ML092110250
| ML092110250 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 07/30/2009 |
| From: | Randy Musser NRC/RGN-II/DRP/RPB4 |
| To: | Waldrep B Carolina Power & Light Co |
| References | |
| IR-09-003 | |
| Download: ML092110250 (32) | |
See also: IR 05000324/2009003
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
SAM NUNN ATLANTA FEDERAL CENTER
61 FORSYTH STREET, SW, SUITE 23T85
ATLANTA, GEORGIA 30303-8931
July 30, 2009
Mr. Benjamin C. Waldrep
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.: 05000325/2009003 AND
Dear Mr. Waldrep:
On June 30, 2009, the US 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 July 16, 2009, with Mr. Ben Waldrep 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.
This report documents one self-revealing finding of very low safety significance (Green). This
finding was determined to involve violations of NRC requirements. However, because of the
very low safety significance and because it is entered into your corrective action program, the
NRC is treating this finding as a non-cited violation (NCV) consistent with Section VI.A.1 of the
NRCs Enforcement Policy. If you contest any NCV, you should provide a response within 30
days of the date of this inspection report, with the basis for your denial, to the Nuclear
Regulatory Commission, ATTN.: Document Control Desk, Washington DC 20555-0001, with
copies to the Regional Administrator, 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. In addition, if you disagree with the
characterization of any finding 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. The information you provide will be considered in accordance with the Inspection Manual
Chapter 0305.
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, 324/2009003
w/Attachment: Supplemental Information
cc w/encl: (See page 3)
_________________________ XG SUNSI REVIEW COMPLETE
OFFICE RII:DRP RII:DRP RII:DRP RII:DRP RII:DRS RII:DRS RII:DRP
SIGNATURE JGW1 PBO GJK2 PBL1 RCC2 RPC1 RAM
NAME JWorosilo POBryan GKolcum PLessard RChou RCarrion RMusser
DATE 0729/2009 07/29/2009 07/29/2009 07/30/2009 0729/2009 07/29/2009 07/30/2009
E-MAIL COPY? YES NO YES NO YES NO YES NO YES NO YES NO YES NO
CP&L 3
cc w/encl:
R. J. Duncan, II, Vice President Garry D. Miller, Manager
Nuclear Operations License Renewal
Carolina Power & Light Company Progress Energy
Electronic Mail Distribution Electronic Mail Distribution
Michael J. Annacone Gene Atkinson
Director Site Operations Supervisor, Licensing/Regulatory Programs
Brunswick Steam Electric Plant Brunswick Steam Electric Plant
Progress Energy Carolinas, Inc. Progress Energy Carolinas, Inc.
Electronic Mail Distribution Electronic Mail Distribution
Edward L. Wills, Jr. Senior Resident Inspector
Plant General Manager Carolina Power and Light Company
Brunswick Steam Electric Plant Brunswick Steam Electric Plant
Progress Energy Carolinas, Inc. U.S. NRC
Electronic Mail Distribution 8470 River Road, SE
Southport, NC 28461
Benjamin C. Waldrep, Vice President
Brunswick Steam Electric Plant John H. O'Neill, Jr.
