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{{#Wiki_filter:February 13, | {{#Wiki_filter:February 13, 2006 | ||
Paul D. Hinnenkamp | |||
Vice President - Operations | |||
Entergy Operations, Inc. | Entergy Operations, Inc. | ||
River Bend Station | River Bend Station | ||
5485 US Highway 61N | 5485 US Highway 61N | ||
St. Francisville, Louisiana | St. Francisville, Louisiana 70775 | ||
On December 31, 2005, the U.S. Nuclear Regulatory Commission (NRC) completed | SUBJECT: RIVER BEND STATION - NRC INTEGRATED INSPECTION | ||
January 4, 2006.The inspection examined activities conducted under your license as they relate to safety | REPORT 05000458/2005005 | ||
Dear Mr. Hinnenkamp: | |||
On December 31, 2005, the U.S. Nuclear Regulatory Commission (NRC) completed an | |||
inspection at your River Bend Station. The enclosed integrated inspection report documents | |||
the inspection findings which were discussed with you and other members of your staff on | |||
January 4, 2006. | |||
The inspection examined activities conducted under your license as they relate to safety and | |||
compliance with the Commissions rules and regulations and with the conditions of your license. | |||
The inspectors reviewed selected procedures and records, observed activities, and interviewed | The inspectors reviewed selected procedures and records, observed activities, and interviewed | ||
personnel.Based on the results of this inspection, two NRC identified findings and one self- | personnel. | ||
safety significance (Green). | Based on the results of this inspection, two NRC identified findings and one self-revealing | ||
finding were evaluated under the risk significance determination process as having very low | |||
safety significance (Green). The NRC has also determined that violations are associated with | |||
these findings. However, because these violations were of very low safety significance and | |||
were entered into your corrective action program, the NRC is treating these violations as | were entered into your corrective action program, the NRC is treating these violations as | ||
noncited violations, consistent with Section VI.A.1 of the | noncited violations, consistent with Section VI.A.1 of the NRCs Enforcement Policy. If you | ||
Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, | contest the violations or the significance of the violations, you should provide a response within | ||
Ryan Plaza Drive, Suite 400, Arlington, Texas 76011-4005; the Director, Office of Enforcement,U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC | 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 | |||
http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room). | copies to the Regional Administrator, U.S. Nuclear Regulatory Commission, Region IV, 611 | ||
Entergy Operations, Inc.-2-Should you have any questions concerning this inspection, we will be pleased to discuss | Ryan Plaza Drive, Suite 400, Arlington, Texas 76011-4005; the Director, Office of Enforcement, | ||
Division of Reactor | U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident | ||
Inspector at the River Bend Station facility. | |||
In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its | |||
enclosure, 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 | |||
NRCs document system (ADAMS). ADAMS is accessible from the NRC Website at | |||
http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room). | |||
Entergy Operations, Inc. -2- | |||
Should you have any questions concerning this inspection, we will be pleased to discuss them | |||
with you. | |||
Sincerely, | |||
/RA/ | |||
Kriss M. Kennedy, Chief | |||
Project Branch C | |||
Division of Reactor Projects | |||
Docket: 50-458 | |||
License: NPF-47 | |||
Enclosures: | |||
NRC Inspection Report 05000458/2005005 | |||
w/Attachment: Supplemental Information | |||
cc w/enclosure: | |||
Senior Vice President and | |||
Chief Operating Officer | |||
Entergy Operations, Inc. | Entergy Operations, Inc. | ||
P.O. Box 31995 | P.O. Box 31995 | ||
Jackson, MS | Jackson, MS 39286-1995 | ||
Vice President | |||
Operations Support | |||
Entergy Operations, Inc. | Entergy Operations, Inc. | ||
P.O. Box 31995 | P.O. Box 31995 | ||
Jackson, MS | Jackson, MS 39286-1995 | ||
General Manager | |||
Plant Operations | |||
Entergy Operations, Inc. | Entergy Operations, Inc. | ||
River Bend Station | River Bend Station | ||
5485 US Highway 61N | 5485 US Highway 61N | ||
St. Francisville, LA | St. Francisville, LA 70775 | ||
Director - Nuclear Safety | |||
Entergy Operations, Inc. | |||
River Bend Station | River Bend Station | ||
5485 US Highway 61N | 5485 US Highway 61N | ||
St. Francisville, LA | St. Francisville, LA 70775 | ||
Entergy Operations, Inc.-3-Wise, Carter, Child & Caraway | Entergy Operations, Inc. -3- | ||
Wise, Carter, Child & Caraway | |||
P.O. Box 651 | P.O. Box 651 | ||
Jackson, MS | Jackson, MS 39205 | ||
Washington, DC | Winston & Strawn LLP | ||
1700 K Street, N.W. | |||
Washington, DC 20006-3817 | |||
Manager - Licensing | |||
Entergy Operations, Inc. | |||
River Bend Station | River Bend Station | ||
5485 US Highway 61N | 5485 US Highway 61N | ||
St. Francisville, LA | St. Francisville, LA 70775 | ||
The Honorable Charles C. Foti, Jr. | |||
Attorney General | |||
Department of Justice | Department of Justice | ||
State of Louisiana | State of Louisiana | ||
P.O. Box 94005 | P.O. Box 94005 | ||
Baton Rouge, LA | Baton Rouge, LA 70804-9005 | ||
3456 Villa Rose | H. Anne Plettinger | ||
P.O. Box 1921 | 3456 Villa Rose Drive | ||
St. Francisville, LA | Baton Rouge, LA 70806 | ||
Burt Babers, President | |||
West Feliciana Parish Police Jury | |||
P.O. Box 1921 | |||
St. Francisville, LA 70775 | |||
Michael E. Henry, State Liaison Officer | |||
Department of Environmental Quality | |||
Permits Division | Permits Division | ||
P.O. Box 4313 | P.O. Box 4313 | ||
Baton Rouge, LA | Baton Rouge, LA 70821-4313 | ||
Brian Almon | |||
Public Utility Commission | |||
William B. Travis Building | William B. Travis Building | ||
P.O. Box 13326 | P.O. Box 13326 | ||
1701 North Congress Avenue | 1701 North Congress Avenue | ||
Austin, TX | Austin, TX 78711-3326 | ||
Entergy Operations, Inc.-4- | |||
Chemical and Nuclear Preparedness | Entergy Operations, Inc. -4- | ||
Chairperson | |||
Denton Field Office | |||
Chemical and Nuclear Preparedness | |||
and Protection Division | |||
Office of Infrastructure Protection | Office of Infrastructure Protection | ||
Preparedness Directorate | Preparedness Directorate | ||
Line 82: | Line 137: | ||
800 North Loop 288 | 800 North Loop 288 | ||
Federal Regional Center | Federal Regional Center | ||
Denton, TX | Denton, TX 76201-3698 | ||
Entergy Operations, Inc.-5-Electronic distribution by RIV:Regional Administrator (BSM1)DRP Director (ATH)DRS Director (DDC)DRS Deputy Director (RJC1)Senior Resident Inspector (PJA)Branch Chief, DRP/C (KMK)Senior Project Engineer, DRP/C (WCW)Team Leader, DRP/TSS (RLN1)RITS Coordinator (KEG)DRS STA (DAP)J. Dixon-Herrity, OEDO RIV Coordinator (JLD)ROPreports | |||
RBS Site Secretary (LGD)W. A. Maier, RSLO (WAM)SUNSI Review Completed: | Entergy Operations, Inc. -5- | ||
G | Electronic distribution by RIV: | ||
G | Regional Administrator (BSM1) | ||
DRP Director (ATH) | |||
DRS Director (DDC) | |||
Report:05000458/2005005 | DRS Deputy Director (RJC1) | ||
Licensee:Entergy Operations, Inc. | Senior Resident Inspector (PJA) | ||
Facility:River Bend | Branch Chief, DRP/C (KMK) | ||
Inspectors:P. Alter, Senior Resident Inspector, Project Branch | Senior Project Engineer, DRP/C (WCW) | ||
P. Elkmann, Emergency Preparedness Inspector, Operations Branch | Team Leader, DRP/TSS (RLN1) | ||
G. Johnston, Senior Operations Engineer, Operations Branch | RITS Coordinator (KEG) | ||
L. Ricketson, Senior Health Physicist, Plant Support | DRS STA (DAP) | ||
Division of Reactor Projects | J. Dixon-Herrity, OEDO RIV Coordinator (JLD) | ||
ROPreports | |||
REACTOR SAFETY......................................................... | RBS Site Secretary (LGD) | ||
....................................... | W. A. Maier, RSLO (WAM) | ||
............................................. | SUNSI Review Completed: _kmk_ ADAMS: : Yes G No Initials: __kmk__ | ||
.................................................. | : Publicly Available G Non-Publicly Available G Sensitive : Non-Sensitive | ||
................................... | R:\_REACTORS\_RB\2005\RB2005-05RP-PJA.wpd | ||
KEY POINTS OF CONTACT................................................A-1 | RIV:SRI:DRP/C RI:DRP/C C:DRS/OB C:DRS/EB1 C:DRS/PSB | ||
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED...........................A- | PJAlter MOMiller ATGody JClark MPShannon | ||
LIST OF ACRONYMS......................................................A-8 | T - KMKennedy E - KMKennedy /RA/ /RA/ /RA/ | ||
2/ /06 2/ /06 2/ /06 2/ /06 2/ /06 | |||
protection inspectors. | C:DRS/EB2 C:DRP/C | ||
LJSmith KMKennedy | |||
GDReplogle for /RA/ | |||
2/13/06 2/13/06 | |||
OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax | |||
U.S. NUCLEAR REGULATORY COMMISSION | |||
REGION IV | |||
Docket: 50-458 | |||
License: NPF-47 | |||
Report: 05000458/2005005 | |||
Licensee: Entergy Operations, Inc. | |||
Facility: River Bend Station | |||
Location: 5485 U.S. Highway 61 | |||
St. Francisville, Louisiana | |||
Dates: October 1 through December 31, 2005 | |||
Inspectors: P. Alter, Senior Resident Inspector, Project Branch C | |||
M. Miller, Resident Inspector, Project Branch C | |||
J. Keeton, Consultant, Region IV | |||
P. Elkmann, Emergency Preparedness Inspector, Operations Branch | |||
G. Johnston, Senior Operations Engineer, Operations Branch | |||
L. Ricketson, Senior Health Physicist, Plant Support Branch | |||
Approved By: Kriss M. Kennedy, Chief | |||
Project Branch C | |||
Division of Reactor Projects | |||
-1- Enclosure | |||
TABLE OF CONTENTS | |||
SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 | |||
REPORT DETAILS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 | |||
REACTOR SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 | |||
1R01 Adverse Weather Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 | |||
1R04 Equipment Alignment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 | |||
1R05 Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 | |||
1R11 Licensed Operator Requalification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 | |||
1R13 Maintenance Risk Assessments and Emergent Work Control . . . . . . . . . . . . . 10 | |||
1R14 Operator Performance During Non-routine Plant Evolutions . . . . . . . . . . . . . . 11 | |||
1R15 Operability Evaluations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 | |||
1R16 Operator Work-Arounds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 | |||
1R17 Permanent Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 | |||
1R19 Postmaintenance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 | |||
1R22 Surveillance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 | |||
1R23 Temporary Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 | |||
1EP2 Alert and Notification System Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 | |||
1EP3 Emergency Response Organization Augmentation . . . . . . . . . . . . . . . . . . . . . 20 | |||
1EP5 Correction of Emergency Preparedness Weaknesses and Deficiencies . . . . . 20 | |||
1EP6 Drill Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 | |||
RADIATION SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 | |||
2OS2 ALARA Planning and Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 | |||
OTHER ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 | |||
4OA1 Performance Indicator Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 | |||
4OA2 Identification and Resolution of Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 | |||
4OA3 Event Followup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 | |||
4OA6 Meetings, Including Exit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 | |||
SUPPLEMENTAL INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1 | |||
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-8 | |||
-2- Enclosure | |||
SUMMARY OF FINDINGS | |||
IR 05000458/2005005; 10/01/2005 - 12/31/2005; River Bend Station; Licensed Operator | |||
Requalification, Operator Performance During Nonroutine Plant Evolutions, Permanent Plant | |||
Modifications. | |||
The report covered a 3-month period of routine baseline inspections by resident inspectors and | |||
announced baseline inspections by regional emergency planning, operations, and radiation | |||
protection inspectors. Three Green noncited violations were identified. The significance of | |||
most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual | most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual | ||
Chapter 0609, | 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 | determination process does not apply may be Green or be assigned a severity level after NRC | ||
management review. | management review. The NRCs program for overseeing the safe operation of commercial | ||
determining that jet pump loop flow mismatch was greater than 5 percent | nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 3, | ||
blown control power fuse, causing Flow Control Valve B to drift open. | dated July 2000. | ||
throttled closed Flow Control Valve A to maintain reactor power at 100 percent, resulting | A. NRC-Identified and Self-Revealing Findings | ||
in a jet pump loop flow mismatch of approximately 8.2 percent. | Cornerstone: Initiating Events | ||
existed for 4.5 hours. | * Green. The NRC identified a noncited violation of Technical Specification 3.4.1.A for the | ||
Condition Report CR-RBS-2006-00274. The finding was more than minor because, if left uncorrected, it would become a | licensees failure to shut down one reactor recirculation loop within 2 hours of | ||
the accident analysis for a loss of coolant accident resulting from a loop break. | determining that jet pump loop flow mismatch was greater than 5 percent while | ||
mismatch could result in core response that is more severe than assumed in the | operating at greater than 70 percent of rated core flow. On October 31, 2005, the | ||
accident analysis. | Reactor Recirculation Flow Control Valve B hydraulic power unit tripped because of a | ||
MC 0609, | blown control power fuse, causing Flow Control Valve B to drift open. Operators | ||
finding was determined to be of very low safety significance based on the short duration | throttled closed Flow Control Valve A to maintain reactor power at 100 percent, resulting | ||
of the flow mismatch, 4.5 hours, and the low likelihood of a loss of coolant accident | in a jet pump loop flow mismatch of approximately 8.2 percent. The flow mismatch | ||
during that time. | existed for 4.5 hours. The licensee entered this into their corrective action program as | ||
requirements (Section 1R14).Cornerstone: | Condition Report CR-RBS-2006-00274. | ||
*Green. | The finding was more than minor because, if left uncorrected, it would become a more | ||
III,Design Control, was identified for the | significant safety concern. Matched recirculation loop flows is an assumption used in | ||
conditions in the sizing calculation for the reactor core isolation cooling turbine exhaust | the accident analysis for a loss of coolant accident resulting from a loop break. A flow | ||
mismatch could result in core response that is more severe than assumed in the | |||
December 10, 2004, when the reactor core isolation cooling system was started | accident analysis. The significance of this finding could not be evaluated using | ||
feedwater, the turbine exhaust line filled with water from the suppression pool, | MC 0609, Significance Determination Process. Based on management review, the | ||
finding was determined to be of very low safety significance based on the short duration | |||
RBS-2005-00724 and reinstalled the turbine exhaust line check valve internals in | of the flow mismatch, 4.5 hours, and the low likelihood of a loss of coolant accident | ||
February 2005. The finding was more than minor because it was associated with the Mitigating | during that time. The cause of this finding is related to the crosscutting element of | ||
the availability and reliability of the reactor core isolation cooling system, a system | human performance in that operators failed to implement Technical Specification | ||
undesirable consequences. | requirements (Section 1R14). | ||
Process, | Cornerstone: Mitigating Systems | ||
significance because it represented a design deficiency that did not result in a loss of | * Green. A self-revealing noncited violation of 10 CFR Part 50, Appendix B, Criterion III, | ||
system function (Section 1R17).Cornerstone: | Design Control, was identified for the licensees failure to address the worst case | ||
*Green. | conditions in the sizing calculation for the reactor core isolation cooling turbine exhaust | ||
emergency action level. | -3- Enclosure | ||
Emergencies, | |||
primary coolant leak rate, relied solely on a computer generated leakrate report that | line vacuum breaker system as part of a plant modification to remove the internals of the | ||
would not be valid under all conditions. | reactor core isolation cooling turbine exhaust line check valve. As a result, on | ||
corrective action program as CR-RBS-2005-03078 and issued Standing Order 192, as | December 10, 2004, when the reactor core isolation cooling system was started and | ||
an interim corrective action, to provide additional criteria to determine whether a primary | subsequently shutdown on high reactor water level following a scram and loss of | ||
coolant leak rate Alert emergency action level declaration was required.The finding is more than minor because it is associated with the | feedwater, the turbine exhaust line filled with water from the suppression pool, causing | ||
objective to ensure the licensee is capable of implementing adequate measures to | the operators to consider the system unavailable and complicating their response to the | ||
protect the health and safety of the public in the event of a radiological emergency. | event. The licensee entered this finding into their corrective action program as CR- | ||
inadequate procedure could result in a failure to declare an Alert emergency | RBS-2005-00724 and reinstalled the turbine exhaust line check valve internals in | ||
classification when required. | February 2005. | ||
Preparedness Significance Determination Process, | The finding was more than minor because it was associated with the Mitigating Systems | ||
very low safety significance since it was a failure to comply with a regulatory | cornerstone attribute of Design Control and affected the cornerstone objective to ensure | ||
requirement associated with a risk-significant planning standard that did not result in the | the availability and reliability of the reactor core isolation cooling system, a system that | ||
loss or degradation of that risk-significant planning standard function (Section 1R11).B.Licensee-Identified Violations | responds to initiating events (loss of feedwater and station blackout), to prevent | ||
undesirable consequences. Using Manual Chapter 0609, Significance Determination | |||
Process, Phase 1 Worksheet, the finding was determined to have very low safety | |||
significance because it represented a design deficiency that did not result in a loss of | |||
100 percent power on October 2, 2005. | system function (Section 1R17). | ||
returned to 100 percent power on October 23, 2005. | Cornerstone: Emergency Preparedness | ||
* Green. The NRC identified a noncited violation of 10 CFR Part 50, Appendix E, | |||
Section IV. B., as a result of inadequate procedures for the implementation of an | |||
emergency action level. The criteria in Procedure EIP-2-001, Classification of | |||
Emergencies, Revision 12, for declaring an Alert emergency action level based on | |||
primary coolant leak rate, relied solely on a computer generated leakrate report that | |||
would not be valid under all conditions. The licensee entered this finding into their | |||
corrective action program as CR-RBS-2005-03078 and issued Standing Order 192, as | |||
an interim corrective action, to provide additional criteria to determine whether a primary | |||
coolant leak rate Alert emergency action level declaration was required. | |||
The finding is more than minor because it is associated with the Emergency | |||
Preparedness Cornerstone attribute of procedural quality and affects the cornerstone | |||
objective to ensure the licensee is capable of implementing adequate measures to | |||
protect the health and safety of the public in the event of a radiological emergency. The | |||
inadequate procedure could result in a failure to declare an Alert emergency | |||
classification when required. Using Manual Chapter 0609, Appendix B, Emergency | |||
Preparedness Significance Determination Process, this finding was determined to be of | |||
very low safety significance since it was a failure to comply with a regulatory | |||
requirement associated with a risk-significant planning standard that did not result in the | |||
loss or degradation of that risk-significant planning standard function (Section 1R11). | |||
B. Licensee-Identified Violations | |||
None. | |||
-4- Enclosure | |||
REPORT DETAILS | |||
Summary of Plant Status | |||
On October 1, 2005, reactor power was lowered to 70 percent to perform a rod sequence | |||
exchange and insert two control rods for planned maintenance. The reactor was returned to | |||
100 percent power on October 2, 2005. On October 21, 2005, reactor power was lowered to 63 | |||
percent to perform power suppression testing for a leaking fuel bundle. The reactor was | |||
returned to 100 percent power on October 23, 2005. On November 5, 2005, reactor power was | |||
lowered to 90 percent to adjust the control rod pattern and the reactor was returned to 100 | lowered to 90 percent to adjust the control rod pattern and the reactor was returned to 100 | ||
percent later that day. | percent later that day. On December 2, 2005, reactor power was lowered to 83 percent to | ||
insert three control rods for planned maintenance. | insert three control rods for planned maintenance. The reactor was returned to 100 percent | ||
power on December 3, 2005. | power on December 3, 2005. On December 9, 2005, reactor power was lowered to 58 percent | ||
to perform a control rod pattern adjustment and conduct turbine valve testing. | to perform a control rod pattern adjustment and conduct turbine valve testing. The reactor was | ||
returned to 100 percent power on December 11, 2005. | returned to 100 percent power on December 11, 2005. On December 17, 2005, reactor power | ||
was lowered to 62 percent to perform power suppression testing for a leaking fuel bundle. | was lowered to 62 percent to perform power suppression testing for a leaking fuel bundle. The | ||
reactor was returned to 100 percent on December 19, 2005, and remained at 100 percent for | reactor was returned to 100 percent on December 19, 2005, and remained at 100 percent for | ||
the remainder of the inspection period.1.REACTOR | the remainder of the inspection period. | ||
