ML062260238
| ML062260238 | |
| Person / Time | |
|---|---|
| Site: | River Bend  |
| Issue date: | 08/14/2006 |
| From: | Kennedy K NRC/RGN-IV/DRP/RPB-C |
| To: | Hinnenkamp P Entergy Operations |
| References | |
| IR-06-003 | |
| Download: ML062260238 (45) | |
See also: IR 05000458/2006003
Text
August 14, 2006
Paul D. Hinnenkamp
Vice President - Operations
Entergy Operations, Inc.
River Bend Station
5485 US Highway 61N
St. Francisville, LA 70775
SUBJECT:
RIVER BEND STATION - NRC INTEGRATED INSPECTION
REPORT 05000458/2006003
Dear Mr. Hinnenkamp:
On June 30, 2006, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at
your River Bend Station. The enclosed integrated inspection report documents the inspection
results, which were discussed on July 5, 2006, with you and other members of your staff.
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.
The report documents three NRC-identified findings and two self-revealing findings of 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 NRC 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.
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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
Enclosure:
NRC Inspection Report 05000458/2006003
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
Wise, Carter, Child & Caraway
P.O. Box 651
Jackson, MS 39205
Entergy Operations, Inc.
-3-
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
Bert Babers, President
West Feliciana Parish Police Jury
P.O. Box 1921
St. Francisville, LA 70775
Richard Penrod, Senior Environmental
Scientist
Office of Environmental Services
Northwestern State University
Russell Hall, Room 201
Natchitoches, LA 71497
Brian Almon
Public Utility Commission
William B. Travis Building
P.O. Box 13326
1701 North Congress Avenue
Austin, TX 78711-3326
Entergy Operations, Inc.
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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.
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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. Lamb, OEDO RIV Coordinator (JGL1)
ROPreports
RBS Site Secretary (LGD)
W. A. Maier, RSLO (WAM)
SUNSI Review Completed: __wcw_ ADAMS: : Yes
G No Initials: __wcw___
- Publicly Available G Non-Publicly Available G Sensitive
- Non-Sensitive
R:\\_REACTORS\\_RB\\2006\\RB2006-03RP-PJA.wpd
RIV:SRI:DRP/C
RI:DRP/C
C:DRS/OB
C:DRS/EB1
C:DRS/PSB
PJAlter
MOMiller
ATGody
JAClark
MPShannon
T - WCWalker
E - WCWalker
/RA/
/RA/
/RA/
8/10/06
8/10/06
8/11/06
8/10/06
8/10/06
C:DRS/EB2
SRA:DRS
C:DRP/C
LJSmith
DPLoveless
KMKennedy
/RA/
/RA/
/RA/
8/10/06
8/14/06
8/14/06
OFFICIAL RECORD COPY
T=Telephone E=E-mail F=Fax
Enclosure
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U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket:
50-458
License:
Report:
Licensee:
Entergy Operations, Inc.
Facility:
River Bend Station
Location:
5485 U.S. Highway 61
St. Francisville, Louisiana
Dates:
April 1 to June 30, 2006
Inspectors:
P. Alter, Senior Resident Inspector, Project Branch C
M. Miller, Resident Inspector, Project Branch C
G. Werner, Senior Project Engineer, Project Branch D
L. Ricketson, P.E., Senior Health Physicist, Plant Support Branch
W. Sifre, Senior Reactor Inspector, Engineering Branch 1
Approved By:
Kriss M. Kennedy, Chief
Project Branch C
Division of Reactor Projects
Enclosure
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TABLE OF CONTENTS
SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
REPORT DETAILS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
REACTOR SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
1R01
Adverse Weather Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
1R04
Equipment Alignment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
1R05
Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
1R08
Inservice Inspection Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
1R11
Licensed Operator Requalification Program . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
1R12
Maintenance Effectiveness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
1R13
Maintenance Risk Assessments and Emergent Work Control . . . . . . . . . . . . . 10
1R14
Operator Performance During Nonroutine Evolutions and Events . . . . . . . . . . 11
1R15
Operability Evaluations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
1R19
Postmaintenance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
1R20
Refueling and Other Outage Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
1R22
Surveillance Testing
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
1R23
Temporary Plant Modifications
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
1EP6 Drill Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
RADIATION SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
2OS1 Access Control to Radiologically Significant Areas . . . . . . . . . . . . . . . . . . . . . 24
2OS2 ALARA Planning and Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
OTHER ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
4OA1 Performance Indicator (PI) Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
4OA2 Identification and Resolution of Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
4OA3 Event Followup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
4OA5 Other Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
4OA6 Meetings, Including Exit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
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-7
Enclosure
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SUMMARY OF FINDINGS
IR 05000458/2006003; 04/01/2006 - 06/30/2006; River Bend Station; Operability Evaluations,
Refueling and Other Outage Activities, Surveillance Testing, Occupational Radiation Safety.
The report covered a 3-month period of routine baseline inspections by resident inspectors and
announced baseline inspections by regional engineering and radiation protection inspectors.
Five 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: Mitigating Systems
Green. A self-revealing noncited violation of 10 CFR Part 50, Appendix B, Criterion XVI,
"Corrective Action," was reviewed involving the failure of the licensee to identify that the
normal supply breaker to the Division III 4.16 kV engineered safety features bus was not
properly racked in for a period of 24 days following maintenance. This issue was
entered into the licensee's corrective action program as CR-RBS-2006-02402.
The finding was more than minor because it was associated with the mitigating system
cornerstone attribute of configuration control and affected the associated cornerstone
objective to ensure the availability, reliability, and capability of systems that respond to
initiating events to prevent undesirable consequences. Utilizing Manual Chapter 0609,
"Significance Determination Process," a Phase 3 analysis concluded that the finding
was of very low safety significance. The cause of the finding was related to the
crosscutting aspect of problem identification and resolution in that the licensee failed to
properly evaluate available indications to identify that the breaker was not properly
racked in. (Section 1R15).
Green. An NRC identified noncited violation of 10 CFR 50.65 Maintenance Rule
Section (a)(4) was identified for the failure of the licensee to provide prescribed
compensatory measures for two Orange shutdown risk conditions during Refueling
Outage 13. Specifically, the preoutage risk assessment recommended that two work
orders be in place for maintenance electricians to provide power to one spent fuel pool
cooling pump in the event of problems with the running pump during periods of electrical
bus maintenance. The inspectors found that the work packages were not in place
before entering shutdown risk condition Orange on April 26, 2006, during the Division II
engineering safety features bus testing, and May 3, 2006, during the Division I
engineered safety features bus outage. This issue was entered into the licensee's
corrective action program as CR-RBS-2006-01937.
The finding was more than minor because the licensee failed to implement a prescribed
compensatory measure during the highest risk condition of Refueling Outage 13. The
Enclosure
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specific compensatory measures were called for in the preoutage risk assessment and
the shutdown operations protection plan. The finding affected the mitigating system
cornerstone because of the increased risk of a sustained loss of spent fuel pool cooling
during core offloading operations. The finding could not be evaluated using the
significance determination process, therefore the finding was reviewed by regional
management and determined to be of very low safety significance. Factors that were
considered included: (1) electrical maintenance technicians had previously performed
the task of providing alternate power to a spent fuel pool cooling pump, (2) the
necessary equipment was staged as part of the abnormal operating procedure for loss
of decay heat removal, and (3) the relatively long time to boil of the spent fuel storage
pool at that time during the refueling outage. The cause of the finding was related to the
crosscutting aspect of human performance because the licensees planned
maintenance activities and the predetermined increase in outage risk was not effectively
managed by prescribed compensatory measures (Section 1R20).
Green. An NRC identified noncited violation of Technical Specification 5.4.1.a was
identified for the failure of the licensee to provide an adequate surveillance test
procedure to perform Technical Specification Surveillance Requirement 3.8.1.1.
Specifically, STP-000-0102, Power Distribution Alignment Check, Revision 4, did not
verify the required offsite power circuit breaker alignment and indicated power
availability for the Division III 4.16 kV engineered safety features bus as required in
Modes 1, 2, and 3. This issue was entered into the licensee's corrective action program
as CR-RBS-2006-02675 and -02402.
The finding was more than minor because it was associated with the mitigating system
cornerstone attribute of configuration control and affected the associated cornerstone
objective to ensure the availability, reliability, and capability of systems that respond to
initiating events to prevent undesirable consequences. Utilizing Manual Chapter 0609,
"Significance Determination Process," a Phase 3 analysis concluded that the finding
was of very low safety significance. (Section 1R22).
Cornerstone: Occupational Radiation Safety
Green. The inspector reviewed a self-revealing noncited violation of Technical Specification 5.7.1, resulting from the licensees failure to control access to a high
radiation area. While transferring reverse osmosis system filters in the radwaste
building, the licensee allowed two workers to inadvertently enter a high radiation area.
This occurred after a guard prematurely left his post in front of the 123 foot elevation
elevator door. The highest dose rate recorded by an electronic alarming dosimeter was
164 millirem per hour. The guard returned and evacuated the workers before they
accrued additional radiation dose. Planned corrective action was still being evaluated by
the licensee at the conclusion of the inspection.
The finding was more than minor because it was associated with the occupational
radiation safety attribute of exposure control and affected the cornerstone objective in
that not controlling a high radiation area could increase personal exposure. Using the
Occupational Radiation Safety Significance Determination Process, the inspector
determined that the finding was of very low safety significance because it did not
Enclosure
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involve: (1) an as low as is reasonably achievable finding, (2) an overexposure, (3) a
substantial potential for overexposure, or (4) an impaired ability to assess dose.
Additionally, this finding had crosscutting aspects associated with human performance
in that the failure of the individual to guard the elevator door directly contributed to the
violation. (Section 2OS1)
Green. The inspector identified a noncited violation of 10 CFR 20.1501(a) because the
license failed to survey airborne radioactivity. During the removal of local power range
monitors, the licensee started collecting an air sample of the work area, but discarded
the sample before analyzing it. Successful passage through the portal monitors at the
exit of the controlled access area confirmed that no worker experienced an uptake of
radioactive material. Planned corrective action is still being evaluated.
