licensee, hasbeen reviewed by the inspectors. Corrective actions taken or planned by the licensee
have been entered into the licensee's corrective action program. This violation and
corrective actions are listed in Section 4OA7 of this report.
Enclosure-6-REPORT
- DETAIL [[]]
SSummary of Plant Status: The plant was operated between 100 percent and 96 percent powerfrom April 1-9, 2007, because of main condenser vacuum concerns. On April 9, reactor power
was reduced to 70 percent to support condenser cleaning. On April 11, reactor power was
further reduced to 65 percent to support condenser cleaning. On April 19, the reactor was
restored to 100 percent power. On April 24, reactor power was reduced to approximately 15
percent to support repairs to a leaking relief valve in the feedwater system. On April 28, the
reactor was restored to 100 percent power. On May 4, the reactor was manually scrammed
following a loss of main transformer cooling. On May 7, plant restart commenced and on May
10, the reactor was restored to 100 percent power. On May 21, reactor recirculation Loop A
flow unexpectedly lowered with a corresponding drop in reactor power from 100 percent to
percent. Control room operators balanced flows between recirculation loops resulting in
reducing reactor power to 90 percent. On May 22, the reactor was shutdown to support repairs
to recirculation pump discharge gate valve A. On June 8, plant restart commenced. Full power
was delayed as repairs were made to one of the reactor feedwater pumps. On June 18, the
reactor reached 100 percent power and remained at 100 percent for the remainder of the
inspection period, except for a normally scheduled down power for a control rod pattern
adjustment on June 19, 2007.1.REACTOR
- SAFET [[]]
YCornerstones: Initiating Events, Mitigating Systems, Barrier Integrity1R01Adverse Weather Protection a.Inspection Scope .1Readiness For Seasonal SusceptibilitiesDuring the week of June 4, 2007, the inspectors completed a review of the licensee'sreadiness for seasonal susceptibilities involving high winds and heavy rain at the
beginning of hurricane season. The inspectors: (1) interviewed the emergency
planning manager and members of the emergency planning staff to discuss changes in
readiness since hurricane Katrina in 2005; (2) conducted in-office reviews of Procedure
EP-302, "Severe Weather Response," Revision 6, abnormal operating Procedure
AOP-0029, "Severe Weather Operation," Revision 19, the Updated Safety Analysis
Report (USAR), and Technical Specifications (TS) to verify that operator actions defined
in adverse weather procedures maintained the readiness of essential systems;
(3) walked down external portions of the protected area to verify that hurricane season
preparations were sufficient to support operability of essential systems, including the
ability to perform safe shutdown functions; (4) evaluated staffing levels to verify the
licensee could maintain the readiness of essential systems required by plant
procedures; and (5) reviewed the corrective action program (CAP) to determine if the
licensee identified and corrected problems related to adverse weather conditions.The inspectors completed one inspection sample.
Enclosure-7- b.FindingsNo findings of significance were identified.1R02Evaluation of Changes, Tests, or Experiments a.Inspection ScopeThe inspectors reviewed the effectiveness of the licensee's implementation of changesto the facility structures, systems, and components (SSC); risk-significant normal and
emergency operating procedures; test programs; and the
- US [[]]
AR in accordance with
CFR 50.59, "Changes, Tests, and Experiments." The inspectors utilized Inspection
Procedure 71111.02, "Evaluation of Changes, Tests, or Experiments," for this
inspection.The inspectors reviewed six safety evaluations performed by the licensee since the lastNRC inspection of this area at River Bend Station. The evaluations were reviewed to
verify that licensee personnel had appropriately considered the conditions under which
the licensee may make changes to the facility or procedures or conduct tests or
experiments without prior NRC approval. The inspectors reviewed eight
licensee-performed applicability determinations and 10 screenings, in which licensee
personnel determined that evaluations were not required, to ensure that the exclusion of
a full evaluation was consistent with the requirements of 10 CFR 50.59. Evaluations,
screenings, and applicability determinations reviewed are listed in the Attachment to this
report.The inspectors reviewed and evaluated a sample of recent licensee condition reports(CRs) to determine whether the licensee had identified problems related to 50.59
evaluations, entered them into the CAP, and resolved technical concerns and regulatory
requirements. The reviewed CRs are identified in the Attachment to this report.The inspection procedure specifies the inspectors review a minimum sample offive licensee safety evaluations and 10 applicability determinations and screenings
(combined). The inspectors completed a review of six licensee safety evaluations and a
combination of 18 applicability determinations and screenings.The inspectors completed 24 inspection samples. b.FindingsNo findings of significance were identified.
Enclosure-8-1R04Equipment Alignment 1.Partial System Walkdowns a.Inspection ScopeThe inspectors: (1) walked down portions of the four risk important systems listed belowand reviewed plant procedures and documents to verify that critical portions of the
selected systems were correctly aligned; and (2) compared deficiencies identified during
the walk down to the licensee's
CAP to ensure problems were being
identified and corrected. Documents reviewed by the inspectors are listed in the
attachment. May 31, 2007, Shutdown Cooling Line-up and Fuel Pool Assist mode ofshutdown coolingMay 31, 2007, Primary Containment Integrity during operations with thepossibility of draining the reactor pressure vesselJune 11, 2007, Division
- II Standby Diesel GeneratorThe inspectors completed four inspection samples. b.FindingsNo findings of significance were identified.
- 2.C omplete System Walkdown a.Inspection ScopeThe inspectors: (1) reviewed plant procedures, drawings, the
USAR, and TS todetermine the correct alignment of the on-site Division I 4.16 Kv electrical distribution
system; (2) reviewed outstanding design issues, operator workarounds, and
- US [[]]
documents to determine if open issues affected the functionality of the on-site Division I
4.16 Kv electrical distribution system; and (3) verified that the licensee was identifyingand resolving equipment alignment problems. Documents reviewed by the inspectors
included:
AC Sources - Operating"The inspectors completed one inspection sample.
Enclosure-9- b.FindingsNo findings of significance were identified.1R05 Fire Protection a.Inspection ScopeQuarterly InspectionThe inspectors walked down the six plant areas listed below to assess the materialcondition of active and passive fire protection features and their operational lineup and
readiness. The inspectors: (1) verified that transient combustibles and hot work
activities were controlled in accordance with plant procedures; (2) observed the
condition of fire detection devices to verify they remained functional; (3) observed fire
suppression systems to verify they remained functional and that access to manual
actuators was unobstructed; (4) verified that fire extinguishers and hose stations were
provided at their designated locations and that they were in a satisfactory condition;
(5) verified that passive fire protection features (electrical raceway barriers, fire doors,
fire dampers, steel fire proofing, penetration seals, and oil collection systems) were in a
satisfactory material condition; and (6) reviewed the CAP to determine if the licensee
identified and corrected fire protection problems. *April 16, 2007, Turbine Building, 67-foot level, reactor feed pump area, Fire AreaTB-67*May 17, 2007, Standby Switchgear 1B Room, 98-foot level, Fire Area C-14
- May 17, 2007, Safety Related Cable Chase II, 98-foot level, Fire Area C-2
- June 11, 2007, Safety Related Water Chiller Equipment 1B Room, 98-foot level,Fire Area C-13E*June 12, 2007, Safety Related Water Chiller Equipment 1A Room, 98-foot level,Fire Area C-13W*June 13, 2007, Standby Switchgear 1A Room, 98-foot level, Fire Area C-15
Documents reviewed by the inspectors included:
Pre-Fire Plan/Strategy Book
RBNP-038, "Site Fire Protection Program," Revision 6BThe inspectors completed six inspection samples.