Progress Energy Carolinas, Inc. Shaw, Pittman, Potts & Trowbridge
Electronic Mail Distribution 2300 N. Street, NW
Washington, DC 20037-1128
Christos Kamilaris, Director
Fleet Support Services Peggy Force, Assistant Attorney General
Carolina Power & Light Company State of North Carolina
Electronic Mail Distribution P.O. Box 629
Raleigh, NC 27602
Thomas D. Walt, Vice President
Nuclear Oversight Chairman, North Carolina Utilities
Carolina Power and Light Company Commission
Electronic Mail Distribution Electronic Mail Distribution
Brian C. McCabe Robert P. Gruber, Executive Director
Manager, Nuclear Regulatory Affairs Public Staff - NCUC
Progress Energy Carolinas, Inc. 4326 Mail Service Center
Electronic Mail Distribution Raleigh, NC 27699-4326
Phyllis N. Mentel David R. Sandifer
Manager, Support Services Brunswick County Board of Commissioners
Brunswick Steam Electric Plant P.O. Box 249
Progress Energy Carolinas, Inc. Bolivia, NC 28422
Electronic Mail Distribution
James Ross
Donald L. Griffith Nuclear Energy Institute
Manager Electronic Mail Distribution
Brunswick Steam Electric Plant
Progress Energy Carolinas, Inc. cc w/encl. (Continued next page)
Electronic Mail Distribution
CP&L 4
cc w/encl. (Continued)
Public Service Commission
State of South Carolina
P.O. Box 11649
Columbia, SC 29211
Beverly O. Hall
Chief, Radiation Protection Section
Department of Environmental Health
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
CP&L 5
Letter to Benjamin C. Waldrep from Randall A. Musser dated July 30, 2009
SUBJECT: BRUNSWICK STEAM ELECTRIC PLANT - NRC INTEGRATED
INSPECTION REPORT NOS.: 05000325/2009003 AND
Distribution w/encl:
C. Evans, RII EICS
L. Slack, RII EICS
OE Mail
RIDSNRRDIRS
PUBLIC
RidsNrrPMBrunswick Resource
U. S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos.: 50-325, 50-324
Report Nos.: 05000325/2009003, 05000324/2009003
Licensee: Carolina Power and Light (CP&L)
Facility: Brunswick Steam Electric Plant, Units 1 & 2
Location: 8470 River Road, SE
Southport, NC 28461
Dates: April 1, 2009 through June 30, 2009
Inspectors: P. OBryan, Senior Resident Inspector
G. Kolcum, Resident Inspector
P. Lessard, Resident Inspector, Harris
R. Chou, Reactor Inspector (1R07)
R. Carrion, Senior Reactor Inspector (1R07)
Approved by: Randall A. Musser, Chief
Reactor Projects Branch 4
Division of Reactor Projects
Enclosure
SUMMARY OF FINDINGS
IR 05000325/2009003, 05000324/2009003; 4/01/2009 - 6/30/2009; Brunswick Steam Electric
Plant, Units 1 & 2; Refueling and Other Outage Activities.
This report covers a three-month period of inspection by resident inspectors and announced
baseline inspections by regional inspectors. One Green non-cited violation (NCV) 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 aspect was determined using IMC 0305, Operating Reactor
Assessment Program. 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: Initiating Events
- Green. A self-revealing Green NCV of Technical Specification (TS) 5.4.1.a,
Administrative Control (Procedures), was identified when the licensee failed to
follow plant procedure OPT-80.1, Reactor Pressure Vessel (RPV) ASME Section
XI Pressure Test during Unit 2 RPV hydrostatic testing on April 7, 2009. The
licensee installed hoses rated for 250 psig although the procedure required
hoses rated at 1150 psig. Specifically, when RPV pressure was raised to
approximately 1000 psig, the improper hose installed at core spray check valve
2-E21-F006B disconnected from its coupling, causing the RPV to rapidly
depressurize to approximately 875 psig and allowing water from the RPV to leak
out of the connection into the drywell. The licensee discovered the leak and
broken hose connection, isolated the leak, and initiated AR329675329675to address
this issue.
The finding was determined to be more than minor because the finding was
associated with the Initiating Events cornerstone attribute of human performance
and affected the cornerstone objective of limiting the likelihood of those events
that upset plant stability and challenge critical safety functions during shutdown
as well as power operations. The inspectors determined that the finding should
be evaluated in accordance with Attachment 1 of IMC 0609, Appendix G,
Shutdown Operations SDP. The inspectors used Checklist 8 contained in
Attachment 1 and determined that the finding did require a phase 2 or phase 3
because the licensee did not meet the appropriate safety function guidelines for
inventory control. Specifically, the finding increases the likelihood of a loss of
RCS inventory. The regional Senior Reactor Analyst (SRA) determined, after a
teleconference with the headquarters SRA with responsibility for Shutdown
findings, that the event did not rise to a level that would require a detailed
analysis be performed. The event did not meet the threshold for a loss of control
as defined by Appendix G. Additional margin was provided by the high elevation
of the leak relative to the top of active fuel, and the suction head requirement of
the residual heat removal (RHR) system, the small size of the opening in the
primary, the low decay heat, and the defense in depth available at the time of the
Enclosure
3
event. Based on this, the finding was determined to be of very low safety
significance (Green). The finding has a cross-cutting aspect in the Work
Practices component of the Human Performance cross cutting area, because the
licensee failed to follow plant procedure 0PT-80.1, Reactor Pressure Vessel
(RPV) ASME Section XI Pressure Test during Unit 2 RPV hydrostatic testing.