systems, and components will remain functional when challenged by cold | 1. REACTOR SAFETY | ||
heaters are operable and monitored; and (3) verified that the cold weather | Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency | ||
procedure. | Preparedness | ||
1R01 Adverse Weather Protection | |||
b. Inspection Scope | |||
Cold Weather Preparation | |||
During the week of December 5, 2005, the inspectors reviewed the licensees | |||
implementation of Operations Section Procedure OSP-0043, Freeze Protection and | |||
Temperature Maintenance, Revision 6, to protect mitigating systems from cold weather | |||
conditions. Specifically, the inspectors: (1) verified that risk-significant structures, | |||
systems, and components will remain functional when challenged by cold weather | |||
conditions; (2) verified that cold weather features such as heat tracing and space | |||
heaters are operable and monitored; and (3) verified that the cold weather procedures | |||
attachments were being completed for changing temperatures as required by the | |||
procedure. The inspectors completed one inspection sample. | |||
c. Findings | |||
No findings of significance were identified. | |||
-5- Enclosure | |||
1R04 Equipment Alignment | |||
1. Partial System Walkdowns | |||
a. Inspection Scope | |||
On October 25, 2005, the inspectors walked down residual heat removal Division II | On October 25, 2005, the inspectors walked down residual heat removal Division II | ||
while residual heat removal Division I was out of service for scheduled maintenance. | while residual heat removal Division I was out of service for scheduled maintenance. | ||
On October 26, 2005, the inspectors walked down the piping and valve lineup of the | On October 26, 2005, the inspectors walked down the piping and valve lineup of the | ||
condensate storage tank, including emergency core cooling system suction and | condensate storage tank, including emergency core cooling system suction and test | ||
alignments by comparing positions of valves, switches, and electrical power breakers to | return valves. In each case, the inspectors verified the correct valve and power | ||
alignments by comparing positions of valves, switches, and electrical power breakers to | |||
the system operating procedures (SOP) and piping and instrument drawings listed | |||
below and applicable sections of the Updated Safety Analysis Report (USAR). The | |||
inspectors completed two inspection samples. | |||
* SOP-0031, Residual Heat Removal System, Revision 46 | |||
* SOP-0008, Condensate Storage, Makeup and Transfer, Revision 16 | |||
* Piping and Instrument PID 04-03A, Condensate Storage, Makeup and | |||
Transfer, Revision 13 | |||
b. Findings | |||
No findings of significance were identified. | |||
2. Complete System Walkdown | |||
a. Inspection Scope | |||
The inspectors conducted a complete walkdown of the drywell and containment leak | |||
detection system during the week of June 26, 2005, during a drywell closeout inspection | |||
and continuing the week of November 20, 2005. The methods of inspection included | |||
field walkdown, in-office reviews, observation of system operation, and interviews of | |||
computer engineering, operations, training, and emergency planning personnel. The | |||
inspectors verified: (1) proper valve and control switch alignments, (2) computer | |||
program algorithm, (3) power supply lineup, (4) associated support system status, and | |||
(5) that alarms and indications in the main control room were as specified in the | |||
following documents: | |||
* SOP-0033, Drywell and Containment Leak Detection System, Revision 11 | |||
* USAR Section 5.2.5.1.1, Detection of Leakage within the Drywell | |||
* Technical Specifications (TS) Section 3.4.5, RCS Operational Leakage | |||
The inspectors also verified electrical power requirements, labeling, hangers and | |||
support installation, and associated support systems status. The walkdowns included | |||
-6- Enclosure | |||
evaluation of system piping and supports to ensure (1) piping and pipe supports did not | |||
show evidence of damage, (2) hangers were secure, and (3) component foundations | |||
were not degraded. The inspectors completed one inspection sample. | |||
b. Findings | |||
No findings of significance were identified. | |||
1R05 Fire Protection | |||
a. Inspection Scope | |||
The inspectors walked down accessible portions of the plant described below to assess: | |||
(1) the licensees control of transient combustible material and ignition sources; (2) fire | |||
detection and suppression capabilities; (3) manual firefighting equipment and capability; | |||
(4) the condition of passive fire protection features, such as, electrical raceway fire | |||
barrier systems, fire doors, and fire barrier penetrations; and (5) any related | |||
compensatory measures. The inspectors reviewed the Pre-Fire Plan/Strategy Book | |||
during the fire protection inspections. The areas inspected were: | |||
* Auxiliary building, 70-foot, RHR Pump B Room, fire Area AB-3, on October 11, | |||
2005 | |||
* Auxiliary building, 95-foot, HPCS piping area, fire Area AB-2/Z-2, on October 12, | |||
2005 | |||
* Auxiliary building, 95-foot, LPCS panel room, fire Area AB-6/Z33, on October 12, | |||
2005 | |||
* Control building, 116-foot, safety-related 125 Vdc switchgear room, fire | |||
Area C-24, on December 9, 2005 | |||
* Control building, 116-foot, safety-related Switchgear 1C room, fire Area C-22, on | |||
December 9, 2005 | |||
* Control building, 116-foot, safety-related ENB inverter Charger A room, fire | |||
Area C-18, on December 9, 2005 | |||
The inspectors completed six inspection samples. | |||
b. Findings | |||
No findings of significance were identified. | |||
-7- Enclosure | |||
1R11 Licensed Operator Requalification Program | |||
a. Inspection Scope | |||
.1 Annual Operating Examination Review | |||
Following the completion of the annual operating examination testing cycle, which ended | |||
the week of September 23, 2005, the inspectors reviewed the overall pass/fail results of | |||
the annual individual job performance measure operating tests and simulator operating | |||
tests administered by the licensee during the operator licensing requalification cycle. | |||
Eight separate crews participated in simulator operating tests and job performance | |||
measure operating tests, totaling 52 licensed operators. All of the crews tested passed | |||
the simulator portion of the annual operating test. Two of the 52 licensed operators | |||
failed the job performance measure portion and were successfully remediated. These | |||
results were compared to the thresholds established in MC 0609, Appendix I, Operator | |||
Requalification Human Performance Significance Determination Process. The | |||
inspector completed one inspection sample. | |||
.2 Resident Inspector Quarterly Review | |||
On November 15, 2005, the inspectors observed simulator training of an operating crew, | |||
as part of the operator requalification training program, to assess licensed operator | |||
performance and the training evaluators critique. The inspection included observation | |||
of high risk licensed operator actions, operator activities associated with the emergency | |||
plan, and lessons learned from industry and plant experiences. In addition, the | |||
inspectors compared simulator control panel configurations with the actual control room | |||
panels for consistency. The simulator examination scenario observed was RSMS-OPS- | |||
612, Loss of Vacuum/ATWS/Drywell Steam Leak - RPV Flooding, Revision 4. The | |||
inspectors completed one inspection sample. | |||
.3 Inadequate Emergency Event Classification Guidance | |||
On June 10, 2005, the inspectors observed operating crew performance in the simulator | |||
during annual requalification exam Scenario RSMS-OPS-509, SRV Tailpipe Steam | |||
Leak Inside The Drywell, Revision 3. The inspectors discussed crew actions and | |||
emergency planning requirements with the examination evaluators, training | |||
management, emergency planning coordinators, and operations management. The | |||
inspectors reviewed the following documents: | |||
* EIP-2-001, Classification of Emergencies, Revision 12 | |||
* USAR 5.2.5.1.1, Detection of Leakage within the Drywell | |||
* Vendor computer manual, VTD-A324-0109, Analog Devices MICROMAC-5000 | |||
Final Draft, Leak Rate Detection PLC Documentation, River Bend Station - | |||
Reactor Building Sump Systems, Revision 0 | |||
-8- Enclosure | |||
* Training Evaluation and Request, TEAR-RBS-2005-0477, Validating Leakage | |||
Report, issued August 23, 2005 | |||
* CR-RBS-2005-03078, Validating Leakage Report, initiated on August 26, 2005 | |||
* Standing Order Number 192, Drywell Leakage Greater Than 50 gpm EAL | |||
Guidance, Revision 0, issued November 3, 2005 | |||
b. Findings | |||
Introduction: The inspectors identified a Green NCV of 10 CFR Part 50, Appendix E, | |||
Section IV.B, for inadequate procedures for implementation of an Alert emergency | |||
action level (EAL). | |||
Description: On June 10 2005, the inspectors observed operating crew performance in | |||
the simulator during annual requalification exam Scenario RSMS-OPS-509, SRV | |||
Tailpipe Steam Leak Inside The Drywell, Revision 3. The inspectors noted that when | |||
the examination evaluators informed the team that the total drywell leakage report was | |||
84 gpm, the team declared an Alert based on that report. Procedure EIP-2-001, | |||
Classification of Emergencies, Revision 12, listed the criteria for an Alert EAL | |||
classification as Total drywell LEAKAGE greater than 50 gpm. | |||
Based on their observations in the simulator, the inspectors questioned the ability of the | |||
leakage computer installed in the plant to accurately calculate total drywell leakage | |||
under certain conditions. The inspectors analyzed the program run by the drywell | |||
leakage computer and determined: (1) the drywell leakage computer would not | |||
calculate total drywell leakage while a drywell sump pump was running; (2) computer | |||
reports of total drywell leakage printed while a drywell sump pump was running would be | |||
invalid; and (3) if a drywell high pressure or low reactor vessel level signal was present, | |||
the valves in the drywell sump pump discharge lines would close, causing the drywell | |||
sump pumps to run continuously, resulting in an invalid drywell total leakage report. The | |||
inspectors determined that the indication used by operators to determine if the criteria | |||
was met for declaring an Alert EAL due to total drywell leakage exceeding 50 gpm would | |||
not be valid under certain conditions. | |||
On August 23, 2005, the licensee initiated training evaluation action request TEAR- | |||
2005-0477 to evaluate this condition to determine what training actions were necessary. | |||
On August 26, 2005, the licensee initiated CR-RBS-2005-03078 that requested an | |||
alternate means of determining the primary coolant leak Alert EAL using main control | |||
room indications. The CR also requested additional training materials and classroom | |||
instruction to reinforce this change. | |||
On November 3, 2005, the licensee issued Standing Order 192 that provided additional | |||
criteria to be used to make the determination of whether a primary coolant leak rate | |||
Alert EAL declaration was required, without relying solely on the drywell leakage | |||
computer. The inspectors concluded that Standing Order 192 was an adequate interim | |||
compensatory measure until the licensee implemented permanent corrective actions. | |||
-9- Enclosure | |||
Analysis: The performance deficiency associated with this finding involved an | |||
inadequate procedural criteria for declaring an Alert EAL in the event that total drywell | |||
leakage exceeds 50 gpm under certain conditions. Specifically, computed drywell | |||
leakrate used by operators to determine if total drywell leakage exceeds 50 gpm may be | |||
invalid under certain conditions. The finding was more than minor because it is | |||
associated with the Emergency Preparedness Cornerstone attribute of procedural | |||
quality and affects the cornerstone objective to ensure the licensee is capable of | |||
implementing adequate measures to protect the health and safety of the public in the | |||
event of a radiological emergency. The inadequate procedure could result in a failure to | |||
declare an Alert emergency classification when required. Using Manual Chapter 0609, | |||
Appendix B, Emergency Preparedness Significance Determination Process, this | |||
finding was determined to be of very low safety significance since it was a failure to | |||
comply with a regulatory requirement associated with a risk-significant planning | |||
standard that did not result in the loss or degradation of that risk-significant planning | |||
standard function. | |||
Enforcement: The failure to provide adequate procedures for implementation of an EAL | |||
was a violation of 10 CFR Part 50, Appendix E, Section IV.B., which requires, in part, | |||
that the licensees emergency plan describe the means to be used for determining the | |||
impact of the release of radioactive materials including EALs. Because this finding was | |||
of very low safety significance and was entered into the licensees corrective action | |||
program as CR-RBS-2005-03078, this violation is being treated as an NCV, consistent | |||
with Section VI.A of the NRC Enforcement Policy: NCV 05000458/2005005-01, | |||
Inadequate procedure for implementation of an EAL. | |||
1R13 Maintenance Risk Assessments and Emergent Work Control | |||
a. Inspection Scope | |||
The inspectors reviewed selected maintenance activities to verify the performance of | |||
assessments of plant risk related to planned and emergent maintenance work activities. | |||
The inspectors verified: (1) the adequacy of the risk assessments and the accuracy and | |||
completeness of the information considered, (2) management of the resultant risk and | |||
implementation of work controls and risk management actions, and (3) effective control | |||
of emergent work, including prompt reassessment of resultant plant risk. The inspectors | |||
completed three inspection samples. | |||
.1 Risk Assessment and Management of Risk | |||
On a routine basis, the inspectors verified performance of risk assessments, in | |||
accordance with administrative Procedure ADM-096, Risk Management Program | |||
Implementation and On-Line Maintenance Risk Assessment, Revision 04, for planned | |||
maintenance activities and emergent work involving structures, systems, and | |||
components within the scope of the maintenance rule. Specific work activities evaluated | |||
included the following planned and emergent work: | |||
* October 23, 2005, Division I residual heat removal and standby service water | |||
equipment outage | |||
-10- Enclosure | |||
* November 28, 2005, Division III work week and station blackout diesel generator | |||
planned maintenance | |||
.2 Emergent Work Control | |||
During emergent work, the inspectors verified that the licensee took actions to minimize | |||
the probability of initiating events, maintained the functional capability of mitigating | |||
systems, and maintained barrier integrity. The inspectors also reviewed the emergent | |||
work activities to ensure the plant was not placed in an unacceptable configuration. The | |||
specific emergent work activity followed was the cleaning of high voltage insulators in | |||
the main transformer switchyard with a high pressure spray on October 7, 2005. | |||
b. Findings | |||
No findings of significance were identified. | |||
1R14 Operator Performance During Nonroutine Evolutions and Events | |||
c. Inspection Scope | |||
The inspectors completed the two inspection samples listed below. | |||
.1 Power Suppression Testing | |||
The inspectors observed portions of and reviewed control room records for power | |||
suppression testing conducted during the weekend of October 21, 2005. The inspectors | |||
reviewed the reactivity control plan, the prejob briefing given in the main control room at | |||
the beginning of the evolution and during control room operator and reactor engineer | |||
shift turnover. The inspectors also reviewed the results of the test with the reactor | |||
engineering representative and shift manager, including the recommendation to insert | |||
Control Rod 20-45 to suppress power in the vicinity of a potential leaking fuel bundle. | |||
Finally, the inspectors reviewed the postsuppression test off-gas pretreatment gaseous | |||
activity levels used to monitor the success of the suppression efforts. | |||
.2 Trip of Reactor Recirculation (RR) Flow Control Valve (FCV) Hydraulic Power | |||
Unit (HPU) | |||
On October 31, 2005, the inspectors observed operator response to a trip of RR FCV B | |||
HPU. As a result, RR FCV B began to drift open. The operators took action to limit or | |||
stop the gradual opening of RR FCV B. As RR FCV B continued to open, operators | |||
throttled closed RR FCV A to maintain reactor power less than 100 percent. These | |||
actions created an RR jet pump loop flow mismatch of greater than 5 percent requiring | |||
entry into TS Action 3.4.1.A. The inspectors reviewed the TS requirements for this | |||
condition and discussed the actions taken by the operators with the operations shift | |||
-11- Enclosure | |||
manager and members of plant management team present in the control room at the | |||
time. The following documents were reviewed by the inspectors as part of this | |||
inspection: | |||
C Main Control Room Logs, October 31, 2005 | |||
C CR-RBS-2005-03748, During Filter RCS-FLTR2B replacement, technicians | |||
bumped an electrical cable, causing a trip of the reactor recirculation flow control | |||
Valve B hydraulic power unit | |||
C W0 00075986, Replace grounded connection to Pressure Switch RCS-PDS90B | |||
C SOP-0003, Reactor Recirculation System, Revision 35 | |||
C TS limiting condition for operation (LCO) 3.4.1 and applicable Bases | |||
i. Findings | |||
Introduction: The inspectors identified a Green noncited violation of TS Action 3.4.1.A.1 | |||
for the licensees failure to restore compliance with LCO 3.4.1 or shut down one RR loop | |||
within 2 hours of determining that RR loop jet pump flow mismatch was greater than | |||
5 percent while operating at greater than 70 percent of rated core flow. | |||
Description: On October 31, 2005, at 2:54 p.m., the RR FCV B HPU tripped. As a | |||
result, RR FCV B began to drift open. The operators took action to limit or stop the | |||
gradual opening of RR FCV B. As RR FCV B continued to open, operators throttled | |||
closed RR FCV A to maintain reactor power less than 100 percent. | |||
At 3:06 p.m., the operators entered TS LCO Condition 3.4.1.A because the RR loop jet | |||
pump flow mismatch exceeded 5 percent with the plant operating at greater than 70 | |||
percent rated core flow. The highest flow mismatch was 8.2 percent. TS Action | |||
3.4.1.A.1 required the licensee to shut down one recirculation loop with 2 hours. | |||
The licensee issued a work request and began to troubleshoot the HPU trip. At the | |||
same time, operators requested that reactor engineers develop a reactivity control plan | |||
to insert control rods to lower reactor power. This would allow operators to reopen | |||
RR FCV A to reduce the RR jet pump loop flow mismatch to less than the required | |||
5 percent. | |||
At 4:24 p.m., the licensee determined that the cause for the HPU trip was a blown | |||
control power fuse. The fuse blew as a result of a grounded wire to a filter high | |||
differential pressure switch, which was bumped by maintenance technicians who were | |||
changing the filter cartridge. The inspectors asked the operators and licensee | |||
management if they intended to shut down one RR loop or perform the actions | |||
necessary to reduce the jet pump flow mismatch to less than 5 percent, as required by | |||
TS 3.4.1. The licensee responded that they did not want to maneuver the plant and | |||
change core conditions, which might exacerbate the existing condition of two leaking | |||
fuel bundles. | |||
-12- Enclosure | |||
At 5:06 p.m., the operators exited TS Action 3.4.1.A without shutting down one RR loop | |||
or reducing jet pump loop flow mismatch to less than 5 percent. Instead they entered | |||
TS Action 3.4.1.D.1, which required that the reactor be placed in Mode 3 in 12 hours. | |||
When asked, the operators and licensee management stated that they could commence | |||
a plant shutdown within the next 6 hours and still meet the requirement to be in Mode 3 | |||
in 12 hours. They also stated that at the 6-hour point, they would commence the | |||
the | |||
inspection:Main Control Room Logs, October 31, | |||
Valve B hydraulic power | |||
within 2 hours of determining that RR loop jet pump flow mismatch was greater than | |||
5 percent while operating at greater than 70 percent of rated core flow.Description: | |||
gradual opening of RR FCV B. | |||
closed RR FCV A to maintain reactor power less than 100 percent. | |||
3.4.1.A.1 required the licensee to shut down one recirculation loop with 2 hours.The licensee issued a work request and began to troubleshoot the HPU trip. | |||
to insert control rods to lower reactor power. | |||
RR FCV A to reduce the RR jet pump loop flow mismatch to less than the required | |||
5 percent. | |||
differential pressure switch, which was bumped by maintenance technicians who were | |||
changing the filter cartridge. | |||
management if they intended to shut down one RR loop or perform the actions | |||
necessary to reduce the jet pump flow mismatch to less than 5 percent, as required by | |||
TS 3.4.1. | |||
fuel bundles. | |||
TS Action 3.4.1.D.1, which required that the reactor be placed in Mode 3 in 12 hours. When asked, the operators and licensee management stated that they could | |||
shutdown with the reactivity control plan to reduce reactor power by inserting control | shutdown with the reactivity control plan to reduce reactor power by inserting control | ||
rods and open RR FCV A to reduce jet pump loop flow mismatch to less than 5 percent. | rods and open RR FCV A to reduce jet pump loop flow mismatch to less than 5 percent. | ||
If that was successful, they would then exit TS LCO 3.4.1.Subsequently, the repairs were completed to the pressure switch wire, the control | If that was successful, they would then exit TS LCO 3.4.1. | ||
the RR FCV B HPU was returned to service. | Subsequently, the repairs were completed to the pressure switch wire, the control power | ||
5 percent and the licensee exited TS LCO 3.4.1. at 7:36 p.m., 4.5 hours after entry | fuse was replaced, and RR FCV B HPU was restarted. Following a one-hour warmup, | ||
the RR FCV B HPU was returned to service. RR jet pump loop flow was reduced below | |||
5 percent and the licensee exited TS LCO 3.4.1. at 7:36 p.m., 4.5 hours after entry into | |||
TS LCO Condition 3.4.1.A. | |||
The inspectors determined that: (1) when the cause of the trip of RR FCV B HPU was | |||
determined to be the grounded pressure switch wire, the licensee knew that the time to | |||
