ML120310377
| ML120310377 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 01/27/2012 |
| From: | Randy Musser NRC/RGN-II/DRP/RPB4 |
| To: | Annacone M Carolina Power & Light Co |
| References | |
| IR-11-005 | |
| Download: ML120310377 (25) | |
See also: IR 05000324/2011502
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
245 PEACHTREE CENTER AVENUE NE, SUITE 1200
ATLANTA, GEORGIA 30303-1257
January 27, 2012
Mr. Michael Annacone
Vice President
Carolina Power and Light Company
Brunswick Steam Electric Plant
P. O. Box 10429
Southport, NC 28461
SUBJECT: BRUNSWICK STEAM ELECTRIC PLANT - NRC INTEGRATED INSPECTION
REPORT NOS.: 05000325/2011005, 05000324/2011005, 05000325/2011502
AND 05000324/2011502
Dear Mr. Annacone:
On December 31, 2011, the U.S. Nuclear Regulatory Commission (NRC) completed an
inspection at your Brunswick Unit 1 and 2 facilities. The enclosed integrated inspection report
documents the inspection findings, which were discussed on January 18, 2012, with Mr. Edward
Wills 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.
One self-revealing finding of very low safety significance (Green) was identified during this
inspection. This finding was determined to involve a violation of NRC requirements. The NRC
is treating this violation as non-cited violation (NCV) consistent with Section 2.3.2 of the
If you contest this non-cited violation, you should provide a response within 30 days of the date
of this inspection report, with the basis of your denial, to the Nuclear Regulatory Commission,
ATTN.: Document Control Desk, Washington DC 20555-0001; with copies to the Regional
Administrator, Region II; the Director, Office of Enforcement, United States Nuclear Regulatory
Commission, Washington DC 20555-0001; and the NRC Resident Inspector at the Brunswick
Steam Electric Plant.
If you disagree with a cross-cutting aspect assignment in this report, you should provide a
response within 30 days of the date of this inspection report, with the basis for your
disagreement, to the Regional Administrator, Region II; and the NRC Resident Inspector at the
Brunswick Steam Electric Plant.
CP&L 2
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 Web site at
http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Randall A. Musser, Chief
Reactor Projects Branch 4
Division of Reactor Projects
Docket Nos.: 50-325, 50-324
Enclosure: Inspection Report 05000325, 324/2011005, 05000325/2011502,
w/Attachment: Supplemental Information
cc w/encl: (See page 3)
__ML120310377__________ X SUNSI REVIEW COMPLETE X FORM 665 ATTACHED
OFFICE RII:DRP RII:DRP RII:DRP RII:DRP RII:DRP RII:DRP RII:DRS
SIGNATURE JGW JSD PBO by email MES1 by email CRS1 by email DHH1 by email BLC2 for by email
NAME JWorosilo JDodson POBryan MSchwieg CStancil DHardage MBates
DATE 01/23/2012 01/23/2012 01/23/2012 01/23/2012 01/23/2012 01/23/2012 01/25/2012
E-MAIL COPY? YES NO YES NO YES NO YES NO YES NO YES NO YES NO
OFFICE RII:DRP
SIGNATURE RAM
NAME RMusser
DATE 01/27/2012 2/ /2012 2/ /2012 2/ /2012 2/ /2012 2/ /2012 2/ /2012
E-MAIL COPY? YES NO YES NO YES NO YES NO YES NO YES NO YES NO
CP&L 3
cc w/encl: Joseph W. Donahue
Edward L. Wills, Jr. Vice President
Director Site Operations Nuclear Oversight
Brunswick Steam Electric Plant Progress Energy
Electronic Mail Distribution Electronic Mail Distribution
Robert J. Duncan II David T. Conley
Vice President Senior Counsel
Nuclear Operations Legal Department
Progress Energy Progress Energy
Electronic Mail Distribution Electronic Mail Distribution
Joseph M. Frisco, Jr Senior Resident Inspector
Plant General Manager U.S. Nuclear Regulatory Commission
Brunswick Steam Electric Plant Brunswick Steam Electric Plant
Progress Energy U.S. NRC
Electronic Mail Distribution 8470 River Road, SE
Southport, NC 28461
Phyllis N. Mentel
Manager, Support Services John H. O'Neill, Jr.
Brunswick Steam Electric Plant Shaw, Pittman, Potts & Trowbridge
Progress Energy Carolinas, Inc. 2300 N. Street, NW
Electronic Mail Distribution Washington, DC 20037-1128
Annette H. Pope Peggy Force
Supervisor, Licensing/Regulatory Programs Assistant Attorney General
Brunswick Steam Electric Plant State of North Carolina
Progress Energy Carolinas, Inc. P.O. Box 629
Electronic Mail Distribution Raleigh, NC 27602
Randy C. Ivey Chairman
Manager, Nuclear Oversight North Carolina Utilities Commission
Brunswick Steam Electric Plant Electronic Mail Distribution
Progress Energy Carolinas, Inc.