The finding was more than minor because it was associated with the occupational
radiation safety program attribute of exposure control and affected the cornerstone
objective in that the lack of knowledge of radiological conditions could increase
personnel dose. Using the Occupational Radiation Safety Significance Determination
Process, the inspector determined that the finding was of very low safety significance
because it did not involve: (1) an as low as is reasonably achievable finding, (2) an
overexposure, (3) a substantial potential for overexposure, or (4) an impaired ability to
assess dose. Additionally, this finding had crosscutting aspects associated with human
performance in that the failure to maintain the sample for analysis directly contributed to
the violation. (Section 2OS1)
B.
Licensee-Identified Violations
None.
Enclosure
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REPORT DETAILS
Summary of Plant Status: The reactor was operated at 100 percent power from April 1-15,
2006, when the reactor scrammed due to a control circuit failure which caused both reactor
recirculation pumps to shift to slow speed. The reactor was restarted on April 17 and attained
100 percent power on April 18. On April 23, the reactor was shut down for Refueling Outage
(RFO) -13. On May 12, the reactor was restarted and attained 100 percent power on May 18.
On June 15, reactor power was reduced to 23 percent because of a problem with the main
turbine bypass valves. The reactor was returned to 100 percent power on June 18. The
reactor remained at 100 percent power for the remainder of the inspection period, with the
exception of regularly scheduled power reductions for control rod pattern adjustments and
turbine testing.
1.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency
Preparedness
1R01
Adverse Weather Protection
a.
Inspection Scope
Hurricane Season Preparations
During the week of June 12, 2006, the inspectors completed a review of the licensee's
readiness for seasonal susceptibilities involving high winds at the beginning of hurricane
season. The inspectors reviewed Procedure ENS-EP-302, Severe Weather
Response, Revision 4. The inspectors: (1) reviewed plant procedures, the Updated
Safety Analysis Report (USAR), and Technical Specifications (TS) to verify that operator
actions defined in adverse weather procedures maintained the readiness of essential
systems; (2) walked down portions of the protected area to verify that hurricane season
preparations were sufficient to support operability of essential systems, including the
ability to perform safe shutdown functions; (3) evaluated operator staffing levels to verify
the licensee could maintain the readiness of essential systems required by plant
procedures; and (4) reviewed the corrective action program (CAP) to determine if the
licensee identified and corrected problems related to adverse weather conditions.
The inspectors completed one inspection sample.
b.
Findings
No findings of significance were identified.
Enclosure
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1R04
Equipment Alignment
Partial System Walkdowns
a.
Inspection Scope
The inspectors: (1) walked down portions of the three risk important systems listed
below and reviewed system operating procedures (SOPs), piping and instrument
diagrams, and other documents to verify that critical portions of the selected systems
were correctly aligned; and (2) compared deficiencies identified during the walkdown to
the licensee's USAR and CAP to verify problems were being identified and corrected.
Alternate decay heat removal system, which was the backup to the inservice
shutdown cooling system during refueling operations, on May 2, 2006
Reactor core isolation cooling system, while the high pressure core spray diesel
was out of service for maintenance, on June 12, 2006
Division I emergency diesel generator (EDG), while Division II EDG was out of
service for planned maintenance, on June 21, 2006
Documents reviewed by the inspectors included:
SOP-0140, Suppression Pool Cleanup and Alternate Decay Heat Removal,
Revision 16
SOP-0035, Reactor Core Isolation Cooling System, Revision 8A
SOP-0053, Standby Diesel Generator and Auxiliaries, Revision 44A
The inspectors completed three inspection samples.
h.
Findings
No findings of significance were identified.
1R05
Fire Protection
b.
Inspection Scope
The inspectors walked down the six plant areas listed below to assess the material
condition of active and passive fire protection features and their operational lineup and
readiness. The inspectors: (1) verified that transient combustibles were controlled in
accordance with plant procedures; (2) observed the condition of fire detection devices to
verify they remained functional; (3) observed fire suppression systems to verify they
remained functional and that access to manual actuators was unobstructed; (4) verified
that fire extinguishers and hose stations were provided at their designated locations and
Enclosure
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that they were in a satisfactory condition; (5) verified that passive fire protection features
(electrical raceway barriers, fire doors, fire dampers, steel fire proofing, penetration
seals, and oil collection systems) were in a satisfactory material condition; (6) verified
that adequate compensatory measures were established for degraded or inoperable fire
protection features and that the compensatory measures were commensurate with the
significance of the deficiency; and (7) reviewed the CAP to determine if the licensee
identified and corrected fire protection problems.
Auxiliary building piping Tunnel D, Fire Area AB-7, on May 9, 2006
Low pressure core spray pump room, Fire Area AB-6/Z-1, on May 9, 2006
High pressure core spray pump room, Fire Area AB-2/Z-1, on May 9, 2006
Control building standby switchgear Room 1A, Fire Area C-15, on June 22, 2006
Control building safety related cable tray area and stairway Number 3, Fire Area
C-16 and C-29, on June 22, 2006
Division I EDG control and diesel engine rooms, Fire Area DG-6/Z-1, on June 22,
2006
Documents reviewed by the inspectors included:
Pre-Fire Plan/Strategy Book
USAR Section 9A.2, Fire Hazards Analysis, Revision 10
River Bend Station postfire safe shutdown analysis
RBNP-038, Site Fire Protection Program, Revision 6B
The inspectors completed six inspection samples.
b.
Findings
No findings of significance were identified.
1R08
Inservice Inspection Activities
a.
Inspection Scope
The inspector witnessed the performance of 12 volumetric (ultrasonic) and four surface
(liquid penetrant) examinations. The sample of nondestructive examination (NDE)
activities is listed in the attachment.
For each of the NDE activities reviewed, the inspector verified that the examinations
were performed in accordance with American Society of Mechanical Engineers (ASME)
Code requirements.
Enclosure
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During the review of each examination, the inspector verified that appropriate NDE
procedures were used, that examinations and conditions were as specified in the
procedure, and that test instrumentation or equipment was properly calibrated and within
the allowable calibration period. The inspector also reviewed documentation to verify
that indications revealed by the examinations were dispositioned in accordance with the
ASME Code specified acceptance standards.
The inspector verified the certifications of the NDE personnel observed performing
examinations or identified during review of completed examination packages.
The inspection procedure requires review of one or two examinations from the previous
outage with recordable indications that were accepted for continued service to ensure
that the disposition was done in accordance with the ASME Code. There were no
recordable indications that required evaluation during the last outage.
If the licensee completed welding on the pressure boundary for Class 1 or 2 systems
since the beginning of the previous outage, the procedure requires verification that
acceptance and preservice examinations were done in accordance with the ASME Code
for one to three welds. There were no welds available for review.
The procedure also requires verification that one or two ASME Code Section XI repairs
or replacements meet code requirements. There were no code repairs or replacements
available at the time of this inspection.
The inspectors completed 16 inspection samples.
b.
Findings
No findings of significance were identified.
1R11
Licensed Operator Requalification Program
a.
Inspection Scope
On June 13, 2006, the inspectors observed testing and training of senior reactor
operators and reactor operators to verify the adequacy of training, to assess operator
performance, and to assess the evaluators critique. The training evaluation scenario
observed was RSMS-OPS-422, Loss of Circ Water Pump, Failure of Steam Flow
Transmitter and Instrument Air System Leak, Revision 4.
The inspectors completed one inspection sample.
b.
Findings
No findings of significance were identified.
Enclosure
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1R12
Maintenance Effectiveness
a.
Inspection Scope
The inspectors reviewed the condition reports (CR) listed below which documented
equipment problems to: (1) verify the appropriate handling of structure, system, and
component (SSC) performance or condition problems; (2) verify the appropriate
handling of degraded SSC functional performance; (3) evaluate the role of work
practices and common cause problems; and (4) evaluate the handling of SSC issues
reviewed under the requirements of the maintenance rule; 10 CFR Part 50, Appendix B;
and TS.
CR-RBS-2006-1898, main steam stop Valve B21-MOVF098C leakage, reviewed
on June 2, 2006, and CR-RBS-2004-4338, main steam stop Valve B21-
MOVF098C high leakage during RFO-11 and -12, reviewed on June 26, 2006.
CR-RBS-2006-2302, primary containment integrity maintenance rule repetitive
functional failure, reviewed on June 26, 2006.
Documents reviewed by the inspectors included:
NUMARC 93-01, Nuclear Energy Institute Industry (NEI) Guideline for Monitoring
the Effectiveness of Maintenance at Nuclear Power Plants, Revision 2
Maintenance rule function list
Maintenance rule performance criteria list
Main steam stop valve maintenance rule performance evaluations
The inspectors completed two inspection samples.
b.
Findings
No findings of significance were identified.
1R13
Maintenance Risk Assessments and Emergent Work Control
a.
Inspection Scope
.1
Risk Assessment and Management of Risk
The inspectors reviewed the planned work weeks listed below to verify: (1) that the
licensee performed risk assessments when required by 10 CFR 50.65 (a)(4) and
administrative Procedure ADM-096, Risk Management Program Implementation and
On-Line Maintenance Risk Assessment, Revision 4B, prior to changes in plant
configuration for maintenance activities and plant operations; (2) the accuracy,
adequacy, and completeness of the information considered in the risk assessment;
Enclosure
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(3) that the licensee recognized, and entered as applicable, the appropriate licensee
established risk category according to the risk assessment results and Procedure ADM-
096; and (4) that the licensee identified and corrected problems related to maintenance
risk assessments. Specific work activities evaluated included planned and emergent
work for the weeks of:
June 5, 2006, Division I work week and preferred station service Transformer
RTX-ESR1F cooling oil dehydration
June 19, 2006, planned Division II EDG outage week
June 26, 2006, nondivisional work week and potential labor work stoppage
.2
Emergent Work Control
For the two emergent work activities listed below, the inspectors: (1) verified that the
licensee performed actions to minimize the probability of initiating events and
maintained the functional capability of mitigating systems and barrier integrity systems;
(2) verified that emergent work related activities such as troubleshooting, work
planning/scheduling, establishing plant conditions, aligning equipment, tagging,
temporary modifications, and equipment restoration did not place the plant in an
unacceptable configuration; and (3) reviewed the CAP to determine if the licensee
identified and corrected risk assessment and emergent work control problems.