Enclosure-10- b.FindingsNo findings of significance were identified.1R11Licensed Operator Requalification Program a.Inspection ScopeOn June 20, 2007, the inspectors observed one Annual 2007 Dynamic SimulatorExamination of senior reactor operators and reactor operators to identify deficiencies
and discrepancies in the examination process, to assess operator performance, and to
assess the evaluator's critique. The training scenario involved reactor feed Pump A
minimum flow failing open, followed by failure of both seals on reactor recirculation
Pump A, and a design basis accident loss of coolant accident (LOCA). Documents
reviewed by the inspectors included:Simulator Examination Scenario
- LO [[]]
CA With Failure to Isolate,"
Revision 1The inspectors completed one inspection sample. b.FindingsNo findings of significance were identified.1R13Maintenance Risk Assessments and Emergent Work Control a.Inspection Scope .1Risk Assessment and Management of RiskThe inspectors reviewed the two assessment activities listed below to verify: (1) performance of risk assessments when required by 10 CFR 50.65 (a)(4) and
administrative Procedure ADM-096, "Risk Management Program Implementation and
On-Line Maintenance Risk Assessment," Revision 04B, prior to changes in plant
configuration for maintenance activities and plant operations; (2) the accuracy,
adequacy, and completeness of the information considered in the risk assessment;
(3) that the licensee recognizes, and/or enters as applicable, the appropriate
licensee-established risk category according to the risk assessment results and licensee
procedures; and (4) the licensee identified and corrected problems related to
maintenance risk assessments. Week of June 18, 2007, Division II work week Week of June 25, 2007, Non-Divisional work week
Enclosure-11-Documents reviewed by the inspectors included:*Computerized equipment out-of-service risk monitor*Daily plant status sheets
Computerized
RBS daily schedule by systemThe inspectors completed two inspection samples. .2Emergent Work ControlThe inspectors: (1) verified that the licensee performed actions to minimize theprobability of initiating events and maintained the functional capability of mitigating
systems and barrier integrity systems; (2) verified that emergent work-related activities
such as troubleshooting, work planning/scheduling, establishing plant conditions,
aligning equipment, tagging, temporary modifications, and equipment restoration did not
place the plant in an unacceptable configuration; and (3) reviewed the CAP to determine
if the licensee identified and corrected risk assessment and emergent work control
problems. April 1-4, 2007, daily power reductions due to main condenser inefficiency Weeks of April 9 and 16, 2007, power reduction to 70 percent and then65 percent for on-line condenser cleaning April 24, 2007, turbine taken off line and the reactor remained critical at 15percent power with pressure control via the turbine bypass valves for feedwater
relief valve maintenance April 25, 2007, power ascension following forced Outage 07-01 May 7, 2007, power ascension following forced Outage 07-02 May 10 and 17, 2007, residual heat removal shutdown cooling outboard isolationvalve logic relay replacement June 1, 2007, operations with potential to drain the reactor vessel during repairof recirculation Loop A discharge gate valve June 2, 2007, operations with potential to drain the reactor vessel during repairof recirculation Loop B discharge gate valve June 10, 2007, power ascension following forced outage 07-03
Enclosure-12-Documents reviewed by the inspectors included: Computerized equipment out-of-service risk monitor Daily plant status sheets Computerized
SOPP)," Revision 16The inspectors completed nine inspection samples. b.FindingsNo findings of significance were identified.1R15Operability Evaluations a.Inspection ScopeThe inspectors: (1) reviewed plant status documents such as operator shift logs,emergent work documentation, deferred modifications, and standing orders to
determine if an operability evaluation was warranted for degraded components;
(2) referred to the
- US [[]]
AR and design basis documents to review the technical adequacy
of licensee operability evaluations; (3) evaluated compensatory measures associated
with operability evaluations; (4) determined degraded component impact on any TS; (5)
used the Significance Determination Process to evaluate the risk significance of
degraded or inoperable equipment; and (6) verified that the licensee has identified and
implemented appropriate corrective actions associated with degraded components. The
licensee operability evaluations were documented in the following
- CR -RBS-2007-02104, Division 2 diesel generator fuel day level transmittersensor tubing, reviewed on May 25,
RBS-2007-02180, Low pressure coolant injection Pump C discharge flowtransmitter fount out of tolerance low during surveillance test, reviewed on
May 30, 2007
Enclosure-13-
- RBS -2007-02230, Division I standby diesel generator excitation cabinettemperature below limits for rounds, reviewed on June 5,
- RBS -2007-02364, Two broken drywell head finger pins (#47 & #48),reviewed on June 15, 2007Documents reviewed by the inspectors included: Nuclear Management ManualProcedure
OP-104, "Operability Determinations," Revision 2.The inspectors completed five inspection samples. b.FindingsNo findings of significance were identified.1R17Permanent Plant Modifications a.Inspection ScopeBiennial ReviewThe inspection procedure requires inspection of a minimum sample size of fivepermanent plant modifications. The inspectors reviewed nine permanent plant modification packages and associateddocumentation, such as implementation reviews, safety evaluation applicability
determinations, and screenings to verify that they were performed in accordance with
regulatory requirements and plant procedures. The inspectors also reviewed the
procedures governing plant modifications to evaluate the effectiveness of the program
for implementing modifications to risk-significant SSCs, such that these changes did not
adversely affect the design and licensing basis of the facility. Procedures and
permanent plant modifications reviewed are listed in the Attachment to this report.
Further, the inspectors interviewed the cognizant design and system engineers for the
identified modifications as to their understanding of the modification packages and
process. The inspectors evaluated the effectiveness of the licensee's corrective action process toidentify and correct problems concerning the performance of permanent plant
modifications by reviewing a sample of related
CRs are identified in
the Attachment to this report.The inspectors completed nine inspection samples.