(H.4(b)). (Section 1R20)
B. Licensee-Identified Violations
None.
Enclosure
REPORT DETAILS
Summary of Plant Status
Unit 1 began the inspection period at rated thermal power. Power was reduced to 70 percent
for rod sequence exchange on May 29, 2009, and then returned to rated thermal power on May
31, 2009. Power was reduced to 90 percent for rod improvement on May 31, 2009, and then
returned to rated thermal power. Power was reduced to 94 percent for rod improvement on
June 1, 2009, and then returned to rated thermal power on June 2, 2009, for the remainder of
the inspection period.
Unit 2 began the inspection period shutdown for the planned refueling outage (B219R1). Unit 2
went critical on April 21, 2009. A manual reactor scram was inserted on April 22, 2009, due to
leak associated with the 2A recirculation pump seal. Unit 2 went critical on April 27, 2009 after
maintenance on the 2A recirculation pump seal. Unit 2 synchronized to the grid on
April 29, 2009 and reached rated thermal power on May 1, 2009. Power was reduced to 57
percent on May 23, 2009, for 2A reactor feed pump vibrations and returned to 67 percent power
on May 26, 2009. Power was reduced to 44 percent on May 26 for removal of 4A and 5A feed
water heaters for maintenance. Power was returned to 67 percent power and remained there
until repairs were completed on the 2A reactor feed pump on June 7, 2009. Unit 2 returned to
rated thermal power on June 7, 2009. Power was reduced to 92 percent for rod improvement
on June 8, 2009, and then returned to rated thermal power. Power was again reduced 91.5
percent for rod improvement on June 8, 2009, and then returned to rated thermal power. Power
was reduced to 80 percent due to loss of power to the circulating water ocean discharge pumps
on June 24, 2009, and then returned to rated thermal power for the remainder of the inspection
period.
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R01 Adverse Weather Protection
.1 Readiness of Offsite and Alternate AC Power Systems
a. Inspection Scope
The inspectors verified that plant features and procedures for operation and continued
availability of offsite and alternate alternating current (AC) power systems during
adverse weather were appropriate. The inspectors reviewed the licensees procedures
affecting these areas and the communications protocols between the transmission
system operator (TSO) and the plant to verify that the appropriate information was being
exchanged when issues arose that could impact the offsite power system. Examples of
aspects considered in the inspectors review included:
- The coordination between the TSO and the plant during off-normal or emergency
events;
Enclosure
5
- The explanations for the events;
- The estimates of when the offsite power system would be returned to a normal
state; and
- The notifications from the TSO to the plant when the offsite power system was
returned to normal.
The inspectors also verified that plant procedures addressed measures to monitor and
maintain availability and reliability of both the offsite AC power system and the onsite
alternate AC power system prior to or during adverse weather conditions. Specifically,
the inspectors verified that the procedures addressed the following:
- The actions to be taken when notified by the TSO that the post-trip voltage of the
offsite power system at the plant would not be acceptable to assure the
continued operation of the safety-related loads without transferring to the onsite
power supply;
- The compensatory actions identified to be performed if it would not be possible to
predict the post-trip voltage at the plant for the current grid conditions;
- A re-assessment of plant risk based on maintenance activities which could affect
grid reliability, or the ability of the transmission system to provide offsite power;
and
- The communications between the plant and the TSO when changes at the plant
could impact the transmission system, or when the capability of the transmission
system to provide adequate offsite power was challenged.
Documents reviewed are listed in the Attachment to this report. The inspectors also
reviewed corrective action program items to verify that the licensee was identifying
adverse weather issues at an appropriate threshold and entering them into their
corrective action program in accordance with station corrective action procedures.
b. Findings
No findings of significance were identified.
.2 Summer Seasonal Readiness Preparations
a. Inspection Scope
The inspectors reviewed the licensees preparations for selected systems for severe
weather conditions prior to hurricane season and hot weather.
During the inspection, the inspectors focused on plant specific design features and the
licensees procedures used to mitigate or respond to adverse weather conditions.
Additionally, the inspectors reviewed the Updated Final Safety Analysis Report (UFSAR)
and performance requirements for systems selected for inspection, and verified that
operator actions were appropriate as specified by plant specific procedures. Specific
documents reviewed during this inspection are listed in the Attachment. The inspectors
also reviewed corrective action program items to verify that the licensee was identifying
Enclosure
6
adverse weather issues at an appropriate threshold and entering them into their
corrective action program in accordance with station corrective action procedures. The
inspectors reviews focused specifically on the following plant systems:
b. Findings
No findings of significance were identified.