Preferred station service Transformer RTX-ESR1F sudden pressure relay failure
on May 30, 2006
Main turbine bypass valves inoperable due to hydraulic oil leak on June 2, 2006
The inspectors completed five inspection samples.
c.
Findings
No findings of significance were identified.
1R14
Operator Performance During Nonroutine Evolutions and Events
a.
Inspection Scope
1.
April 4, 2006, Automatic Initiation of Standby Service Water
The inspectors: (1) reviewed operator logs, plant computer data, and strip charts for the
April 4, 2006, unexpected initiation of Division II standby service water that occurred
while swapping the running normal service water pumps to evaluate operator
performance in coping with the event; (2) verified that operator actions were in
accordance with the response required by plant procedures and training; and (3) verified
that the licensee identified and implemented appropriate corrective actions associated
with personnel performance problems that occurred during the transient. In addition, the
Enclosure
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inspectors reviewed CR-RBS-2006-01257, which documented the procedural problems
that led to the event and reviewed the following procedures used by the operators:
AOP-53, Initiation of Standby Service Water With Normal Service Water
Running, Revision 8
SOP-42, Standby Service Water System, Revision 25
SOP-66, Control Building HVAC Chilled Water System, Revision 33B
2.
April 15, 2006, Reactor Scram
The inspectors: (1) reviewed operator logs, plant computer data, and strip charts for the
April 15, 2006, unexpected reactor recirculation pump downshift and subsequent reactor
scram to evaluate operator performance in coping with the event; (2) verified that
operator actions were in accordance with the response required by plant procedures
and training; and (3) verified that the licensee identified and implemented appropriate
corrective actions associated with personnel performance problems that occurred during
the transient. In addition the inspectors reviewed the postscram report documented in
Procedure GOP-003, Scram Recovery, Revision 16A, and observed the onsite safety
review committee review of the postscram report.
The inspectors completed two inspection samples.
e.
Findings
No findings of significance were identified.
1R15
Operability Evaluations
a.
Inspection Scope
For the operability evaluations associated with the documents listed below, the
inspectors: (1) reviewed plants status documents such as operator shift logs, emergent
work documentation, deferred modifications, and standing orders, to determine if an
operability evaluation was warranted for degraded components; (2) referred to the
USAR and design basis documents to review the technical adequacy of licensee
operability evaluations; (3) evaluated compensatory measures associated with
operability evaluations; (4) determined degraded component impact on any TS; (5) used
the significance determination process to evaluate the risk significance of degraded or
inoperable equipment; and (6) verified that the licensee identified and implemented
appropriate corrective actions associated with degraded components.
CR-RBS-2006-01207 and -01215, Primary containment purge exhaust line fails
to meet leak rate acceptance criteria, reviewed during the week of April 3, 2006
Enclosure
-13-
CR-RBS-2005-02805, Inserted control Rod 24-29 control blade lifetime
calculation revised for extended operating cycle, reviewed during the week of
April 17, 2006
Work Request (WR) 76625, NNS-ACB23 control power light out, suspect bad
socket, reviewed during the week of May 29, 2006
TS-LCO-06-0711, Division II EDG Generator Output Breaker charging springs
did not charge during tagout restoration, reviewed on June 23, 2006
CR-RBS-2006-01257, Division II standby service water start on low service water
pressure, reviewed on June 28, 2006
CR-RBS-2006-02632, turbine bypass valves hydraulic oil leak, reviewed on
June 28, 2006
Other documents reviewed by the inspectors are listed in the attachment.
The inspectors completed six inspection samples.
b.
Findings
Introduction: The inspectors reviewed a self-revealing noncited violation (NCV) of
10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," involving the failure of
the licensee to identify that the normal supply breaker to the Division III 4.16 kV
engineered safety features (ESF) bus was not properly racked in following maintenance.
Description: Following the completion of planned maintenance on Switchgear NNS-
SWG1A on April 29, 2006, operators were assigned to clear equipment tags and restore
the system alignment. As part of this task, operators racked in Breaker NNS-ACB23,
the normal supply breaker to 4.16 kV Switchgear NNS-SWG1C. No actions, such as
cycling the breaker, were required to verify that the breaker was properly racked in.
On May 9, 2006, after noting that the control power light associated with Breaker NNS-
ACB23 was not lit, operators wrote WR 76625 to repair the light. The WR stated that
the white control power light on Control Room Panel H13-P808 was out with the breaker
racked in and the control power fuses installed. The WR also indicated that the
suspected cause was a bad socket and that position Switch 52H had failed in the past to
make up during closure. A work control center senior reactor operator determined that
an operability evaluation was not required for the condition described in WR 76625. The
WR was classified 4D, which indicated that it should be scheduled as resources
allowed within the normal 16-week work planning schedule. The inspectors noted the
licensee did not write a CR. The white control power light provides indication that the
breaker is functional, specifically, that: (1) there is no electrical fault on the line or load
side of the breaker, (2) the breaker Lockout button is not depressed on Panel 808, and
(3) the breaker is fully racked into the switchgear. On May 9, 2006, there were no
electrical faults on Breaker NNS-ACB23 and the Lockout was reset on Panel 808.
Enclosure
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On May 22, 2006, while aligning Switchgear NNS-SWG1C and the Division III 4.16 kV
ESF bus to the Transformer RSS1 offsite power supply, Breaker NNS-ACB23 failed to
close. Operators racked the breaker out and in, but the breaker failed to close on the
second attempt. Subsequent troubleshooting identified that the breaker had not been
fully racked in as electricians were able to rotate the racking device one additional turn.
The white light on Panel 808 came on and the breaker was successfully closed. The
operators and electricians determined that Breaker NNS-ACB23 had not been not
properly racked in, wrote CR-RBS-2006-02325 and -02337 and initiated WR 77478 to
investigate the problem with racking in Breaker NNS-ACB23.
On May 25, 2006, the inspectors questioned the impact that the failure of the breaker to
close had on the licensees compliance with TS. Specifically, TS 3.8.1.a requires two
qualified circuits between the offsite transmission network and the onsite Class 1E ac
electrical power distribution system when the plant is in Modes 1, 2, and 3. On May 12,
the plant was taken from Mode 4 to Mode 2 without two qualified offsite power sources
available to the Division III 4.16 kV ESF bus. The licensee wrote CR-RBS-2006-2402
and determined that they did not comply with TS 3.8.1.a when they changed modes on
May 12. In addition, the Division III 4.16 kV ESF bus was inoperable for a period of
10 days (May 12-22), which exceeded the allowed outage time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> specified in
TS Condition 3.8.1.A. The licensee also discovered that, on May 14 during the conduct
of maintenance on the Division I EDG, with Breaker NNS-ACB23 unable to be closed,
they unknowingly entered TS Condition 3.8.1.d. TS Condition 3.8.1.d states that with
One required offsite circuit inoperable AND on required [E]DG inoperable, restore the
EDG or the offsite power supply to an operable status in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> or place the plant in
Mode 3 within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The Division I EDG was inoperable for 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> and
15 minutes.
The inspectors found that the licensees procedures did not require Breaker NNS-
ACB23 to be cycled to verify proper operation after it was racked in on April 29.
Procedure OSP-0022, Operations General Administrative Guidelines, Revision 01,
step 4.5.5, required that breakers be functionally tested following any activity involving
safety related equipment which requires the breaker to be racked out. Because
Breaker NNS-ACB23 is not classified as a safety-related breaker, it was not required to
be functionally tested after it was racked in on April 29.
Analysis: The performance deficiency associated with this finding involved the failure of
operators to identify that Breaker NNS-ACB23 was not functional on April 29, 2006. The
finding was more than minor because it was associated with the mitigating system
cornerstone attribute of configuration control and affected the associated cornerstone
objective to ensure the availability, reliability, and capability of systems that respond to
initiating events to prevent undesirable consequences. The Phase 1 worksheets in
Manual Chapter (MC) 0609, "Significance Determination Process," were used to
conclude that a Phase 2 analysis was required because both the mitigating systems and
the containment barrier cornerstones were affected.
In accordance with NRC Inspection Manual Chapter 0609, Appendix A, Attachment 1,
"User Guidance for Determining the Significance of Reactor Inspection Findings for
At-Power Situations," the inspectors estimated the risk of the subject finding using the
Enclosure
-15-
Risk-Informed Inspection Notebook for River Bend Station, Revision 2. The inspectors
assumed that Division III power was available, but degraded, while Breaker NNS-ACB23
was not properly installed for the 10 days that the plant was in Mode 3 or above, from
May 12-22, 2006. Therefore, the exposure window used was 3-30 days. No operator
recovery was credited because on two occasions, operators had proven incapable of
properly positioning the breaker, ultimately requiring maintenance technicians to
properly install the breaker. Using Manual Chapter 0609, Appendix A, Attachment 2,
Rule 2.1, Inspection Finding that Degrades Mitigation Capability and Does Not Reduce
Remaining Mitigation Capability Credit to a Value Less Than Full Mitigation Credit, the
inspectors determined that all sequences containing the functions that would be affected
by a loss of Division III power, including the Division I standby service water loop
(HPCS, LPI, CHR, HPCS/LC, and REC/SSW), should be quantified, giving full mitigation
capability credit to each of these functions. Because the performance deficiency
affected the electric power system, Table 2 of the risk-informed notebook required that
all worksheets be evaluated. The resulting dominant sequences are provided in Table 1
below:
Table 1
Phase 2 Worksheet Results
Initiator
Sequence
Mitigating Functions
Result
TNSW
5
3
SSW - REC/SSW
7*
4
3
9*
1
3
CHR - LDEP
8
2
3
CHR - SPCFAN
8
4
3
9*
6
3
EAC1&2 - HPCS - REC6 - FPW
9*
8
3
EAC1&2 - HPCS - SBODG - REC4
9*
9
3
EAC1&2 - REC1 - HPCS -RCIC
9*
SORV
1
3
CHR-LDEP
8
2
3
CHR - SPCFAN
9
4
3
9*
LOIA
2
4
CHR - SPCFAN
8
1
4
CHR-LDEP
9
4
2
8
1
6
CHR
9
- Denotes sequences indicated as LERF contributors in the Phase 2 notebook.