make the repairs and return the HPU to service would exceed the 2-hour completion | |||
time of TS Action 3.4.1.A.1; and (2) the licensee was capable of restoring RR jet pump | time of TS Action 3.4.1.A.1; and (2) the licensee was capable of restoring RR jet pump | ||
loop flow mismatch to less than 5 percent or shutting down one RR loop within the | loop flow mismatch to less than 5 percent or shutting down one RR loop within the | ||
2-hour completion time of TS Action 3.4.1.A.1. Analysis: | 2-hour completion time of TS Action 3.4.1.A.1. | ||
it would become a more significant safety concern. | Analysis: The licensees failure to restore compliance with TS LCO 3.4.1 or complete | ||
the required action of TS 3.4.1.A.1 to shut down one RR loop within 2 hours was a | |||
performance deficiency. The finding was more than minor because, if left uncorrected, | |||
it would become a more significant safety concern. According to TS LCO 3.4.1 Bases, | |||
the operation of the RR pumps is an initial condition assumed for the design basis loss- | the operation of the RR pumps is an initial condition assumed for the design basis loss- | ||
of-coolant accident (LOCA). | of-coolant accident (LOCA). During a LOCA caused by a RR loop break, the intact RR | ||
loop is assumed to provide coolant flow during the first few seconds of the accident. | loop is assumed to provide coolant flow during the first few seconds of the accident. | ||
The initial core flow decrease is rapid because the RR pump in the broken loop ceases | The initial core flow decrease is rapid because the RR pump in the broken loop ceases | ||
to pump water through the vessel almost immediately. | to pump water through the vessel almost immediately. The pump in the intact loop | ||
coasts down more slowly. | coasts down more slowly. This pump coast down governs the core flow response for | ||
the next several seconds until the jet pump suctions are uncovered. | the next several seconds until the jet pump suctions are uncovered. The analyses | ||
assume that both RR loops are operating at the same flow prior to the LOCA. | assume that both RR loops are operating at the same flow prior to the LOCA. However, | ||
if the LOCA analysis is reviewed for an initial jet pump flow mismatch with the break | |||
assumed to be in the loop with the higher flow, the flow coast down and core response | assumed to be in the loop with the higher flow, the flow coast down and core response | ||
are potentially more severe, since the intact loop starts at a lower flow rate. The significance of this finding could not be evaluated using MC 0609, | are potentially more severe, since the intact loop starts at a lower flow rate. | ||
The significance of this finding could not be evaluated using MC 0609, Significance | |||
Determination Process. Based on management review, the finding was determined to | |||
be of very low safety significance based on the short duration of the flow mismatch, | be of very low safety significance based on the short duration of the flow mismatch, | ||
4.5 hours, and the low likelihood of a LOCA during that time. | 4.5 hours, and the low likelihood of a LOCA during that time. The cause of this finding | ||
is related to the | is related to the crosscutting element of human performance in that operators failed to | ||
implement TS requirements. | |||
Enforcement: TS LCO 3.4.1 states that two RR loops shall be in operation with | |||
the above, on October 31 , 2005, 2 hours after RR loop jet pump flow mismatch was | matched flows when the reactor is in Modes 1 or 2. If RR loop jet pump flow mismatch | ||
greater than 5 percent of rated core flow, the licensee exited TS 3.4.1.A.1 | -13- Enclosure | ||
5 percent. | |||
into the | is not less than or equal to 5 percent of rated core flow when operating at greater than | ||
being treated as an NCV in accordance with Section IV.A of the NRC | or equal to 70 percent of rated core flow (Condition 3.4.1.A), then the licensee must shut | ||
actions within allowed completion time. | down one RR loop (Required Action A.1) within 2 hours (Completion Time). Contrary to | ||
listed below. | the above, on October 31 , 2005, 2 hours after RR loop jet pump flow mismatch was | ||
and control of compensatory measures if needed, and (3) compliance with TS, the | greater than 5 percent of rated core flow, the licensee exited TS 3.4.1.A.1 without | ||
Technical Requirements Manual, the USAR, and other associated design-basis | shutting down one RR loop or restoring the jet pump flow mismatch to less than | ||
documents. | 5 percent. Because the finding is of very low safety significance and has been entered | ||
October 19, 2005*CR-RBS-2005-04251, -04252, Safety-related Inverter ENB-INV01B1 | into the licensees corrective action program as CR-RBS-2006-00274, this violation is | ||
reviewed on December 27, | being treated as an NCV in accordance with Section IV.A of the NRC Enforcement | ||
Policy and is identified as NCV 05000458/2005005-02: Failure to complete TS required | |||
workaround which required operators to hold the control switch for throttle valves for at | actions within allowed completion time. | ||
least 5 seconds after the full closed indication is received. | 1R15 Operability Evaluations | ||
operators to determine if they knew specifically which valves were affected and if they | a. Inspection Scope | ||
were aware of this operational requirement from memory. | The inspectors reviewed selected operability determinations on the basis of potential | ||
risk importance. The selected samples are addressed in the condition reports (CRs) | |||
the ability of the operators to respond in a correct and timely manner to plant | listed below. The inspectors assessed: (1) the accuracy of the evaluations, (2) the use | ||
and control of compensatory measures if needed, and (3) compliance with TS, the | |||
*Operator workaround report*Operator burden report | Technical Requirements Manual, the USAR, and other associated design-basis | ||
*Daily plant status reports | documents. The inspectors review included a verification that the operability | ||
*Operations shift turnover sheet | determinations were made as specified by Entergy Procedure EN-OP-104, Operability | ||
*Standing Order Number 190, | Determinations, Revision 1. The operability evaluations reviewed were associated with: | ||
* CR-RBS-2004-1270, Check valves in primary Containment 113' elevation airlock | |||
started and ran for a short period of time before shutting down on high reactor water | not included in the in-service testing program, reviewed on October 11, 2005 | ||
level. | * CR-RBS-2005-3563, Check valves in primary Containment 113' elevation airlock | ||
observed water draining from the drain trap for 12 hours. | not included in the in-service testing procedure, reviewed on October 19, 2005 | ||
part of this inspection are listed in the attachment. | * CR-RBS-2005-3568, In-service test program changed for primary containment | ||
inspection sample. | 113' elevation airlock without changing in-service test procedure, reviewed on | ||
result, on December 10, 2004, when RCIC was started and subsequently shut down on | October 19, 2005 | ||
high reactor water level following a scram and loss of feedwater, the RCIC exhaust line | * CR-RBS-2005-04251, -04252, Safety-related Inverter ENB-INV01B1 frequency | ||
filled with water from the suppression pool, causing the operators to consider RCIC | and safety-related instrument Bus VBS-PNL01B voltage out of specification high, | ||
unavailable, complicating their response to the event.Description: | reviewed on December 27, 2005 | ||
Exhaust Check Valve E51-VF040. | The inspectors completed two inspection samples. | ||
evaluation was performed on the adequacy of the RCIC turbine exhaust line vacuum | f. Findings | ||
breaker system to prevent the siphoning of suppression pool water into the RCIC | No findings of significance were identified. | ||
determined that the as-built vacuum breaker vent line was not in accordance with the | -14- Enclosure | ||
original design of the vacuum breaker line. | |||
as-built configuration (globe valves and lift check valves versus gate valves and swing | 1R16 Operator Workarounds | ||
check valves). | a. Inspection Scope | ||
Exhaust Line Vacuum Breaker Vent Line Sizing Verification, | An operator workaround is defined as a degraded or nonconforming condition that | ||
RCIC exhaust line would be at equilibrium conditions when the turbine tripped. | complicates the operation of plant equipment and is compensated for by operator | ||
same temperature and that the only cooling effect would be to ambient. | action. | ||
that the gradual cooldown of the steam and exhaust piping would cause the formation of | During the week of November 28, 2005, the inspectors reviewed an operator | ||
a vacuum in approximately 35.5 minutes. | workaround which required operators to hold the control switch for throttle valves for at | ||
a time as 3.5 minutes.On December 10, 2004, following a reactor scram, RCIC was started to maintain | least 5 seconds after the full closed indication is received. The inspectors interviewed | ||
Turbine Valve E51-MOV045 stroked full open, it automatically reclosed due to the high | operators to determine if they knew specifically which valves were affected and if they | ||
reactor water level interlock. | were aware of this operational requirement from memory. | ||
turbine for approximately 11 seconds. | During the week of December 5, 2005, the inspectors reviewed the cumulative effect of | ||
condensed more rapidly than assumed and the exhaust line pressure became a vacuum | the existing operator workarounds on: (1) the reliability, availability, and potential for | ||
within 17 seconds. | misoperation of any mitigating system; (2) whether they could increase the frequency of | ||
vent line and 84 gallons of suppression pool water was siphoned into the RCIC turbine | an initiating event; and (3) their effect on the operation of multiple mitigating systems. In | ||
exhaust line. | addition, the inspectors reviewed the cumulative effects of the operator workarounds on | ||
the ability of the operators to respond in a correct and timely manner to plant transients | |||
hammer transient would occur. | and accidents. The procedures and other documents reviewed by the inspectors were: | ||
manufacturer, the licensee also determined that the turbine would experience no | * Operator Workaround - Control Room Deficiency Program Guidelines, | ||
damage and not trip on overspeed if it were to be started with water in its exhaust line. | Revision 11 | ||
The turbine startup would be slower than normal, but within the assumed values in the | * Operator workaround report | ||
safety analysis. | * Operator burden report | ||
February 2005.Analysis: | * Daily plant status reports | ||
removal of the exhaust line check valve was a performance deficiency. | * Operations shift turnover sheet | ||
more than minor because it was associated with the Mitigating Systems cornerstone | * Standing Order Number 190, Electrically Operated Throttle Valve Operations, | ||
attribute of Design Control and affected the cornerstone objective to ensure the | Revision 0 | ||
availability and reliability of the RCIC system, a system that responds to initiating events(loss of feedwater and station blackout), to prevent undesirable consequences. | The inspectors completed two inspection samples. | ||
the MC 0609, | b. Findings | ||
was determined to have very low safety significance because it represented a design | No findings of significance were identified. | ||
deficiency that did not result in a loss of system function. Enforcement: | 1R17 Permanent Plant Modifications | ||
measures commensurate with those applied to the original design. | a. Inspection Scope | ||
above, the RCIC turbine exhaust line vacuum breaker vent line sizing calculation, used | The inspectors reviewed MR96-0063, Remove Internals of [Reactor Core Isolation | ||
as part of the modification process to remove the exhaust line check valve, did not take | Cooling Turbine (RCIC) Exhaust Check Valve] E51-VF040, dated September 18, 1996, | ||
into consideration the most limiting exhaust line conditions. | -15- Enclosure | ||
breaker vent line was not capable of preventing the siphoning of suppression pool water | |||
into the RCIC Turbine Exhaust line. | and the assumptions made with respect to the capability of the RCIC turbine exhaust | ||
significance and was documented in the | line vacuum breaker vent line. On December 10, 2004, the RCIC turbine was manually | ||
CR-RBS-2005-00724, it is being treated as an NCV in accordance with Section IV. A of | started and ran for a short period of time before shutting down on high reactor water | ||
the NRC Enforcement Policy and is identified as NCV 05000458/2005005-03: | level. The RCIC exhaust line drain trap high level alarm came in and operators | ||
which maintenance function(s) may have been affected; (3) reviewed each test | observed water draining from the drain trap for 12 hours. The documents reviewed as | ||
procedure to verify that the procedure did adequately test the safety function(s) that | part of this inspection are listed in the attachment. The inspectors completed one | ||
the procedure to ensure consistency with information in the applicable licensing basis | inspection sample. | ||
and/or design-basis documents; and (5) identified that the procedure was | b. Findings | ||
Introduction: The inspectors identified a self-revealing NCV of 10 CFR Part 50, | |||
Appendix B, Criterion III, Design Control, for failure to address a full spectrum of design | |||
capable of performing their intended safety functions and provided operational | conditions for the RCIC turbine exhaust line vacuum breaker system as part of a plant | ||
readiness. | modification to remove the internals of the RCIC turbine exhaust line check valve. As a | ||
calibration of test equipment; and (3) verified that equipment was properly restored at | result, on December 10, 2004, when RCIC was started and subsequently shut down on | ||
the completion of the testing. | high reactor water level following a scram and loss of feedwater, the RCIC exhaust line | ||
surveillance tests and surveillance test procedures (STP):STP-552-4202, "Post Accident Monitoring/Remote Shutdown System -Suppression Pool Water Level Channel Calibration (CMS-LT23B, CMS-ESX23B, | filled with water from the suppression pool, causing the operators to consider RCIC | ||
CMS-LI23B, CMS-TR40B, CMS-LIX23B)," Revision 9A, performed on | unavailable, complicating their response to the event. | ||
October 13, 2005 | Description: In September 1996, in response to a request from mechanical | ||
maintenance, design engineering processed a design change to remove RCIC Turbine | |||
(SWP-AOV599), | Exhaust Check Valve E51-VF040. As part of Modification Request MR-96-0063, an | ||
Revision 14A, performed on November 28, | evaluation was performed on the adequacy of the RCIC turbine exhaust line vacuum | ||
related 120 volt ac electrical distribution Panel SCM-PNL01B from safety-related power | breaker system to prevent the siphoning of suppression pool water into the RCIC turbine | ||
Supply RPS-XRC10B1 so that repairs to safety-related power Supply SCM-XRC14B1 | exhaust line following a shutdown of the RCIC turbine. During the evaluation it was | ||
could be made; and (2) temporary Alteration TA05-0014-01 to install radiation shielding | determined that the as-built vacuum breaker vent line was not in accordance with the | ||
in front of standby gas treatment control Panels GTS-PNL28A/B until a permanent | original design of the vacuum breaker line. A new calculation was performed for the | ||
solution could be installed. | as-built configuration (globe valves and lift check valves versus gate valves and swing | ||
evaluation showed that the total integrated dose for standby gas treatment Panel GTS-PNL28A/B could exceed qualification doses of internal electrical equipment after the | check valves). The basic assumption used for Calculation PH-056, RCIC Turbine | ||
annulus mixing system was retired. | Exhaust Line Vacuum Breaker Vent Line Sizing Verification, Revision 1A, was that the | ||
the system' | RCIC exhaust line would be at equilibrium conditions when the turbine tripped. The | ||
(3) reviewed the postinstallation test results to confirm that the actual impact of the | turbine would run long enough for the exhausted steam and exhaust piping to be at the | ||
temporary modification on SCM-PNL01B and GTS-PNL28A/B had been adequately | same temperature and that the only cooling effect would be to ambient. The result was | ||
verified. | that the gradual cooldown of the steam and exhaust piping would cause the formation of | ||
Cornerstone: | a vacuum in approximately 35.5 minutes. The revised sizing calculation showed that the | ||
as-built vacuum breaker vent line was capable of relieving a vacuum created in as short | |||
Preparedness in Support of Nuclear Power Plants, | a time as 3.5 minutes. | ||
Management Agency (FEMA) Report REP-10, | On December 10, 2004, following a reactor scram, RCIC was started to maintain reactor | ||
Notification Systems for Nuclear Power Plants, | water level due to the pending loss of all reactor feed pumps. When RCIC Steam to | ||
FEMA-approved alert and notification system design report. | Turbine Valve E51-MOV045 stroked full open, it automatically reclosed due to the high | ||
Testing, | reactor water level interlock. It was later determined that steam was admitted to the | ||
*Details of 10 staffing augmentation and quarterly pager | turbine for approximately 11 seconds. As a result, the steam in the exhaust line | ||
condensed more rapidly than assumed and the exhaust line pressure became a vacuum | |||
2003, 2004, and 2005*Four licensee self-assessments | within 17 seconds. This rapid pressure reduction overwhelmed the vacuum breaker | ||
*Licensee evaluation reports for 11 drills and exercises | vent line and 84 gallons of suppression pool water was siphoned into the RCIC turbine | ||
exhaust line. | |||
The | -16- Enclosure | ||
independently evaluated the emergency operations facility during an October 18, 2005,drill and compared the postdrill critique of licensee performance. | |||
The licensee later determined that the static and dynamic loads on the turbine exhaust | |||
protective action recommendation development activities. | line for a restart on the RCIC turbine would be within design limits, although a water | ||
evaluated the licensee assessment of classification, notification, and protective | hammer transient would occur. Based on test data provided by the turbine | ||
assessment:EIP-2-001, | manufacturer, the licensee also determined that the turbine would experience no | ||
damage and not trip on overspeed if it were to be started with water in its exhaust line. | |||
The turbine startup would be slower than normal, but within the assumed values in the | |||
inspector used the requirements in 10 CFR Part 20 and the | safety analysis. The turbine exhaust line check valve internals were reinstalled in | ||
required by TS as criteria for determining compliance. | February 2005. | ||
licensee personnel and reviewed:*Current 3-year rolling average collective exposure | Analysis: The failure to adequately address worst case design conditions in the sizing | ||
*Three on-line maintenance work activities scheduled during the inspection | calculation for the RCIC turbine exhaust line vacuum breaker vent line to allow for the | ||
highest personnel collective exposures*Site-specific ALARA procedures | removal of the exhaust line check valve was a performance deficiency. The finding was | ||
*ALARA work activity evaluations, exposure estimates, and exposure | more than minor because it was associated with the Mitigating Systems cornerstone | ||
*Method for adjusting exposure estimates, or replanning work, when | attribute of Design Control and affected the cornerstone objective to ensure the | ||
availability and reliability of the RCIC system, a system that responds to initiating events | |||
(loss of feedwater and station blackout), to prevent undesirable consequences. Using | |||
used to verify the | the MC 0609, Significance Determination Process, Phase 1 Worksheet, the finding | ||
accuracy of performance indicator data reported during the assessment period. | was determined to have very low safety significance because it represented a design | ||
deficiency that did not result in a loss of system function. | |||
Procedure EN-LI-114, | Enforcement: 10 CFR Part 50, Appendix B, Criterion III, Design Control, states, in part, | ||
*Alert and Notification System | that design changes, including field changes, shall be subject to design change control | ||
measures commensurate with those applied to the original design. Contrary to the | |||
records associated with training sessions, drills, and exercises conducted during | above, the RCIC turbine exhaust line vacuum breaker vent line sizing calculation, used | ||
as part of the modification process to remove the exhaust line check valve, did not take | |||
siren test records. | into consideration the most limiting exhaust line conditions. As a result the vacuum | ||
accountable for collecting and evaluating the performance indicator data.The inspector completed three inspection samples. | breaker vent line was not capable of preventing the siphoning of suppression pool water | ||
into the RCIC Turbine Exhaust line. Because this finding was of very low safety | |||
and radiation worker practices. | significance and was documented in the licensees corrective action program as | ||
listed in the attachment against the | CR-RBS-2005-00724, it is being treated as an NCV in accordance with Section IV. A of | ||
program requirements. | the NRC Enforcement Policy and is identified as NCV 05000458/2005005-03: | ||
also considered the results of daily inspector screening of CRs and licensee trending | Inadequate design assumption results in RCIC turbine exhaust header filling with water | ||
efforts. | following an automatic high water level shutdown. | ||
December 2005. | 1R19 Postmaintenance Testing | ||
conditions adverse to quality. | a. Inspection Scope | ||
*Procedure EN-OP-104, | The inspectors reviewed selected work orders (WO) to ensure that testing activities | ||
Safety, | were adequate to verify system operability and functional capability. The inspectors: | ||
(1) identified the safety function(s) for each system by reviewing applicable licensing | |||
The inspectors found that this system was an effective mechanism for resolution of | basis and/or design-basis documents; (2) reviewed each maintenance activity to identify | ||
the condition adverse to quality (system inoperability) or a discussion of the | which maintenance function(s) may have been affected; (3) reviewed each test | ||
the inspectors observed that a number of operability determinations | procedure to verify that the procedure did adequately test the safety function(s) that may | ||
have been affected by the maintenance activity; (4) reviewed the acceptance criteria in | |||