Annual ReviewThe inspectors reviewed key affected parameters associated with materials/replacementcomponents, timing, control signals, equipment protection from hazards, operations,
Enclosure-14-flowpaths, ventilation boundary, structural, licensing basis, and failure modes for themodification listed below. The inspectors verified that: (1) modification preparation,
staging, and implementation did not impair emergency/abnormal operating procedure
actions, key safety functions, or operator response to loss of key safety functions;
(2) postmodification testing maintained the plant in a safe configuration during testing by
verifying that unintended system interactions would not occur, SSC performance
characteristics still met the design basis, the appropriateness of modification design
assumptions, and the modification test acceptance criteria had been met; and (3) the
licensee had identified and implemented appropriate corrective actions associated with
permanent plant modifications.*Week of May 21, 2007,
CHL1CDocuments reviewed by the inspectors included:
- WO 00102689, Replace Breaker
CHL1C ghost light indications in "test" positionThe inspectors completed one inspection sample. b.FindingsNo findings of significance were identified.1R19Postmaintenance Testing a.Inspection ScopeThe inspectors selected the five postmaintenance test activities listed below of risksignificant systems or components. For each item, the inspectors: (1) reviewed the
applicable licensing basis and/or design-basis documents to determine the safety
functions; (2) evaluated the safety functions that may have been affected by the
maintenance activity; and (3) reviewed the test procedure to ensure it adequately tested
the safety function that may have been affected. The inspectors either witnessed or
reviewed test data to verify that acceptance criteria were met, plant impacts were
evaluated, test equipment was calibrated, procedures were followed, jumpers were
properly controlled, the test data results were complete and accurate, the test
equipment was removed, the system was properly re-aligned, and deficiencies during
testing were documented. The inspectors also reviewed the CAP to determine if the
licensee identified and corrected problems related to postmaintenance testing. The
postmaintenance testing was part of the following work orders (WO):
EJS-ACB-036,reviewed on April 19, 2007
Enclosure-15-
- WO 50690110 03, disassemble, clean, inspect check valves & orifices forpenetration valve leakage control Compressor B,
LSV-C3B, reviewed on
June 4, 2007.
RCIC steam line flow high transmitter, E31-PDTN083B,reviewed on June 19, 2007 WO00091258 01, replace reactor trip Logic A relay, C71-K71, reviewed onJune 23, 2007The inspectors completed five inspection samples. b.FindingsNo findings of significance were identified.1R20Refueling and Other Outage Activities a.Inspection ScopeDuring three forced outages: April 24-25, 2007, to repair a leaking feedwater systemrelief valve; May 4-7, 2007, in response to main transformer cooling system failure; and
May 22 through June 10, 2007, in response to recirculation system Loop A discharge
gate valve stem/disk separation; the inspectors reviewed the following risk significant
outage activities to verify defense in depth commensurate with the outage risk control
plan, compliance with the TS, and adherence to commitments in response to Generic Letter 88-17, "Loss of Decay Heat Removal": (1) the risk control plan;
(2) tagging/clearance activities; (3) reactor coolant system (RCS) instrumentation; (4)
electrical power; (5) decay heat removal; (6) inventory control; (7) containment closure;
(8) operations with the potential to drain the reactor pressure vessel; (9) heatup and
cooldown activities; (10) restart activities; and (11) licensee identification and
implementation of appropriate corrective actions associated with outage activities. The
inspectors' drywell inspections included observations of supports, braces, and snubbers
for evidence of excessive stress, water hammer, or aging. Specific outage activities
observed and reviewed included: Installation of recirculation loop level indication systems Plugging of jet pump nozzles Draining of recirculation loops Restoration of recirculation loops Plant restart, heatup, and connection to the gridDocuments reviewed by the inspectors are listed in the attachment.
The inspectors completed three inspection samples.
Enclosure-16- b.FindingsNo findings of significance were identified.1R22Surveillance Testing a.Inspection ScopeThe inspectors reviewed the
TS to ensure that theseven Surveillance Test Procedures (STP) listed below demonstrated that the SSC's
tested were capable of performing their intended safety functions. The inspectors either
witnessed or reviewed test data to verify that the following significant surveillance test
attributes were adequate: (1) preconditioning; (2) evaluation of testing impact on the
plant; (3) acceptance criteria; (4) test equipment; (5) procedures; (6) jumper/lifted lead
controls; (7) test data; (8) testing frequency and method demonstrated TS operability;
(9) test equipment removal; (10) restoration of plant systems; (11) fulfillment of
- AS [[]]
ME
Code requirements; (12) updating of performance indicator data; (13) engineering
evaluations, root causes, and bases for returning tested SSC's not meeting the test
acceptance criteria to operable status; (14) reference setting data; and
(15) annunciators and alarms setpoints. The inspectors also verified that the licensee
identified and implemented any needed corrective actions associated with the
surveillance testing. *STP-500-4203, "RPS-Scram Discharge Volume Water Level-High ChannelCalibration Test and Logic System Functional Test (C11-LTN012B;
C11-N0601B," Revision 12, performed on May 15, 2007*STP-309-0203, "Division
STP-302-1201, "ENS-SWG1A Degraded Voltage Channel Functional Test,"Revision 11, performed on June 21, 2007*WO00112179 01, "Change the Range of Transmitters B21-LTN027 andC33-LTN017 for Mode 4 and 5 Operation," Revision 8/13/2006, performed on
June 21, 2007*STP-309-0201, "Division I Diesel Generator Operability Test," Revision 031,performed on June 23, 2007*STP-505-4517, "RPS/Control Rod Block-APRM Setdown Channel FunctionalTest (C51-K605A Through C51-K605H)," Revision 04, performed on
June 26, 2007*STP-204-6304, "Div
- II [[]]
RHR Quarterly valve Operability Test," Revision 018,performed on December 1, 2006 (Inservice test surveillance)The inspectors completed seven inspection samples.
Enclosure-17- b.FindingsNo findings of significance were identified.1R23Temporary Plant Modifications a.Inspection ScopeThe inspectors reviewed the
TS toensure that one temporary modification was properly implemented. The inspectors:
(1) verified that the modification did not have an affect on system operability/availability;
(2) verified that the installation was consistent with modification documents; (3) ensured
that the post installation test results were satisfactory and that the impact of the
temporary modification on permanently installed SSC's was supported by the test; and
(4) verified that appropriate safety evaluations were completed. The inspectors verified
that the licensee identified and implemented any needed corrective actions associated
with the temporary modification. Temporary thermocouples to monitor core exit temperatures, reviewedMay 13, 2007 Documents reviewed by the inspectors included:
EQIS M-553, "Analysis of teflon insulated thermocouple wire for temporaryreactor coolant temperature monitoring instrumentation"The inspectors completed one inspection sample. b.FindingsNo findings of significance were identified.