By application of the counting rule, the internal event risk contribution of this finding to
the change in core damage frequency (CDF) was determined to be of low to moderate
risk significance (WHITE).
A senior reactor analyst performed further evaluation of the risk associated with this
issue (Phase 3/Modified Phase 2). Because the assumptions made during the Phase 2
estimation process were overly conservative and did not completely represent the actual
exposure time nor the actual affect the performance deficiency had on the availability of
power to the Division III diesel generator, the senior reactor analyst modified these
Enclosure
-16-
assumptions to more precisely quantify the change in risk. Specifically, the exposure
time was 10 days as opposed to the 30 days used in the risk-informed notebook.
Additionally, the Phase 2 evaluation included loss of offsite power initiating events that
were not affected by the performance deficiency because offsite power to Division III
would in all likelihood be lost during a design basis loss of offsite power. The senior
reactor analyst performed a modified Phase 2 estimation and determined that the
internal event risk contribution of the subject finding to the CDF was of very low risk
significance (Green). The best estimate value of this probability (CDFINTERNAL) was
calculated by the senior reactor analyst to be 1.2 x 10-7. The analyst evaluated the
contribution of external initiating events to the risk and calculated a bounding risk
estimate of 2.9 x 10-7 as the CDF for internal fire events.
Using Manual Chapter 0609, Appendix H, Containment Integrity Significance
Determination Process, the analyst estimated that the potential risk contribution from
large early release frequency was 6.6 x 10-8.
Given the independence of each initiating event, the analyst determined that the best
estimate of the total risk related to the subject performance deficiency was the
summation of the CDF calculated for both internal and external initiators. Therefore,
the best estimate was 4.1 x 10-7. The change in risk related to large early release
frequency was determined to be below 6.6 x 10-8, corroborating that the finding was of
very low risk significance. The performance deficiency resulted in a finding that was of
very low risk significance (Green). The cause of the finding was related to the
crosscutting aspect of problem identification and resolution in that operators failed to
identify that Breaker NNS-ACB23 was not properly racked in.
Enforcement: 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires, in
part, that measures be established to assure that conditions adverse to quality are
promptly identified and corrected. Contrary to this, from April 29 to May 22, 2006, the
licensee failed to identify that Breaker NNS-ACB23, which supplied one of the two
required offsite power supplies to the Division III 4.16 kV ESF bus, was not properly
racked in to Switchgear NNS-SWGIC. The root cause involved the licensees lack of
understanding that Breaker NNS-ACB23 was required to be functional to meet
TS 3.8.1.a requirements for two offsite power circuits to the Division III 4.16 kV ESF
bus. The corrective actions to restore compliance included: (1) changes to operations
section procedures to verify the white control power light, when applicable, after a circuit
breaker is racked in, (2) expansion of the requirement to functionally test safety-related
breakers to the nonsafety-related breakers in the TS required offsite power circuits, and
(3) operator lessons learned training on the event and all of its ramifications. Because
the finding was of very low safety significance and has been entered into the licensees
CAP as CR-RBS-2006-02402, this violation is being treated as an NCV consistent with
Section VI.A of the Enforcement Policy: NCV 05000458/2006003-01, Failure to identify
Division III ESF bus supply breaker not racked in.
Enclosure
-17-
1R19
Postmaintenance Testing
a.
Inspection Scope
For the five postmaintenance test activities of risk significant systems or components
listed below, the inspectors: (1) reviewed the applicable licensing basis and/or design-
basis documents to determine the safety functions; (2) evaluated the safety functions
that may have been affected by the maintenance activity; and (3) reviewed the test
procedure to verify that it adequately tested the safety function that may have been
affected. The inspectors either witnessed or reviewed test data to verify that
acceptance criteria were met, plant impacts were evaluated, test equipment was
calibrated, procedures were followed, jumpers were properly controlled, the test data
results were complete and accurate, the test equipment was removed, the system was
properly re-aligned, and deficiencies during testing were documented. The inspectors
also reviewed the CAP to determine if the licensee identified and corrected problems
related to postmaintenance testing.
Work Order (WO) 50370422, Division II battery cell post seal replacement,
reviewed during the week of May 8, 2006
WO 87721, replace control Rods 40-37, 44-41, and 48-25 and 12-25 individual
scram test switches, reviewed May 19, 2006
WO 69816, low pressure core spray keep fill pump discharge check valve, E21-
VF033 replacement, reviewed during the week of June 19, 2006
WO 85194, signature testing on high pressure core spray room unit cooler
service water outlet valve, SWP-MOV74B, reviewed during the week of June 19,
2006
WO 90342, Division II EDG generator output Breaker ENS-SWG1B-ACB027
charging springs failed to charge during tagout restoration, reviewed on June 23,
2006
The inspectors completed five inspection samples.
g.
Findings
No findings of significance were identified.
1R20
Refueling and Other Outage Activities
a.
Inspection Scope
The inspectors reviewed the following risk important refueling outage activities to verify
defense in depth commensurate with the outage risk control plan and compliance with
the TS during RFO-13 from April 23 to May 12, 2006: (1) the risk control plan;
(2) tagging/clearance activities; (3) reactor coolant system instrumentation; (4) electrical
Enclosure
-18-
power; (5) decay heat removal; (6) spent fuel pool cooling; (7) inventory control;
(8) reactivity control; (9) containment closure; (10) reduced inventory conditions;
(11) refueling activities; (12) heatup and cooldown activities; (13) restart activities; and
(14) licensee identification and implementation of appropriate corrective actions
associated with RFO activities. The inspectors' containment inspections included
observations of the containment sump for damage and debris, and supports, braces,
and snubbers for evidence of excessive stress, water hammer, or aging. Specific
outage activities observed and reviewed included:
Outage risk assessment team (ORAT) report to onsite safety review committee
Reactor shutdown, cooldown, and vessel disassembly
Refueling operations, fuel sipping, and off loaded fuel inspections
Daily/shiftly shutdown operations protection plan assessments
Shutdown postscram report to onsite safety review committee
Reactor recirculation pump trip logic modification installation and testing
Main steam line local leak rate testing
Transformer RSS1 offsite power line equipment inspection and upgrade
Division II to Division I protected division swap
Infrequently performed test or evolution briefings for:
- Divisional loss of offsite power/loss of coolant accident testing
- Concurrent control rod mechanism and blade changeout
- Reactor vessel pressure test and scram time testing
- Reactor startup, heatup, and power ascension
- Onsite safety review committee meeting to recommend startup
- Drywell 900 psi walkdown (after shutdown and during startup)
Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed one inspection sample.
b.
Findings
Introduction: An NRC identified NCV of 10 CFR 50.65, Maintenance Rule,
Section (a)(4) was identified for the failure of the licensee to provide prescribed
compensatory measures for the highest shutdown risk condition during RFO-13.
Specifically, the preoutage risk assessment recommended that two WOs be in place for
maintenance electricians to provide power to one spent fuel pool cooling pump in the
event of problems with the running pump during periods of safety-related electrical bus
maintenance. The inspectors found that the WOs were not in place before entering
shutdown risk condition Orange on April 26, 2006, during the Division II ESF bus testing,
and on May 3, 2006, during the Division I ESF bus outage.
Description: The inspectors observed the onsite safety review committee meeting to
discuss and approve the ORAT report for RFO-13. The report noted two Orange
shutdown risk conditions for spent fuel pool cooling (SFC). Only one SFC pump would
be available after the beginning of core offload: (1) during the Division II ESF bus
testing with the SFC-P1B breaker racked out, and (2) during the Division I ESF bus
outage when SFC-P1A was without power. As a result of the ORAT review of
Enclosure
-19-
Procedure AOP-0051, Loss of Decay Heat Removal, Revision 17, they recommended
that the planned maintenance optimization group develop WOs for maintenance
electricians to provide alternate power from the station blackout diesel generator to the
deenergized SFC pump in the event of a failure of the running pump.
In addition, Procedure OSP-0037, Shutdown Operations Protection Plan, Revision 16,
Section 4.7, Fuel Pool Cooling, required that: (1) if work was required on SFC during
the outage, then it should be done as early as possible in the outage and not after fuel
offload (when heat load is the highest); and (2) if work was required after fuel offload,
then a contingency plan shall be in place prior to removing the system from service.
The inspectors determined that this requirement applied to deenergizing an SFC pump
for electrical bus maintenance.
On May 3, 2006, during the Division I ESF bus outage, the inspectors asked the
operations shift manager if the required WO was available to provide alternate power to
SFC-P1A in the event that the running SFC-P1B failed. He stated that he assumed that
the WO was written and that he would check. The inspectors then requested a copy of
the WO and a senior work planner reported that the WO was not available since it was
not yet approved for use in the electronic work planning program. Following discussions
with operators in the work management center, the licensee immediately took actions to
ensure that both WOs were processed and made ready for use.