were being taken to ensure system operability, but no mechanism was in place | the procedure to ensure consistency with information in the applicable licensing basis | ||
where the nonconforming condition was not corrected within a reasonable period of | and/or design-basis documents; and (5) identified that the procedure was properly | ||
time. | reviewed and approved. The eight WOs inspected are listed below: | ||
Ultimate Heat Sink Long Term Heat Removal Capacity | -17- Enclosure | ||
the CR against the requirements of the | |||
described in nuclear management manual Procedure LI-102, | C WO 00063768, replace hydrogen igniter in containment dome, review conducted | ||
Process, | during the week of October 31, 2005 | ||
was a trip of standby diesel Generator B immediately after a small line break event, with | C WO 00075881, replace rod control and information system isolation transformer, | ||
bypass, coincident with a loss-of-offsite power and plant trip, (2) the ultimate heat sink | reviewed during the week of October 31, 2005 | ||
capacity would be less than 30 days if, instead, all ECCS systems worked as | C WO 00074806, rebuild control rod drive Hydraulic Control Unit 4833, review | ||
replenish the ultimate heat sink during a loss-of-offsite power had not been written. | conducted during the week of December 12, 2005 | ||
response to the inspectors' concerns, the licensee wrote CR-RBS-2002-01243 and took | C WO 50969759, rebuild control rod drive Hydraulic Control Unit 1625, review | ||
the following corrective actions: | conducted during the week of December 12, 2005 | ||
no single failure occurred and to provide instructions for makeup to the ultimate heat | C WO 00066597, rework Inverter BYS-INV01A to fix blown fuse problem, review | ||
conducted during the week of December 12, 2005 | |||
as expected by operators following an unplanned reactor scram. | C WO 50968926, replace frequency detector board on Inverter ENB-INV01B1, | ||
2004, a failure of a balance of plant instrument bus caused the feedwater | review conducted during the week of December 12, 2005 | ||
pumps overfed the reactor and tripped on high reactor water level. | C WO 00072137, quarterly inspection and lubrication of the station blackout diesel, | ||
feedwater caused reactor water level to continue to rise after the feed pump trip. | review conducted during the week of December 19, 2005 | ||
wide-range level recorders' digital output continued to indicate reactor water level | C WO 50967030, clean, inspect, and lubricate the station blackout diesel, review | ||
greater than +60 inches, the top end of the wide-range level instruments. | conducted during the week of December 19, 2005 | ||
simulator stopped at +60 inches. | The inspectors completed eight inspection samples. | ||
complicated the operators' response to the event. | b. Findings | ||
2004-04289, -04295, -04296 and -04299 written by the licensee in response to this | No findings of significance were identified. | ||
event. | 1R22 Surveillance Testing | ||
from analog to digital models, the simulator modification made the software for the | a. Inspection Scope | ||
recorders stop indicating at the top of scale (+60 inches). | The inspectors verified, by witnessing and reviewing test data, that risk-significant | ||
in the control room, however, had no upper limit on the digital indication. | system and component surveillance tests met TS, USAR, and procedure requirements. | ||
December 10, 2004, reactor water level rose above the reference leg tap for the level | The inspectors ensured that surveillance tests demonstrated that the systems were | ||
transmitter and, as the reference leg condensing chamber cooled down, the wide-range | capable of performing their intended safety functions and provided operational | ||
level transmitters | readiness. The inspectors specifically: (1) evaluated surveillance tests for | ||
as high as +140 inches. | preconditioning; (2) evaluated clear acceptance criteria, range, accuracy and current | ||
licensee and determined that they were reasonable and adequate to correct the | calibration of test equipment; and (3) verified that equipment was properly restored at | ||
operator knowledge deficiency caused by the simulator fidelity issue. | the completion of the testing. The inspectors observed and reviewed the following | ||
interviewed a cross-section of control room operators and determined that the | surveillance tests and surveillance test procedures (STP): | ||
phenomena was understood and they understood that any wide-range digital indication | C STP-552-4202, "Post Accident Monitoring/Remote Shutdown System - | ||
greater that +60 inches was invalid and not indicative of actual reactor water level. | Suppression Pool Water Level Channel Calibration (CMS-LT23B, CMS-ESX23B, | ||
CMS-LI23B, CMS-TR40B, CMS-LIX23B)," Revision 9A, performed on | |||
deenergized, causing a partial loss of off-site power and start of the Division 2 | October 13, 2005 | ||
emergency diesel generator; and (2) main transformer protection relays caused a main | -18- Enclosure | ||
generator lockout, which resulted in a generator load reject reactor scram.NRC Integrated Inspection Report 05000458/2004005, issued February 14, 2005,documented a Green, self-revealing finding associated with this event for preconditioned | |||
speed testing of station switchyard breakers and three similar failures of station | C MCP-4303, Functional Test of Standby Cooling Tower #1 Station Blackout | ||
switchyard breakers. | Division I Standby Service Water Return Valve and Valve Logic | ||
preconditioning the breakers.NRC Supplemental Inspection Report 05000458/2005012, issued October 24, 2005,documented a supplemental inspection performed in accordance with Inspection | (SWP-AOV599), Revision 01A, performed on October 25, 2005 | ||
Procedure 95001. | C STP-552-4502, "Post Accident Monitoring/Remote Shutdown System - Drywell | ||
reactor scrams that occurred between August 15, 2004, and January 15, 2005. | Pressure Channel Calibration (CMS-PT2A, CMS-T103, CMS-PR2A)," | ||
incorporated into a switchyard reliability program to improve switchyard | Revision 14A, performed on November 28, 2005 | ||
requirements. | The inspectors completed three inspection samples. | ||
staff who acknowledged the findings. | b. Findings | ||
information was not provided or examined during the inspection.On November 4, 2005, the inspector presented the licensed operator | No findings of significance were identified. | ||
other members of the | 1R23 Temporary Plant Modifications | ||
findings presented. | a. Inspection Scope | ||
provided or examined during the inspection.On December 8, 2005, the inspector presented the ALARA inspection results | During the week of December 19, 2005, the inspectors reviewed the following temporary | ||
acknowledged the findings. | plant modifications: (1) temporary Alteration TA05-0015-00 to supply Division II safety- | ||
not provided or examined during the inspection. | related 120 volt ac electrical distribution Panel SCM-PNL01B from safety-related power | ||
Supply RPS-XRC10B1 so that repairs to safety-related power Supply SCM-XRC14B1 | |||
management. | could be made; and (2) temporary Alteration TA05-0014-01 to install radiation shielding | ||
examined during the inspection.ATTACHMENT: | in front of standby gas treatment control Panels GTS-PNL28A/B until a permanent | ||
solution could be installed. This shielding was installed after an equipment qualification | |||
evaluation showed that the total integrated dose for standby gas treatment Panel GTS- | |||
PNL28A/B could exceed qualification doses of internal electrical equipment after the | |||
annulus mixing system was retired. Specifically, the inspectors: (1) reviewed each | |||
temporary modification and its associated 10 CFR 50.59 screening against the system's | |||
design basis documentation, including the USAR and TS; (2) verified that the installation | |||
of the temporary modification was consistent with the modification documents; and | |||
(3) reviewed the postinstallation test results to confirm that the actual impact of the | |||
temporary modification on SCM-PNL01B and GTS-PNL28A/B had been adequately | |||
verified. The inspectors completed two inspection samples. | |||
b. Findings | |||
No findings of significance were identified. | |||
Cornerstone: Emergency Preparedness | |||
1EP2 Alert and Notification System Testing | |||
a. Inspection Scope | |||
The inspector discussed with licensee staff the status of offsite siren systems to | |||
determine the adequacy of licensee methods for testing the alert and notification system | |||
-19- Enclosure | |||
in accordance with 10 CFR Part 50, Appendix E. The licensees alert and notification | |||
system testing program was compared with criteria in NUREG-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 licensees current | |||
FEMA-approved alert and notification system design report. The inspector also | |||
reviewed Procedures EPP-2-701, Prompt Notification System Maintenance and | |||
Testing, Revision 18, and EPP-2-401, Inadvertent Siren Sounding, Revision 7. The | |||
inspector completed one inspection sample. | |||
b. Findings | |||
No findings of significance were identified. | |||
1EP3 Emergency Response Organization Augmentation | |||
a. Inspection Scope | |||
The inspector reviewed the following documents to determine the licensees ability to | |||
staff emergency response facilities in accordance with the licensee emergency plan and | |||
the requirements of 10 CFR Part 50, Appendix E. | |||
* EIP-2-006, Notifications, Revision 32 | |||
* EPP-2-502, Emergency Communications Equipment Testing, Revision 21 | |||
* Details of 10 staffing augmentation and quarterly pager drills | |||
The inspector completed one inspection sample. | |||
b. Findings | |||
No findings of significance were identified. | |||
1EP5 Correction of Emergency Preparedness Weaknesses and Deficiencies | |||
a. Inspection Scope | |||
The inspector reviewed the following documents related to the licensees corrective | |||
action program to determine the licensees ability to identify and correct problems in | |||
accordance with 10 CFR 50.47(b)(14) and 10 CFR Part 50, Appendix E: | |||
* Quality assurance audits of the emergency preparedness program conducted in | |||
2003, 2004, and 2005 | |||
* Four licensee self-assessments | |||
* Licensee evaluation reports for 11 drills and exercises | |||
-20- Enclosure | |||
* Summaries of 146 corrective actions assigned to the emergency preparedness | |||
department between February 2003 and October 2005 | |||
* Details of 17 selected CRs | |||
The licensees corrective action program was also compared with the requirements of | |||
Procedure EN-LI-102, Corrective Action Process, Revision 2. The inspector | |||
independently evaluated the emergency operations facility during an October 18, 2005, | |||
drill and compared the postdrill critique of licensee performance. The inspector | |||
completed one inspection sample. | |||
b. Findings | |||
No findings of significance were identified. | |||
1EP6 Drill Evaluation | |||
a. Inspection Scope | |||
The inspectors observed the emergency preparedness drill conducted on October 18, | |||
2005, to identify any weaknesses and deficiencies in classification, notification, and | |||
protective action recommendation development activities. The inspectors also | |||
evaluated the licensee assessment of classification, notification, and protective action | |||
recommendation development during the drill in accordance with plant procedures and | |||
NRC guidelines. The inspectors also observed the drill evaluator immediate critiques of | |||
the drill participants classification, notification, and protective action recommendation | |||
activities. The following procedures and documents were reviewed during the | |||
assessment: | |||
C EIP-2-001, Classification of Emergencies, Revision 13 | |||
C EIP-2-006, Notifications, Revision 32 | |||
C EIP-2-007, Protective Action Guidelines Recommendations, Revision 21 | |||
The inspectors completed one inspection sample. | |||
b. Findings | |||
No findings of significance were identified. | |||
-21- Enclosure | |||
2. RADIATION SAFETY | |||
Cornerstone: Occupational Radiation Safety | |||
2OS2 ALARA Planning and Controls | |||
a. Inspection Scope | |||
The inspector assessed licensee performance with respect to maintaining individual and | |||
collective radiation exposures as low as is reasonably achievable (ALARA). The | |||
inspector used the requirements in 10 CFR Part 20 and the licensees procedures | |||
required by TS as criteria for determining compliance. The inspector interviewed | |||
licensee personnel and reviewed: | |||
* Current 3-year rolling average collective exposure | |||
* Three on-line maintenance work activities scheduled during the inspection period | |||
and associated work activity exposure estimates which were likely to result in the | |||
highest personnel collective exposures | |||
* Site-specific ALARA procedures | |||
* ALARA work activity evaluations, exposure estimates, and exposure mitigation | |||
requirements | |||
* Intended versus actual work activity doses and the reasons for any | |||
inconsistencies | |||
* Dose rate reduction activities in work planning | |||
* Method for adjusting exposure estimates, or replanning work, when unexpected | |||
changes in scope or emergent work were encountered | |||
* Use of engineering controls to achieve dose reductions and dose reduction | |||
benefits afforded by shielding | |||
* Radiation worker and radiation protection technician performance during work | |||
activities in radiation areas, airborne radioactivity areas, or high radiation areas | |||
* Self-assessments and audits related to the ALARA program since the last | |||
inspection | |||
* Corrective action documents related to the ALARA program and follow-up | |||
activities such as initial problem identification, characterization, and tracking | |||
The inspector completed 9 of the required 15 inspection samples and 2 of the optional | |||
inspection samples. | |||
-22- Enclosure | |||
b. Findings | |||
No findings of significance were identified. | |||
4. OTHER ACTIVITIES | |||
4OA1 Performance Indicator Verification | |||
Emergency Preparedness Cornerstone | |||
a. Inspection Scope | |||
The inspector sampled licensee submittals for the performance indicators listed below | |||
for the period July 1, 2004, through September 30, 2005. The definitions and guidance | |||
of NEI 99-02, Regulatory Assessment Indicator Guideline, Revisions 2 and 3, were | |||
used to verify the licensees basis for reporting each data element in order to verify the | |||
accuracy of performance indicator data reported during the assessment period. The | |||
licensees performance indicator data was also reviewed against the requirements of | |||
Procedure EN-LI-114, Performance Indicator Process, Revision 0. | |||
* Drill and Exercise Performance | |||
* Emergency Response Organization Participation | |||
* Alert and Notification System Reliability | |||
The inspector reviewed a 100 percent sample of drill and exercise scenarios, licensed | |||
operator 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 emergency responder qualification, training, | |||
and drill participation records for 20 key licensee emergency response personnel. The | |||
inspector reviewed procedures for conducting siren testing and a 100 percent sample of | |||
siren test records. The inspector also interviewed licensee personnel that were | |||
accountable for collecting and evaluating the performance indicator data. | |||
The inspector completed three inspection samples. | |||
b. Findings | |||
No findings of significance were identified. | |||
4OA2 Identification and Resolution of Problems | |||
1. Emergency Preparedness Annual Sample Review | |||
a. Inspection Scope | |||
The inspector reviewed a summary listing of 146 corrective actions assigned to the | |||
emergency preparedness department, reviewed 17 CRs in detail, and independently | |||
-23- Enclosure | |||
assessed the licensees ability to identify problems associated with an October 18, 2005, | |||
integrated drill, in order to assess the licensees ability to identify and correct problems. | |||
The inspector completed one inspection sample. | |||
b. Findings | |||
No findings of significance were identified. | |||
2. ALARA Planning and Controls Annual Sample Review | |||
a. Inspection Scope | |||
The inspector evaluated the effectiveness of the licensee's problem identification and | |||
resolution processes regarding exposure tracking, higher than planned exposure levels, | |||
and radiation worker practices. The inspector reviewed the corrective action documents | |||
listed in the attachment against the licensees problem identification and resolution | |||
program requirements. The inspector completed one inspection sample. | |||
b. Findings | |||
No findings of significance were identified. | |||
3. Semiannual Trend Review | |||
a. Inspection Scope | |||
The inspectors performed a 6-month review of the licensees corrective action program | |||
and associated documents to identify trends that could indicate the existence of a more | |||
significant safety issue. The inspectors review was focused on repetitive issues, but | |||
also considered the results of daily inspector screening of CRs and licensee trending | |||
efforts. The inspectors review considered the six month period of July through | |||
December 2005. Inspectors reviewed 76 specific CRs and their associated operability | |||
evaluations. Operability determinations set the priority for corrective actions to resolve | |||
conditions adverse to quality. The CR numbers are listed in the attachment. | |||
The inspectors also evaluated the CRs and the operability determinations against the | |||
requirements of the following guidance documents: | |||
* Procedure EN-LI-102, Corrective Action Process, Revision 1 | |||
* Procedure EN-OP-104, Operability Determinations, Revision 1 | |||
* Procedure OSP-0040, LCO Tracking and Safety Function Determination | |||
Program, Revision 10 | |||
* MC 9900, Operability Determinations and Functionality Assessments for | |||
Resolution of Degraded or Nonconforming Conditions Adverse to Quality or | |||
Safety, dated September 26, 2005 | |||
-24- Enclosure | |||
The inspectors completed one inspection sample. | |||
b. Assessment and Observations | |||
There were no findings of significance identified. The inspectors determined that a | |||
number of operability determinations stated that the equipment that was the subject of | |||
the CR was currently inoperable and being tracked using the LCO Tracking System. | |||
The inspectors found that this system was an effective mechanism for resolution of TS | |||
LCOs. However, from a corrective action program perspective, there was no closure of | |||
the condition adverse to quality (system inoperability) or a discussion of the corrective | |||
actions taken to restore the equipment to operable status in the subject CR. In addition, | |||
the inspectors observed that a number of operability determinations described | |||
conditions where the system was declared operable but the system or a support system | |||
was in a degraded or nonconforming condition. In some cases, compensatory actions | |||
were being taken to ensure system operability, but no mechanism was in place to | |||
ensure that these compensatory measures remained in place until the degraded or | |||
nonconforming condition was corrected. The inspectors did not find any examples | |||
where the nonconforming condition was not corrected within a reasonable period of | |||
time. | |||
4. Resident Inspector Annual Sample Review | |||
The inspectors completed two inspection samples. | |||
Ultimate Heat Sink Long Term Heat Removal Capacity | |||
c. Inspection Scope | |||
The inspectors reviewed CR-RBS-2002-01243, ultimate heat sink capacity less than the | |||
30-day requirement, during the week of November 28, 2005. The inspectors evaluated | |||
the CR against the requirements of the licensees corrective action program as | |||
described in nuclear management manual Procedure LI-102, Corrective Action | |||
Process, Revision 4, and 10 CFR Part 50, Appendix B, Criterion XVI. | |||
b. Findings and Observations | |||
There were no findings of significance identified. On August 28, 2002, the inspectors | |||
found: (1) the single failure assumption made for the design of the ultimate heat sink | |||
was a trip of standby diesel Generator B immediately after a small line break event, with | |||
bypass, coincident with a loss-of-offsite power and plant trip, (2) the ultimate heat sink | |||
capacity would be less than 30 days if, instead, all ECCS systems worked as designed | |||
and no operator actions were taken to secure ECCS, and (3) specific procedures to | |||
replenish the ultimate heat sink during a loss-of-offsite power had not been written. In | |||
response to the inspectors' concerns, the licensee wrote CR-RBS-2002-01243 and took | |||
the following corrective actions: (1) revised their procedures to clarify operator actions if | |||
no single failure occurred and to provide instructions for makeup to the ultimate heat | |||
-25- Enclosure | |||
sink during a 30-day loss-of-offsite power; and (2) issued license amendment Request | |||
LAR-2001-026, dated March 18, 2003, to revise their TS Bases 3.7, Standby Service | |||
Water System and Ultimate Heat Sink, and USAR. | |||
Simulator Fidelity Issue Regarding Wide-Range Level Recorders | |||
d. Inspection Scope | |||
The inspectors reviewed the corrective actions taken by the licensee in response to | |||
NCV 05000458/2004005-02, wide-range reactor water level indication did not respond | |||
as expected by operators following an unplanned reactor scram. On December 10, | |||
2004, a failure of a balance of plant instrument bus caused the feedwater regulating | |||
valves to fail in their 100 percent flow position. Following a reactor scram, the feedwater | |||
pumps overfed the reactor and tripped on high reactor water level. The excess | |||
feedwater caused reactor water level to continue to rise after the feed pump trip. The | |||
wide-range level recorders' digital output continued to indicate reactor water level | |||
greater than +60 inches, the top end of the wide-range level instruments. The reactor | |||
operators were not aware that the recorders digital output would continue to increase | |||
beyond +60 inches because the digital readout of wide-range level recorders in the | |||
simulator stopped at +60 inches. This response caused some confusion and | |||
complicated the operators' response to the event. The inspectors reviewed CR-RBS- | |||
2004-04289, -04295, -04296 and -04299 written by the licensee in response to this | |||
event. | |||
e. Findings and Observations | |||
There were no findings of significance identified. The inspectors found that, when a | |||
design change was implemented changing the wide-range reactor water level recorders | |||
from analog to digital models, the simulator modification made the software for the | |||
recorders stop indicating at the top of scale (+60 inches). The digital recorders installed | |||