Electronic Mail Distribution cc w/encl. (continued next page)
Paul E. Dubrouillet
Manager, Training
Brunswick Steam Electric Plant
Electronic Mail Distribution
Kelvin Henderson
General Manager
Nuclear Fleet Operations
Progress Energy
Electronic Mail Distribution
CP&L 4
cc w/encl. (continued)
Robert P. Gruber
Executive Director
Public Staff - NCUC
4326 Mail Service Center
Raleigh, NC 27699-4326
Anthony Marzano
Director
Brunswick County Emergency Services
Electronic Mail Distribution
Public Service Commission
State of South Carolina
P.O. Box 11649
Columbia, SC 29211
W. Lee Cox, III
Section Chief
Radiation Protection Section
N.C. Department of Environmental
Commerce & Natural Resources
Electronic Mail Distribution
Warren Lee
Emergency Management Director
New Hanover County Department of
Emergency Management
230 Government Center Drive
Suite 115
Wilmington, NC 28403
U. S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos.: 50-325, 50-324
Report Nos.: 05000325/2011005, 05000324/2011005, 05000325/2011502,
Licensee: Carolina Power and Light (CP&L)
Facility: Brunswick Steam Electric Plant, Units 1 & 2
Location: 8470 River Road, SE
Southport, NC 28461
Dates: October 1, 2011 through December 31, 2011
Inspectors: P. OBryan, Senior Resident Inspector
M. Schwieg, Resident Inspector
C. Stancil, Resident Inspector, Browns Ferry
D. Hardage, Resident Inspector, Hatch
M. Bates, Operator Licensing Inspector
Approved by: Randall A. Musser, Chief
Reactor Projects Branch 4
Division of Reactor Projects
Enclosure
SUMMARY OF FINDINGS
IR 05000325/2011005, 05000324/2011005, 05000325/2011502, 05000324/2011502; 10/01/11 -
12/31/11; Brunswick Steam Electric Plant, Units 1 & 2; Maintenance Effectiveness.
This report covers a three-month period of inspection by resident inspectors and announced
baseline inspections by regional inspectors. One Green finding was identified by the inspectors.
The significance of most findings is indicated by their color (Green, White, Yellow, Red) using
Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). The
cross-cutting aspects were determined using IMC 0310, Components Within the Cross-Cutting
Areas. Findings for which the SDP does not apply may be Green or be assigned a severity
level after NRC management review.
A. NRC-Identified and Self-Revealing Findings
Cornerstone: Mitigating Systems
- Green. A self-revealing Green non-cited violation of TS 5.4.1, Procedures, was
identified for failure to implement procedural requirements for verifying lubrication
levels on the 2B RHRSW Booster pump. This finding resulted in failure of the 2B
RHRSW Booster pump. The condition was entered into the licensees corrective
action program as AR #489386 and the licensee investigated the failure and repaired
the pump.
The failure to follow procedural requirements for verifying lubrication levels was a
performance deficiency. The performance deficiency was more than minor because
it was associated with the Mitigating Systems cornerstone attribute of Equipment
Performance - Availability, and adversely affected the cornerstone objective to
ensure the availability, reliability, and capability of systems that respond to initiating
events to prevent undesirable consequences. Specifically, the performance
deficiency resulted in the failure of the 2B RHRSW booster pump which is credited
for decay heat removal and service water injection. Using Inspection Manual
Chapter 0609, Significance Determination Process, Attachment 0609.04, Phase 1
Screening Worksheet, the finding screened as potentially greater than green
because it represented an actual loss of a single train of equipment for more than its
Technical Specifications (TS) allowed outage time. Therefore, a phase 2
significance determination evaluation was required. Inspectors with assistance from
a regional Senior Reactor Analyst (SRA) determined the significance of this finding to
be very low safety significance (Green) using Phase 2 pre-solved tables. The cause
of the finding was directly related to the training cross-cutting aspect in the
Resources component of the Human Performance area because the licensee failed
to ensure that workers had adequate knowledge of the RHRSW pump oilers to
execute procedures for verifying lubrication levels which caused a failure of a safety-
related pump. H.2(b) (Section 1R12)
B. Licensee-Identified Violations
None
Enclosure
REPORT DETAILS
Summary of Plant Status
Unit 1 began the inspection period at rated thermal power (RTP). On December 22, 2011,
power was reduced to approximately 16 percent due to high unidentified leakage inside the
primary containment. After repairs, power was returned to RTP on December 23, 2011, and
remained at or near RTP for the remainder of the inspection period.
Unit 2 began the inspection period at RTP. On October 28, 2011, power was reduced to
approximately 44 percent due to an inadvertent trip of the 2B recirculation pump. The unit was
returned to RTP on November 2, 2011. On November 4, 2011, the unit was shut down for a
planned maintenance outage. The unit began a reactor startup on November 16, 2011, but
operators scrammed the reactor due to high unidentified leakage inside of the primary
containment and remained shut down until December 1, 2011. The details of the NRC review of
this issue are contained in NRC inspection report 05000324/2011013. Unit returned to RTP on
December 9, 2011, and remained at or near RTP for the remainder of the inspection period.
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R04 Equipment Alignment
.1 Quarterly Partial System Walkdowns
a. Inspection Scope
The inspectors performed three (3) partial system walkdowns of the following risk-
significant systems:
- Emergency Diesel Generator (EDG) #4 with EDG #3 out of service for planned
maintenance on October 19, 2011;
- EDG #2 following planned maintenance on November 8, 2011; and
- Unit 2 High Pressure Injection Cooling (HPIC) following planned maintenance on
November 15, 2011.