The inspectors reviewed AOP-0051, Attachment 1, Spent Fuel Pool Curves, and
determined that the approximate time to boil for the spent fuel pool at that time with
offload fuel in the pool was approximately 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. Based on that data and the time
needed to generate the WOs, the inspectors determined that there was adequate time
for the licensee to connect an alternate power supply to the SFC pumps before the
spent fuel pool water started to boil if there was a failure of the running pump.
Analysis: The performance deficiency associated with this finding involved the failure to
establish prescribed compensatory measures for the highest outage risk condition
during RFO-13 as required by the shutdown operations protection plan. The finding was
more than minor because the licensee failed to implement prescribed compensatory
measures and failed to effectively manage those measures. The finding affected the
mitigating system cornerstone because of the increased risk of a sustained loss of SFC
during core offloading operations. The finding could not be evaluated using the
significance determination process; therefore, the finding was reviewed by regional
management and determined to be of very low safety significance. Factors that were
considered included: (1) electrical maintenance technicians had previously performed
the task of providing alternate power to an SFC pump, (2) the necessary equipment was
staged as part of the abnormal operating procedure for loss of decay heat removal, and
(3) the relatively long time to boil of the spent fuel storage pool at that time during the
refueling outage. The cause of the finding was related to the crosscutting aspect of
human performance because the licensees planned maintenance activities and the
predetermined increase in outage risk was not effectively managed by prescribed
compensatory measures.
Enclosure
-20-
Enforcement: 10 CFR 50.65(a)(4) requires, in part, that before performing maintenance
activities, the licensee shall assess and manage the increase in risk that may result from
the proposed maintenance activities. Contrary to this, the licensee failed to properly
manage the highest outage risk condition of RFO-13. On April 26, 2006, the plant
entered an Orange outage risk condition for SFC during core offload, when SFC-P1B
was deenergized for Division II ESF bus testing. On May 3, 2006, the plant entered an
Orange outage risk condition for SFC during core offload, when SFC-P1A was
deenergized for a Division I ESF bus outage. WOs were not written and ready for use
to have electricians provide alternate power to an SFC pump in the event the running
pump failed. The root cause involved the failure of the licensee to ensure that the WO
was in place before the plant entered the Orange shutdown risk condition. Corrective
action was taken to process the WOs for immediate use. Because the finding was of
very low safety significance and was entered into the licensees CAP as CR-RBS-2006-
01937, this violation is being treated as an NCV consistent with Section VI.A of the
Enforcement Policy: NCV 05000458/2006003-02, "Failure to adequately manage an
increase in plant risk."
1R22
Surveillance Testing
a.
Inspection Scope
The inspectors reviewed the USAR, procedure requirements, and TS to ensure that the
six surveillance activities listed below demonstrated that the SSCs tested were capable
of performing their intended safety functions. The inspectors either witnessed or
reviewed test data to verify that the following significant surveillance test attributes were
adequate: (1) preconditioning; (2) evaluation of testing impact on the plant;
(3) acceptance criteria; (4) test equipment; (5) procedures; (6) jumper/lifted lead
controls; (7) test data; (8) testing frequency and method demonstrated TS operability;
(9) test equipment removal; (10) restoration of plant systems; (11) fulfillment of ASME
Code requirements; (12) updating of performance indicator (PI) data; (13) engineering
evaluations, root causes, and bases for returning tested SSCs not meeting the test
acceptance criteria were correct; (14) reference setting data; and (15) annunciator and
alarm setpoints. The inspectors also verified that the licensee identified and
implemented any needed corrective actions associated with the surveillance testing.
STP-208-3601, "A Main Steam Line MSIVs and Outboard Drain Valve Leak
Rate Test and Inboard MSIV Inleakage Test," Revision 6, performed on May 2,
2006
STP-305-1606, [Division I Battery] ENB-BAT1A Service Discharge Test,
Revision 17, performed on May 6, 2006
STP-050-3601, Shutdown Margin Demonstration, Revision 27, performed on
May 12, 2006
STP-000-0102, Power Distribution Alignment Check, Revision 5, performed on
May 14 and 15, 2006
Enclosure
-21-
STP-508-4543, Turbine First Stage Pressure Channel Functional Test,
Revision 7, performed on June 4, 2006
Reactor coolant sample using Procedures COP-0001, Sampling via Various
Balance-Of-Plant Systems, Attachment 8, Reactor Sample Panel Routine
Sample Points, Revision 14, and COP-0305, Operation of the Countroom
Analysis Systems, Revision 2, performed on June 15, 2006
Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed six inspection samples.
h.
Findings
Introduction: The inspectors identified an NCV of TS 5.4.1.a for the failure of the
licensee to provide an adequate surveillance test procedure to perform TS Surveillance
Requirement (SR) 3.8.1.1. Specifically, STP-000-0102, Power Distribution Alignment
Check, Revision 4, did not include steps to verify the required offsite power circuit
breaker alignment and indicated power availability for the Division III 4.16 kV ESF bus
as required in Modes 1, 2, and 3.
Description: As discussed in Section 1R15 of this report, operators failed to properly
rack in Breaker NNS-ACB23 on April 29, 2006. This condition was discovered on
May 22, when the breaker failed to close. During this period, on May 14, 2006, the
Division I EDG was removed from service to replace a leaking section of jacket cooling
water vent tubing. With the Division I EDG removed from service, TS Required
Action 3.8.1.a.1 required that operators perform TS SR 3.8.1.1 within one hour and
once every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> until the EDG was operable. TS SR 3.8.1.1 required operators to
verify the correct breaker alignment and indicated power for each required offsite power
circuit. Operators utilized Procedure STP-000-0102, Power Distribution Alignment
Check, Revision 4, to satisfy the requirements of TS SR 3.8.1.1; however, the
inspectors identified that the procedure did not have steps to verify the correct breaker
alignment and indicated power availability to the Division III 4.16 kV ESF bus. As a
result, the operators did not identify that Breaker NNS-ACB23 was not racked in.
During the period that the Division I EDG was removed from service, the plant was
actually in TS Condition 3.8.1.d. TS Condition 3.8.1.d states that with One required
offsite circuit inoperable AND one required [E]DG inoperable, restore the EDG or the
offsite power supply to an operable status in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> or place the plant in Mode 3 within
the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The Division I EDG was inoperable for 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> and 15 minutes.
Procedure STP-000-0102, Section 1.1, states, in part, that its purpose is to verify the
correct breaker alignment and indicated power availability for each required offsite
power circuit in accordance with TS SR 3.8.1.1 in Modes 1, 2, and 3. TS 3.8.1 bases
defines an offsite power circuit as follows: Each offsite circuit consists of incoming
breakers and disconnects to the respective preferred station service Transformers 1C
and 1D [RSS1 and RSS2], the 1C and 1D preferred station service transformers, and
the respective circuit path including feeder breakers to the three 4.16 kV ESF buses.
Enclosure
-22-
NNS-ACB23 is one of the circuit breakers between preferred station service
Transformer RTX-XSR1C and the Division III 4.16 kV ESF bus.
Analysis: The performance deficiency associated with this finding involved the
licensees failure to provide operators with an adequate STP to meet the requirements
of TS SR 3.8.1.1 to verify correct breaker alignment and indicated power availability to
the Division III ESF bus for each required offsite circuit. A review of previous revisions
of STP-000-0102 showed that the procedure has never verified the required offsite
power circuits for the Division III 4.16 kV ESF bus in Modes 1, 2, and 3. Although this
performance deficiency caused the failure to verify the offsite power circuit for an
extended period of time, the risk impact was limited to the 10 days from May 12-22,
2006. Therefore, the risk characterization of this finding is the same as that described in
Section 1R15 of this inspection report. The cause of the finding was related to the
crosscutting aspect of human performance because the licensee did not provide the
operators with an adequate STP to complete the TS SR to verify the required offsite
power circuits breaker alignment to all three 4.16 kV ESF buses. Additionally, the
cause of the finding was related to the crosscutting aspect of problem identification and
resolution in that on two occasions, June 18, 2005, and May 22, 2006, operators
entered TS Condition 3.8.1.a for one inoperable offsite power circuit to the Division III
4.16 kV ESF bus and performed STP-000-0102 to meet the Required Action to perform
SR 3.8.1.1, but did not recognize that STP-000-0102 did not verify the other offsite
power circuit breaker alignment to the Division III 4.16 kV ESF bus.
Enforcement: TS 5.4.1.a requires that written procedures be established, implemented,
and maintained covering the activities specified in Appendix A, "Typical Procedures for
Pressurized Water Reactors and Boiling Water Reactors," of Regulatory Guide 1.33,
"Quality Assurance Program Requirements (Operation)," dated February 1978.
Regulatory Guide 1.33, Appendix A, Section 8.a, requires procedures for all TS SRs.
Procedure STP-000-0102 states that it verified the correct breaker alignment and power
availability for each required offsite circuit in accordance with TS SR 3.8.1.1 in Modes 1,
2, and 3. Contrary to this, Procedure STP-000-0102, Revision 4, did not require
verification of the correct breaker alignment for the offsite power circuits to the
Division III 4.16 kV ESF bus in Modes 1, 2, and 3. The root cause involved the incorrect
interpretation of the Division III 4.16 kV bus SRs as they apply to the unique River Bend
Station ESF electrical distribution system. The corrective actions to restore compliance
included as an interim measure entering in the control room logs the breaker alignment
for and the bus voltage available to the Division III 4.16 kV ESF bus, until STP-000-0102
could be revised. Because the finding was of very low safety significance and has been
entered into the licensees CAP as CR-RBS-2006-02675 and -02402, this violation is
being treated as an NCV consistent with Section VI.A of the Enforcement Policy: NCV 05000458/2006003-03, Inadequate procedure to verify required offsite power breaker
alignment.
Enclosure
-23-
1R23
Temporary Plant Modifications
a.