.3 Readiness For Impending Adverse Weather Condition
a. Inspection Scope
On April 6, 2009, a tornado warning was issued for the plant area, and inspectors
reviewed the licensees overall preparations/protection for impending adverse weather
conditions. The inspectors walked down areas of the plant susceptible to high winds,
including the licensees emergency alternating current (AC) power systems. The
inspectors evaluated the licensee staffs preparations against the sites procedures and
determined that the staffs actions were adequate. During the inspection, the inspectors
focused on plant-specific design features and the licensees procedures used to respond
to specified adverse weather conditions. The inspectors also toured the plant grounds to
look for any loose debris that could become missiles during a tornado. The inspectors
evaluated operator staffing and accessibility of controls and indications for those
systems required to control the plant. Additionally, the inspectors reviewed the Updated
Final Safety Analysis Report (UFSAR) and performance requirements for systems
selected for inspection, and verified that operator actions were appropriate as specified
by plant specific procedures. Specific documents reviewed during this inspection are
listed in the attachment.
b. Findings
No findings of significance were identified.
1R04 Equipment Alignment
.1 Quarterly Partial System Walkdowns
a. Inspection Scope
The inspectors performed partial system walkdowns of the following risk-significant
systems:
- EDGs #1, 2, 3, and 4 air start lineup on April 6, 2009
- 2A residual heat removal train while the 2B residual heat removal train was
inoperable for testing on April 19, 2009
Enclosure
7
- 2A1 battery charger with the 2A2 battery charger out of service for maintenance
on May 21, 2009.
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), Technical
Specification (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 the systems incapable of performing their intended
functions. The inspectors also walked down accessible portions of the systems to verify
system components and support equipment were aligned correctly and 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. Documents reviewed are listed in the
attachment.
b. Findings
No findings of significance were identified.
.2 Semi-Annual Complete System Walkdown
a. Inspection Scope
During the week of June 8, 2009, the inspectors performed a complete system alignment
inspection of Unit 1 and Unit 2 High Pressure Coolant Injection System to verify the
functional capability of the system. This system was selected because it was considered
both safety-significant and risk-significant in the licensees probabilistic risk assessment.
A Review of Operating Experience Smart Sample: OpESS FY2009-02, Negative Trend
and Recurring Events Involving Feedwater Systems was performed. The inspectors
walked down the system to review mechanical and electrical equipment line-ups,
electrical power availability, system pressure and temperature indications, as
appropriate, component labeling, component lubrication, component and equipment
cooling, hangers and supports, operability of support systems, and to ensure that
ancillary equipment or debris did not interfere with equipment operation. A review of a
sample of past and outstanding work orders (WOs) was performed to determine whether
any deficiencies significantly affected the system function. In addition, the inspectors
reviewed the corrective action program (CAP) database to ensure that system
equipment alignment problems were being identified and appropriately resolved. The
documents used for the walkdown and issue review are listed in the attachment.
Enclosure
8
b. Findings
No findings of significance were identified.
1R05 Fire Protection
.1 Quarterly Resident Inspector Tours
a. Inspection Scope
The inspectors conducted fire protection walkdowns which were focused on availability,
accessibility, and the condition of firefighting equipment in the following risk-significant
plant areas:
y Diesel Generator Cell 1 23' Elevation 1PFP-DG-5
y Diesel Generator Cell 2 23' Elevation 1PFP-DG-4
y Diesel Generator Cell 3 23' Elevation 2PFP-DG-3
y Diesel Generator Cell 4 23' Elevation 2PFP-DG-2
y Service Water Building 20' Elevation 0PFP-SW-1a
y Battery Room 2A 23' Elevation 2PFP-CB-9
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.
b. Findings
No findings of significance were identified.