in the control room, however, had no upper limit on the digital indication. On | |||
December 10, 2004, reactor water level rose above the reference leg tap for the level | |||
transmitter and, as the reference leg condensing chamber cooled down, the wide-range | |||
level transmitters output continued to increase and the digital indication showed a level | |||
as high as +140 inches. The inspectors reviewed the corrective actions taken by the | |||
licensee and determined that they were reasonable and adequate to correct the | |||
operator knowledge deficiency caused by the simulator fidelity issue. The inspectors | |||
interviewed a cross-section of control room operators and determined that the | |||
phenomena was understood and they understood that any wide-range digital indication | |||
greater that +60 inches was invalid and not indicative of actual reactor water level. | |||
4OA3 Event Followup | |||
1. (Closed) Licensee Event Report (LER) 50-458/04-001-00, Automatic Reactor Scram | |||
Due to Main Generator Trip Resulting from Switchyard Fault | |||
On August 15, 2004, a transmission tower guy wire failed. This allowed a 230 kV | |||
transmission line structure between Port Hudson and Fancy Point (Line 353) to fall and | |||
-26- Enclosure | |||
create a ground fault condition on the line. Four breakers in the station switchyard were | |||
slow to open to clear the fault. As a result: (1) Reserve Station Transformer 2 was | |||
deenergized, causing a partial loss of off-site power and start of the Division 2 | |||
emergency diesel generator; and (2) main transformer protection relays caused a main | |||
generator lockout, which resulted in a generator load reject reactor scram. | |||
NRC Integrated Inspection Report 05000458/2004005, issued February 14, 2005, | |||
documented a Green, self-revealing finding associated with this event for preconditioned | |||
speed testing of station switchyard breakers and three similar failures of station | |||
switchyard breakers. The licensee revised the speed testing procedures to avoid | |||
preconditioning the breakers. | |||
NRC Supplemental Inspection Report 05000458/2005012, issued October 24, 2005, | |||
documented a supplemental inspection performed in accordance with Inspection | |||
Procedure 95001. The supplemental inspection was in response to four unplanned | |||
reactor scrams that occurred between August 15, 2004, and January 15, 2005. The | |||
licensees root cause analysis identified several programmatic changes which were | |||
incorporated into a switchyard reliability program to improve switchyard maintenance | |||
practices. | |||
The inspectors reviewed the LER and the licensees resolution of identified problems | |||
and determined there were no findings of significance and no other violations of NRC | |||
requirements. The licensee documented the failed equipment in CR-RBS-2004-02332. | |||
4OA6 Meetings, Including Exit | |||
Exit Meetings | |||
On October 21, 2005, the inspector presented the emergency preparedness inspection | |||
results to Mr. J. Leavines, Manager, Emergency Planning, and other members of his | |||
staff who acknowledged the findings. The inspector confirmed that proprietary | |||
information was not provided or examined during the inspection. | |||
On November 4, 2005, the inspector presented the licensed operator requalification | |||
program inspection results to Mr. Mike Cantrell, Operations Training Supervisor, and | |||
other members of the licensees management staff. The licensee acknowledged the | |||
findings presented. The inspector confirmed that proprietary information was not | |||
provided or examined during the inspection. | |||
On December 8, 2005, the inspector presented the ALARA inspection results to | |||
Mr. R. King, Director, Nuclear Safety Assurance, and other members of his staff who | |||
acknowledged the findings. The inspector confirmed that proprietary information was | |||
not provided or examined during the inspection. | |||
-27- Enclosure | |||
On January 4, 2006, the inspectors presented the integrated baseline inspection results | |||
to Paul Henninkamp, Vice President, Operations, and other members of licensee | |||
management. The inspector confirmed that proprietary information was not provided or | |||
examined during the inspection. | |||
ATTACHMENT: SUPPLEMENTAL INFORMATION | |||
-28- Enclosure | |||
SUPPLEMENTAL INFORMATION | |||
KEY POINTS OF CONTACT | |||
Licensee Personnel | |||
M. Boyle, Manager, Radiation Protection | |||
D. Burnett, Superintendent, Chemistry | |||
M. Cantrell, Operations Training Supervisor | M. Cantrell, Operations Training Supervisor | ||
J. Clark, Assistant Operations Manager - Training | J. Clark, Assistant Operations Manager - Training | ||
Line 560: | Line 1,193: | ||
C. Stafford, Manager, Operations | C. Stafford, Manager, Operations | ||
W. Trudell, Manager, Training and Development | W. Trudell, Manager, Training and Development | ||
D. Vinci, General Manager - Plant | D. Vinci, General Manager - Plant Operations | ||
A- | LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED | ||
RJPM-OPS-109.4, July 26, 2005 | Opened and Closed | ||
RJPM-OPS-110-04, Synchronize the Main Generator with the Grid, August 2, 2005 | 05000458/2005005-01 NCV Inadequate procedure for implementation of an EAL | ||
RJPM-OPS-256-03R4, Restore level in the SBCT with deepwell pumps, July 26, 2005 | 05000458/2005005-02 NCV Failure to complete TS required actions within allowed | ||
RJPM-OPS-309-050, July 19, 2005 | completion time | ||
RJPM-OPS-508-04, Restore RPS B Normal Power Supply, August 19, 2005 | 05000458/2005005-03 NCV Inadequate design assumption results in RCIC turbine | ||
RJPM-OPS-508-07, Respond to reactor scram with control rods failing to insert,August 2, | exhaust header filling with water following an automatic | ||
RJPM-OPS-05304R, Startup A recirc HPU, July 12, 2005 | high water level shutdown | ||
RJPM-OPS-20005R, Perform ATC actions for remote shutdown, August 2, 2005 | Closed | ||
RJPM-OPS-20006R5, Perform Attachment 13 UO actions, July 26, 2005 | 05000458/2004-001-00 LER Automatic Reactor Scram Due to Main Generator Trip | ||
Resulting from Switchyard Fault | |||
RSMS-OPS-823, APRM Failure /SRV Failure / EHC Failure / ATWS, Revision: | A-1 Attachment | ||
RSMS-OPS-824, LPRM Failure / Loss of Vacuum with MSIV Closure / ATWS,Revision: | |||
A- | LIST OF DOCUMENTS REVIEWED | ||
NUREG-0989, RBS Safety Evaluation Report and Supplements, May 1984 | The following documents were selected and reviewed by the inspectors to accomplish the | ||
GS AID-56, HPCI/RCI Turbine Exhaust Check Valve Cycling, August 1985 | objectives and scope of the inspection and to support any findings: | ||
VPF-3622-353 (1) - 1, RCIC Turbine Instruction Manual, January 1975 | Section 1R11: Licensed Operator Requalification Program | ||
A- | Job Performance Measures | ||
Revision | RJPM-OPS-052-04, Alternate Control Rod Drive Pumps, August 4, 2005 | ||
RJPM-OPS-053-03R5, Reset a FCV runback, July 26, 2005 | |||
RJPM-OPS-109.4, July 26, 2005 | |||
March 22, | RJPM-OPS-110-04, Synchronize the Main Generator with the Grid, August 2, 2005 | ||
A- | RJPM-OPS-256-03R4, Restore level in the SBCT with deepwell pumps, July 26, 2005 | ||
Quality Assurance Audit Report, QA-7-2005-RBS- | RJPM-OPS-309-050, July 19, 2005 | ||
CR-RBS-2003- | RJPM-OPS-508-04, Restore RPS B Normal Power Supply, August 19, 2005 | ||
CR-RBS- | RJPM-OPS-508-07, Respond to reactor scram with control rods failing to insert, | ||
CR-RBS-2003- | August 2, 2005 | ||
CR-RBS- | RJPM-OPS-800-17R1, Vent the CCRD over-piston volume, July 26, 2005 | ||
CR-RBS-2003- | RJPM-OPS-05206R2, Control rod operability faulted, July 12, 2005 | ||
CR-RBS- | RJPM-OPS-05207R2, Alternate control rod drive pumps (Fuel Bldg), July 12, 2005 | ||
CR-RBS- | RJPM-OPS-05304R, Startup A recirc HPU, July 12, 2005 | ||
CR-RBS- | RJPM-OPS-20005R, Perform ATC actions for remote shutdown, August 2, 2005 | ||
CR-RBS-2005- | RJPM-OPS-20006R5, Perform Attachment 13 UO actions, July 26, 2005 | ||
CR-RBS-2005- | Scenarios | ||
CR-RBS- | RSMS-OPS-822, Loss of All Feed Water / RCIC Failure / LOCA, Revision: 00 | ||
CR-RBS-2005- | RSMS-OPS-823, APRM Failure /SRV Failure / EHC Failure / ATWS, Revision: 00 | ||
CR-RBS- | RSMS-OPS-824, LPRM Failure / Loss of Vacuum with MSIV Closure / ATWS, | ||
Revision: 00 | |||
A-2 Attachment | |||
RSMS-OPS-825, Loss of RPS B / Relief Valve Fails Open / Steam Leak in the Drywell | |||
March 24, 2005 | With Failure of the Drywell, Revision: 00 | ||
April 19, 2005 | RSMS-OPS-827, Rod Drop / Fuel Failure / RCIC Steam Leak / Partial ATWS, | ||
June 21, | Revision: 00 | ||
2005 Emergency Planning Program Assessment | RSMS-OPS-829, Failure Of STX-XS2B / Loss Of Condenser Vacuum / ATWS, | ||
Snapshot Assessment of RBS Siren | Revision: 00 | ||
EIP-2-001, | RSMS-OPS-830, Inadvertent HPCS Injection and Loss of Stator Cooling, Revision: 00 | ||
EIP-2-002, | Section 1R17: Permanent Plant Modifications | ||
EIP-2-006, | Event Notification 41252, Reactor Scram due to Loss of Vital Instrument Bus | ||
EIP-2-007, | LER 05-458/04-005-01, Unplanned Automatic Scram due to Loss of Non-Vital 120 Volt | ||
EIP-2-007, | Instrument Bus, June 22, 2005 | ||
A- | CR-RBS-2004-04291 RCIC system initiated and subsequently tripped on Level 8 | ||
CR-RBS-2005- | CR-RBS-2005-00724 MR96-0063 removed internals from RCIC Turbine Exhaust Check | ||
CR-RBS-2005- | Valve E51-VF040 | ||
(July 11-13, 2005)QS-2005-RBS- | SDRP-P43, System Design Requirements Document, Reactor Core Isolation Cooling, | ||
Radiation Work | Revision 0 | ||
2005- | SDC-209, Reactor Core Isolation Cooling System Design Criteria, Revision 0, | ||
AMC 05- | November 9, 1998 | ||
AMC 05- | SDC-209, Reactor Core Isolation Sooling System Design Criteria, Revision 3, | ||
CR-RBS-2005- | September 27, 2004 | ||
CR-RBS-2005- | RBS USAR Section 5.4.6, Reactor Core Isolation Cooling System, Revision 17 | ||
CR-RBS-2005- | NUREG-0989, RBS Safety Evaluation Report and Supplements, May 1984 through | ||
CR-RBS-2005- | October 1985 | ||
CR-RBS-2005- | GE SIL-30, HPCI/RCIC Turbine Exhaust Line Vacuum Breakers, October 31, 1973 | ||
CR-RBS-2005- | GS AID-56, HPCI/RCI Turbine Exhaust Check Valve Cycling, August 1985 | ||
CR-RBS-2005- | VPF-3622-353 (1) - 1, RCIC Turbine Instruction Manual, January 1975 through | ||
CR-RBS-2005-02626 | March 1978 | ||
A- | MR96-0063, Remove Internals of [RCIC Exhaust Check Valve] E51-VF040, | ||
CR-RBS-2005- | September 18, 1996 | ||
CR-RBS-2005- | A-3 Attachment | ||
CR-RBS-2005- | |||
CR-RBS-2005- | CR-RBS-1996-1671, Existing plant configuration of RCIC turbine exhaust line vacuum | ||
CR-RBS-2005- | breaker vent line does not correspond with configuration assumed in Calculation PH-56, | ||
CR-RBS-2005- | Revision 0 | ||
CR-RBS-2005- | Calculation PH-56, RCIC Turbine Exhaust Line Vacuum Breaker Vent Line Sizing | ||
CR-RBS-2005- | Verification, Revision 1A, November 27, 1996 | ||
CR-RBS-2005- | Piping and Instrument Drawing PID-27-06A, Reactor Core Isolation Cooling System, | ||
CR-RBS-2005- | Revision 42 | ||
CR-RBS-2005- | Calculation G13.18.2.0-079, Determination of Quantity of Water Entering RCIC Turbine | ||
CR-RBS-2005- | Exhaust Line, May 11, 2005 | ||
CR-RBS-2005- | Calculation G13.18.10.2*225, RCIC Fluid Transient Analysis - Water in Turbine Exhaust | ||
CR-RBS-2005- | Line, May 17, 2005 | ||
CR-RBS-2005- | ER-RB-2005-0084-000, Replace Check Valve E51-VF040 or Reinstall Internal Parts, | ||
CR-RBS-2005- | February 20, 2005 | ||
CR-RBS-2005- | Terry Turbine SAM-12, Terry Wheel Water Slug Test, March 1, 1973 | ||
CR-RBS-2005- | Section 1EP2: Alert and Notification System Testing | ||
CR-RBS-2005- | River Bend Station Emergency Plan, Revision 28 | ||
CR-RBS-2005- | River Bend Station Prompt Notification System Design Report, Revision 1, | ||
CR-RBS-2005- | December 2001 | ||
CR-RBS-2005- | Section 1EP3: Emergency Response Organization Augmentation Testing | ||
CR-RBS-2005- | Evaluation Reports for Pager and Augmentation Tests conducted: | ||
CR-RBS-2005- | February 10, 2004 December 8, 2004 July 25, 2005 | ||
CR-RBS-2005- | June 17, 2004 January 25, 2005 September 27, 2005 | ||
CR-RBS-2005- | August 24, 2004 March 22, 2005 | ||
CR-RBS-2005- | September 23, 2004 | ||
CR-RBS-2005- | Section 1EP5: Correction of Emergency Preparedness Weaknesses and Deficiencies | ||
CR-RBS-2005- | Procedures | ||
CR-RBS-2005- | EN-LI-118, Root Cause Analysis Process, Revision 1 | ||
CR-RBS-2005- | EN-LI-119, Apparent Cause Evaluation Process, Revision 3 | ||
CR-RBS-2005- | A-4 Attachment | ||
CR-RBS-2005- | |||
CR-RBS-2005- | Quality Assurance | ||
CR-RBS-2005- | Quality Assurance Audit Report, QA-7-2003-RBS-1 | ||
CR-RBS-2005- | Quality Assurance Audit Report, QA-7-2004-RBS-1 | ||
CR-RBS-2005- | Quality Assurance Audit Report, QA-7-2005-RBS-1 | ||
CR-RBS-2005- | Condition Reports | ||
CR-RBS-2005- | CR-RBS-1999-1316 CR-RBS-2004-3086 | ||
CR-RBS-2005- | CR-RBS-2003-0586 CR-RBS-2004-3811 | ||
CR-RBS-2005- | CR-RBS-2003-0624 CR-RBS-2005-1433 | ||
CR-RBS-2005- | CR-RBS-2003-1950 CR-RBS-2005-1602 | ||
CR-RBS-2005- | CR-RBS-2003-1992 CR-RBS-2005-1632 | ||
CR-RBS-2005- | CR-RBS-2003-2094 CR-RBS-2005-1391 | ||
CR-RBS-2005- | CR-RBS-2003-3050 CR-RBS-2005-2516 | ||
CR-RBS-2005- | CR-RBS-2004-1090 CR-RBS-2005-2646 | ||
CR-RBS-2005- | CR-RBS-2004-1159 | ||
CR-RBS-2005- | Evaluation Reports for Drills conducted | ||
CR-RBS-2005- | September 3, 2003 December 1, 2004 (simulator) | ||
CR-RBS-2005- | March 2 2004 December 1, 2004 (medical) | ||
CR-RBS-2005- | April 20, 2004 March 24, 2005 | ||
CR-RBS-2005- | May 25, 2004 April 19, 2005 | ||
CR-RBS-2005- | June 9, 2004 June 21, 2005 | ||
CR-RBS-2005- | July 27, 2004 | ||
CR-RBS-2005- | Licensee Self-Assessments | ||
CR-RBS-2005- | 2004 Evaluated Exercise Pre-Assessment | ||
CR-RBS-2005- | LO-RLO-2004-00004 CA56, 2004 Long Range ERO Staffing Assessment | ||
CR-RBS-2005- | 2005 Emergency Planning Program Assessment | ||
CR-RBS-2005- | Snapshot Assessment of RBS Siren System | ||
CR-RBS-2005-04118 | Section 4OA1: Performance Indicator Verification | ||
A- | Procedures | ||
EN-EP-201, Emergency Planning Performance Indicators, Revision 2 | |||
CR- | EPP-2-703, Performance Indicators, Revision 2 | ||
EIP-2-001, Classification of Emergencies, Revision 12 | |||
EIP-2-002, Classification Actions, Revision 24 | |||
EIP-2-006, Notifications, Revision 32 | |||
EIP-2-007, Protective Action Recommendation Guidelines, Revision 20 | |||
EIP-2-007, Protective Action Recommendation Guidelines, Revision 21 | |||
A-5 Attachment | |||
Section 2OS2: ALARA Planning and Controls | |||
Condition Reports | |||
CR-RBS-2005-01472 CR-RBS-2005-02558 | |||
CR-RBS-2005-01474 CR-RBS-2005-03382 | |||
CR-RBS-2005-02076 CR-RBS-2005-04004 | |||
Audits and Self-Assessments | |||
QA-14-2005-RBS-1 Quality Assurance Audit of Radiation Protection Snapshot | |||
Assessment /Benchmark on: Effectiveness of the RP TAC/TRG | |||
(July 11-13, 2005) | |||
QS-2005-RBS-009 ALARA Planning and Controls (August 22 through | |||
September 1, 2005) | |||
LO#2005-00123 Radiation Protection Program (July 11-15, 2005) | |||
Radiation Work Permits | |||
2005-1073 Change out filter elements LWS-SKD5-F100A | |||
2005-1110 Clean-up FB 113' cask pool and install cask pool impact limiter | |||
2005-1310 Recirc Flow Control Valve Maintenance | |||
Procedures | |||
ENS-RP-105 Radiation Work Permits, Revision 7 | |||
RP-110 ALARA Program, Revision 2 | |||
ALARA Committee Minutes | |||
AMC 05-01 January 11, 2005 | |||
AMC 05-02 January 12, 2005 | |||
AMC 05-03 January 17, 2005 | |||
AMC 05-11 July 14, 2005 | |||
Section 4OA2: Identification and Resolution of Problems | |||
Condition reports | |||
CR-RBS-2005-02444 CR-RBS-2005-02570 | |||
CR-RBS-2005-02481 CR-RBS-2005-02590 | |||
CR-RBS-2005-02486 CR-RBS-2005-02605 | |||
CR-RBS-2005-02494 CR-RBS-2005-02621 | |||
CR-RBS-2005-02548 CR-RBS-2005-02624 | |||
CR-RBS-2005-02563 CR-RBS-2005-02626 | |||
A-6 Attachment | |||
CR-RBS-2005-02645 CR-RBS-2005-03446 | |||
CR-RBS-2005-02649 CR-RBS-2005-03471 | |||
CR-RBS-2005-02659 CR-RBS-2005-03474 | |||
CR-RBS-2005-02664 CR-RBS-2005-03503 | |||
CR-RBS-2005-02686 CR-RBS-2005-03509 | |||
CR-RBS-2005-02693 CR-RBS-2005-03513 | |||
CR-RBS-2005-02695 CR-RBS-2005-03515 | |||
CR-RBS-2005-02722 CR-RBS-2005-03554 | |||
CR-RBS-2005-02724 CR-RBS-2005-03586 | |||
CR-RBS-2005-02727 CR-RBS-2005-03594 | |||
CR-RBS-2005-02738 CR-RBS-2005-03619 | |||
CR-RBS-2005-02754 CR-RBS-2005-03629 | |||
CR-RBS-2005-02760 CR-RBS-2005-03645 | |||
CR-RBS-2005-02767 CR-RBS-2005-03670 | |||
CR-RBS-2005-02768 CR-RBS-2005-03706 | |||
CR-RBS-2005-03106 CR-RBS-2005-03728 | |||
CR-RBS-2005-03111 CR-RBS-2005-03747 | |||
CR-RBS-2005-03114 CR-RBS-2005-03753 | |||
CR-RBS-2005-03125 CR-RBS-2005-03787 | |||
CR-RBS-2005-03131 CR-RBS-2005-03831 | |||
CR-RBS-2005-03138 CR-RBS-2005-03847 | |||
CR-RBS-2005-03151 CR-RBS-2005-03887 | |||
CR-RBS-2005-03152 CR-RBS-2005-03918 | |||
CR-RBS-2005-03165 CR-RBS-2005-03948 | |||
CR-RBS-2005-03178 CR-RBS-2005-03969 | |||
CR-RBS-2005-03182 CR-RBS-2005-04018 | |||
CR-RBS-2005-03220 CR-RBS-2005-04064 | |||
CR-RBS-2005-03242 CR-RBS-2005-04071 | |||
CR-RBS-2005-03265 CR-RBS-2005-04095 | |||
CR-RBS-2005-03273 CR-RBS-2005-04103 | |||
CR-RBS-2005-03279 CR-RBS-2005-04106 | |||
CR-RBS-2005-03443 CR-RBS-2005-04118 | |||
A-7 Attachment | |||
LIST OF ACRONYMS | |||
ALARA as low as is reasonably achievable | |||
CFR Code of Federal Regulations | |||
CR condition report | |||
CR-RBS River Bend Station condition report | |||
EAL emergency action level | |||
FEMA Federal Emergency Management Agency | |||
FCV flow control valve | |||
HPU hydraulic power unit | |||
MC manual chapter | |||
LER licensee event report | |||
LCO limiting condition for operation | |||
LOCA loss of coolant accident | |||
NCV noncited violation | |||
NEI Nuclear Energy Institute | |||
NRC U.S. Nuclear Regulatory Commission | |||
RCIC reactor core isolation cooling system | |||
RCS reactor coolant system | |||
RR reactor recirculation system | |||
SOP system operating procedures | |||
STP surveillance test procedure | |||
TS Technical Specification | |||
USAR Updated Safety Analysis Report | |||
WO work order | |||
A-8 Attachment | |||
}} | }} |
Latest revision as of 23:22, 23 November 2019
ML060450209 | |
Person / Time | |
---|---|
Site: | River Bend ![]() |
Issue date: | 02/13/2006 |
From: | Kennedy K NRC/RGN-IV/DRP/RPB-C |
To: | Hinnenkamp P Entergy Operations |
References | |
IR-05-005 | |
Download: ML060450209 (41) | |
See also: IR 05000458/2005005
Text
February 13, 2006
Paul D. Hinnenkamp
Vice President - Operations
Entergy Operations, Inc.
River Bend Station
5485 US Highway 61N
St. Francisville, Louisiana 70775
SUBJECT: RIVER BEND STATION - NRC INTEGRATED INSPECTION
REPORT 05000458/2005005
Dear Mr. Hinnenkamp:
On December 31, 2005, the U.S. Nuclear Regulatory Commission (NRC) completed an
inspection at your River Bend Station. The enclosed integrated inspection report documents
the inspection findings which were discussed with you and other members of your staff on
January 4, 2006.
The inspection examined activities conducted under your license as they relate to safety and
compliance with the Commissions rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed
personnel.
Based on the results of this inspection, two NRC identified findings and one self-revealing
finding were evaluated under the risk significance determination process as having very low
safety significance (Green). The NRC has also determined that violations are associated with
these findings. However, because these violations were of very low safety significance and
were entered into your corrective action program, the NRC is treating these violations as
noncited violations, consistent with Section VI.A.1 of the NRCs Enforcement Policy. If you
contest the violations or the significance of the 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, U.S. Nuclear Regulatory Commission, Region IV, 611
Ryan Plaza Drive, Suite 400, Arlington, Texas 76011-4005; the Director, Office of Enforcement,
U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident
Inspector at the River Bend Station facility.
In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its
enclosure, 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
NRCs document system (ADAMS). ADAMS is accessible from the NRC Website at
http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Entergy Operations, Inc. -2-
Should you have any questions concerning this inspection, we will be pleased to discuss them
with you.
Sincerely,
/RA/
Kriss M. Kennedy, Chief
Project Branch C
Division of Reactor Projects
Docket: 50-458
License: NPF-47
Enclosures:
NRC Inspection Report 05000458/2005005
w/Attachment: Supplemental Information
cc w/enclosure:
Senior Vice President and
Chief Operating Officer
Entergy Operations, Inc.
P.O. Box 31995
Jackson, MS 39286-1995
Vice President
Operations Support
Entergy Operations, Inc.
P.O. Box 31995
Jackson, MS 39286-1995
General Manager
Plant Operations
Entergy Operations, Inc.
River Bend Station
5485 US Highway 61N
St. Francisville, LA 70775
Director - Nuclear Safety
Entergy Operations, Inc.
River Bend Station
5485 US Highway 61N
St. Francisville, LA 70775
Entergy Operations, Inc. -3-
Wise, Carter, Child & Caraway
P.O. Box 651
Jackson, MS 39205
Winston & Strawn LLP
1700 K Street, N.W.
Washington, DC 20006-3817
Manager - Licensing
Entergy Operations, Inc.
River Bend Station
5485 US Highway 61N
St. Francisville, LA 70775
The Honorable Charles C. Foti, Jr.
Attorney General
Department of Justice
State of Louisiana
P.O. Box 94005
Baton Rouge, LA 70804-9005
H. Anne Plettinger
3456 Villa Rose Drive
Baton Rouge, LA 70806
Burt Babers, President
West Feliciana Parish Police Jury
P.O. Box 1921
St. Francisville, LA 70775
Michael E. Henry, State Liaison Officer
Department of Environmental Quality
Permits Division
P.O. Box 4313
Baton Rouge, LA 70821-4313
Brian Almon
Public Utility Commission
William B. Travis Building
P.O. Box 13326
1701 North Congress Avenue
Austin, TX 78711-3326
Entergy Operations, Inc. -4-
Chairperson
Denton Field Office
Chemical and Nuclear Preparedness
and Protection Division
Office of Infrastructure Protection
Preparedness Directorate
Dept. of Homeland Security
800 North Loop 288
Federal Regional Center
Denton, TX 76201-3698
Entergy Operations, Inc. -5-
Electronic distribution by RIV:
Regional Administrator (BSM1)
DRP Director (ATH)
DRS Director (DDC)
DRS Deputy Director (RJC1)
Senior Resident Inspector (PJA)
Branch Chief, DRP/C (KMK)
Senior Project Engineer, DRP/C (WCW)
Team Leader, DRP/TSS (RLN1)
RITS Coordinator (KEG)
J. Dixon-Herrity, OEDO RIV Coordinator (JLD)
ROPreports
RBS Site Secretary (LGD)
W. A. Maier, RSLO (WAM)
SUNSI Review Completed: _kmk_ ADAMS: : Yes G No Initials: __kmk__
- Publicly Available G Non-Publicly Available G Sensitive : Non-Sensitive
R:\_REACTORS\_RB\2005\RB2005-05RP-PJA.wpd
RIV:SRI:DRP/C RI:DRP/C C:DRS/OB C:DRS/EB1 C:DRS/PSB
PJAlter MOMiller ATGody JClark MPShannon
T - KMKennedy E - KMKennedy /RA/ /RA/ /RA/
2/ /06 2/ /06 2/ /06 2/ /06 2/ /06
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LJSmith KMKennedy
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2/13/06 2/13/06
OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket: 50-458
License: NPF-47
Report: 05000458/2005005
Licensee: Entergy Operations, Inc.