Inspection Scope
The inspectors reviewed the USAR, plant drawings, procedure requirements, and TS to
ensure that Temporary Alteration 2006-0011, Off Gas Pretreatment Radiation Monitor
Sample Chamber Drain Line Modification, was properly implemented. The inspectors:
(1) verified that the modification did not have an affect on system operability/availability;
(2) verified that the installation was consistent with modification documents; (3) ensured
that the postinstallation test results were satisfactory and that the impact of the
temporary modification on the operation of the pretreatment radiation monitor were
supported by the test; (4) verified that the modification was identified on control room
drawings and that appropriate identification tags were placed on the affected drawings;
and (5) verified that appropriate safety evaluations were completed. The inspectors
verified that the licensee identified and implemented any needed corrective actions
associated with temporary modifications.
The inspectors completed one inspection sample.
b.
Findings
No findings of significance were identified.
Cornerstone: Emergency Preparedness
1EP6 Drill Evaluation
a.
Inspection Scope
On June 20, 2006, the inspectors observed the full scope exercise dress rehearsal,
which was used to contribute to Drill/Exercise Performance and Emergency Response
Organization Drill Performance PI. The inspectors: (1) observed the training evolution
to identify any weaknesses and deficiencies in classification, notification, and protective
action requirements development activities; (2) compared the identified weaknesses and
deficiencies against licensee identified findings to determine whether the licensee was
properly identifying failures; and (3) determined whether licensee performance was in
accordance with the guidance of the NEI 99-02, "Voluntary Submission of Performance
Indicator Data," Revision 2, acceptance criteria. The scenario used was RDRL-EP-
0602, Tornado/Loss of Offsite Power/Main Steam Line Break, dated June 16, 2006.
Emergency [plan] implementing procedures reviewed by the inspectors included:
EIP-2-001, Classification of Emergencies, Revision 13
EIP-2-006, Notifications, Revision 32
EIP-2-007, Protective Action Guidelines Recommendations, Revision 21
The inspectors completed one inspection sample.
Enclosure
-24-
b.
Findings
No findings of significance were identified.
2.
RADIATION SAFETY
Cornerstone: Occupational Radiation Safety
2OS1 Access Control to Radiologically Significant Areas
a.
Inspection Scope
This area was inspected to assess the licensees performance in implementing physical
and administrative controls for airborne radioactivity areas, radiation areas, high
radiation areas, and worker adherence to these controls. The inspector used the
requirements in 10 CFR Part 20, TS, and the licensees procedures required by TS as
criteria for determining compliance. During the inspection, the inspector interviewed the
radiation protection manager, radiation protection supervisors, and radiation workers.
The inspector performed independent radiation dose rate measurements and reviewed
the following items:
PI events and associated documentation packages reported by the licensee in
the occupational radiation safety cornerstone
Controls (surveys, posting, and barricades) of three radiation, high radiation, or
airborne radioactivity areas
Radiation work permits, procedures, engineering controls, and air sampler
locations
Conformation of electronic personal dosimeter alarm setpoints with survey
indications and plant policy; workers knowledge of required actions when their
electronic personnel dosimeter noticeably malfunctions or alarms
Barrier integrity and performance of engineering controls in airborne radioactivity
areas
Adequacy of the licensees internal dose assessment for any actual internal
exposure greater than 50 millirem committed effective dose equivalent
Physical and programmatic controls for highly activated or contaminated
materials (nonfuel) stored within spent fuel and other storage pools.
Self-assessments, audits, licensee event reports (LER), and special reports
related to the access control program since the last inspection
Corrective action documents related to access controls
Enclosure
-25-
Licensee actions in cases of repetitive deficiencies or significant individual
deficiencies
Radiation work permit briefings and worker instructions
Adequacy of radiological controls, such as required surveys, radiation protection
job coverage, and contamination controls during job performance
Dosimetry placement in high radiation work areas with significant dose rate
gradients
Changes in licensee procedural controls of high dose rate - high radiation areas
and very high radiation areas
Controls for special areas that have the potential to become very high radiation
areas during certain plant operations
Posting and locking of entrances to all accessible high dose rate - high radiation
areas and very high radiation areas
Radiation worker and radiation protection technician performance with respect to
radiation protection work requirements
The inspector completed 21 of the required 21 samples.
b.
Findings
1.
Unguarded High Radiation Area Boundary
Introduction: The inspector reviewed a self-revealing NCV of TS 5.7.1, resulting from
the licensees failure to control access to a high radiation area. The finding had very low
safety significance.
Description: On April 6, 2006, the licensee transferred reverse osmosis system filters
from one elevation of the radwaste building to another. Because dose rates on the filter
barrels were as high as 600 millirem per hour, the licensee assigned personnel to guard
the elevator entrances to prevent workers from entering high radiation areas. On this
occasion, the guards were not using radios, as was a common practice. Because of the
lack of good communication, a guard prematurely left his post in front of the 123-foot
elevation elevator door. Coincidently, two workers attempted to board the elevator on
the 123-foot elevation after the guard had left. The elevator carrying the barrels of
radioactive filters stopped at the 123-foot elevation, the doors opened, and the
electronic dosimeters of the workers alarmed because of the high dose rates. The
guard returned and evacuated the workers before they accrued additional radiation
dose. The highest dose rate recorded by an electronic alarming dosimeter was 164
millirem per hour. Planned corrective action was still being evaluated by the licensee at
the conclusion of the inspection.
Enclosure
-26-
Analysis: The failure to control access to a high radiation area was a performance
deficiency. The significance of the finding was greater than minor because it was
associated with the occupational radiation safety attribute of exposure control and
affected the cornerstone objective, in that not controlling access to a high radiation area
could increase personal exposure. Using the Occupational Radiation Safety
Significance Determination Process, the inspector determined that the finding was of
very low safety significance because it did not involve: (1) an as low as is reasonably
achievable (ALARA) finding, (2) an overexposure, (3) a substantial potential for
overexposure, or (4) an impaired ability to assess dose. Additionally, this finding had
crosscutting aspects associated with human performance in that the failure of the
individual to guard the elevator door directly contributed to the violation.
Enforcement: TS 5.7.1 requires each high radiation area, as defined in 10 CFR Part 20,
in which the intensity of radiation is greater than 100 millirems per hour but less than
1000 millirems per hour, be barricaded and conspicuously posted as a high radiation
area and entrance thereto shall be controlled by requiring issuance of a radiation work
permit. The licensee violated TS 5.7.1 when it failed to barricade and conspicuously
post the elevator housing the radioactive filter barrels or maintain a guard to ensure
workers did not enter a high radiation area. Because this failure to control a high
radiation area was of very low safety significance and has been entered into the
licensees CAP as CR-RBS-2006-01294, this violation is being treated as an NCV,
consistent with Section VI.A of the NRC Enforcement Policy:
NCV 05000458/2006003-04, Failure to control access to a high radiation area.
2.
Unanalyzed Airborne Radioactivity Survey
Introduction: The inspector identified an NCV of 10 CFR 20.1501(a) because the
licensee failed to survey airborne radioactivity. The finding had very low significance.
Description: On May 2, 2006, during the removal of local power range monitors, the
licensee started collecting an air sample of the work area. The air sample spanned two
shifts. A health physics technician on the second shift discarded the sample because
the first shift had not documented a start time. Therefore, the sample was never
analyzed. However, all workers successfully passed through the portal monitors at the
exit of the controlled access area without alarm, confirming that no worker experienced
an uptake of radioactive material. Planned corrective action is still being evaluated.
Analysis: The failure to survey airborne radioactivity was a performance deficiency.
This finding was greater than minor because it was associated with the occupational
radiation safety program attribute of exposure control and affected the cornerstone
objective in that the lack of knowledge of radiological conditions could increase
personnel dose. Using the Occupational Radiation Safety Significance Determination
Process, the inspector determined that the finding was of very low safety significance
because it did not involve: (1) an ALARA finding, (2) an overexposure, (3) a substantial
potential for overexposure, or (4) an impaired ability to assess dose. Additionally, this
finding had crosscutting aspects associated with human performance in that the failure
to maintain the sample for analysis directly contributed to the violation.
Enclosure
-27-
Enforcement: 10 CFR 20.1501(a) requires that each licensee make or cause to be
made surveys that may be necessary for the licensee to comply with the regulations in
10 CFR Part 20 and that are reasonable under the circumstances to evaluate the extent
of radiation levels, concentrations or quantities of radioactive materials, and the potential
radiological hazards that could be present. Pursuant to 10 CFR 20.1003, a survey
means an evaluation of the radiological conditions and potential hazards incident to the
production, use, transfer, release, disposal, or presence of radioactive material or other
sources of radiation. In part, 10 CFR 20.1201(a) states that the licensee shall control
the occupational dose to individual adults. The licensee violated 10 CFR 20.1501(a)
when it failed to perform an evaluation of airborne radioactivity to ensure compliance
with 10 CFR 20.1201(a). Because this failure to perform a radiological survey was of
very low safety significance and has been entered into the licensees CAP as
CR-RBS-2006-01994, this violation is being treated as an NCV, consistent with
Section VI.A of the NRC Enforcement Policy: NCV 05000458/2006003-05, Failure to
perform airborne radiation survey.
2OS2 ALARA Planning and Controls
a.
Inspection Scope
The inspector assessed licensee performance with respect to maintaining individual and
collective radiation exposures 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 outage or 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
ALARA work activity evaluations, exposure estimates, and exposure mitigation
requirements
Intended versus actual work activity doses and the reasons for any
inconsistencies
Shielding requests and dose/benefit analyses
Dose rate reduction activities in work planning
Use of engineering controls to achieve dose reductions and dose reduction
benefits afforded by shielding
Workers use of the low dose waiting areas
First-line job supervisors contribution to ensuring work activities are conducted
in a dose efficient manner
Enclosure
-28-
Radiation worker and radiation protection technician performance during work
activities in radiation areas, airborne radioactivity areas, or high radiation areas
The inspector completed 6 of the required 15 samples and 4 of the optional samples.
b.