1R06 Flood Protection Measures
a. Inspection Scope
The inspectors reviewed selected risk-important plant design features and licensee
procedures intended to protect the plant and its safety-related equipment from internal
Enclosure
9
flooding events. The inspectors reviewed flood analyses and design documents,
including the UFSAR, engineering calculations, and abnormal operating procedures
(AOPs), for licensee commitments. The specific documents reviewed are listed in the
attachment. In addition, the inspectors reviewed licensee drawings to identify areas and
equipment that may be affected by internal flooding caused by the failure or
misalignment of nearby sources of water, such as the fire suppression or the circulating
water systems. The inspectors walked down the Radwaste Building, 23 elevation, after
a leak was discovered in the 1B fuel pool cooling filter cubicle on April 8, 2009, to assess
the adequacy of watertight doors and verify drains and sumps were clear of debris and
were operable, and that the licensee complied with its commitments.
b. Findings
No findings of significance were identified.
1R07 Heat Sink Performance (Triennial Review)
a. Inspection Scope
The inspectors reviewed inspection records, test results, maintenance work orders, and
other documentation associated with risk-significant heat exchangers (HXs) and heat
sinks, including components such as outlet piping and the outlet canal, to ensure that
deficiencies that could mask or degrade performance were identified and corrected.
Risk-significant heat exchangers or coolers reviewed included the Residual Heat
Removal (RHR) 1A Heat Exchanger, the RHR 2B Pump Motor Cooler, and the
Emergency Diesel Generator (EDG) #1 Jacket Water Cooler.
The inspectors reviewed the licensees Generic Letter (GL) 89-13 Program procedure,
inspection and cleaning procedures, completed inspection and cleaning records and
results, and design specification sheets for the selected safety-related HXs and coolers,
the intake structure, and the outlet canal and the outlet pumping station. Currently, the
licensee uses an inspection and cleaning program instead of thermal testing for the heat
exchanger and heat sink performance check.
The inspectors also reviewed general health of the Service Water (SW) and Circulating
Water (CW) systems via review of design basis documents, system health reports, self-
assessments, sodium hypochlorite treatment and sampling documents, and discussions
with system engineers. These documents were reviewed to verify that the design bases
were being maintained and to verify adequate SW and CW system performance under
the current licensees regimen of preventive maintenance, which includes chemical
treatment, inspection, physical cleaning, and proceduralized frequencies (which vary due
to conditions).
In addition, the inspectors conducted a walkdown of HXs, coolers, CW and SW piping
systems and pumps, the chemical treatment station, the intake and diversion structures
(observing maintenance and repair activities for the diversion structure), intake and
outlet canals, the outlet pumping station, and other major components to assess general
Enclosure
10
material condition and to identify any degraded conditions of the components. The
inspectors also observed the flow, pressure, and temperature measurements for the
thermal efficiency calculation of EDG #1 Jacket Water Cooler.
Corrective action reports such as Nuclear Condition Reports (NCRs) and Action
Requests (ARs) were reviewed for potential common cause problems and problems
which could affect system performance, to confirm that the licensee was entering
problems into the corrective action program and initiating appropriate corrective actions.
b. Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification Program
a. Inspection Scope
On June 3, 2009, 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 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
- 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 of significance were identified.
1R12 Maintenance Effectiveness
a. Inspection Scope
The inspectors evaluated degraded performance issues involving the following risk
significant systems:
Enclosure
11
- Failure of the pressure reducing valve, 2-DSA-PRV-1689, on EDG #1 on April 8,
2009
- Failure of EDG #4 to start during testing on April 10, 2009
The inspectors reviewed events where ineffective equipment maintenance has resulted
in 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;
- 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. Documents reviewed are listed in the Attachment.
b. Findings
No findings of significance were identified.
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
five 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:
- EDG #4 testing with plant in Yellow risk on April 8, 2009.
- Comprehensive review of the maintenance planned and conducted during the
Unit 2 refueling outage during the week of April 26, 2009.
- Battery charger 2A2 and the 2A nuclear service water pump out of service on
May 21, 2009.
- EDG #1 and the 2A main feed pump out of service on June 2, 2009.
- Unit 1 condensate storage tank returned to service and realignment of HPCI and
RCIC suction during week of June 15, 2009.
Enclosure
12
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 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 risk
analysis assumptions were valid and applicable requirements were met.
b. Findings
No findings of significance were identified.