The inspectors selected these systems based on their risk-significance relative to the
reactor safety cornerstones at the time they were inspected. The inspectors attempted
to identify any discrepancies that could impact the function of the system, and, therefore,
potentially increase risk. The inspectors reviewed applicable operating procedures,
system diagrams, Updated Final Safety Analysis Report (UFSAR), TS requirements,
outstanding work orders, condition reports, and the impact of ongoing work activities on
redundant trains of equipment in order to identify conditions that could have rendered
Enclosure
4
the systems incapable of performing their intended functions. The inspectors also
walked down accessible portions of the systems to verify that system components and
support equipment were aligned correctly and were operable. The inspectors examined
the material condition of the components and observed operating parameters of
equipment to verify that there were no obvious deficiencies. The inspectors also verified
that the licensee had properly identified and resolved equipment alignment problems
that could cause initiating events or impact the capability of mitigating systems or
barriers and entered them into the corrective action program with the appropriate
significance characterization.
b. Findings
No findings were identified.
1R05 Fire Protection
.1 Quarterly Resident Inspector Tours
a. Inspection Scope
The inspectors conducted four (4) fire protection walkdowns which were focused on
availability, accessibility, and the condition of firefighting equipment in the following risk-
significant plant areas:
- Unit 2 Reactor Building East 50' Elevation 2PFP-RB2-1h E;
- Diesel Generator 23' Elevation 1-PFP-DG-5;
- Unit 2 HPCI Room -17' Elevation 2PFP-RB2-2; and
- Unit 1 Battery Room 1B 23' Elevation 1PFP-CB-8.
The inspectors reviewed areas to assess if the licensee had implemented a fire
protection program that adequately controlled combustibles and ignition sources within
the plant, effectively maintained fire detection and suppression capability, maintained
passive fire protection features in good material condition, and had implemented
adequate compensatory measures for out-of-service, degraded or inoperable fire
protection equipment, systems, or features in accordance with the licensees fire plan.
The inspectors selected fire areas based on their overall contribution to internal fire risk
as documented in the plants Individual Plant Examination of External Events with later
additional insights, their potential to impact equipment which could initiate or mitigate a
plant transient, or their impact on the plants ability to respond to a security event. Using
the documents listed in the attachment, the inspectors verified that fire hoses and
extinguishers were in their designated locations and available for immediate use; that
fire detectors and sprinklers were unobstructed, that transient material loading was
within the analyzed limits; and fire doors, dampers, and penetration seals appeared to
be in satisfactory condition. The inspectors also verified that minor issues identified
during the inspection were entered into the licensees corrective action program.
Enclosure
5
b. Findings
No findings were identified.
1R11 Licensed Operator Requalification Program
.1 Quarterly Licensed Operator Continuing Training
a. Inspection Scope
On October 25, 2011, the inspectors observed a crew of licensed operators in the plants
simulator during licensed operator requalification examinations to verify that operator
performance was adequate, evaluators were identifying and documenting crew
performance problems, and to ensure that training was being conducted in accordance
with licensee procedures. The inspectors evaluated the following areas:
- licensed operator performance;
- crews clarity and formality of communications;
- ability to take timely actions in the conservative direction;
- prioritization, interpretation, and verification of annunciator alarms;
- correct use and implementation of abnormal and emergency procedures;
- control board manipulations;
- oversight and direction from supervisors; and
- the ability to identify and implement appropriate TS actions and Emergency Plan
actions and notifications.
The crews performance in these areas was compared to pre-established operator action
expectations and successful critical task completion requirements.
b. Findings
No findings were identified.
.2 Licensed Operator Requalification
a. Inspection Scope
Annual Review of Licensee Requalification Examination Results. The licensee
completed the comprehensive biennial requalification written examinations and annual
requalification operating tests required to be administered to all licensed operators in
accordance with 10 CFR 55.59(a)(2). The inspectors performed an in-office review of
the overall pass/fail results of the written examinations, individual operating tests and the
crew simulator operating tests. These results were compared to the thresholds
established in Manual Chapter 609 Appendix I, Operator Requalification Human
Performance Significance Determination Process.
Enclosure
6
b. Findings
No findings were identified.
1R12 Maintenance Effectiveness
a. Inspection Scope
The inspectors evaluated one (1) degraded performance issue involving the following
risk-significant system:
- Unit 2 2B residual heat removal service water (RHRSW) booster pump bearing
failure on September 21, 2011.
The inspectors reviewed events where ineffective equipment maintenance may have
resulted in equipment failure or invalid automatic actuations of Engineered Safeguards
Systems and independently verified the licensee's actions to address system
performance or condition problems in terms of the following:
- implementing appropriate work practices;
- identifying and addressing common cause failures;
- scoping of systems in accordance with 10 CFR 50.65(b) of the maintenance rule;
- characterizing system reliability issues for performance;
- charging unavailability for performance;
- trending key parameters for condition monitoring; and
- ensuring 10 CFR 50.65(a)(1) or (a)(2) classification or re-classification; and verifying
appropriate performance criteria for structures, systems and components
(SSCs)/functions classified as (a)(2) or appropriate and adequate goals and
corrective actions for systems classified as (a)(1).