Cornerstone: Emergency Preparedness1EP2Alert and Notification System Testing a.Inspection ScopeThe inspector discussed with licensee staff the status of offsite siren and tone alert radiosystems to determine the adequacy of licensee methods for testing the alert and
notification system in accordance with 10 CFR Part 50, Appendix E. The licensee's alert
and notification system testing program was compared with criteria in
- NUR [[]]
EG-0654,
"Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and
Preparedness in Support of Nuclear Power Plants," Revision 1, Federal Emergency
Management Agency (FEMA) Report REP-10, "Guide for the Evaluation of Alert and
Notification Systems for Nuclear Power Plants," and the licensee's current
Enclosure-18-FEMA-approved alert and notification system design report, "River Bend Station PromptNotification System Design Report," Revision 1, December 2001. The inspector also
reviewed procedures
EPP-2-502,
"Emergency Communications Equipment Testing," Revision 22, and EPP-2-701,
"Prompt Notification System Maintenance and Testing," Revisions 18 and 19.
The inspector completed one inspection sample. b.FindingsNo findings of significance were identified.1EP3Emergency Response Organization Augmentation a.Inspection ScopeThe inspector discussed with licensee staff the status of primary and backup systemsfor augmenting the on-shift emergency response staff to determine the adequacy of
licensee methods for staffing emergency response facilities. The inspector reviewed the
references listed in the Attachment to this report related to the emergency response
organization augmentation system to evaluate the licensee's ability to staff the
emergency response facilities in accordance with the licensee emergency plan and the
requirements of
- 10 CFR Part 50, Appendix E.The inspector completed one inspection sample. b.FindingsNo findings of significance were identified.1
EP4Emergency Action Level and Emergency Plan Changes a.Inspection ScopeThe inspector performed an in-office review of Revisions 15 and 16 to Emergency Planimplementing Procedure EIP-2-001, "Classification of Emergencies," submitted
April 19, 2007. These revisions implemented a scheme of emergency action levels
based on Nuclear Engineering Institute (NEI) 99-01, "Methodology for Development of
Emergency Action Levels," Revision 4, as approved by the NRC by letter dated
October 25,
NRC Safety Analysis Report dated October 25, 2005, the criteria of NRC Bulletin 2005-002, "Emergency Preparedness and
Response Actions for Security Based Events," the criteria of NEI 99-01, Revision 4, and
to the standards in 10 CFR 50.47(b) to determine if the revisions were adequately
conducted following the requirements of 10 CFR 50.54(q). This review was not
documented in a Safety Evaluation Report and did not constitute approval of licensee
changes; therefore, these revisions are subject to future inspection.
Enclosure-19-The inspector completed two inspection samples. b.FindingsNo findings of significance were identified.1EP5Correction of Emergency Preparedness Weaknesses and Deficiencies a.Inspection ScopeThe inspector reviewed the licensee's
LI-119, "Apparent Cause Evaluation
Process," Revision 3. The inspector reviewed summaries of 180 CRs assigned to the
emergency preparedness department between November 2005 and May 2007, and
selected 13 for detailed review against the program requirements. The inspector
evaluated the response to the corrective action requests to determine the licensee's
ability to identify, evaluate, and correct problems in accordance with the licensee
program requirements and
CFR 50 Appendix E. The
inspector reviewed the licensee's audit program requirements in Procedure
QV-109,
"Audit Process," Revision 9, the 2006 quality assurance audit, quality assurance
surveillances conducted in 2006 and 2007, and licensee self-assessments of
emergency preparedness. The inspector also reviewed other documents listed in the
attachment to this report.The inspector completed one inspection sample. b.FindingsNo findings of significance were identified.1EP6Exercise Evaluation a.Inspection ScopeFor the exercise below, the inspectors: (1) observed the evolution to identify anyweaknesses and deficiencies in classification, notification, and Protective Action
Requirements development activities; and (2) reviewed the identified weaknesses and
deficiencies against licensee-identified findings to determine whether the licensee is
properly identifying deficiencies.*June 6, 2007 Force-On-Force Drill, Day 2
Documents reviewed by the inspectors included:
- AOP-0054, "Security Events," Revision 007*Technical support center lead controller notes
- Completed notification forms
- ENS-NS-215, "Conduct of Security Force Exercises and Drills," Revision 1
Enclosure-20-*EIP-2-001, "Classifications of Emergencies," Revision 14*EIP-2-006, "Notifications," Revision 32The inspectors completed one inspection sample.8.OTHER
- ACTIVI [[]]
- TIES [[]]
PI) Verification a.Inspection ScopeCornerstone: Emergency PreparednessThe inspector reviewed licensee evaluations for the three emergency preparednesscornerstone PIs of Drill and Exercise Performance, Emergency Response Organization
Participation, and Alert and Notification System Reliability, for the period July 1, 2006,
through March 31, 2007. The definitions and guidance of NEI 99-02, "Regulatory
Assessment Indicator Guideline," Revisions 2 through 4, and the licensee
LI-114, "Performance Indicator Process," Revision 2, were used to verify the accuracy
of the licensee's evaluations for each PI reported during the assessment period. The inspector reviewed a 100 percent sample of drill and exercise scenarios and licensedoperator simulator training sessions, notification forms, and attendance and critique records
associated with training sessions, drills, and exercises conducted during the verification
period. The inspector reviewed drill participation records for key emergency responders.
The inspector reviewed alert and notification system testing procedures, maintenance
records, and a 100 percent sample of siren test records. The inspector also reviewed other
documents listed in the Attachment to this report. The inspector completed one inspection sample. b.FindingsNo findings of significance were identified.4OA2Identification and Resolution of Problems a.Inspection Scope .1Routine Review of Identification and Resolution of ProblemsThe inspectors performed a daily screening of items entered into the licensee's
CRs and WOs and attending corrective action
review and work control meetings. The inspectors: (1) verified that equipment, human
performance, and program issues were being identified by the licensee at an appropriate
threshold and that the issues were entered into the CAP; (2) verified that corrective actions
were commensurate with the significance of the issue; and (3) identified conditions that
might warrant additional follow-up through other baseline inspection procedures.
Enclosure-21-The inspectors completed one inspection sample. .2Semiannual Trend ReviewThe inspectors completed a semiannual trend review of repetitive or closely related issuesthat were documented in corrective maintenance documents, metrics, and trend reports to
identify trends that might indicate the existence of more safety significant issues. The
inspectors review consisted of the six month period of July - December 2006. When
warranted, some of the samples expanded beyond those dates to fully assess the issue.
The inspectors also reviewed CAP items associated with work control. The inspectors
compared and contrasted their results with the results contained in the licensee's quarterly
trend reports. Corrective actions associated with a sample of the issues identified in the
licensee's trend report were reviewed for adequacy. Documents reviewed by the inspectors
included:
CAP Search results on terms "KW-Vendor" and "KW- Planning," executed on March 23, 2007The inspectors completed one inspection sample. .3Annual Sample ReviewThe inspector selected 13 CRs for detailed review. The reports were reviewed to ensurethat the full extent of the issues were identified, an appropriate evaluation was performed,
and appropriate corrective actions were specified and prioritized. The inspectors evaluated
the
EN-LI-102, "Corrective Action Process."The inspector completed one inspection sample. b. Findings and ObservationsThere were no findings identified associated with the review of licensee corrective actions inthat the full extent of issues were identified and the licensee identified appropriate corrective
actions; however, the inspector identified a developing trend in that 7 of 13 CRs were closed
prior to completing the assigned corrective actions. The inspector determined that the
corrective actions had been appropriately completed in all cases.