Facility: River Bend Station
Location: 5485 U.S. Highway 61
St. Francisville, Louisiana
Dates: October 1 through December 31, 2005
Inspectors: P. Alter, Senior Resident Inspector, Project Branch C
M. Miller, Resident Inspector, Project Branch C
J. Keeton, Consultant, Region IV
P. Elkmann, Emergency Preparedness Inspector, Operations Branch
G. Johnston, Senior Operations Engineer, Operations Branch
L. Ricketson, Senior Health Physicist, Plant Support Branch
Approved By: Kriss M. Kennedy, Chief
Project Branch C
Division of Reactor Projects
-1- Enclosure
TABLE OF CONTENTS
SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
REPORT DETAILS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
REACTOR SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
1R01 Adverse Weather Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
1R04 Equipment Alignment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
1R05 Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
1R11 Licensed Operator Requalification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
1R13 Maintenance Risk Assessments and Emergent Work Control . . . . . . . . . . . . . 10
1R14 Operator Performance During Non-routine Plant Evolutions . . . . . . . . . . . . . . 11
1R15 Operability Evaluations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
1R16 Operator Work-Arounds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
1R17 Permanent Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
1R19 Postmaintenance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
1R22 Surveillance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
1R23 Temporary Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
1EP2 Alert and Notification System Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
1EP3 Emergency Response Organization Augmentation . . . . . . . . . . . . . . . . . . . . . 20
1EP5 Correction of Emergency Preparedness Weaknesses and Deficiencies . . . . . 20
1EP6 Drill Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
RADIATION SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
2OS2 ALARA Planning and Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
OTHER ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
4OA1 Performance Indicator Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
4OA2 Identification and Resolution of Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
4OA3 Event Followup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
4OA6 Meetings, Including Exit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
SUPPLEMENTAL INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1
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-8
-2- Enclosure
SUMMARY OF FINDINGS
IR 05000458/2005005; 10/01/2005 - 12/31/2005; River Bend Station; Licensed Operator
Requalification, Operator Performance During Nonroutine Plant Evolutions, Permanent Plant
Modifications.
The report covered a 3-month period of routine baseline inspections by resident inspectors and
announced baseline inspections by regional emergency planning, operations, and radiation
protection inspectors. Three Green noncited violations were identified. The significance of
most findings is indicated by their color (Green, White, Yellow, 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 3,
dated July 2000.
A. NRC-Identified and Self-Revealing Findings
Cornerstone: Initiating Events
- Green. The NRC identified a noncited violation of Technical Specification 3.4.1.A for the
licensees failure to shut down one reactor recirculation loop within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of
determining that jet pump loop flow mismatch was greater than 5 percent while
operating at greater than 70 percent of rated core flow. On October 31, 2005, the
Reactor Recirculation Flow Control Valve B hydraulic power unit tripped because of a
blown control power fuse, causing Flow Control Valve B to drift open. Operators
throttled closed Flow Control Valve A to maintain reactor power at 100 percent, resulting
in a jet pump loop flow mismatch of approximately 8.2 percent. The flow mismatch
existed for 4.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. The licensee entered this into their corrective action program as
Condition Report CR-RBS-2006-00274.
The finding was more than minor because, if left uncorrected, it would become a more
significant safety concern. Matched recirculation loop flows is an assumption used in
the accident analysis for a loss of coolant accident resulting from a loop break. A flow
mismatch could result in core response that is more severe than assumed in the
accident analysis. The significance of this finding could not be evaluated using
MC 0609, Significance Determination Process. Based on management review, the
finding was determined to be of very low safety significance based on the short duration
of the flow mismatch, 4.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />, and the low likelihood of a loss of coolant accident
during that time. The cause of this finding is related to the crosscutting element of
human performance in that operators failed to implement Technical Specification
requirements (Section 1R14).
Cornerstone: Mitigating Systems
- Green. A self-revealing noncited violation of 10 CFR Part 50, Appendix B, Criterion III,
Design Control, was identified for the licensees failure to address the worst case
conditions in the sizing calculation for the reactor core isolation cooling turbine exhaust
-3- Enclosure
line vacuum breaker system as part of a plant modification to remove the internals of the
reactor core isolation cooling turbine exhaust line check valve. As a result, on
December 10, 2004, when the reactor core isolation cooling system was started and
subsequently shutdown on high reactor water level following a scram and loss of
feedwater, the turbine exhaust line filled with water from the suppression pool, causing
the operators to consider the system unavailable and complicating their response to the
event. The licensee entered this finding into their corrective action program as CR-
RBS-2005-00724 and reinstalled the turbine exhaust line check valve internals in
February 2005.
The finding was more than minor because it was associated with the Mitigating Systems
cornerstone attribute of Design Control and affected the cornerstone objective to ensure
the availability and reliability of the reactor core isolation cooling system, a system that
responds to initiating events (loss of feedwater and station blackout), to prevent
undesirable consequences. Using Manual Chapter 0609, Significance Determination
Process, Phase 1 Worksheet, the finding was determined to have very low safety
significance because it represented a design deficiency that did not result in a loss of
system function (Section 1R17).
Cornerstone: Emergency Preparedness
- Green. The NRC identified a noncited violation of 10 CFR Part 50, Appendix E,
Section IV. B., as a result of inadequate procedures for the implementation of an
emergency action level. The criteria in Procedure EIP-2-001, Classification of
Emergencies, Revision 12, for declaring an Alert emergency action level based on
primary coolant leak rate, relied solely on a computer generated leakrate report that
would not be valid under all conditions. The licensee entered this finding into their
corrective action program as CR-RBS-2005-03078 and issued Standing Order 192, as
an interim corrective action, to provide additional criteria to determine whether a primary
coolant leak rate Alert emergency action level declaration was required.
The finding is more than minor because it is associated with the Emergency
Preparedness Cornerstone attribute of procedural quality and affects the cornerstone
objective to ensure the licensee is capable of implementing adequate measures to
protect the health and safety of the public in the event of a radiological emergency. The
inadequate procedure could result in a failure to declare an Alert emergency
classification when required. Using Manual Chapter 0609, Appendix B, Emergency
Preparedness Significance Determination Process, this finding was determined to be of
very low safety significance since it was a failure to comply with a regulatory
requirement associated with a risk-significant planning standard that did not result in the
loss or degradation of that risk-significant planning standard function (Section 1R11).
B. Licensee-Identified Violations
None.
-4- Enclosure
REPORT DETAILS
Summary of Plant Status
On October 1, 2005, reactor power was lowered to 70 percent to perform a rod sequence
exchange and insert two control rods for planned maintenance. The reactor was returned to
100 percent power on October 2, 2005. On October 21, 2005, reactor power was lowered to 63
percent to perform power suppression testing for a leaking fuel bundle. The reactor was
returned to 100 percent power on October 23, 2005. On November 5, 2005, reactor power was
lowered to 90 percent to adjust the control rod pattern and the reactor was returned to 100
percent later that day. On December 2, 2005, reactor power was lowered to 83 percent to
insert three control rods for planned maintenance. The reactor was returned to 100 percent
power on December 3, 2005. On December 9, 2005, reactor power was lowered to 58 percent
to perform a control rod pattern adjustment and conduct turbine valve testing. The reactor was
returned to 100 percent power on December 11, 2005. On December 17, 2005, reactor power
was lowered to 62 percent to perform power suppression testing for a leaking fuel bundle. The
reactor was returned to 100 percent on December 19, 2005, and remained at 100 percent for
the remainder of the inspection period.
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency
Preparedness
1R01 Adverse Weather Protection
b. Inspection Scope
Cold Weather Preparation
During the week of December 5, 2005, the inspectors reviewed the licensees
implementation of Operations Section Procedure OSP-0043, Freeze Protection and
Temperature Maintenance, Revision 6, to protect mitigating systems from cold weather
conditions. Specifically, the inspectors: (1) verified that risk-significant structures,
systems, and components will remain functional when challenged by cold weather
conditions; (2) verified that cold weather features such as heat tracing and space
heaters are operable and monitored; and (3) verified that the cold weather procedures
attachments were being completed for changing temperatures as required by the
procedure. The inspectors completed one inspection sample.
c. Findings
No findings of significance were identified.
-5- Enclosure
1R04 Equipment Alignment
1. Partial System Walkdowns
a. Inspection Scope
On October 25, 2005, the inspectors walked down residual heat removal Division II
while residual heat removal Division I was out of service for scheduled maintenance.
On October 26, 2005, the inspectors walked down the piping and valve lineup of the
condensate storage tank, including emergency core cooling system suction and test
return valves. In each case, the inspectors verified the correct valve and power
alignments by comparing positions of valves, switches, and electrical power breakers to
the system operating procedures (SOP) and piping and instrument drawings listed
below and applicable sections of the Updated Safety Analysis Report (USAR). The
inspectors completed two inspection samples.
- SOP-0031, Residual Heat Removal System, Revision 46
- SOP-0008, Condensate Storage, Makeup and Transfer, Revision 16
- Piping and Instrument PID 04-03A, Condensate Storage, Makeup and
Transfer, Revision 13
b. Findings
No findings of significance were identified.
2. Complete System Walkdown
a. Inspection Scope
The inspectors conducted a complete walkdown of the drywell and containment leak
detection system during the week of June 26, 2005, during a drywell closeout inspection
and continuing the week of November 20, 2005. The methods of inspection included
field walkdown, in-office reviews, observation of system operation, and interviews of
computer engineering, operations, training, and emergency planning personnel. The
inspectors verified: (1) proper valve and control switch alignments, (2) computer
program algorithm, (3) power supply lineup, (4) associated support system status, and
(5) that alarms and indications in the main control room were as specified in the
following documents:
- SOP-0033, Drywell and Containment Leak Detection System, Revision 11
- USAR Section 5.2.5.1.1, Detection of Leakage within the Drywell
- Technical Specifications (TS) Section 3.4.5, RCS Operational Leakage
The inspectors also verified electrical power requirements, labeling, hangers and
support installation, and associated support systems status. The walkdowns included
-6- Enclosure
evaluation of system piping and supports to ensure (1) piping and pipe supports did not
show evidence of damage, (2) hangers were secure, and (3) component foundations
were not degraded. The inspectors completed one inspection sample.
b. Findings
No findings of significance were identified.
1R05 Fire Protection
a. Inspection Scope
The inspectors walked down accessible portions of the plant described below to assess:
(1) the licensees control of transient combustible material and ignition sources; (2) fire
detection and suppression capabilities; (3) manual firefighting equipment and capability;
(4) the condition of passive fire protection features, such as, electrical raceway fire
barrier systems, fire doors, and fire barrier penetrations; and (5) any related
compensatory measures. The inspectors reviewed the Pre-Fire Plan/Strategy Book
during the fire protection inspections. The areas inspected were:
- Auxiliary building, 70-foot, RHR Pump B Room, fire Area AB-3, on October 11,
2005
- Auxiliary building, 95-foot, HPCS piping area, fire Area AB-2/Z-2, on October 12,
2005
- Auxiliary building, 95-foot, LPCS panel room, fire Area AB-6/Z33, on October 12,
2005
- Control building, 116-foot, safety-related 125 Vdc switchgear room, fire
Area C-24, on December 9, 2005
- Control building, 116-foot, safety-related Switchgear 1C room, fire Area C-22, on
December 9, 2005
- Control building, 116-foot, safety-related ENB inverter Charger A room, fire
Area C-18, on December 9, 2005
The inspectors completed six inspection samples.
b. Findings
No findings of significance were identified.
-7- Enclosure
1R11 Licensed Operator Requalification Program
a. Inspection Scope
.1 Annual Operating Examination Review
Following the completion of the annual operating examination testing cycle, which ended
the week of September 23, 2005, the inspectors reviewed the overall pass/fail results of
the annual individual job performance measure operating tests and simulator operating
tests administered by the licensee during the operator licensing requalification cycle.
Eight separate crews participated in simulator operating tests and job performance
measure operating tests, totaling 52 licensed operators. All of the crews tested passed
the simulator portion of the annual operating test. Two of the 52 licensed operators
failed the job performance measure portion and were successfully remediated. These
results were compared to the thresholds established in MC 0609, Appendix I, Operator
Requalification Human Performance Significance Determination Process. The
inspector completed one inspection sample.
.2 Resident Inspector Quarterly Review
On November 15, 2005, the inspectors observed simulator training of an operating crew,
as part of the operator requalification training program, to assess licensed operator
performance and the training evaluators critique. The inspection included observation
of high risk licensed operator actions, operator activities associated with the emergency
plan, and lessons learned from industry and plant experiences. In addition, the
inspectors compared simulator control panel configurations with the actual control room
panels for consistency. The simulator examination scenario observed was RSMS-OPS-
612, Loss of Vacuum/ATWS/Drywell Steam Leak - RPV Flooding, Revision 4. The
inspectors completed one inspection sample.
.3 Inadequate Emergency Event Classification Guidance
On June 10, 2005, the inspectors observed operating crew performance in the simulator
during annual requalification exam Scenario RSMS-OPS-509, SRV Tailpipe Steam
Leak Inside The Drywell, Revision 3. The inspectors discussed crew actions and
emergency planning requirements with the examination evaluators, training
management, emergency planning coordinators, and operations management. The
inspectors reviewed the following documents:
- EIP-2-001, Classification of Emergencies, Revision 12
- USAR 5.2.5.1.1, Detection of Leakage within the Drywell
- Vendor computer manual, VTD-A324-0109, Analog Devices MICROMAC-5000
Final Draft, Leak Rate Detection PLC Documentation, River Bend Station -
Reactor Building Sump Systems, Revision 0
-8- Enclosure
- Training Evaluation and Request, TEAR-RBS-2005-0477, Validating Leakage
Report, issued August 23, 2005
- CR-RBS-2005-03078, Validating Leakage Report, initiated on August 26, 2005
- Standing Order Number 192, Drywell Leakage Greater Than 50 gpm EAL
Guidance, Revision 0, issued November 3, 2005
b. Findings
Introduction: The inspectors identified a Green NCV of 10 CFR Part 50, Appendix E,
Section IV.B, for inadequate procedures for implementation of an Alert emergency
action level (EAL).
Description: On June 10 2005, the inspectors observed operating crew performance in
the simulator during annual requalification exam Scenario RSMS-OPS-509, SRV
Tailpipe Steam Leak Inside The Drywell, Revision 3. The inspectors noted that when
the examination evaluators informed the team that the total drywell leakage report was
84 gpm, the team declared an Alert based on that report. Procedure EIP-2-001,
Classification of Emergencies, Revision 12, listed the criteria for an Alert EAL
classification as Total drywell LEAKAGE greater than 50 gpm.
Based on their observations in the simulator, the inspectors questioned the ability of the
leakage computer installed in the plant to accurately calculate total drywell leakage
under certain conditions. The inspectors analyzed the program run by the drywell
leakage computer and determined: (1) the drywell leakage computer would not
calculate total drywell leakage while a drywell sump pump was running; (2) computer
reports of total drywell leakage printed while a drywell sump pump was running would be
invalid; and (3) if a drywell high pressure or low reactor vessel level signal was present,
the valves in the drywell sump pump discharge lines would close, causing the drywell
sump pumps to run continuously, resulting in an invalid drywell total leakage report. The
inspectors determined that the indication used by operators to determine if the criteria
was met for declaring an Alert EAL due to total drywell leakage exceeding 50 gpm would
not be valid under certain conditions.
On August 23, 2005, the licensee initiated training evaluation action request TEAR-
2005-0477 to evaluate this condition to determine what training actions were necessary.
On August 26, 2005, the licensee initiated CR-RBS-2005-03078 that requested an
alternate means of determining the primary coolant leak Alert EAL using main control
room indications. The CR also requested additional training materials and classroom
instruction to reinforce this change.
On November 3, 2005, the licensee issued Standing Order 192 that provided additional
criteria to be used to make the determination of whether a primary coolant leak rate
Alert EAL declaration was required, without relying solely on the drywell leakage
computer. The inspectors concluded that Standing Order 192 was an adequate interim
compensatory measure until the licensee implemented permanent corrective actions.
-9- Enclosure
Analysis: The performance deficiency associated with this finding involved an
inadequate procedural criteria for declaring an Alert EAL in the event that total drywell
leakage exceeds 50 gpm under certain conditions. Specifically, computed drywell
leakrate used by operators to determine if total drywell leakage exceeds 50 gpm may be
invalid under certain conditions. The finding was more than minor because it is
associated with the Emergency Preparedness Cornerstone attribute of procedural
quality and affects the cornerstone objective to ensure the licensee is capable of
implementing adequate measures to protect the health and safety of the public in the
event of a radiological emergency. The inadequate procedure could result in a failure to
declare an Alert emergency classification when required. Using Manual Chapter 0609,
Appendix B, Emergency Preparedness Significance Determination Process, this
finding was determined to be of very low safety significance since it was a failure to
comply with a regulatory requirement associated with a risk-significant planning
standard that did not result in the loss or degradation of that risk-significant planning
standard function.
Enforcement: The failure to provide adequate procedures for implementation of an EAL
was a violation of 10 CFR Part 50, Appendix E, Section IV.B., which requires, in part,
that the licensees emergency plan describe the means to be used for determining the
impact of the release of radioactive materials including EALs. Because this finding was
of very low safety significance and was entered into the licensees corrective action
program as CR-RBS-2005-03078, this violation is being treated as an NCV, consistent
with Section VI.A of the NRC Enforcement Policy: NCV 05000458/2005005-01,
Inadequate procedure for implementation of an EAL.
1R13 Maintenance Risk Assessments and Emergent Work Control
a. Inspection Scope
The inspectors reviewed selected maintenance activities to verify the performance of
assessments of plant risk related to planned and emergent maintenance work activities.
The inspectors verified: (1) the adequacy of the risk assessments and the accuracy and
completeness of the information considered, (2) management of the resultant risk and
implementation of work controls and risk management actions, and (3) effective control
of emergent work, including prompt reassessment of resultant plant risk. The inspectors
completed three inspection samples.
.1 Risk Assessment and Management of Risk
On a routine basis, the inspectors verified performance of risk assessments, in
accordance with administrative Procedure ADM-096, Risk Management Program
Implementation and On-Line Maintenance Risk Assessment, Revision 04, for planned
maintenance activities and emergent work involving structures, systems, and
components within the scope of the maintenance rule. Specific work activities evaluated
included the following planned and emergent work:
- October 23, 2005, Division I residual heat removal and standby service water
equipment outage
-10- Enclosure
- November 28, 2005, Division III work week and station blackout diesel generator
planned maintenance
.2 Emergent Work Control
During emergent work, the inspectors verified that the licensee took actions to minimize
the probability of initiating events, maintained the functional capability of mitigating
systems, and maintained barrier integrity. The inspectors also reviewed the emergent
work activities to ensure the plant was not placed in an unacceptable configuration. The
specific emergent work activity followed was the cleaning of high voltage insulators in
the main transformer switchyard with a high pressure spray on October 7, 2005.
b. Findings
No findings of significance were identified.
1R14 Operator Performance During Nonroutine Evolutions and Events
c. Inspection Scope
The inspectors completed the two inspection samples listed below.
.1 Power Suppression Testing
The inspectors observed portions of and reviewed control room records for power
suppression testing conducted during the weekend of October 21, 2005. The inspectors
reviewed the reactivity control plan, the prejob briefing given in the main control room at
the beginning of the evolution and during control room operator and reactor engineer
shift turnover. The inspectors also reviewed the results of the test with the reactor
engineering representative and shift manager, including the recommendation to insert
Control Rod 20-45 to suppress power in the vicinity of a potential leaking fuel bundle.
Finally, the inspectors reviewed the postsuppression test off-gas pretreatment gaseous
activity levels used to monitor the success of the suppression efforts.
.2 Trip of Reactor Recirculation (RR) Flow Control Valve (FCV) Hydraulic Power
Unit (HPU)
On October 31, 2005, the inspectors observed operator response to a trip of RR FCV B
HPU. As a result, RR FCV B began to drift open. The operators took action to limit or
stop the gradual opening of RR FCV B. As RR FCV B continued to open, operators
throttled closed RR FCV A to maintain reactor power less than 100 percent. These
actions created an RR jet pump loop flow mismatch of greater than 5 percent requiring
entry into TS Action 3.4.1.A. The inspectors reviewed the TS requirements for this
condition and discussed the actions taken by the operators with the operations shift
-11- Enclosure
manager and members of plant management team present in the control room at the
time. The following documents were reviewed by the inspectors as part of this
inspection:
C Main Control Room Logs, October 31, 2005
C CR-RBS-2005-03748, During Filter RCS-FLTR2B replacement, technicians
bumped an electrical cable, causing a trip of the reactor recirculation flow control
Valve B hydraulic power unit
C W0 00075986, Replace grounded connection to Pressure Switch RCS-PDS90B
C SOP-0003, Reactor Recirculation System, Revision 35
C TS limiting condition for operation (LCO) 3.4.1 and applicable Bases
i. Findings
Introduction: The inspectors identified a Green noncited violation of TS Action 3.4.1.A.1
for the licensees failure to restore compliance with LCO 3.4.1 or shut down one RR loop
within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of determining that RR loop jet pump flow mismatch was greater than
5 percent while operating at greater than 70 percent of rated core flow.
Description: On October 31, 2005, at 2:54 p.m., the RR FCV B HPU tripped. As a
result, RR FCV B began to drift open. The operators took action to limit or stop the
gradual opening of RR FCV B. As RR FCV B continued to open, operators throttled
closed RR FCV A to maintain reactor power less than 100 percent.
At 3:06 p.m., the operators entered TS LCO Condition 3.4.1.A because the RR loop jet
pump flow mismatch exceeded 5 percent with the plant operating at greater than 70
percent rated core flow. The highest flow mismatch was 8.2 percent. TS Action
3.4.1.A.1 required the licensee to shut down one recirculation loop with 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.