The inspectors assessed performance issues with respect to the reliability, availability,
and condition monitoring of the system. In addition, the inspectors verified maintenance
effectiveness issues were entered into the corrective action program with the appropriate
significance characterization.
b. Findings
Introduction: A self-revealing Green non-cited violation of TS 5.4.1, Procedures, was
identified for failure to implement procedural requirements for verifying lubrication levels
on the 2B RHRSW booster pump. This finding resulted in a failure of the 2B RHRSW
booster pump.
Description: On September 21, 2011, the 2B RHRSW booster pump was started for
suppression pool cooling. After several hours of operation, a security officer performing
rounds in the unit 2 reactor building observed a smoky odor in the vicinity of 2B RHRSW
Enclosure
7
booster pump. The Reactor Building Auxiliary Operator investigated and observed
sparks coming from the pump thrust bearing. The pump was secured and it was
determined that the thrust bearing had overheated due to lack of lubrication. The
condition was entered into the licensees corrective action program as AR #489386 and
the licensee repaired the pump.
The insufficient lubrication of the 2B RHRSW booster pump thrust bearing was caused
by a low oil level in the thrust bearing casing. The oil level in the thrust bearing casing
was low due to a failure of the licensee to verify the oil level on two different occasions.
The first occurrence was on April 3, 2011, during reinstallation of the 2B RHRSW
booster pump following modification of the pumps bed plate. During the modification of
the bed plate, the pump was moved several times and the oiler level adjustment
mechanism was removed. Upon reinstallation of the pump, the oiler level adjustment
mechanism was not reinstalled. Without the leveling mechanism, the oil level could not
be aligned properly to the pump tab mark in accordance with procedure 0MMM-053,
Equipment Lubrication Application Guidance and Lubrication Listing. The work order for
the pump reinstallation (WO #1037629) had specific instructions to verify and adjust
lubricant levels in accordance with procedure 0MMM-053. This procedure provides
specific guidance for Trico oilers (step 5.1.4) that states level should be at or just below
pump tab (1/16). Failure to properly verify thrust bearing oil level following
reinstallation of the pump left the oil level in the bearing casing below the normal
operating level. Although this level was sufficient to lubricate the bearing at the time of
the pumps reinstallation, it was not sufficient to ensure an adequate amount of oil
existed in the bearing casing to make up for any additional losses of oil.
The second occurrence was on July 13, 2011, when a routine oil sample was taken from
the 2B RHRSW booster pump thrust bearing. A significant quantity of oil was removed
from the bearing, and oil was added back by refilling the oil bubbler. The work order
(WO #1820326) contained specific instructions to perform oil samples in accordance
with procedure 0MMM-053. This procedure provides specific guidance for taking
samples for Trico oilers (step 5.1.4) to measure exact amount removed to ensure exact
amount is replaced and level should be at or just below pump tab (1/16). The
licensee failed to measure the oil removed or check that level was at or just below tab
(1/16) prior to returning the pump to service. It is probable after July 13, 2011, that oil
level in the thrust bearing casing was insufficient for the 2B RHRSW booster pump to
satisfy its safety function. This condition resulted in the pump bearing failure on
September 21, 2011.
Analysis: The failure to follow procedural requirements for verifying lubrication levels
was a performance deficiency. The performance deficiency was more than minor
because it was associated with the Mitigating Systems cornerstone attribute of
Equipment Performance - Availability, and adversely affected the cornerstone objective
to ensure the availability, reliability, and capability of systems that respond to initiating
events to prevent undesirable consequences. Specifically, the performance deficiency
resulted in the failure of the 2B RHRSW booster pump which is credited for decay heat
Enclosure
8
removal and emergency service water injection. Using Inspection Manual Chapter 0609,
Significance Determination Process, Attachment 0609.04, Phase 1 Screening
Worksheet, the finding screened as potentially greater than green because it
represented an actual loss of a single train of equipment for more than its TS allowed
outage time. Therefore, a Phase 2 significance determination evaluation was required.
Inspectors with assistance from a regional Senior Reactor Analyst (SRA) determined the
significance of this finding to be very low safety significance (Green) using Phase 2 pre-
solved tables. The cause of the finding was directly related to the training cross-cutting
aspect in the Resources component of the Human Performance area because the
licensee failed to ensure that workers had adequate knowledge of the RHRSW pump
oilers to execute procedures for verifying lubrication levels which caused a failure of a
safety-related pump. H.2(b).
Enforcement: TS 5.4.1, Procedures, requires, in part, that written procedures shall be
implemented covering applicable procedures recommended in Regulatory Guide 1.33,
Appendix A, November 1972 (Safety Guide 33, November 1972). Regulatory Guide
1.33, Appendix A, November 1972 (Safety Guide 33, November 1972),Section I,
requires written procedures for maintenance which can affect performance of safety
related equipment. Plant procedure 0MMM-053, Equipment Lubrication Application
Guidance and Lubrication Listing, is the licensees procedure for lubrication maintenance
on safety-related pumps and describes requirements for verifying the proper oil level for
Trico oilers. Contrary to the above, on April 13, 2011, and July 13, 2011, the licensee
failed to properly implement procedure 0MMM-053. Specifically, oil levels were not
properly verified on the 2B RHRSW booster pump. This resulted in a failure of the pump
thrust bearing. Upon discovery of this condition, the licensee reinstalled oil level control
mechanism, held special training sessions with maintenance personnel, and repaired the
pump. Because this finding is of very low safety significance and has been entered into
the licensees corrective action program as AR #489386, it is being treated as a non-
cited violation, consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000324/2011005-01, Failure to Verify Bearing Oil Level Resulted in Residual Heat
Removal Service Water Pump Failure.