1R15 Operability Evaluations
a. Inspection Scope
The inspectors reviewed the following issues:
- EDG #3 with degraded four-day storage tank level indication on April 7, 2009
- Past operability of emergency diesel generator #4 with degraded control oil boost
discovered on April 10, 2009
- 2B RHRSW pump was found with low oil level on April 23, 2009
- Past operability of 1A standby liquid control train after discovery of a leaking
accumulator test connection on May 7, 2009
- Diesel Generator service water discharge line out of round on June 8, 2009
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 Technical Specifications (TS) and Updated Final Safety
Analysis Report (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 documents to
verify that the licensee was identifying and correcting any deficiencies associated with
operability evaluations. Documents reviewed are listed in the attachment.
Enclosure
13
b. Findings
No findings of significance were identified.
1R19 Post Maintenance Testing
a. Inspection Scope
The inspectors reviewed the following eight post-maintenance (PM) activities to verify
that procedures and test activities were adequate to ensure system operability and
functional capability:
- 0PT-24.4, Service Water System Valve Operability Test after Unit 2 CSW
(conventional service water) pump seal leakage maintenance on April 4, 2009
- 0SMP-LOG005, Diesel Generator Jet Assist Logic Test on EDG #3 after
maintenance on the auxiliary switch functions of the RHR pump and EDG output
breakers on April 4, 2009
- 0PT-15.4A, Secondary Containment Isolation Operability Test on April 4, 2009
after secondary containment maintenance
- 0PT-12.2C, No. 3 Diesel Generator Monthly Load Test on April 5, 2009 after
maintenance on the starting air distributor
- 0PT-07.2.4A, Unit 2 Core Spray System Operability Test - Loop A on April 5,
2009 after maintenance on room cooler only
- 0PT-12.2A, No. 1 Diesel Generator Monthly Load Test on April 9, 2009 after
maintenance on the diesel engine starting air tank pressure-reducing valve
- 0PT-80.1, Unit 2 Reactor Pressure Vessel ASME Section XI Pressure Test on
April 9, 2009
- 0PT-12.2D, No. 4 Diesel Generator Monthly Load Test on April 10, 2009 after
maintenance on the fuel rack limit cylinder and mechanical governor
These activities were selected based upon the structure, system, or component's ability
to impact risk. The inspectors evaluated these activities for the following: 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 the 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.
Documents reviewed are listed in the attachment.
Enclosure
14
b. Findings
No findings of significance were identified.
1R20 Outage Activities
.1 Refueling Outage Activities
a. Inspection Scope
Unit 2 continued in a refueling outage at the beginning of the inspection period. During
this inspection period, the inspectors monitored licensee controls over the outage
activities listed below. Documents reviewed during the inspection are listed in the
attachment.
- Licensee configuration management, including maintenance of defense-in-depth
commensurate with the OSP for key safety functions and compliance with the
applicable TS when taking equipment out of service
- Installation and configuration of reactor coolant pressure, level, and temperature
instruments to provide accurate indications, accounting for instrument error
- Controls over the status and configuration of electrical systems to ensure that TS
and outage safety plan requirements were met, and controls over switchyard
activities
- 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, tracking of startup prerequisites,
walkdown of the drywell (primary containment) to verify that debris had not been
left which could block emergency core cooling system suction strainers, and
reactor physics testing
- Licensee identification and resolution of problems related to refueling outage
activities
b. Findings
Failure to Follow Plant Procedures During Performance of a Reactor Pressure Vessel
Hydrostatic Test
Introduction. A self revealing Green NCV of TS 5.4.1.a, Administrative Control
(Procedures), was identified when the licensee failed to follow plant procedure 0PT-80.1,
Reactor Pressure Vessel (RPV) ASME Section XI Pressure Test during Unit 2 RPV
Enclosure
15
hydrostatic testing on April 7, 2009. The licensee installed hoses rated for 250 psig
although the procedure required hoses rated at 1150 psig. Specifically, when RPV
pressure was raised to approximately 1000 psig, the improper hose installed at core
spray check valve 2-E21-F006B disconnected from its coupling, causing the RPV to
rapidly depressurize to approximately 875 psig and allowing water from the RPV to leak
out of the connection into the drywell.
Description. On April 7, 2009, Unit 2 was in Mode 4 during refueling outage 2B19R1.