The licensee issued a work request and began to troubleshoot the HPU trip. At the
same time, operators requested that reactor engineers develop a reactivity control plan
to insert control rods to lower reactor power. This would allow operators to reopen
RR FCV A to reduce the RR jet pump loop flow mismatch to less than the required
5 percent.
At 4:24 p.m., the licensee determined that the cause for the HPU trip was a blown
control power fuse. The fuse blew as a result of a grounded wire to a filter high
differential pressure switch, which was bumped by maintenance technicians who were
changing the filter cartridge. The inspectors asked the operators and licensee
management if they intended to shut down one RR loop or perform the actions
necessary to reduce the jet pump flow mismatch to less than 5 percent, as required by
TS 3.4.1. The licensee responded that they did not want to maneuver the plant and
change core conditions, which might exacerbate the existing condition of two leaking
fuel bundles.
-12- Enclosure
At 5:06 p.m., the operators exited TS Action 3.4.1.A without shutting down one RR loop
or reducing jet pump loop flow mismatch to less than 5 percent. Instead they entered
TS Action 3.4.1.D.1, which required that the reactor be placed in Mode 3 in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
When asked, the operators and licensee management stated that they could commence
a plant shutdown within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and still meet the requirement to be in Mode 3
in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. They also stated that at the 6-hour point, they would commence the
shutdown with the reactivity control plan to reduce reactor power by inserting control
rods and open RR FCV A to reduce jet pump loop flow mismatch to less than 5 percent.
If that was successful, they would then exit TS LCO 3.4.1.
Subsequently, the repairs were completed to the pressure switch wire, the control power
fuse was replaced, and RR FCV B HPU was restarted. Following a one-hour warmup,
the RR FCV B HPU was returned to service. RR jet pump loop flow was reduced below
5 percent and the licensee exited TS LCO 3.4.1. at 7:36 p.m., 4.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> after entry into
TS LCO Condition 3.4.1.A.
The inspectors determined that: (1) when the cause of the trip of RR FCV B HPU was
determined to be the grounded pressure switch wire, the licensee knew that the time to
make the repairs and return the HPU to service would exceed the 2-hour completion
time of TS Action 3.4.1.A.1; and (2) the licensee was capable of restoring RR jet pump
loop flow mismatch to less than 5 percent or shutting down one RR loop within the
2-hour completion time of TS Action 3.4.1.A.1.
Analysis: The licensees failure to restore compliance with TS LCO 3.4.1 or complete
the required action of TS 3.4.1.A.1 to shut down one RR loop within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> was a
performance deficiency. The finding was more than minor because, if left uncorrected,
it would become a more significant safety concern. According to TS LCO 3.4.1 Bases,
the operation of the RR pumps is an initial condition assumed for the design basis loss-
of-coolant accident (LOCA). During a LOCA caused by a RR loop break, the intact RR
loop is assumed to provide coolant flow during the first few seconds of the accident.
The initial core flow decrease is rapid because the RR pump in the broken loop ceases
to pump water through the vessel almost immediately. The pump in the intact loop
coasts down more slowly. This pump coast down governs the core flow response for
the next several seconds until the jet pump suctions are uncovered. The analyses
assume that both RR loops are operating at the same flow prior to the LOCA. However,
if the LOCA analysis is reviewed for an initial jet pump flow mismatch with the break
assumed to be in the loop with the higher flow, the flow coast down and core response
are potentially more severe, since the intact loop starts at a lower flow rate.
The significance of this finding could not be evaluated using MC 0609, Significance
Determination Process. Based on management review, the finding was determined to
be of very low safety significance based on the short duration of the flow mismatch,
4.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />, and the low likelihood of a LOCA during that time. The cause of this finding
is related to the crosscutting element of human performance in that operators failed to
implement TS requirements.
Enforcement: TS LCO 3.4.1 states that two RR loops shall be in operation with
matched flows when the reactor is in Modes 1 or 2. If RR loop jet pump flow mismatch
-13- Enclosure
is not less than or equal to 5 percent of rated core flow when operating at greater than
or equal to 70 percent of rated core flow (Condition 3.4.1.A), then the licensee must shut
down one RR loop (Required Action A.1) within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> (Completion Time). Contrary to
the above, on October 31 , 2005, 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> after RR loop jet pump flow mismatch was
greater than 5 percent of rated core flow, the licensee exited TS 3.4.1.A.1 without
shutting down one RR loop or restoring the jet pump flow mismatch to less than
5 percent. Because the finding is of very low safety significance and has been entered
into the licensees corrective action program as CR-RBS-2006-00274, this violation is
being treated as an NCV in accordance with Section IV.A of the NRC Enforcement
Policy and is identified as NCV 05000458/2005005-02: Failure to complete TS required
actions within allowed completion time.
1R15 Operability Evaluations
a. Inspection Scope
The inspectors reviewed selected operability determinations on the basis of potential
risk importance. The selected samples are addressed in the condition reports (CRs)
listed below. The inspectors assessed: (1) the accuracy of the evaluations, (2) the use
and control of compensatory measures if needed, and (3) compliance with TS, the
Technical Requirements Manual, the USAR, and other associated design-basis
documents. The inspectors review included a verification that the operability
determinations were made as specified by Entergy Procedure EN-OP-104, Operability
Determinations, Revision 1. The operability evaluations reviewed were associated with:
- CR-RBS-2004-1270, Check valves in primary Containment 113' elevation airlock
not included in the in-service testing program, reviewed on October 11, 2005
- CR-RBS-2005-3563, Check valves in primary Containment 113' elevation airlock
not included in the in-service testing procedure, reviewed on October 19, 2005
- CR-RBS-2005-3568, In-service test program changed for primary containment
113' elevation airlock without changing in-service test procedure, reviewed on
October 19, 2005
- CR-RBS-2005-04251, -04252, Safety-related Inverter ENB-INV01B1 frequency
and safety-related instrument Bus VBS-PNL01B voltage out of specification high,
reviewed on December 27, 2005
The inspectors completed two inspection samples.
f. Findings
No findings of significance were identified.
-14- Enclosure
1R16 Operator Workarounds
a. Inspection Scope
An operator workaround is defined as a degraded or nonconforming condition that
complicates the operation of plant equipment and is compensated for by operator
action.
During the week of November 28, 2005, the inspectors reviewed an operator
workaround which required operators to hold the control switch for throttle valves for at
least 5 seconds after the full closed indication is received. The inspectors interviewed
operators to determine if they knew specifically which valves were affected and if they
were aware of this operational requirement from memory.
During the week of December 5, 2005, the inspectors reviewed the cumulative effect of
the existing operator workarounds on: (1) the reliability, availability, and potential for
misoperation of any mitigating system; (2) whether they could increase the frequency of
an initiating event; and (3) their effect on the operation of multiple mitigating systems. In
addition, the inspectors reviewed the cumulative effects of the operator workarounds on
the ability of the operators to respond in a correct and timely manner to plant transients
and accidents. The procedures and other documents reviewed by the inspectors were:
- Operator Workaround - Control Room Deficiency Program Guidelines,
Revision 11
- Operator workaround report
- Operator burden report
- Daily plant status reports
- Operations shift turnover sheet
- Standing Order Number 190, Electrically Operated Throttle Valve Operations,
Revision 0
The inspectors completed two inspection samples.
b. Findings
No findings of significance were identified.
1R17 Permanent Plant Modifications
a. Inspection Scope
The inspectors reviewed MR96-0063, Remove Internals of [Reactor Core Isolation
Cooling Turbine (RCIC) Exhaust Check Valve] E51-VF040, dated September 18, 1996,
-15- Enclosure
and the assumptions made with respect to the capability of the RCIC turbine exhaust
line vacuum breaker vent line. On December 10, 2004, the RCIC turbine was manually
started and ran for a short period of time before shutting down on high reactor water
level. The RCIC exhaust line drain trap high level alarm came in and operators
observed water draining from the drain trap for 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The documents reviewed as
part of this inspection are listed in the attachment. The inspectors completed one
inspection sample.
b. Findings
Introduction: The inspectors identified a self-revealing NCV of 10 CFR Part 50,
Appendix B, Criterion III, Design Control, for failure to address a full spectrum of design
conditions for the RCIC turbine exhaust line vacuum breaker system as part of a plant
modification to remove the internals of the RCIC turbine exhaust line check valve. As a
result, on December 10, 2004, when RCIC was started and subsequently shut down on
high reactor water level following a scram and loss of feedwater, the RCIC exhaust line
filled with water from the suppression pool, causing the operators to consider RCIC
unavailable, complicating their response to the event.
Description: In September 1996, in response to a request from mechanical
maintenance, design engineering processed a design change to remove RCIC Turbine
Exhaust Check Valve E51-VF040. As part of Modification Request MR-96-0063, an
evaluation was performed on the adequacy of the RCIC turbine exhaust line vacuum
breaker system to prevent the siphoning of suppression pool water into the RCIC turbine
exhaust line following a shutdown of the RCIC turbine. During the evaluation it was
determined that the as-built vacuum breaker vent line was not in accordance with the
original design of the vacuum breaker line. A new calculation was performed for the
as-built configuration (globe valves and lift check valves versus gate valves and swing
check valves). The basic assumption used for Calculation PH-056, RCIC Turbine
Exhaust Line Vacuum Breaker Vent Line Sizing Verification, Revision 1A, was that the
RCIC exhaust line would be at equilibrium conditions when the turbine tripped. The
turbine would run long enough for the exhausted steam and exhaust piping to be at the
same temperature and that the only cooling effect would be to ambient. The result was
that the gradual cooldown of the steam and exhaust piping would cause the formation of
a vacuum in approximately 35.5 minutes. The revised sizing calculation showed that the
as-built vacuum breaker vent line was capable of relieving a vacuum created in as short
a time as 3.5 minutes.
On December 10, 2004, following a reactor scram, RCIC was started to maintain reactor
water level due to the pending loss of all reactor feed pumps. When RCIC Steam to
Turbine Valve E51-MOV045 stroked full open, it automatically reclosed due to the high
reactor water level interlock. It was later determined that steam was admitted to the
turbine for approximately 11 seconds. As a result, the steam in the exhaust line
condensed more rapidly than assumed and the exhaust line pressure became a vacuum
within 17 seconds. This rapid pressure reduction overwhelmed the vacuum breaker
vent line and 84 gallons of suppression pool water was siphoned into the RCIC turbine
exhaust line.
-16- Enclosure
The licensee later determined that the static and dynamic loads on the turbine exhaust
line for a restart on the RCIC turbine would be within design limits, although a water
hammer transient would occur. Based on test data provided by the turbine
manufacturer, the licensee also determined that the turbine would experience no
damage and not trip on overspeed if it were to be started with water in its exhaust line.
The turbine startup would be slower than normal, but within the assumed values in the
safety analysis. The turbine exhaust line check valve internals were reinstalled in
February 2005.
Analysis: The failure to adequately address worst case design conditions in the sizing
calculation for the RCIC turbine exhaust line vacuum breaker vent line to allow for the
removal of the exhaust line check valve was a performance deficiency. The finding was
more than minor because it was associated with the Mitigating Systems cornerstone
attribute of Design Control and affected the cornerstone objective to ensure the
availability and reliability of the RCIC system, a system that responds to initiating events
(loss of feedwater and station blackout), to prevent undesirable consequences. Using
the MC 0609, Significance Determination Process, Phase 1 Worksheet, the finding
was determined to have very low safety significance because it represented a design
deficiency that did not result in a loss of system function.
Enforcement: 10 CFR Part 50, Appendix B, Criterion III, Design Control, states, in part,
that design changes, including field changes, shall be subject to design change control
measures commensurate with those applied to the original design. Contrary to the
above, the RCIC turbine exhaust line vacuum breaker vent line sizing calculation, used
as part of the modification process to remove the exhaust line check valve, did not take
into consideration the most limiting exhaust line conditions. As a result the vacuum
breaker vent line was not capable of preventing the siphoning of suppression pool water
into the RCIC Turbine Exhaust line. Because this finding was of very low safety
significance and was documented in the licensees corrective action program as
CR-RBS-2005-00724, it is being treated as an NCV in accordance with Section IV. A of
the NRC Enforcement Policy and is identified as NCV 05000458/2005005-03:
Inadequate design assumption results in RCIC turbine exhaust header filling with water
following an automatic high water level shutdown.
1R19 Postmaintenance Testing
a. Inspection Scope
The inspectors reviewed selected work orders (WO) to ensure that testing activities
were adequate to verify system operability and functional capability. The inspectors:
(1) identified the safety function(s) for each system by reviewing applicable licensing
basis and/or design-basis documents; (2) reviewed each maintenance activity to identify
which maintenance function(s) may have been affected; (3) reviewed each test
procedure to verify that the procedure did adequately test the safety function(s) that may
have been affected by the maintenance activity; (4) reviewed the acceptance criteria in
the procedure to ensure consistency with information in the applicable licensing basis
and/or design-basis documents; and (5) identified that the procedure was properly
reviewed and approved. The eight WOs inspected are listed below:
-17- Enclosure
C WO 00063768, replace hydrogen igniter in containment dome, review conducted
during the week of October 31, 2005
C WO 00075881, replace rod control and information system isolation transformer,
reviewed during the week of October 31, 2005
C WO 00074806, rebuild control rod drive Hydraulic Control Unit 4833, review
conducted during the week of December 12, 2005
C WO 50969759, rebuild control rod drive Hydraulic Control Unit 1625, review
conducted during the week of December 12, 2005
C WO 00066597, rework Inverter BYS-INV01A to fix blown fuse problem, review
conducted during the week of December 12, 2005
C WO 50968926, replace frequency detector board on Inverter ENB-INV01B1,
review conducted during the week of December 12, 2005
C WO 00072137, quarterly inspection and lubrication of the station blackout diesel,
review conducted during the week of December 19, 2005
C WO 50967030, clean, inspect, and lubricate the station blackout diesel, review
conducted during the week of December 19, 2005
The inspectors completed eight inspection samples.
b. Findings
No findings of significance were identified.
1R22 Surveillance Testing
a. Inspection Scope
The inspectors verified, by witnessing and reviewing test data, that risk-significant
system and component surveillance tests met TS, USAR, and procedure requirements.
The inspectors ensured that surveillance tests demonstrated that the systems were
capable of performing their intended safety functions and provided operational
readiness. The inspectors specifically: (1) evaluated surveillance tests for
preconditioning; (2) evaluated clear acceptance criteria, range, accuracy and current
calibration of test equipment; and (3) verified that equipment was properly restored at
the completion of the testing. The inspectors observed and reviewed the following
surveillance tests and surveillance test procedures (STP):
C STP-552-4202, "Post Accident Monitoring/Remote Shutdown System -
Suppression Pool Water Level Channel Calibration (CMS-LT23B, CMS-ESX23B,
CMS-LI23B, CMS-TR40B, CMS-LIX23B)," Revision 9A, performed on
October 13, 2005
-18- Enclosure
C MCP-4303, Functional Test of Standby Cooling Tower #1 Station Blackout
Division I Standby Service Water Return Valve and Valve Logic
(SWP-AOV599), Revision 01A, performed on October 25, 2005
C STP-552-4502, "Post Accident Monitoring/Remote Shutdown System - Drywell
Pressure Channel Calibration (CMS-PT2A, CMS-T103, CMS-PR2A),"
Revision 14A, performed on November 28, 2005
The inspectors completed three inspection samples.
b. Findings
No findings of significance were identified.
1R23 Temporary Plant Modifications
a. Inspection Scope
During the week of December 19, 2005, the inspectors reviewed the following temporary
plant modifications: (1) temporary Alteration TA05-0015-00 to supply Division II safety-
related 120 volt ac electrical distribution Panel SCM-PNL01B from safety-related power
Supply RPS-XRC10B1 so that repairs to safety-related power Supply SCM-XRC14B1
could be made; and (2) temporary Alteration TA05-0014-01 to install radiation shielding
in front of standby gas treatment control Panels GTS-PNL28A/B until a permanent
solution could be installed. This shielding was installed after an equipment qualification
evaluation showed that the total integrated dose for standby gas treatment Panel GTS-
PNL28A/B could exceed qualification doses of internal electrical equipment after the
annulus mixing system was retired. Specifically, the inspectors: (1) reviewed each
temporary modification and its associated 10 CFR 50.59 screening against the system's
design basis documentation, including the USAR and TS; (2) verified that the installation
of the temporary modification was consistent with the modification documents; and
(3) reviewed the postinstallation test results to confirm that the actual impact of the
temporary modification on SCM-PNL01B and GTS-PNL28A/B had been adequately
verified. The inspectors completed two inspection samples.
b. Findings
No findings of significance were identified.
Cornerstone: Emergency Preparedness
1EP2 Alert and Notification System Testing
a. Inspection Scope
The inspector discussed with licensee staff the status of offsite siren systems to
determine the adequacy of licensee methods for testing the alert and notification system
-19- Enclosure
in accordance with 10 CFR Part 50, Appendix E. The licensees alert and notification
system testing program was compared with criteria in NUREG-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 licensees current
FEMA-approved alert and notification system design report. The inspector also
reviewed Procedures EPP-2-701, Prompt Notification System Maintenance and
Testing, Revision 18, and EPP-2-401, Inadvertent Siren Sounding, Revision 7. The
inspector completed one inspection sample.
b. Findings
No findings of significance were identified.
1EP3 Emergency Response Organization Augmentation
a. Inspection Scope
The inspector reviewed the following documents to determine the licensees ability to
staff emergency response facilities in accordance with the licensee emergency plan and
the requirements of 10 CFR Part 50, Appendix E.
- EIP-2-006, Notifications, Revision 32
- EPP-2-502, Emergency Communications Equipment Testing, Revision 21
- Details of 10 staffing augmentation and quarterly pager drills
The inspector completed one inspection sample.
b. Findings
No findings of significance were identified.
1EP5 Correction of Emergency Preparedness Weaknesses and Deficiencies
a. Inspection Scope
The inspector reviewed the following documents related to the licensees corrective
action program to determine the licensees ability to identify and correct problems in
accordance with 10 CFR 50.47(b)(14) and 10 CFR Part 50, Appendix E:
- Quality assurance audits of the emergency preparedness program conducted in
2003, 2004, and 2005
- Four licensee self-assessments
- Licensee evaluation reports for 11 drills and exercises
-20- Enclosure
- Summaries of 146 corrective actions assigned to the emergency preparedness
department between February 2003 and October 2005
- Details of 17 selected CRs
The licensees corrective action program was also compared with the requirements of
Procedure EN-LI-102, Corrective Action Process, Revision 2. The inspector
independently evaluated the emergency operations facility during an October 18, 2005,
drill and compared the postdrill critique of licensee performance. The inspector
completed one inspection sample.
b. Findings
No findings of significance were identified.
1EP6 Drill Evaluation
a. Inspection Scope
The inspectors observed the emergency preparedness drill conducted on October 18,
2005, to identify any weaknesses and deficiencies in classification, notification, and
protective action recommendation development activities. The inspectors also
evaluated the licensee assessment of classification, notification, and protective action
recommendation development during the drill in accordance with plant procedures and
NRC guidelines. The inspectors also observed the drill evaluator immediate critiques of
the drill participants classification, notification, and protective action recommendation
activities. The following procedures and documents were reviewed during the
assessment:
C EIP-2-001, Classification of Emergencies, Revision 13
C EIP-2-006, Notifications, Revision 32
C EIP-2-007, Protective Action Guidelines Recommendations, Revision 21
The inspectors completed one inspection sample.
b. Findings
No findings of significance were identified.
-21- Enclosure
2. RADIATION SAFETY
Cornerstone: Occupational Radiation Safety
2OS2 ALARA Planning and Controls
a. Inspection Scope
The inspector assessed licensee performance with respect to maintaining individual and
collective radiation exposures as low as is reasonably achievable (ALARA). The
inspector used the requirements in 10 CFR Part 20 and the licensees procedures
required by TS as criteria for determining compliance. The inspector interviewed
licensee personnel and reviewed:
- Current 3-year rolling average collective exposure
- Three on-line maintenance work activities scheduled during the inspection period
and associated work activity exposure estimates which were likely to result in the
highest personnel collective exposures
- Site-specific ALARA procedures
- ALARA work activity evaluations, exposure estimates, and exposure mitigation
requirements
- Intended versus actual work activity doses and the reasons for any
inconsistencies
- Dose rate reduction activities in work planning
- Method for adjusting exposure estimates, or replanning work, when unexpected
changes in scope or emergent work were encountered
- Use of engineering controls to achieve dose reductions and dose reduction
benefits afforded by shielding
- Radiation worker and radiation protection technician performance during work
activities in radiation areas, airborne radioactivity areas, or high radiation areas
- Self-assessments and audits related to the ALARA program since the last
inspection
- Corrective action documents related to the ALARA program and follow-up
activities such as initial problem identification, characterization, and tracking
The inspector completed 9 of the required 15 inspection samples and 2 of the optional
inspection samples.
-22- Enclosure
b. Findings
No findings of significance were identified.
4. OTHER ACTIVITIES
4OA1 Performance Indicator Verification
Emergency Preparedness Cornerstone
a. Inspection Scope
The inspector sampled licensee submittals for the performance indicators listed below
for the period July 1, 2004, through September 30, 2005. The definitions and guidance
of NEI 99-02, Regulatory Assessment Indicator Guideline, Revisions 2 and 3, were
used to verify the licensees basis for reporting each data element in order to verify the
accuracy of performance indicator data reported during the assessment period. The
licensees performance indicator data was also reviewed against the requirements of
Procedure EN-LI-114, Performance Indicator Process, Revision 0.
- Drill and Exercise Performance
- Emergency Response Organization Participation
- Alert and Notification System Reliability
The inspector reviewed a 100 percent sample of drill and exercise scenarios, licensed
operator 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 emergency responder qualification, training,
and drill participation records for 20 key licensee emergency response personnel. The
inspector reviewed procedures for conducting siren testing and a 100 percent sample of
siren test records. The inspector also interviewed licensee personnel that were
accountable for collecting and evaluating the performance indicator data.