Enclosure-22-4OA3Event Followup .1Missing scram discharge instrument volume vent plugIntroduction. A Green self-revealing
TS 5.4.1.a was identified involving the failure tofollow a surveillance procedure for scram discharge instrument volume water level channel
calibration. Specifically, a vent plug was not replaced following surveillance testing. As a
result, on May 4, 2007, following a reactor scram, reactor coolant sprayed out of the scram
discharge instrument volume (SDIV) and contaminated some accessible portions of the
containment building causing three inadvertent personnel contaminations. Description. On May 4, the reactor was manually scrammed when a main transformercooling system failed. Following the scram, licensee non-destructive examination
inspectors performed post-scram inspections of the hydraulic control unit piping. When
they completed the inspection while processing through personnel contamination monitors
they were found to be contaminated. The licensee investigation found that a vent plug was
not installed on a vent connection on the west side
- SD [[]]
IV as required resulting in leakage of
water following the scram. The missing vent plug resulted in an opening in the
- SD [[]]
IV to
become part of the RCS pressure boundary. Reactor coolant sprayed through the vent
opening in the
- SD [[]]
IV until the scram was reset. The operators reset the scram which
isolated the
- SD [[]]
- IV to atmospheric conditions. The previous documented manipulation of that vent was on February 9, 2007, during theperformance of
RPS-Scram Discharge Volume Water Level - High Channel
Calibration Test and Logic System Functional Test (C11-LTN012B; C11-N601B)." The
inspectors determined most plausible cause of the vent plug not being installed was that
during the performance of STP-500-4203 the technicians failed to reinstall the plug as
required by the surveillance procedure. Specifically, procedure STP-500-4203, Section 7.3,
"Restoration," Revision 12, states, "Reinstall vent plugs."Analysis. The finding was more than minor because it was associated with the initiatingevent cornerstone attribute of equipment performance and affected the cornerstone
objective to limit the likelihood of those events that upset plant stability and challenge critical
safety functions during power operations. A Phase 2 estimation was required, asdetermined by the Manual Chapter 0609, Appendix A, Phase 1 Worksheet, "SDP Phase 1Screening Worksheet for Initiating Events, Mitigation Systems, and Barriers Cornerstones,"because the associated performance deficiency resulted in a reactor coolant leak greaterthan the Technical Specification limit for identified reactor coolant system leakage. Usingthe plant-specific Phase 2 risk-informed notebook, this violation was determined to havevery low safety significance because the violation only increased the likelihood of a small-break loss of coolant accident by a very small amount and mitigation capability wasunaffected. The cause of the finding was related to the human performance crosscuttingcomponent of work practices because neither self nor peer checking actions identified the
failure to replace the vent plug (H.4(a)).
Enclosure-23-Enforcement. TS 5.4.1.a requires that written procedures be established, implemented, andmaintained covering the activities specified in Regulatory Guide 1.33, Revision 2,
Appendix A, dated February 1978. Regulatory Guide 1.33, Appendix A, section 9, requires
procedures for performing maintenance activities. Contrary to this, maintenance
technicians failed to implement
RPS-Scram Discharge Volume Water
Level - High Channel Calibration Test and Logic System Functional Test (C11-LTN012B;
C11-N601B)," that required reinstallation of the scram discharge instrument volume vent
plugs. Because the finding is of very low safety significance and has been entered into the
licensee's
VI.A of the Enforcement Policy: NCV 05000458/2007003-01, "Missing vent plug caused breach of scram dischargeinstrument volume." .2Reactor Recirculation Loop 'A' Flow Anomaly a.Inspection ScopeThe inspectors assessed the circumstances related to the separation of reactor recirculationsystem Loop A discharge gate valve disk from its stem. The inspectors reviewed the
actions taken by the licensee to control recirculation system loop flow mismatch, the overall
risk assessment and management during the subsequent forced outage, the adequacy of
contingencies implemented for high risk plant configurations, and the scope and conduct of
the maintenance on the recirculation loop discharge gate valves. In addition, the inspectors
developed a detailed sequence of events, reviewed the licensee's extent of condition
review, and evaluated pertinent industry operating experience and potential precursors to
the event, including the effectiveness of licensee actions taken in response to applicable
operating experience. b. Findings and ObservationsIntroduction. A Green self-revealing finding was identified involving the failure to implementvendor recommendations concerning vibration induced wear on the recirculation systemsuction and discharge gate valves. This deficiency resulted in the failure to identify and
implement timely actions prior to disk to stem failure of recirculation Pump A discharge gate
valve that occurred on May 21, 2007. Description. On May 21, 2007, reactor recirculation loop Train A flow unexpectedly loweredby 4,000 pounds mass per hour, without any change in the reactor recirculation flow control
valve Train A position or operator action. There was a corresponding drop in reactor power
from 100 percent to 96 percent. The licensee balanced flows between the two reactor
recirculation loops. The licensee held reactor power at 90 percent while they evaluated the
flow anomaly. The licensee concluded that the most likely cause was stem/disk separation
of recirculation Loop A discharge gate valve. On May 22, 2007, the reactor was shutdown
to further investigate the flow anomaly. The licensee conducted a problem analysis, prior to the shutdown, and concluded that thedisk had likely separated from the stem of recirculation discharge gate valve (RDGV)
Loop A, B33-MOVF067A, and that disk partially blocked flow through recirculation Loop A,
Enclosure-24-producing the indications received on May 21, 2007. Upon disassembly of B33-MOVF067A, the licensee confirmed disk to stem separation of the valve. The failure
mechanism was due to turbulent flow induced vibrations resulting in wear of the valve stem,
upper wedge threads, and wedge pin. The licensee replaced the disk and stem assembly in
both B33-MOVF067A and B. The licensee's root cause investigation team determined that several opportunities toprevent the unexpected failure were missed. It had been known as early as 1988 that there
was the possibility of
- RD [[]]
GV damage due to turbulent flow. An important missed opportunity
occurred in 1998 when the licensee failed to implement vendor recommendations. In 1998,
the licensee stated that system engineers would implement vendor recommendations to
monitor the performance of the recirculation loop suction and discharge gate valves by
periodically checking vibration, flow, and checking the loose parts monitoring system for
abnormal noise patterns. The licensee determined these recommendations were not
effectively implemented resulting in the failure to identify the degrading condition prior to the
failure experienced on May 21, 2007. Analysis. The performance deficiency associated with this finding involved the licensee'sfailure to implement vendor recommendations to monitor the performance of the
recirculation loop suction and discharge gate valves. The finding was more than minor
because it was associated with the initiating events cornerstone attribute of equipment
performance and affected the associated cornerstone objective to limit the likelihood of
those events that upset plant stability and challenge critical safety functions during
shutdown and power operations. Using the Manual Chapter 0609, "SignificanceDetermination Process," Phase 1 Worksheet, the finding was determined to have very low
safety significance because the finding did not contribute to the likelihood that mitigating