During preparations for performing procedure 0PT-80.1, Reactor Pressure Vessel (RPV)
ASME Section XI Pressure Test, hoses were installed around the core spray system
injection line check valves. These hoses are installed around the check valves in order
to pressurize portions of the core spray system upstream of the check valves during the
test. 0PT-80.1 specifies that RPV pressure be between 1050 psig and 1070 psig, and
that the hoses used to bypass the core spray system injection line check valves be rated
for at least 1150 psig. However, the hoses installed around the check valves were only
rated to 250 psig. These hoses were used because they were stored in a bag that was
labeled CS Jumper 0PT-80.1/20.7B, and licensee personnel assumed they were the
correct hoses without verification of the hoses pressure ratings. After RPV pressure
was raised to 1045 psig, personnel in the drywell noted water coming from the upper
level of the drywell (the exact amount of water was not quantified, but the drywell sump
filled and approximately one inch of water accumulated on the lowest drywell level floor).
Control room operators also noted a rapid drop in RPV pressure. Upon investigation,
licensee personnel in the drywell discovered the broken hose connection, and isolated
the leak.
Analysis. The inspectors determined that the failure to follow the requirements of
procedure 0PT-80.1, Reactor Pressure Vessel (RPV) ASME Section XI Pressure Test,
was a performance deficiency. The finding was determined to be more than minor
because the finding was associated with the Initiating Events cornerstone attribute of
human performance and affected the cornerstone objective of limiting the likelihood of
those events that upset plant stability and challenge critical safety functions during
shutdown as well as power operations. Specifically, when RPV pressure was raised to
approximately 1000 psig, the improper hose installed at core spray check valve 2-E21-
F006B disconnected from its coupling, causing the RPV to rapidly depressurize to
approximately 875 psig and allowing water from the RPV to leak out of the connection
into the drywell. The inspectors determined that the finding should be evaluated in
accordance with Attachment 1 of IMC 0609, Appendix G, Shutdown Operations SDP.
The inspectors used Checklist 8 contained in Attachment 1 and determined that the
finding did require a phase 2 or phase 3 because the licensee did not meet the
appropriate safety function guidelines for inventory control. Specifically, the finding
increases the likelihood of a loss of RCS inventory. The regional Senior Reactor Analyst
(SRA) determined, after a teleconference with the headquarters SRA with responsibility
for Shutdown findings, that the event did not rise to a level that would require a detailed
analysis be performed. The event did not meet the threshold for a loss of control as
defined by Appendix G. Additional margin was provided by the high elevation of the leak
relative to the top of active fuel, and the suction head requirement of the residual heat
removal (RHR) system, the small size of the opening in the primary, the low decay heat,
Enclosure
16
and the defense in depth available at the time of the event. Based on this, the finding
was determined to be of very low safety significance (Green).
The finding has a cross-cutting aspect in the Work Practices component of the Human
Performance cross cutting area, because the licensee failed to follow plant procedure
0PT-80.1, Reactor Pressure Vessel (RPV) ASME Section XI Pressure Test during Unit 2
RPV hydrostatic testing. (H.4(b)).
Enforcement. Technical Specification Section 5.4.1.a, Administrative Control
(Procedures), states, in part, that written procedures shall be established, implemented,
and maintained, covering applicable procedures recommended in Regulatory Guide
1.33, Appendix A, November 1972 (Safety Guide 33, November 1972). Section l.1 of
Regulatory Guide 1.33, Appendix A, November 1972, (Safety Guide 33,
November 1972) states, in part, that maintenance that can affect the performance of
safety-related equipment should be properly planned and performed in accordance with
written procedures, documented instructions, or drawings appropriate to the
circumstances. The licensee established OPT-80.1, Reactor Pressure Vessel (RPV)
ASME Section XI, Pressure Test, as the implementing procedure for the hydrostatic test.
Contrary to the above, on April 7, 2009, the licensee failed to follow procedure 0PT-80.1,
Reactor Pressure Vessel (RPV) ASME Section XI Pressure Test. Step 5.1.1 requires
installation of hoses with a pressure rating of at least 1150 psig. Specifically, the
licensee installed hoses rated at 250 psig, instead of the required hoses. As a result of
this maintenance error, the RPV depressurized and RPV water leaked into the drywell.
The licensee discovered the leak and broken hose connection, isolated the leak, and
initiated AR329675329675to address this issue. Because this violation was of very low safety
significance and it was entered into the licensees CAP (AR 329675329675, this violation is
being treated as an NCV, consistent with the NRC Enforcement Policy. This violation is
therefore designated as NCV 05000324/2009003-01, Failure to Follow Plant Procedures
During Performance of a Reactor Pressure Vessel Hydrostatic Test.