1R13 Maintenance Risk Assessments and Emergent Work Control
a. Inspection Scope
The inspectors reviewed the licensee's evaluation and management of plant risk for the
four (4) maintenance and emergent work activities affecting risk-significant equipment
listed below to verify that the appropriate risk assessments were performed prior to
removing equipment for work:
- Emergent work on the EDG #2 Voltage Regulator on November 8, 2011;
- Increased shutdown risk for the decay heat removal key safety function during work
on the A loop of the unit 2 residual heat removal (RHR) system on November 18,
2011;
Enclosure
9
- Planned work on the unit 2, A loop of the RHR system with the 1B reactor building
closed cooling water system heat exchanger out of service (increased risk for unit 2)
on December 15, 2011; and
- Planned work on the unit 1 high pressure coolant injection (HPCI) pump with the 2C
conventional service water pump out of service (increased risk for unit 1) on
December 20, 2011.
These activities were selected based on their potential risk-significance relative to the
reactor safety cornerstones. As applicable for each activity, the inspectors verified that
risk assessments were performed as required by 10 CFR 50.65(a)(4) and were accurate
and complete. When emergent work was performed, the inspectors verified that the
plant risk was promptly reassessed and managed. The inspectors reviewed the scope
of maintenance work, discussed the results of the assessment with the licensee's
probabilistic risk analyst or shift technical advisor, and verified that plant conditions were
consistent with the risk assessment. The inspectors also reviewed TS requirements and
walked down portions of redundant safety systems, when applicable, to verify that risk
analysis assumptions were valid and applicable requirements were met.
b. Findings
No findings were identified.
1R15 Operability Evaluations
a. Inspection Scope
The inspectors reviewed the following four (4) issues:
- EDG #2 voltage regulator preset potentiometer limit switch failure (AR #498277);
- Relay 2-E4-AK0-27E1, E4 Undervoltage Relay, out of calibration (AR #497761);
The inspectors selected these potential operability issues based on the risk-significance
of the associated components and systems. The inspectors evaluated the technical
adequacy of the evaluations to ensure that TS operability was properly justified and the
subject component or system remained available such that no unrecognized increase in
risk occurred. The inspectors compared the operability and design criteria in the
appropriate sections of the TS and UFSAR to the licensees evaluations, to determine
whether the components or systems were operable. Where compensatory measures
were required to maintain operability, the inspectors determined whether the measures
in place would function as intended and were properly controlled. The inspectors
determined, where appropriate, compliance with bounding limitations associated with the
evaluations. Additionally, the inspectors also reviewed a sampling of corrective action
Enclosure
10
documents to verify that the licensee was identifying and correcting any deficiencies
associated with operability evaluations.
b. Findings
No findings were identified.
1R19 Post-Maintenance Testing
a. Inspection Scope
The inspectors reviewed the following six (6) post-maintenance activities to verify that
procedures and test activities were adequate to ensure system operability and functional
capability:
- 2OP-43, Service Water Operation on October 4, 2011 after 2B CSW pump planned
maintenance outage;
- 0PT-12.2C, No. 3 Diesel Generator Monthly Load Test on October 20, 2011 after
corrective maintenance on the collector rings and other planned maintenance;
- 0PT-12.2A, No. 1 Diesel Generator Monthly Load Test on November 2, 2011 after
corrective maintenance on the collector rings and other planned maintenance;
- 0PT-12.2B No. 2 Diesel Generator Monthly Load Test on November 19, 2011 after
corrective maintenance on the automatic voltage regulator;
- 0PT-80.1, Reactor Pressure Vessel Test on November 29, 2011 after the unit 2
reactor head reassembly; and
- 0PT-12.2D, No. 4 Diesel Generator Monthly Load Test on December 28, 2011 after
a planned diesel maintenance outage.
These activities were selected based upon the structure, system, or component's ability
to impact risk. The inspectors evaluated these activities for the following (as applicable):
the effect of testing on the plant had been adequately addressed; testing was adequate
for the maintenance performed; acceptance criteria were clear and demonstrated
operational readiness; test instrumentation was appropriate; tests were performed as
written in accordance with properly reviewed and approved procedures; equipment was
returned to its operational status following testing, and test documentation was properly
evaluated. The inspectors evaluated the activities against TS and UFSAR to ensure that
the test results adequately ensured that the equipment met the licensing basis and
design requirements. In addition, the inspectors reviewed corrective action documents
associated with post-maintenance tests to determine whether the licensee was
identifying problems and entering them in the corrective action program and that the
problems were being corrected commensurate with their importance to safety.
b. Findings
No findings were identified.
Enclosure
11
1R20 Outage Activities
a. Inspection Scope
The inspectors evaluated outage activities for a scheduled unit 2 maintenance outage,
conducted from November 5, 2011, to December 2, 2011. The inspectors reviewed
activities to ensure that the licensee considered risk in developing, planning, and
implementing the outage schedule.