equipment or functions would not be available following a reactor trip. This issue was
entered into the licensee's
- FIN 05000458/2007003-02,"Failure to Implement Vendor Recommendations." .3Load Line Analysis Limit ExceededIntroduction. A Green self-revealing
TS 5.4.1.a was identified involving the failure tofollow procedure resulting in an average power range monitor rod block. Description. On April 26, 2007, during power ascension the reactor engineer noted thatreactor power, calculated by the heat balance, did not rise as fast as predicted. The reactor
engineer failed to determine that the feedwater flow and temperature input data to the heat
balance was not updating; therefore, the reactor power level calculated by the heat balance
program was inaccurate. The reactor engineer was monitoring core parameters during control rod withdrawal, andnoted that reactor power indicated 75 percent instead of the expected 77-78 percent. He
also noted effective multiplication factor (Keff) and the rod-line was indicated differently than
expected; however, the thermal limits and margin to preconditioning were consistent with
the indicated power level. He discussed these observations with another reactor engineer
Enclosure-25-and concluded the Keff change was curious but not an indication of further problems thatneeded to be investigated. The control room supervisor and reactor engineer discussed the
difference between expected conditions and indicated conditions. Control rod pull sheets
were discussed and approved for implementation by the reactor engineer. The control
room supervisor ordered rod withdrawal to continue power ascension. During the
subsequent withdrawal of control rods an average power range monitor rod block stopped
the rod withdrawal. Following this automatic safety feature stopping the withdrawal of
control rods the reactor engineer identified that the heat balance was inaccurate and
requested that the control room supervisor halt the power ascension.The inspectors noted that the licensee evaluated the safety significance in consultation withthe fuel vendor. They reached the conclusion that no thermal limits or preconditioning limits
were exceeded therefore no potential for fuel damage occurred. The inspectors reviewed the licensee's root cause analysis report, personnel statements, and discussed the issue with reactor engineers and station management. The inspectors
reviewed reactor engineering Instruction 08, "Reactor Engineering Standards and
Expectations," Revision 09, which provided guidelines and department expectations for
reactor engineering personnel such that activities are carried out in an effective and
consistent manner. The inspectors noted that the licensee's investigation team determinedthat the root cause of the load line excursion was that the reactor engineering
Instruction 08, "Reactor Engineering Standards and Expectations," Revision 09., was not
followed correctly.Reactor engineering Instruction 08, "Reactor Engineering Standards and Expectations,"Revision 09, requires that when unexpected conditions arise (e.g., significantly higher/lower
rodlines than planned, unplanned or unanticipated core parameter changes, etc.) put the
reactor in a safe condition and evaluate the condition so that it is fully understood before
proceeding. Contrary to this, when the anomaly presented itself and the actual power and
Keff deviated from the predicted power and Keff, the reactor engineer did not investigate
thoroughly enough to fully understand the condition. He proceeded forward with further rod
withdrawals to achieve desired load line and did not recognize that he was in a position of
uncertainty. The result was an average power range monitor rod block and the load line
analysis limit was exceeded by 2.4 percent for 15 minutes at 80 percent power. The inspectors concluded that the combined failures of self checking and peer checkingdemonstrated a lack of engineering rigor and resulted in the failure to conclude the heat
balance was inaccurate in time to prevent the load line excursion event.Analysis. The performance deficiency associated with this finding involved the licensee'sfailure to comply with the requirements of reactor engineering Instruction 08, "Reactor
Engineering Standards and Expectations," Revision 09. The finding was more than minor
because it was associated with the barrier integrity cornerstone attribute of configuration
control and it affected the cornerstone objective to provide reasonable assurance that
physical design barriers, such as fuel cladding, protect the public from radio-nuclide
releases caused by accidents or events. Using Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheet, the finding was determined to have a very low
safety significance because it did not have the potential to affect the integrity of the reactor
coolant system barrier.
Enclosure-26-The cause of this finding is related to the human performance crosscutting component ofwork practices because neither self nor peer checking actions prevented the automatic rod
withdrawal block (H.4(a)).Enforcement. TS 5.4.1.a requires that written procedures be established, implemented, andmaintained covering the activities specified in Regulatory Guide 1.33, Revision 2,
Appendix A, dated February 1978. Regulatory Guide 1.33, Appendix A, section 2.b,
requires that procedures for power operation and process monitoring be written and
implemented. Contrary to this requirement, the requirements of reactor engineering
Instruction 08, "Reactor Engineering Standards and Expectations," Revision 09, were not
implemented. Specifically, on April 26, 2007, following unexpected conditions during power
ascension the reactor was not placed in a safe condition and the condition evaluated and
understood before proceeding. This deficiency resulted in exceeding the load line analysis
limit and actuation of a rod block protection feature during control rod withdrawal. Because
the finding is of very low safety significance and has been entered into the licensee's
CR-RBS-2007-01691, this violation is being treated as an
NRC Enforcement Policy: NCV 05000458/2007003-03,
"Failure to Follow Instructions Resulted in Exceeding Load Line Analysis Limit." .4Inadequate Maintenance InstructionsIntroduction. The inspectors identified a Green finding involving the failure to provideadequate instructions in a
WO failed to provide instructions to safely
remove the manual actuator from feedwater system isolation valve FWS-V1 while it was
subjected to the high energy conditions of the feedwater system normal operating pressure
and temperature. Description. On June 10, 2007, while attempting to put a third feedwater regulating valve inservice during power ascension following forced outage 07-03, the operators were unable to
open manual isolation Valve
WO 00113850-06 for
mechanical maintenance technicians to open FWS-V1 while it was subjected to feedwater
system normal operating pressure and temperature. WO 00113850-06 provided
instructions to: (1) remove the manual actuator; (2) install a stem lifting tool; (3) open
FWS-V1; (4) rebuild the manual actuator; (5) remove the lifting tool and; (6) reinstall the
manual actuator. The inspectors noted the WO failed to provide the instructions necessary
to restrain
- FWS -V1 stem and prevent unexpected valve stem movement or ejection.On June 10, 2007, while removing the manual actuator from
FWS-V1, the mechanicsobserved that as they loosened the eight actuator mounting bolts the stem was moving out
of the valve body on its own. FWS-V1 stem had moved out approximately one-quarter inch.
The mechanics stopped and asked for and received permission to open the valve at that
time because they no longer needed to remove the damaged manual actuator and install
the stem lifting tool prior to opening FWS-V1. The mechanics removed four of the eight actuator mounting bolts and replaced them withlong threaded rods. Next, the mechanics began manipulating the remaining four actuator
mounting bolts and the four long threaded rods to allow the valve stem to travel out of the
valve body. The inspectors noted that these steps were not in the original WO instructions.