Findings
No findings of significance were identified.
4.
OTHER ACTIVITIES
4OA1 Performance Indicator Verification
a.
Inspection Scope
1.
Barrier Integrity Cornerstone
The inspectors sampled licensee submittals for the two PIs listed below for the period
October 1, 2004, through March 31, 2006. The definitions and guidance of NEI 99-02,
Regulatory Assessment Indicator Guideline, Revision 4, were used to verify the
licensees basis for reporting each data element in order to verify the accuracy of PI
data reported during the assessment period. The inspectors: (1) reviewed reactor
coolant system (RCS) chemistry sample analyses for dose equivalent Iodine-131 and
compared the results to the TS limit; (2) observed a chemistry technician obtain and
analyze an RCS sample; (3) reviewed operating logs and surveillance results for
measurements of RCS identified leakage; and (4) observed a surveillance test that
determined RCS identified leakage.
C
RCS Specific Activity
C
RCS Leakage
The inspectors completed two inspection samples.
2.
Occupational Radiation Safety Cornerstone
The review included corrective action documentation that identified occurrences in
locked high radiation areas (as defined in the licensees TS), very high radiation areas
(as defined in 10 CFR 20.1003), and unplanned personnel exposures (as defined in
NEI 99-02), specifically CR-RBS-2006-01910. Additional records reviewed included
ALARA records and whole-body counts of selected individual exposures. The inspector
interviewed licensee personnel that were accountable for collecting and evaluating the
PI data. In addition, the inspector toured plant areas to verify that high radiation, locked
high radiation, and very high radiation areas were properly controlled. PI definitions and
guidance contained in NEI 99-02, "Regulatory Assessment Indicator Guideline,"
Revision 3, were used to verify the basis in reporting for each data element.
Enclosure
-29-
Occupational Exposure Control Effectiveness
The inspector completed the one required sample in this cornerstone.
3.
Public Radiation Safety Cornerstone
The inspector reviewed licensee documents from June 1, 2005, through March 31,
2006. Licensee records reviewed included corrective action documentation that
identified occurrences for liquid or gaseous effluent releases that exceeded PI
thresholds and those reported to the NRC. The inspector interviewed licensee
personnel that were accountable for collecting and evaluating the PI data. PI definitions
and guidance contained in NEI 99-02, "Regulatory Assessment Indicator Guideline,"
Revision 3, were used to verify the basis in reporting for each data element.
Radiological Effluent Technical Specification/Offsite Dose Calculation Manual
Radiological Effluent Occurrences
The inspector completed the one required sample in this cornerstone.
f.
Findings
No findings of significance were identified.
4OA2 Identification and Resolution of Problems
1.
Semiannual Trend Review
g.
Inspection Scope
The inspectors completed a semiannual trend review of repetitive or closely related
issues related to identify trends that might indicate the existence of more safety
significant issues. The inspectors review consisted of the 6-month period from
January 1 to June 30, 2006, of CAP items associated with the three EDG starting air
systems documented in 42 CRs. When warranted, some of the samples expanded
beyond those dates to fully assess the issue. The inspectors compared and contrasted
their results with the results contained in adverse trend CRs for problems related to the
starting air compressors and air dryers. Corrective actions associated with a sample of
the issues identified were reviewed for adequacy. The CRs reviewed by the inspectors
are listed in the attachment.
The inspectors completed one inspection sample.
b. Findings and Observations
There were no findings of significance identified associated with the CRs reviewed.
The inspectors noted that the licensee had identified a long-standing issue related to the
performance of the EDG starting air systems air compressors. Since January 1, 2006,
Enclosure
-30-
there were 18 CRs written for high metal wear products in monthly air compressor oil
samples. Each of these CRs was closed to CR-RBS-2004-02165. An additional
28 CRs written since August 2, 2004, for high metal wear product concentrations and
high moisture content in monthly compressor oil samples were closed to CR-RBS-2004-
02165. In addition, operators wrote adverse trend CR-RBS-2006-02407 to detail
compressor problems, including excessive run times. The inspectors determined that
the licensee is taking appropriate actions to understand the problem with the EDG
starting air compressors, including sending the system engineer to observe the vendors
teardown and refurbishment of two of the starting air compressors.
Another four CRs have been written since January 1, 2006, describing problems with
starting air system dryers and dryer prefilters. Following a June 29, 2006, meeting held
to discuss overall EDG starting air system maintenance problems, the licensee wrote
CR-RBS-2006-02799, to look into the relationship between the prefilter and dryer
problems. The inspectors noted that this meeting was the first discussion of the overall
condition of the EDG starting air systems and to evaluate the interrelationship between
compressor, dryer, and prefilter problems.
2.
a.
Inspection Scope
The inspector evaluated the effectiveness of the licensees problem identification and
resolution process with respect to the following inspection areas:
Access Control to Radiologically Significant Areas (Section 2OS1)
ALARA Planning and Controls (Section 2OS2)
b. Findings and Observations
No findings of significance were identified.
3.
Inservice Inspection Activities
a.
Inspection Scope
The inspector reviewed selected inservice inspection related CRs issued during the
current and past refueling outages. The review served to verify that the licensees CAP
was being correctly utilized to identify conditions adverse to quality and that those
conditions were being adequately evaluated, corrected, and trended.
b.
Findings
No findings of significance were identified.
Enclosure
-31-
4OA3 Event Followup
1.
(Closed) LER 50-458/2004-003-01, Unplanned Automatic Start of Standby Diesel
Generator Due to Loss of Division 1 Switchgear
On October 31, 2004, technicians caused an unexpected degraded voltage signal,
which resulted in a loss of the Division I 4.16 kV ESF bus during preparations for the
Division I loss of offsite power/loss of coolant accident test. The Division I EDG
automatically started and powered the ESF bus and all equipment operated as
expected. Initial inspection of this event was documented in NRC integrated inspection
Report 05000458/2004005. During this inspection period, the inspectors reviewed the
LER, the root cause analysis, and corrective actions documented in
CR-RBS-2004-03518. No additional findings of significance were identified. This LER
is closed.
2.
(Closed) LER 50-458/2004-004-01, Unplanned Automatic Start of Standby Diesel
Generator Due to Loss of Division 2 Switchgear
On November 1, 2004, technicians inadvertently caused a trip of Transformer RSS2
preferred station service Transformer RTX-XSR1F while troubleshooting a transformer
sudden pressure relay trip circuit. As a result, power was also lost to preferred station
Transformer RTX-XSR1D and the Division II 4.16 kV ESF bus. The running shutdown
cooling, alternate decay heat removal, and plant operating water cleanup systems lost
power until the Division II EDG started and restored power to the ESF bus. Shutdown
cooling was restored in less than one hour. Initial inspection of this event was
documented in NRC integrated inspection Report 05000458/2004005. During this
inspection period, the inspectors reviewed the LER, the root cause analysis, and
corrective actions documented in CR-RBS-2004-03546. No additional findings of
significance were identified. This LER is closed.
3.
(Closed) LER 50-458/2004-005-01, Unplanned Automatic Scram Due to Loss of
Non-Vital 120 Volt Instrument Bus
On December 10, 2004, an automatic scram occurred due to a loss of power to
nonsafety-related instrumentation Bus VBN-PNL01B1. A capacitor on the control board
for the nonsafety-related Inverter BYS-INV01B static switch failed, which caused a loss
of power to Bus VBN-PNL01B1, a subsequent downshift of the plant operating
recirculation pumps and a lockup of the main feedwater regulating valves. The result
was an automatic plant scram complicated by a loss of normal feedwater. Inspection of
this event was documented in NRC integrated inspection Report 05000458/2004005.
Additional inspection was documented in NRC supplemental inspection Report
05000458/2005012. During this inspection period, the inspectors reviewed the LER, the
root cause analysis, and corrective actions documented in CR-RBS-2004-04289. No
additional findings of significance were identified. This LER is closed.
Enclosure
-32-
4.
(Closed) LER 50-458 /2005-001-01, Unplanned Manual Scram Due to Indication of
Ground Fault in Main Generator
On January 15, 2005, while the plant was at 100 percent power, a main generator field
ground fault alarm was received. Control room operators tripped the turbine in
accordance with alarm response Procedure ARP-680-09. The licensee later determined
that one of the five rectifier banks in the generator excitation control system was the
source of the ground and removed it from service. In addition, the licensee tested the
relay that causes the main generator ground fault alarm and found it to be out of
calibration such that it alarmed before the ground current reached its setpoint. The
alarm response procedure requirement to trip the turbine was revised to allow validation
of the alarm before tripping the main turbine. Inspection of this event was documented
in NRC integrated inspection Report 05000458/2005002. Additional inspection was
documented in NRC supplemental inspection Report 05000458/2005012. During this
inspection period, the inspectors reviewed the LER, the root cause analysis, and
corrective actions documented in CR-RBS-2005-00140. No additional findings of
significance were identified. This LER is closed.
4OA5 Other Activities
Implementation of Temporary Instruction 2515/165 - Operational Readiness of Offsite
Power and Impact on Plant Risk
a.
Inspection Scope
The objective of Temporary Instruction 2515/165, "Operational Readiness of Offsite
Power and Impact on Plant Risk," was to gather information to support the assessment
of nuclear power plant operational readiness of offsite power systems and impact on
plant risk. During this inspection, the inspectors interviewed licensee personnel,
reviewed licensee procedures, and gathered information for further evaluation by the
Office of Nuclear Reactor Regulation.
b.
Findings
No findings of significance were identified.