During the outage, the inspectors observed portions of the shutdown and cooldown
processes and monitored licensee controls over the outage activities listed below:
- Licensee configuration management, including maintenance of defense-in-depth for
key safety functions and compliance with the applicable TS when taking equipment
out of service;
- Implementation of clearance activities and confirmation that tags were properly hung
and equipment appropriately configured to safely support the work or testing;
- Installation and configuration of reactor coolant pressure, level, and temperature
instruments to provide accurate indication, accounting for instrument error;
- Controls over the status and configuration of electrical systems;
- Monitoring of decay heat removal processes, systems, and components;
- Controls to ensure that outage work was not impacting the ability of the operators to
operate the spent fuel pool cooling system;
- Reactor water inventory controls including flow paths, configurations, and alternative
means for inventory addition, and controls to prevent inventory loss;
- Controls over activities that could affect reactivity;
- Maintenance of secondary containment as required by TS;
- Refueling activities, including fuel handling and sipping to detect fuel assembly
leakage;
- Startup and ascension to full power operation; and
- Licensee identification and resolution of problems related to outage activities.
b. Findings
No findings were identified.
1R22 Surveillance Testing
.1 Routine Surveillance Testing
a. Inspection Scope
The inspectors either observed three (3) surveillance tests or reviewed the test results
for the following activities to verify the tests met TS surveillance requirements, UFSAR
commitments, in-service testing requirements, and licensee procedural requirements.
Enclosure
12
The inspectors assessed the effectiveness of the tests in demonstrating that the SSCs
were operationally capable of performing their intended safety functions.
- 0MST-RGE15Q RGE, Unit 1 Reactor Building Ventilation Monitoring Channel
Functional Test on October 5, 2011;
- 1MST-HPC127Q, Unit 1 HPCI and reactor core isolation cooling (RCIC) Low Water
Level Instrument Channel Calibration on October 13, 2011; and
November 17, 2011;
b. Findings
No findings were identified.
.2 In-Service Testing (IST) Surveillance
a. Inspection Scope
The inspectors reviewed the performance of 0PT-10.1.1, RCIC System Operability Test
on December 13, 2011, to evaluate the effectiveness of the licensees American Society
of Mechanical Engineers (ASME)Section XI testing program for determining equipment
availability and reliability. The inspectors evaluated selected portions of the following
areas: 1) testing procedures; 2) acceptance criteria; 3) testing methods; 4) compliance
with the licensees IST program, TS, selected licensee commitments, and code
requirements; 5) range and accuracy of test instruments; and 6) required corrective
actions.
b. Findings
No findings were identified.
1EP6 Emergency Planning Drill Evaluation
a. Inspection Scope
The inspectors observed a site emergency preparedness training drill conducted on
October 18, 2011. The inspectors reviewed the drill scenario narrative to identify the
timing and location of classifications, notifications, and protective action
recommendations development activities. During the drill, the inspectors assessed the
adequacy of event classification and notification activities. The inspectors observed
portions of the licensees post-drill. The inspectors verified that the licensee properly
evaluated the drills performance with respect to performance indicators and assessed
drill performance with respect to drill objectives.
Enclosure
13
b. Findings
No findings were identified.
4. OTHER ACTIVITIES
4OA1 Performance Indicator (PI) Verification
.1 Mitigating Systems Cornerstone
a. Inspection Scope
The inspectors sampled licensee submittals for the Mitigating Systems Performance
Index performance indicators listed below for the period from the 3rd quarter 2010
through the 3rd quarter 2011. The inspectors reviewed the licensees operator narrative
logs, issue reports, Mitigating System Performance Index (MSPI) derivation reports,
event reports and NRC Integrated Inspection reports for the period to validate the
accuracy of the submittals. The inspectors also reviewed the licensees issue report
database to determine if any problems had been identified with the PI data collected or
transmitted for this indicator and none were identified.
- Mitigating Systems Performance Index, High Pressure Coolant Injection System
- Mitigating Systems Performance Index, Heat Removal System (Reactor Core
Isolation Cooling System)
b. Findings
No findings were identified.
4OA2 Identification and Resolution of Problems
.1 Routine Review of Items Entered Into the Corrective Action Program
a. Inspection Scope
To aid in the identification of repetitive equipment failures or specific human performance
issues for follow-up, the inspectors performed frequent screenings of items entered into
the licensees corrective action program. The review was accomplished by reviewing
daily action request reports.
b. Findings
No findings were identified.
Enclosure
14
.2 Semi-Annual Trend Review
a. Inspection Scope
The inspectors performed a review of the licensees CAP and associated documents to
identify trends that could indicate the existence of a more significant safety issue. The
inspectors review was focused on repetitive equipment issues, but also considered the
results of daily inspector CAP item screening discussed in Section 4OA2.1 above,
licensee trending efforts, and licensee human performance results. The inspectors
review nominally considered the six-month period of July 1, 2011, through December 31,
2011, although some examples expanded beyond those dates where the scope of the
trend warranted.