Enclosure-27-By the time the valve stem had traveled three inches out of the valve body, the mechanicsreceived instructions to stop the job so that the work activity could be re-evaluated. The
FWS-V1, remove and repair thedamaged manual actuator, reinstall the actuator, and open FWS-V1 manually with that
actuator. These activities were successfully implemented.The inspectors interviewed the mechanics and found that the prejob brief did not mentionthe fact that FWS-V1 was at full system pressure and temperature of approximately
1,100 psig and 350F. The prejob brief also did not cover operating experience associatedwith valve stem ejection accidents. The mechanics stated that they were not aware those
conditions existed until the inspectors informed them of the conditions during the interview.
The inspectors concluded that even though the mechanics did not recognize that a valve
stem ejection accident was possible on this job, their actions prevented what could have
been a valve stem ejection accident. Analysis. The performance deficiency associated with this finding involved inadequatemaintenance instructions for opening feedwater regulating Valve A isolation valve, FWS-V1.
The finding was more than minor because it could become a more significant safety
concern if left uncorrected. Using the Manual Chapter 0609, "Significance DeterminationProcess," Phase 1 Worksheet, the finding was determined to have very low safety
significance because the deficiency did not contribute to both the likelihood of a reactor trip
and the likelihood that mitigation equipment or functions would not be available. This issue
was entered into the licensee's
CR-RBS-2007-02576. The cause of this finding was related to the human performance crosscutting component ofresources in that the licensee did not ensure a complete and accurate work package was
available prior to the start of the job (H.2(c)).Enforcement. No violation of
NCVs related to crosscutting area of humanperformance:*The finding was associated with the human performance crosscuttingcomponent of resources in that the licensee did not ensure a complete and
accurate work package was available prior to the start of the job (H.2(c))*One NCV was associated with the human performance crosscutting componentof work practices in that neither self or peer checking actions prevented an
automatic rod withdrawal block (H.4(a))*One NCV was associated with the human performance crosscutting componentof work practices in that neither self or peer checking actions identified a failure
to reinstall a vent plug (H.4(a))
Enclosure-28-4OA6Management MeetingsOn April 20, 2007, the inspectors presented the safety evaluation and permanent plantmodifications inspection results to Mr. J. Venable, Senior Vice President, and other
members of licensee management who acknowledged those results. No proprietary
information was included in this report.On May 18, 2007, the inspector presented the emergency preparedness inspection resultsto Mr. E. Olson, General Manager, Plant Operations, and other members of licensee
management who acknowledged the findings. The inspector confirmed that proprietary
information was not retained following the inspection.On July 9, 2007, the inspectors presented the integrated baseline inspection results to Mr. J. Venable, Senior Vice President, and other members of licensee management who
acknowledged the findings. The inspector confirmed that proprietary information was not
retained following the inspection.4OA7Licensee-Identified ViolationsThe following violation of very low safety significance (Green) was identified by the licenseeand is a violation of
VI of the
CFR Part 50.47(b)(2) states, ". . . adequate staffing to provide initial facility accidentresponse in key functional areas is maintained at all times. . . ."
CFR Part 50.47(b)(15) states, "Radiological emergency response training is provided
to those who may be called on to assist in an emergency." Contrary to the above, one
chemistry technician whose emergency response organization qualifications had expired
stood 11 watches as the required on-shift dose assessor between January 15 and
August 5, 2006. Although the licensee's on-shift staffing process allowed more than two
shifts during a 30-day period to go below emergency plan requirements, this
performance deficiency has been evaluated as being of low safety significance (Green)
because the finding was not a functional failure of planning standard 50.47(b)(2), in that,
the technician was present and may have been capable of performing their required
emergency plan function, and other trained licensee personnel not usually assigned
dose assessment responsibilities were present and could have assisted if necessary.
This issue was identified in the licensee's
- SUPPLE [[]]
- MENTAL [[]]
- INFORM [[]]
- INFORM [[]]
- POINTS [[]]
- OF [[]]
- CONTAC [[]]
TLicensee PersonnelL. Ballard, Manager, Quality ProgramsC. Bush, Manager, Outage
M. Chase, Manager, Training and Development
J. Clark, Assistant Operations Manager - Training
C. Forpahl, Manager, Corrective Action Program
B. Heath, Acting Superintendent, Chemistry
K. Higginbotham, Assistant Operations Manager - Shift
B. Houston, Manager, Radiation Protection
A. James, Superintendent, Plant Security
N. Johnson, Manager, Engineering Programs & Components
J. Laque, Manager, Plant Maintenance
J. Leavines, Manager, Emergency Planning
D. Lorfing, Manager, Licensing
J. Maher, Superintendent, Reactor Engineering
W. Mashburn, Manager, Design Engineering
B. Matherne, Manager, Planning and Scheduling/Outage
J. Miller, Manager, Operations
E. Olson, General Manager - Plant Operations
J. Roberts, Director, Nuclear Safety Assurance
P. Russell, Manager, System Engineering
- LIST [[]]
- OF [[]]
- ITEMS [[]]
- AND [[]]
DISCUSSEDOpened and Closed05000458/2007003-01NCVFailure to Install Scram Discharge Instrument Volume VentPlug05000458/2007003-02FINFailure to Implement Vendor Recommendations05000458/2007003-03NCVFailure to Follow Instructions Resulted in Exceeding LoadLine Analysis Limit05000458/2007003-04FINInadequate Work Instructions
AttachmentA-2LIST
- OF [[]]
- REVIEW [[]]
- EDT he following documents were selected and reviewed by the inspectors to accomplish theobjectives and scope of the inspection and to support any findings:Section 1R02: Evaluation of Changes, Tests, or Experiments10
- EC -0000000252Continuous Backfill/Flush on E31-PDTN084A/BTransmitter0ER-RB-2006-0250Add time delay relay to standby service water initiationlogic0ER-RB-2006-0111Removal of
- PS 44A(B) input to control roomannunciator0ER-RB-2005-0350Delete Condensate Filter Thermal Relief Valves0ER-RB-2004-0131Standby 480V Load Centers, Division I & II0
- RB -2004-0210Fabrication and Installation of vented steel floor plugsfor reactor water cleanup system demineralizer cubicles010
- PNL 2D3, Breakers 7 through 15 withGround Fault Interrupting Breakers0ER-RB-2004-0466Provide Welded Patch Details for
- RB -2003-0237Evaluate the removal of by-pass valve in gland steamexhaust condenser0ER-RB-2002-0509Isolation valves for generator core monitor0ER-RB-2002-0342Minor mod required for WTH0
RB-2002-0509Isolation valves for generator core monitor0
AOP-0016Loss of Standby Service Water14
AttachmentA-3Applicability DeterminationsNumberTitleRevisionER-RB-2005-0345Replacement valves for N64-VF004A&B0ER-RB-2005-0346Replacement valve for
SOP-0079R16PR-17SOP-0079, Reactor Protection System17
- RBS [[-2005-032611R04: Equipment AlignmentApplicability DeterminationsNumberTitleRevisionSOP-0031Residual Heat Removal301OSP-0017Normal Control Board Lineups for SafetyRelated Systems301OSP-0037Shutdown Operations Protection Plan (SOPP)16STP-000-0702Primary Containment Shutdown Verification14B]]
DRA2(171' Airlock)May 31,2007SOP-0042Standby Service Water System026
SOP-0053Standby Diesel Generator and Auxiliaries304
AttachmentA-4Section 1R17B: Permanent Plant ModificationsEngineering ChangesNumberTitleRevisionER-RB-1999-0161Removing Support to Inspect the Pipe Under the SupportCollar0ER-RB-1999-0728Limitorque Actuator to Increase Torque Output0ER-RB-1999-0794Scheme to allow the use of normal station transformers0
- RB -2004-0367Replace breakers 7 through 15 with ground faultinterrupting breakers0ER-RB-2005-0087Perform design to reinstall original transformer as
- DC -112Engineering Change Request and Project InitiationProcess0EN-DC-114Project Management3EN-DC-115Engineering Change Development2
DC-115Engineering Request Response Development10
FHP-0003Refuel Platform Operation Procedure20
Spec. No. 210.502Field Application of Protective Coatings InsideContainment3
AttachmentA-5DrawingsNumberTitleRevisionSK-EC 252Panel H22-P0040PID-25-01GSystem 051 Reference Leg Backfill System2
ASystem 209 Reactor Core Isolation Cooling42
05-1678Jib Crane
R-STM-118Service Water SystemCondition ReportsCR-RBS-2005-01732CR-RBS-2005-02003
- RBS -2005-03255MiscellaneousNumberTitleRevision/DateLBDC 09.01-091Dry Fuel Storage System ConsiderationsNov.