The inspector completed three inspection samples.
b. Findings
No findings of significance were identified.
4OA2 Identification and Resolution of Problems
1. Emergency Preparedness Annual Sample Review
a. Inspection Scope
The inspector reviewed a summary listing of 146 corrective actions assigned to the
emergency preparedness department, reviewed 17 CRs in detail, and independently
-23- Enclosure
assessed the licensees ability to identify problems associated with an October 18, 2005,
integrated drill, in order to assess the licensees ability to identify and correct problems.
The inspector completed one inspection sample.
b. Findings
No findings of significance were identified.
2. ALARA Planning and Controls Annual Sample Review
a. Inspection Scope
The inspector evaluated the effectiveness of the licensee's problem identification and
resolution processes regarding exposure tracking, higher than planned exposure levels,
and radiation worker practices. The inspector reviewed the corrective action documents
listed in the attachment against the licensees problem identification and resolution
program requirements. The inspector completed one inspection sample.
b. Findings
No findings of significance were identified.
3. Semiannual Trend Review
a. Inspection Scope
The inspectors performed a 6-month review of the licensees corrective action program
and associated documents to identify trends that could indicate the existence of a more
significant safety issue. The inspectors review was focused on repetitive issues, but
also considered the results of daily inspector screening of CRs and licensee trending
efforts. The inspectors review considered the six month period of July through
December 2005. Inspectors reviewed 76 specific CRs and their associated operability
evaluations. Operability determinations set the priority for corrective actions to resolve
conditions adverse to quality. The CR numbers are listed in the attachment.
The inspectors also evaluated the CRs and the operability determinations against the
requirements of the following guidance documents:
- Procedure EN-LI-102, Corrective Action Process, Revision 1
- Procedure EN-OP-104, Operability Determinations, Revision 1
- Procedure OSP-0040, LCO Tracking and Safety Function Determination
Program, Revision 10
Resolution of Degraded or Nonconforming Conditions Adverse to Quality or
Safety, dated September 26, 2005
-24- Enclosure
The inspectors completed one inspection sample.
b. Assessment and Observations
There were no findings of significance identified. The inspectors determined that a
number of operability determinations stated that the equipment that was the subject of
the CR was currently inoperable and being tracked using the LCO Tracking System.
The inspectors found that this system was an effective mechanism for resolution of TS
LCOs. However, from a corrective action program perspective, there was no closure of
the condition adverse to quality (system inoperability) or a discussion of the corrective
actions taken to restore the equipment to operable status in the subject CR. In addition,
the inspectors observed that a number of operability determinations described
conditions where the system was declared operable but the system or a support system
was in a degraded or nonconforming condition. In some cases, compensatory actions
were being taken to ensure system operability, but no mechanism was in place to
ensure that these compensatory measures remained in place until the degraded or
nonconforming condition was corrected. The inspectors did not find any examples
where the nonconforming condition was not corrected within a reasonable period of
time.
4. Resident Inspector Annual Sample Review
The inspectors completed two inspection samples.
Ultimate Heat Sink Long Term Heat Removal Capacity
c. Inspection Scope
The inspectors reviewed CR-RBS-2002-01243, ultimate heat sink capacity less than the
30-day requirement, during the week of November 28, 2005. The inspectors evaluated
the CR against the requirements of the licensees corrective action program as
described in nuclear management manual Procedure LI-102, Corrective Action
Process, Revision 4, and 10 CFR Part 50, Appendix B, Criterion XVI.
b. Findings and Observations
There were no findings of significance identified. On August 28, 2002, the inspectors
found: (1) the single failure assumption made for the design of the ultimate heat sink
was a trip of standby diesel Generator B immediately after a small line break event, with
bypass, coincident with a loss-of-offsite power and plant trip, (2) the ultimate heat sink
capacity would be less than 30 days if, instead, all ECCS systems worked as designed
and no operator actions were taken to secure ECCS, and (3) specific procedures to
replenish the ultimate heat sink during a loss-of-offsite power had not been written. In
response to the inspectors' concerns, the licensee wrote CR-RBS-2002-01243 and took
the following corrective actions: (1) revised their procedures to clarify operator actions if
no single failure occurred and to provide instructions for makeup to the ultimate heat
-25- Enclosure
sink during a 30-day loss-of-offsite power; and (2) issued license amendment Request
LAR-2001-026, dated March 18, 2003, to revise their TS Bases 3.7, Standby Service
Water System and Ultimate Heat Sink, and USAR.
Simulator Fidelity Issue Regarding Wide-Range Level Recorders
d. Inspection Scope
The inspectors reviewed the corrective actions taken by the licensee in response to
NCV 05000458/2004005-02, wide-range reactor water level indication did not respond
as expected by operators following an unplanned reactor scram. On December 10,
2004, a failure of a balance of plant instrument bus caused the feedwater regulating
valves to fail in their 100 percent flow position. Following a reactor scram, the feedwater
pumps overfed the reactor and tripped on high reactor water level. The excess
feedwater caused reactor water level to continue to rise after the feed pump trip. The
wide-range level recorders' digital output continued to indicate reactor water level
greater than +60 inches, the top end of the wide-range level instruments. The reactor
operators were not aware that the recorders digital output would continue to increase
beyond +60 inches because the digital readout of wide-range level recorders in the
simulator stopped at +60 inches. This response caused some confusion and
complicated the operators' response to the event. The inspectors reviewed CR-RBS-
2004-04289, -04295, -04296 and -04299 written by the licensee in response to this
event.
e. Findings and Observations
There were no findings of significance identified. The inspectors found that, when a
design change was implemented changing the wide-range reactor water level recorders
from analog to digital models, the simulator modification made the software for the
recorders stop indicating at the top of scale (+60 inches). The digital recorders installed
in the control room, however, had no upper limit on the digital indication. On
December 10, 2004, reactor water level rose above the reference leg tap for the level
transmitter and, as the reference leg condensing chamber cooled down, the wide-range
level transmitters output continued to increase and the digital indication showed a level
as high as +140 inches. The inspectors reviewed the corrective actions taken by the
licensee and determined that they were reasonable and adequate to correct the
operator knowledge deficiency caused by the simulator fidelity issue. The inspectors
interviewed a cross-section of control room operators and determined that the
phenomena was understood and they understood that any wide-range digital indication
greater that +60 inches was invalid and not indicative of actual reactor water level.
4OA3 Event Followup
1. (Closed) Licensee Event Report (LER) 50-458/04-001-00, Automatic Reactor Scram
Due to Main Generator Trip Resulting from Switchyard Fault
On August 15, 2004, a transmission tower guy wire failed. This allowed a 230 kV
transmission line structure between Port Hudson and Fancy Point (Line 353) to fall and
-26- Enclosure
create a ground fault condition on the line. Four breakers in the station switchyard were
slow to open to clear the fault. As a result: (1) Reserve Station Transformer 2 was
deenergized, causing a partial loss of off-site power and start of the Division 2
emergency diesel generator; and (2) main transformer protection relays caused a main
generator lockout, which resulted in a generator load reject reactor scram.
NRC Integrated Inspection Report 05000458/2004005, issued February 14, 2005,
documented a Green, self-revealing finding associated with this event for preconditioned
speed testing of station switchyard breakers and three similar failures of station
switchyard breakers. The licensee revised the speed testing procedures to avoid
preconditioning the breakers.
NRC Supplemental Inspection Report 05000458/2005012, issued October 24, 2005,
documented a supplemental inspection performed in accordance with Inspection
Procedure 95001. The supplemental inspection was in response to four unplanned
reactor scrams that occurred between August 15, 2004, and January 15, 2005. The
licensees root cause analysis identified several programmatic changes which were
incorporated into a switchyard reliability program to improve switchyard maintenance
practices.
The inspectors reviewed the LER and the licensees resolution of identified problems
and determined there were no findings of significance and no other violations of NRC
requirements. The licensee documented the failed equipment in CR-RBS-2004-02332.
4OA6 Meetings, Including Exit
Exit Meetings
On October 21, 2005, the inspector presented the emergency preparedness inspection
results to Mr. J. Leavines, Manager, Emergency Planning, and other members of his
staff who acknowledged the findings. The inspector confirmed that proprietary
information was not provided or examined during the inspection.
On November 4, 2005, the inspector presented the licensed operator requalification
program inspection results to Mr. Mike Cantrell, Operations Training Supervisor, and
other members of the licensees management staff. The licensee acknowledged the
findings presented. The inspector confirmed that proprietary information was not
provided or examined during the inspection.
On December 8, 2005, the inspector presented the ALARA inspection results to
Mr. R. King, Director, Nuclear Safety Assurance, and other members of his staff who
acknowledged the findings. The inspector confirmed that proprietary information was
not provided or examined during the inspection.
-27- Enclosure
On January 4, 2006, the inspectors presented the integrated baseline inspection results
to Paul Henninkamp, Vice President, Operations, and other members of licensee
management. The inspector confirmed that proprietary information was not provided or
examined during the inspection.
ATTACHMENT: SUPPLEMENTAL INFORMATION
-28- Enclosure
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
M. Boyle, Manager, Radiation Protection
D. Burnett, Superintendent, Chemistry
M. Cantrell, Operations Training Supervisor
J. Clark, Assistant Operations Manager - Training
T. Coleman, Manager, Planning and Scheduling/Outage
M. Davis, Acting Manager, Radiation Protection
C. Forpahl, Manager, Corrective Actions
H. Goodman, Director, Engineering
P. Hinnenkamp, Vice President - Operations
B. Houston, Manager, Plant Maintenance
G. Huston, Assistant Operations Manager - Shift
R. King, Director, Nuclear Safety Assurance
J. Leavines, Manager, Emergency Planning
D. Lorfing, Manager, Licensing
J. Maher, Superintendent, Reactor Engineering
W. Mashburn, Manager, Design Engineering
P. Russell, Manager, System Engineering
C. Stafford, Manager, Operations
W. Trudell, Manager, Training and Development
D. Vinci, General Manager - Plant Operations
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened and Closed
05000458/2005005-01 NCV Inadequate procedure for implementation of an EAL
05000458/2005005-02 NCV Failure to complete TS required actions within allowed
completion time
05000458/2005005-03 NCV Inadequate design assumption results in RCIC turbine
exhaust header filling with water following an automatic
high water level shutdown
Closed
05000458/2004-001-00 LER Automatic Reactor Scram Due to Main Generator Trip
Resulting from Switchyard Fault
A-1 Attachment
LIST OF DOCUMENTS REVIEWED
The following documents were selected and reviewed by the inspectors to accomplish the
objectives and scope of the inspection and to support any findings:
Section 1R11: Licensed Operator Requalification Program
RJPM-OPS-052-04, Alternate Control Rod Drive Pumps, August 4, 2005
RJPM-OPS-053-03R5, Reset a FCV runback, July 26, 2005
RJPM-OPS-109.4, July 26, 2005
RJPM-OPS-110-04, Synchronize the Main Generator with the Grid, August 2, 2005
RJPM-OPS-256-03R4, Restore level in the SBCT with deepwell pumps, July 26, 2005
RJPM-OPS-309-050, July 19, 2005
RJPM-OPS-508-04, Restore RPS B Normal Power Supply, August 19, 2005
RJPM-OPS-508-07, Respond to reactor scram with control rods failing to insert,
August 2, 2005
RJPM-OPS-800-17R1, Vent the CCRD over-piston volume, July 26, 2005
RJPM-OPS-05206R2, Control rod operability faulted, July 12, 2005
RJPM-OPS-05207R2, Alternate control rod drive pumps (Fuel Bldg), July 12, 2005
RJPM-OPS-05304R, Startup A recirc HPU, July 12, 2005
RJPM-OPS-20005R, Perform ATC actions for remote shutdown, August 2, 2005
RJPM-OPS-20006R5, Perform Attachment 13 UO actions, July 26, 2005
Scenarios
RSMS-OPS-822, Loss of All Feed Water / RCIC Failure / LOCA, Revision: 00
RSMS-OPS-823, APRM Failure /SRV Failure / EHC Failure / ATWS, Revision: 00
RSMS-OPS-824, LPRM Failure / Loss of Vacuum with MSIV Closure / ATWS,
Revision: 00
A-2 Attachment
RSMS-OPS-825, Loss of RPS B / Relief Valve Fails Open / Steam Leak in the Drywell
With Failure of the Drywell, Revision: 00
RSMS-OPS-827, Rod Drop / Fuel Failure / RCIC Steam Leak / Partial ATWS,
Revision: 00
RSMS-OPS-829, Failure Of STX-XS2B / Loss Of Condenser Vacuum / ATWS,
Revision: 00
RSMS-OPS-830, Inadvertent HPCS Injection and Loss of Stator Cooling, Revision: 00
Section 1R17: Permanent Plant Modifications
Event Notification 41252, Reactor Scram due to Loss of Vital Instrument Bus
LER 05-458/04-005-01, Unplanned Automatic Scram due to Loss of Non-Vital 120 Volt
Instrument Bus, June 22, 2005
CR-RBS-2004-04291 RCIC system initiated and subsequently tripped on Level 8
CR-RBS-2005-00724 MR96-0063 removed internals from RCIC Turbine Exhaust Check
Valve E51-VF040
SDRP-P43, System Design Requirements Document, Reactor Core Isolation Cooling,
Revision 0
SDC-209, Reactor Core Isolation Cooling System Design Criteria, Revision 0,
November 9, 1998
SDC-209, Reactor Core Isolation Sooling System Design Criteria, Revision 3,
September 27, 2004
RBS USAR Section 5.4.6, Reactor Core Isolation Cooling System, Revision 17
NUREG-0989, RBS Safety Evaluation Report and Supplements, May 1984 through
October 1985
GE SIL-30, HPCI/RCIC Turbine Exhaust Line Vacuum Breakers, October 31, 1973
GS AID-56, HPCI/RCI Turbine Exhaust Check Valve Cycling, August 1985
VPF-3622-353 (1) - 1, RCIC Turbine Instruction Manual, January 1975 through
March 1978
MR96-0063, Remove Internals of [RCIC Exhaust Check Valve] E51-VF040,
September 18, 1996
A-3 Attachment
CR-RBS-1996-1671, Existing plant configuration of RCIC turbine exhaust line vacuum
breaker vent line does not correspond with configuration assumed in Calculation PH-56,
Revision 0
Calculation PH-56, RCIC Turbine Exhaust Line Vacuum Breaker Vent Line Sizing
Verification, Revision 1A, November 27, 1996
Piping and Instrument Drawing PID-27-06A, Reactor Core Isolation Cooling System,
Revision 42
Calculation G13.18.2.0-079, Determination of Quantity of Water Entering RCIC Turbine
Exhaust Line, May 11, 2005
Calculation G13.18.10.2*225, RCIC Fluid Transient Analysis - Water in Turbine Exhaust
Line, May 17, 2005
ER-RB-2005-0084-000, Replace Check Valve E51-VF040 or Reinstall Internal Parts,
February 20, 2005
Terry Turbine SAM-12, Terry Wheel Water Slug Test, March 1, 1973
Section 1EP2: Alert and Notification System Testing
River Bend Station Emergency Plan, Revision 28
River Bend Station Prompt Notification System Design Report, Revision 1,
December 2001
Section 1EP3: Emergency Response Organization Augmentation Testing
Evaluation Reports for Pager and Augmentation Tests conducted:
February 10, 2004 December 8, 2004 July 25, 2005
June 17, 2004 January 25, 2005 September 27, 2005
August 24, 2004 March 22, 2005
September 23, 2004
Section 1EP5: Correction of Emergency Preparedness Weaknesses and Deficiencies
Procedures
EN-LI-118, Root Cause Analysis Process, Revision 1
EN-LI-119, Apparent Cause Evaluation Process, Revision 3
A-4 Attachment
Quality Assurance
Quality Assurance Audit Report, QA-7-2003-RBS-1
Quality Assurance Audit Report, QA-7-2004-RBS-1
Quality Assurance Audit Report, QA-7-2005-RBS-1
Condition Reports
CR-RBS-1999-1316 CR-RBS-2004-3086
CR-RBS-2003-0586 CR-RBS-2004-3811
CR-RBS-2003-0624 CR-RBS-2005-1433
CR-RBS-2003-1950 CR-RBS-2005-1602
CR-RBS-2003-1992 CR-RBS-2005-1632
CR-RBS-2003-2094 CR-RBS-2005-1391
CR-RBS-2003-3050 CR-RBS-2005-2516
CR-RBS-2004-1090 CR-RBS-2005-2646
Evaluation Reports for Drills conducted
September 3, 2003 December 1, 2004 (simulator)
March 2 2004 December 1, 2004 (medical)
April 20, 2004 March 24, 2005
May 25, 2004 April 19, 2005
June 9, 2004 June 21, 2005
July 27, 2004
Licensee Self-Assessments
2004 Evaluated Exercise Pre-Assessment
LO-RLO-2004-00004 CA56, 2004 Long Range ERO Staffing Assessment
2005 Emergency Planning Program Assessment
Snapshot Assessment of RBS Siren System
Section 4OA1: Performance Indicator Verification
Procedures
EN-EP-201, Emergency Planning Performance Indicators, Revision 2
EPP-2-703, Performance Indicators, Revision 2
EIP-2-001, Classification of Emergencies, Revision 12
EIP-2-002, Classification Actions, Revision 24
EIP-2-006, Notifications, Revision 32
EIP-2-007, Protective Action Recommendation Guidelines, Revision 20
EIP-2-007, Protective Action Recommendation Guidelines, Revision 21
A-5 Attachment
Section 2OS2: ALARA Planning and Controls
Condition Reports
CR-RBS-2005-01472 CR-RBS-2005-02558
CR-RBS-2005-01474 CR-RBS-2005-03382
CR-RBS-2005-02076 CR-RBS-2005-04004
Audits and Self-Assessments
QA-14-2005-RBS-1 Quality Assurance Audit of Radiation Protection Snapshot
Assessment /Benchmark on: Effectiveness of the RP TAC/TRG
(July 11-13, 2005)
QS-2005-RBS-009 ALARA Planning and Controls (August 22 through
September 1, 2005)
LO#2005-00123 Radiation Protection Program (July 11-15, 2005)
Radiation Work Permits
2005-1073 Change out filter elements LWS-SKD5-F100A
2005-1110 Clean-up FB 113' cask pool and install cask pool impact limiter
2005-1310 Recirc Flow Control Valve Maintenance
Procedures
ENS-RP-105 Radiation Work Permits, Revision 7
RP-110 ALARA Program, Revision 2
ALARA Committee Minutes
AMC 05-01 January 11, 2005
AMC 05-02 January 12, 2005
AMC 05-03 January 17, 2005
AMC 05-11 July 14, 2005
Section 4OA2: Identification and Resolution of Problems
Condition reports
CR-RBS-2005-02444 CR-RBS-2005-02570
CR-RBS-2005-02481 CR-RBS-2005-02590
CR-RBS-2005-02486 CR-RBS-2005-02605
CR-RBS-2005-02494 CR-RBS-2005-02621
CR-RBS-2005-02548 CR-RBS-2005-02624
CR-RBS-2005-02563 CR-RBS-2005-02626
A-6 Attachment
CR-RBS-2005-02645 CR-RBS-2005-03446
CR-RBS-2005-02649 CR-RBS-2005-03471
CR-RBS-2005-02659 CR-RBS-2005-03474
CR-RBS-2005-02664 CR-RBS-2005-03503
CR-RBS-2005-02686 CR-RBS-2005-03509
CR-RBS-2005-02693 CR-RBS-2005-03513
CR-RBS-2005-02695 CR-RBS-2005-03515
CR-RBS-2005-02722 CR-RBS-2005-03554
CR-RBS-2005-02724 CR-RBS-2005-03586
CR-RBS-2005-02727 CR-RBS-2005-03594
CR-RBS-2005-02738 CR-RBS-2005-03619
CR-RBS-2005-02754 CR-RBS-2005-03629
CR-RBS-2005-02760 CR-RBS-2005-03645
CR-RBS-2005-02767 CR-RBS-2005-03670
CR-RBS-2005-02768 CR-RBS-2005-03706
CR-RBS-2005-03106 CR-RBS-2005-03728
CR-RBS-2005-03111 CR-RBS-2005-03747
CR-RBS-2005-03114 CR-RBS-2005-03753
CR-RBS-2005-03125 CR-RBS-2005-03787
CR-RBS-2005-03131 CR-RBS-2005-03831
CR-RBS-2005-03138 CR-RBS-2005-03847
CR-RBS-2005-03151 CR-RBS-2005-03887
CR-RBS-2005-03152 CR-RBS-2005-03918
CR-RBS-2005-03165 CR-RBS-2005-03948
CR-RBS-2005-03178 CR-RBS-2005-03969
CR-RBS-2005-03182 CR-RBS-2005-04018
CR-RBS-2005-03220 CR-RBS-2005-04064
CR-RBS-2005-03242 CR-RBS-2005-04071
CR-RBS-2005-03265 CR-RBS-2005-04095
CR-RBS-2005-03273 CR-RBS-2005-04103
CR-RBS-2005-03279 CR-RBS-2005-04106
CR-RBS-2005-03443 CR-RBS-2005-04118
A-7 Attachment
LIST OF ACRONYMS
ALARA as low as is reasonably achievable
CFR Code of Federal Regulations
CR condition report
CR-RBS River Bend Station condition report
EAL emergency action level
FEMA Federal Emergency Management Agency
FCV flow control valve
HPU hydraulic power unit
MC manual chapter
LER licensee event report
LCO limiting condition for operation
LOCA loss of coolant accident
NCV noncited violation
NEI Nuclear Energy Institute
NRC U.S. Nuclear Regulatory Commission
RCIC reactor core isolation cooling system
RR reactor recirculation system
SOP system operating procedures
STP surveillance test procedure
TS Technical Specification
USAR Updated Safety Analysis Report
WO work order
A-8 Attachment