4OA6 Meetings, Including Exit
Exit Meetings
On May 5, 2006, the inspector presented the occupational radiation safety inspection
results to Mr. D. Vinci, General Manager, Plant Operations, 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 May 5, 2006, the inspector presented the results of this inspection of inservice
inspection activities to Mr. P. Russell, Manager, System Engineering, and other
Enclosure
-33-
members of licensee management. The inspector confirmed that proprietary
information was not provided or examined during the inspection.
On July 5, 2006, the resident inspectors presented the integrated baseline inspection
results to Mr. P. Hinnenkamp, Vice President - Operations, and other members of
licensee management. The inspectors confirmed that proprietary information was not
provided or examined during the inspection.
ATTACHMENT: SUPPLEMENTAL INFORMATION
Attachment
A-1
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
T. Baccus, Acting Supervisor, ALARA Planning
L. Ballard, Manager, Quality Programs
D. Burnett, Superintendent, Chemistry
C. Bush, Manager, Outage
J. Clark, Assistant Operations Manager - Training
T. Coleman, Manager, Planning and Scheduling/Outage
M. Davis, Manager, Radiation Protection
C. Forpahl, Manager, Corrective Action Program
T. Gates, Manager, Equipment Reliability
H. Goodman, Director, Engineering
K. Higginbotham, Assistant Operations Manager - Shift
P. Hinnenkamp, Vice President - Operations
B. Houston, Manager, Plant Maintenance
A. James, Superintendent, Plant Security
K. Jenks, Supervisor, Engineering Codes and Standards
N. Johnson, Manager, Engineering Programs & Components
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
J. Miller, Manager, Training and Development
P. Russell, Manager, System Engineering
C. Stafford, Manager, Operations
D. Vinci, General Manager - Plant Operations
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened and Closed
Failure to identify Division III ESF bus supply breaker not
racked in
Failure to adequately manage an increase in plant risk 05000458/2006003-03
Inadequate procedure to verify required offsite power
breaker alignment
Failure to control access to a high radiation area
Failure to perform airborne radiation survey
Attachment
A-2
Closed
50-458/2004-003-01
LER
Unplanned Automatic Start of Standby Diesel Generator
Due to Loss of Division 1 Switchgear
50-458/2004-004-01
LER
Unplanned Automatic Start of Standby Diesel Generator
Due to Loss of Division 2 Switchgear
50-458/2004-005-01
LER
Unplanned Automatic Scram Due to Loss of Non-Vital 120
Volt Instrument Bus
50-458 /2005-001-01
LER
Unplanned Manual Scram Due to Indication of Ground
Fault in Main Generator
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 1R06: Inservice Inspection Activities
Procedures
CEP-NDE-0400, Ultrasonic Examination, Revision 0
CEP-NDE-0404, Manual Ultrasonic Examination of Ferritic Piping Welds (ASME XI),
Revision 1
CEP-NDE-0407, Straight Beam Ultrasonic Examination of Bolts and Studs (ASME XI),
Revision 1
CEP-NDE-0423, Manual Ultrasonic Examination of Austenitic Piping Welds (ASME XI),
Revision 1
CEP-NDE-0424, Manual Ultrasonic Examination of the Reactor Vessel Flange Ligament Areas
(ASME XI), Revision 1
CEP-NDE-0428, Manual Ultrasonic Throughwall Sizing in Piping Welds (ASME XI), Revision 1
CEP-NDE-0641, Liquid Penetrant Examination for ASME Section XI, Revision 1
CEP-NDE-0731, Magnetic Particle Examination (ASME Section XI), Revision 0
SPP-7010, Preparation of Weld Data Documents, Revision 9
Attachment
Miscellaneous Documents
7228.000-701-131A, Risk Informed Break Exclusion Region Evaluation for River Bend
Station, Revision 0
Liquid Penetrant Examinations
BOP-PT-06-024
BOP-PT-06-025
BOP-PT-06-026
BOP-PT-06-029
UT Calibration Reports
CAL -06-015
CAL -06-016
CAL-06-017
ISI-UT-06-003
ISI-UT-06-006
ISI-UT-06-009
ISI-UT-06-012
ISI-UT-06-004
ISI-UT-06-007
ISI-UT-06-010
ISI-UT-06-013
ISI-UT-06-005
ISI-UT-06-008
ISI-UT-06-011
ISI-UT-06-014
Condition Reports
CR-RBS-2005-00067
CR-RBS-2005-01379
Section 1R15: Operability Evaluations
Primary Containment Purge Exhaust Line Operability
CR-RBS-2006-00964, primary containment purge exhaust line leak rate test results showing
negative trend
ADM-0050, Primary Containment Leakage Rate Testing Program, Revision 8
SEP-APJ-001, Primary containment Leakage Rate Testing (Appendix J) Program,
Revision 0G
STP-403-7301, Containment Purge System Isolation Valve Leak Rate Test, Revisions 0, 1, 2,
and 3
RBS-ER-00-0589, Post RF-09 LLRT Testing Interval Determination, dated January 25, 2001
RBS TS Amendment 81, dated July 20, 1995
RBS TS Bases Revision 126, dated March 31, 206
Attachment
A-4
NNS-ACB23 Not Functional
Electrical Drawings
EE-001AC, Startup Electrical Distribution Chart, Revision 33
ESK-05NNS03, Elementary Diagram - 4.16 kV Switchgear Bus 1C Normal Supply ACB,
Revision 13
Corrective Action Documents
CR-RBS-1998-00190
Procedures
OSP-0022, Operations General Administrative Guidelines, Revision 01
GOP-0001, Plant Startup, Revision 47, performed on May 12, 2006
STP-000-0102, Power Distribution Alignment Check, Revision 4, performed on May 9, 2006
STP-000-0102, Power Distribution Alignment Check, Revision 4, performed on May 22, 2006
Work Requests
WR 77441
Miscellaneous Documents
Main Control Room Logs
TS LCO Records: 1-OPT-06-0187
1-TS-06-0694
RBS Tagout Record: 1-302-NNS-SWG1A-006-A
Section 1R20: Refueling and Other Outage Activities
Procedures
RSP-0217, Auxiliary Access Control Functions, Revision 27
GOP-0003, Scram Recovery, Revision 14A, post scram report, dated April 23, 2006
OSP-0031, Shutdown Operations Protection Plan, Revision 16
OSP-0041, Alternate Decay Heat Removal, Revision 8A
AOP-0051, Loss of Decay Heat Removal, Revision 18
OSP-0034, Control of Obstructions for Primary Containment/Fuel Building Operability,
Revision 3
Attachment
A-5
GOP-0001, Plant Startup, Revision 47, performed on May 12, 2006
Corrective Action Documents
CR-RBS-2006-01937
Miscellaneous Documents
Control Room Logs
TS LCO Logs
Daily Refueling Outage Updates
ORAT Report
WO 50340401 and 81284
ER-RB-2005-0157-000, Install new relays on the output of EOC-RPT optical output cards
C71A-AT17 and C71A-AT18, dated May 16, 2006
WO 5034041's task outline to configure the station blackout diesel to supply power to spent fuel
pool cooling Pump SFC-P1A
WO 5034041, Configure the station blackout diesel to supply power to spent fuel pool cooling
Pump SFC-P1A, written May 3, 2006
Section 1R22: Surveillance Testing
Drawing EE-001AC, Startup Electrical Distribution Chart, Revision 33
TS Section 3.8.1 and Bases 3.8.1, Revision 0
USAR Section 8.2.1.2.1, General Design Criteria, Revision 16
NUREG-0989, Safety Evaluation Report Related to the Operation of River Bend Station,
dated May 1984
TS LCO Logs
1-TS-06-0694
I-TS-06-0685
1-TS-05-0386
Corrective Action Documents
CR-RBS-2006-02402
Attachment
A-6
Section 4OA2: Identification and Resolution of Problems
Semiannual Trend Review
CR-RBS-2006-00159
CR-RBS-2006-00279
CR-RBS-2006-00434
CR-RBS-2006-00798
CR-RBS-2006-00928
CR-RBS-2006-01131
CR-RBS-2006-01205
CR-RBS-2006-01270
CR-RBS-2006-01333
CR-RBS-2006-01464
CR-RBS-2006-01490
CR-RBS-2006-02348
CR-RBS-2006-02356
CR-RBS-2006-02406
CR-RBS-2006-02469
CR-RBS-2006-02540
CR-RBS-2006-02550
CR-RBS-2006-02559
CR-RBS-2006-02661
CR-RBS-2006-02683
CR-RBS-2006-02733
Section 2OS1: Access Controls to Radiologically Significant Areas
Corrective Action Documents
CR-RBS-2006-00090 CR-RBS- 2006-01294 CR-RBS-2006-01787 CR-RBS- 2006-01950
Radiation Work Permits
2006-1915
RFO-13, Remove and Replace LPRMs, Including Support Activities
2006-1921
RFO-13, Flow Control Valve Maintenance, Including Support Activities
2006-1929
RFO-13, Recirc Pump Work, Including Support Activities
Procedures
RP-103
Access Control, Revision 2
RP-106
Radiological Survey Documentation, Revision 1
RP-108
Radiation Protection Posting, Revision 2
RPP-0006
Performance of Radiological Surveys, Revision 19
Section 2OS2: ALARA Planning and Controls (71121.02)
Corrective Action Documents
Procedures
ENS-RP-105 Radiation Work Permits, Revision 7
Attachment
A-7
LIST OF ACRONYMS
core damage frequency
as low as is reasonably achievable
American Society of Mechanical Engineers
corrective action program
CFR
Code of Federal Regulations
CR-RBS
River Bend Station condition report
LER
licensee event report
MC
inspection manual chapter
noncited violation
NEI
Nuclear Energy Institute
NRC
U.S. Nuclear Regulatory Commission
outage risk assessment team
performance indicators
refueling outage
SFC
spent fuel pool cooling system
system operating procedures
SR
surveillance requirement
structures, systems, or components
surveillance test procedure
TS
Technical Specifications
Updated Safety Analysis Report
work order
work request