- FS [[]]
RE: Deletion of Shield Building Annulus Mixing
System Technical SpecificationsOct. 2004RBG-46183License Amendment Request Deletion of Technical Specification 3.6.4.4 Shield
Building Annulus Mixing System; and Revision of
Main Steam Isolation Valve Surveillance
Requirement
RBG-46222Supplement to Amendment Request Deletion ofTechnical Specification 3.6.4.4 Shield Building
Annulus Mixing System and Revision of Main Steam
Isolation Valve Surveillance Requirement SR 3.6.1.3.10Feb. 2004RBG-46303Supplement to Amendment Request Deletion ofTechnical Specification 3.6.4.4 Shield Building
Annulus Mixing System and Revision of Main Steam
Isolation Valve Surveillance Requirement SR 3.6.1.3.10Aug. 2004
AttachmentA-6SDC-309River bend System Design Criteria Standby DieselGenerator Division I and II, 309
Diesel Generator Building Ventilation, 4053Section 1R20: Refueling and Other Outage ActivitiesNumberDescriptionRevisionOSP-0034Control of Obstructions for PrimaryContainment/Fuel Building Operability3OSP-0033Operations with a Potential to Drain theReactor Vessel/Cavity16OSP-0037Shutdown Operations Protection Plan
RBS-2007-02113Recirculation Loop A flow decrease/Powerdecrease to 95 percent without operator
actionMay 27,
- GE [[]]
CFR 50.59 Evaluation for installation ofjet pump plugsGOP-3Scram Recovery19
MOVF067A,Recirc Pump A Disch VLV - Maintenance0Assembly Drawing 94-1357020X16X20-90M Venturi Welding EndsOutside Screw & Yoke 316 Stainless Steel
Gate Valve with Smb-1 Limitorque Valve
Control Discharge ValveK
AttachmentA-7IPTE Briefing SheetsSenior Managerno date orrevisionPrimavera computer printoutsSystem "FO0703
- EC -1541 to Controlling Documentno date orrevisionEngineering P & I Diagram,PID-25-01CReactor Recirculation26Licensing Basis DocumentChange Request for
- US [[]]
- AR [[5.4.1.3Reactor Recirculation System DescriptionMay 28, 2007Contingency Action Plan (CAP)Recirculation Pump discharge Valveno date orrevisionPNO-IV-07-005Preliminary Notice of Event or UnusualOccurrenceML071430449Operator Logsevery shiftWO 112116Transport plan for B33-MOVF0067A/BUndated]]
EP3: Emergency Response Organization AugmentationEIP-2-016, "Operations Support Center," Revision 23EIP-2-018, "Technical Support Center," Revision 29
EIP-2-020, "Emergency Operations Facility," Revision 28
EPP-2-202, "Emergency Response Organization," Revision 11
EPP-2-502, "Emergency Communications Equipment Testing," Revision 22Pager Test Checklists for Drills Conducted2005 - November 112006 - March 9, June 13, September 11, November 6
2007 - March 20Section
EIP-2-101, "Periodic Review of the Emergency Plan," Revision 21Procedure EIP-2-102, "Training, Drills, and Exercises," Revision 25
Procedure
QV-109, "Audit Process," Revision 9
AttachmentA-8Procedure
- EPP -2-201, "River Bend Station Emergency Preparedness Organization and Responsibilities," Revision 19Audit
QAS-2006-RBS-008, "Review of the Plant Paging System," October 21
through November 3,
QS-2007-RBS-005, June 2006 through April 2007Emergency Planning Program Assessment, RLO-2006-00001
River Bend Station Emergency Preparedness Corporate Assessment, June 5-6, 2006
Emergency Planning Program Assessment,
RLO-2007-00038 CA 00001
Standing Order #196, "Interim Actions for Sensitivity to Systems with Risk Impact and
Diagnosis Actions," Revision 3Training Evaluation Action Request 2007-14
Drills and Exercises Conducted2005 - October 182006 - March 15, May 23, June 20, August 16, October 3
2007 - February 20Condition Reports 2006-011412006-01486
2006-02605
2006-027302006-028372006-02921
2006-03003
2006-032642006-035432006-03599
2006-042702006-043482006-04645
2007-001102007-020202007-02023
2007-02051Section
PI) VerificationEIP-2-001, "Classification of Emergencies," Revisions 14 to 16EIP-2-006, "Notifications," Revisions 32, 33
EIP-2-007, "Protective Action Recommendations," Revision 21Station Drill schedules for 2005, 2006, and 2007
Miscellaneous DocumentsRiver Bend Station Emergency Plan, Revision 31
AttachmentA-9LIST
- OF [[]]
- LE [[]]
- LO [[]]
CAloss of coolant accident
- NE [[]]
- NR [[]]
CU.S. Nuclear Regulatory Commission
PIPerformance Indicators
- RD [[]]
- SD [[]]
IVscram discharge instrument volume
SSCstructures, systems, and components
STPsurveillance test procedure
- USA [[]]
RUpdated Safety Analysis Report