Inspectors also reviewed major equipment problem lists, repetitive and rework
maintenance lists, departmental problem/challenges lists, system health reports, quality
assurance audit/surveillance reports, self-assessment reports, and Maintenance Rule
assessments. The inspectors compared and contrasted their results with the results
contained in the licensees CAP trending reports. Corrective actions associated with a
sample of the issues identified in the licensees trending reports were reviewed for
adequacy.
b. Findings and Observations
Inspectors, concurrent with the licensee, noted an ongoing adverse trend in human
performance, as exemplified by the following events: 1) AOP-20, Pneumatic System
Failures on November, 24, 2011, due to operator error, 2) failure of the 2B RHRSW
booster pump on September 21, 2011, (see section 1R12 or this report), and 3) multiple
human errors associated with the inadequate tensioning of the unit 2 reactor vessel
head studs and declaration of an Unusual Event on November 16, 2011. Details of the
inadequate tensioning of the unit 2 reactor vessel head studs are contained in NRC
inspection report 05000324/2011013. The licensee has entered the issues into their
corrective action program.
.3 Assessments and Observations
Annual Sample: Review of Operator Workarounds (OWAs)
a. Inspection Scope
The inspectors evaluated the licensees implementation of their process used to identify,
document, track, and resolve operational challenges. Inspection activities included, but
were not limited to, a review of the cumulative effects of the OWAs on system availability
and the potential for improper operation of the system, for potential impacts on multiple
systems, and on the ability of operators to respond to plant transients or accidents. The
inspectors performed a review of the cumulative effects of OWAs. The inspectors
Enclosure
15
reviewed both current and historical operational challenge records to determine whether
the licensee was identifying operator challenges at an appropriate threshold, had
entered them into their corrective action program and proposed or implemented
appropriate and timely corrective actions which addressed each issue. Reviews were
conducted to determine if any operator challenge could increase the possibility of an
Initiating Event, if the challenge was contrary to training, required a change from long-
standing operational practices, or created the potential for inappropriate compensatory
actions. Daily plant and equipment status logs, degraded instrument logs, and operator
aids or tools being used to compensate for material deficiencies were also assessed to
identify any potential sources of unidentified operator workaround.
b. Findings
No findings were identified.
4OA3 Follow-up of Events
Unusual Event Declaration for Excessive Unit 2 Unidentified Leakage
a. Inspection Scope
The inspectors reviewed the plants response to an Unusual Event declared for unit 2
unidentified leakage inside of primary containment exceeding 10 gallons per minute on
November 16, 2011. The leakage developed shortly after reactor startup and
pressurization and was due to an improperly installed reactor vessel head. Details of the
event are included in NRC Special Inspection Report 05000324/2011013.
b. Findings
Results associated with this event are in NRC Special Inspection Report 05000324/2011013.
4OA5 Other Activities
.1 Quarterly Resident Inspector Observations of Security Personnel and Activities
a. Inspection Scope
During the inspection period the inspectors conducted observations of security force
personnel and activities to ensure that the activities were consistent with licensee
security procedures and regulatory requirements relating to nuclear plant security.
These observations took place during both normal and off-normal plant working hours.
These quarterly resident inspector observations of security force personnel and activities
did not constitute any additional inspection samples. Rather, they were considered an
integral part of the inspectors' normal plant status reviews and inspection activities.
Enclosure
16
b. Findings
No findings were identified.
.2 Operation of an Independent Spent Fuel Storage Installation (ISFSI)
a. Inspection Scope
During the inspection period the inspectors conducted observations of selected activities
and independent evaluation, that the licensee has maintained fuel stored in the ISFSI in
a safe manner and in compliance with approved procedures. Inspectors also reviewed
selected records that the licensee has identified each fuel assembly placed in the ISFSI,
has recorded the parameters and characteristics of each fuel assembly, and has
maintained a record of each fuel assembly as a controlled document.
b. Findings
No findings were identified.
4OA6 Management Meetings
Exit Meeting Summary
On January 18, 2011, the inspectors presented the inspection results to Mr. Edward
Wills, and other members of the licensee staff. The inspectors confirmed that
proprietary information was not provided or examined during the inspection period.
ATTACHMENT: SUPPLEMENTAL INFORMATION
Enclosure
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
M. Annacone, Site Vice President
S. Bostic, Supervisor - Major Projects
A. Brittain, Manager - Security
J. Burke, Director - Engineering
C. Dunsmore, Manager - Shift Operations
P. Dubrouillet, Manager - Training
J. Frisco, Plant General Manager
C. George, Manager - Technical Support Engineering
K. Gerald, Acting Manager - Maintenance
S. Gordy, Manager - Operations
L. Grzeck, Lead Engineer - Technical Support
R. Ivey, Manager - Nuclear Oversight Services
F. Jefferson, Manager - Systems Engineering
J. Johnson, Manager - Environmental and Radiological Controls
P. Mentel, Manager - Support Services
W. Murray, Licensing Specialist
D. Petrusic, Superintendent - Environmental and Chemistry
A. Pope, Supervisor - Licensing and Regulatory Affairs
T. Sherrill, Engineer - Technical Support
P. Smith, Superintendent - Electrical, Instrumentation, and Controls Maintenance
M. Turkal, Lead Engineer - Technical Support
J. Vincelli, Superintendent - Radiation Protection
H. Willets, Manager- Design Engineering
E. Wills, Director - Site Operations
NRC Personnel
Randall A. Musser, Chief, Reactor Projects Branch 4, Division of Reactor Projects Region II
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened and Closed
05000324/2011005-01 NCV Failure to Verify Bearing Oil Level Resulted in
Residual Heat Removal Service Water Pump Failure
(Section 1R12)
Attachment
LIST OF DOCUMENTS REVIEWED
Section 1R04: Equipment Alignment
0OP-50.1, Diesel Generator Emergency Power System Operating Procedure
Drawing D-02265, sheets 1A and 1B, drawing D-02266, sheets 2A and 2B, Piping Diagram for
Diesel Generators Starting Air System Units 1 and 2
Drawing D-02268, sheets 1A and 1B, drawing D-02269, sheets 2A and 2B, Piping Diagram for
Diesel Generators Fuel Oil System Units 1 and 2
Drawing D-02270, sheets 1A and 1B, drawing D-02271, sheets 2A and 2B, Piping Diagram for
Diesel Generators Lube Oil to Lube Oil System Units 1 and 2
Drawing D-02272, sheets 1A and 1B, drawing D-02273, sheets 2A and 2B, Piping Diagram for
Diesel Generators Jacket Water System Units 1 and 2
Drawing D-02272, sheets 1A and 1B, drawing D-02273, sheets 2A and 2B, Piping Diagram for
Diesel Generators Jacket Water System Units 1 and 2
Drawing D-02274, sheets 1 and 2, Piping Diagram for Diesel Generators Service and
Demineralized Water System Units 1 and 2
OPT-12.2B, No. 2 Diesel Generator Monthly Load Test
OPT-12.2D, No. 4 Diesel Generator Monthly Load Test
0OP-39, Diesel Generator Operating Procedure
SD-39, Emergency Diesel Generators
0OP-19, High Pressure Coolant Injection System Operating Procedure
SD-19, High Pressure Coolant Injection System Description
Section 1R05: Fire Protection
0PFP-CB, Control Building Prefire Plans
0PFP-DG, Diesel Generator Building Prefire Plans
0PFP-013, General Fire Plan
2PFP-RB, Reactor Building Prefire Plans Unit 2
0PFP-MBPA, Miscellaneous Buildings Pre-Fire Plans - Protected Area
Section 1R11: Licensed Operator Requalification
0TPP, Licensed Operator Continuing Training Program
TRN-NGGC-0014, NRC Initial Licensed Operator Exam Development and Administration
1EOP-01-LPC, Level/Power Control
0PEP-2.1.1, Emergency Control - Notification of Unusual Event, Alert, Site Area Emergency, or
General Emergency
0PEP-02.1, Initial Emergency Actions
Section 1R12: Maintenance Effectiveness
ADM-NGGC-0101, Maintenance Rule Program
NUMARC 93-01, Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear
Power Plants
Attachment
3
ADM-NGGC-0203, Preventive Maintenance and Surveillance Testing
Administration
EGR-NGGC-0351, Condition Monitoring of Structures
ADM-NGGC-0203, Preventive Maintenance and Surveillance test Administration
0AP-022, BNP Outage Risk Management
Section 1R13: Maintenance Risk Assessment and Emergent Work Control
0AP-022, BNP Outage Risk Management
ADM-NGCC-0104, Work Management Process
0AI-144, Risk Management
ADM-NGGC-0006, Online EOOS Model
Section 1R15: Operability Evaluations
OPS-NGGC-1305, Operability Determinations
OPS-NGGC-1307, Operational Decision making
Section 1R19: Post Maintenance Testing
0PLP-20, Post Maintenance Testing Program
2OP-43 Service Water Operation
0PT-12.2A No. 1 Diesel Generator Monthly Load Test
0PT-12.2B No. 2 Diesel Generator Monthly Load Test
0PT-12.2C No. 3 Diesel Generator Monthly Load Test
0PT-12.2D No. 4 Diesel Generator Monthly Load Test
SD-39, Emergency Diesel Generators
SD-43, Service Water System
0PT-80.1, Reactor Pressure Vessel ASME Section XI Pressure Test
Section 1R20: Outage Activities
2OP17, Residual Heat Removal System Operating Procedure
0GP-01, Prestartup Checklist
0GP-02, Approach to Criticality and Pressurization of the Reactor
0GP-03, Unit Startup and Synchronization
0GP-05, Unit Shutdown
0SMP-RPV502, Reactor Vessel Reassembly
0MMM-015, Operation and Inspection of Cranes and Material Handling Equipment
Section 1R22: Surveillance Testing
0MST-RGE15Q RGE Reactor Bldg Vent Monitoring Channel Functional
1MST-HPC127Q HPCI and RCIC Low Water Level Instrument Channel Cal
1OP-03.2 RODSR Attachment 1 Drywell Leakage Rate Calculation
0PT-10.1.1, RCIC System Operability Test
SD-16, Reactor Core Isolation Cooling (RCIC) System
Attachment
4
Section 4OA1: Performance Indicator Verification
Procedures
REG-NGGC-0009, NRC Performance Indicators and Monthly Operating Report Data
Records and Data
Monthly PI Reports, October 2010 - September 2011
Section 4OA3: Event Followup
1OP17, Residual Heat Removal System Operating Procedure
2OP17, Residual Heat Removal System Operating Procedure
0GP-01, Prestartup Checklist
0GP-02, Approach to Criticality and Pressurization of the Reactor
0GP-03, Unit Startup and Synchronization
0GP-05, Unit Shutdown
Attachment