1R22 Surveillance Testing
.1 Routine Surveillance Testing
a. Inspection Scope
The inspectors either observed surveillance tests or reviewed the test results for the
following four activities to verify the tests met TS surveillance requirements, UFSAR
commitments, inservice testing requirements, and licensee procedural requirements.
The inspectors assessed the effectiveness of the tests in demonstrating that the SSCs
were operationally capable of performing their intended safety functions.
- 2MST-SW12Q, Service Water Diesel Generator Cooling Water Supply Low
Pressure Functional Test for EDG #3 on April 4, 2009
- 0MST-DG13R, DG-3 Loading Test on April 5, 2009
Enclosure
17
- 0PT12.18L, Unit Substation E7 Local Control Operability Test on April 6, 2009
- 0PT-13.1, Unit 1 Reactor Recirculation Jet Pump Operability on April 7, 2009
b. Findings
No findings of significance were identified.
.2 Inservice Testing (IST) Surveillance
a. Inspection Scope
The inspectors reviewed the performance of 0PT-10.1.1, RCIC System Operability Test
on June 24, 2009, 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 of significance were identified.
.3 Reactor Coolant System Leak Detection Inspection Surveillance
a. Inspection Scope
The inspectors observed and reviewed the test results for a reactor coolant system leak
detection surveillance, 0PT-80.1, Reactor Pressure Vessel ASME Section XXI Pressure
Test on April 8, 2009. The inspectors observed plant activities and reviewed procedures
and associated records to determine whether: effects of the testing were adequately
addressed by control room personnel or engineers prior to the commencement of the
testing; acceptance criteria were clearly stated, demonstrated operational readiness, and
were consistent with the system design basis; plant equipment calibration was correct,
accurate, and properly documented; and the calibration frequency were in accordance
with TSs, the UFSAR, procedures, and applicable commitments; applicable
prerequisites described in the test procedures were satisfied; test frequencies met TS
requirements to demonstrate operability and reliability; tests were performed in
accordance with the test procedures and other applicable procedures; test data and
results were accurate, complete, within limits, and valid; equipment was returned to a
position or status required to support the performance of its safety functions; and all
problems identified during the testing were appropriately documented and dispositioned
in the corrective action program. Documents reviewed are listed in the attachment.
Enclosure
18
b. Findings
No findings of significance were identified.
1EP6 Emergency Planning Drill Evaluation
a. Inspection Scope
The inspectors observed two site emergency preparedness training drill/simulator
scenarios conducted on June 9 and June 24, 2009. 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.
b. Findings
No findings of significance were identified.
4. OTHER ACTIVITIES
4OA1 Performance Indicator (PI) Verification
a. Inspection Scope
To verify the accuracy of the PI data reported to the NRC, the inspectors compared the
licensees basis in reporting each data element to the PI definitions and guidance
contained in Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment
Indicator Guideline.
Mitigating Systems Cornerstone
y Mitigating Systems Performance Index, Emergency AC Power
y Mitigating Systems Performance Index, Cooling Water Systems
The inspectors sampled licensee submittals for the Mitigating Systems Performance
Index performance indicators listed above for the period from the second quarter of 2008
through the first quarter of 2009. The inspectors reviewed the licensees operator
narrative logs, issue reports, MSPI derivation reports, event reports and NRC Integrated
Inspection reports for the period to validate the accuracy of the submittals. The
inspectors reviewed the MSPI component risk coefficient to determine if it had changed
by more than 25 percent in value since the previous inspection, and if so, that the
change was in accordance with applicable NEI guidance. The inspectors also reviewed
the licensees issue report database to determine if any problems had been identified
Enclosure
19
with the PI data collected or transmitted for this indicator and none were identified.
Specific documents reviewed are described in the Appendix to this report.
y Safety System Functional Failures
The inspectors reviewed licensee submittals for the Safety System Functional Failures
performance indicator for the period from the second quarter of 2008 through the first
quarter of 2009. The inspectors reviewed the licensees operator narrative logs,
operability assessments, maintenance rule records, maintenance work orders, issue
reports, event reports and NRC Integrated Inspection reports for the period to validate
the accuracy of the submittals. Specific documents reviewed are described in the
Appendix to this report.
b. Findings
No findings of significance were identified.
4OA2 Identification and Resolution of Problems
.1 Routine Review of Items Entered Into the Corrective Action Program
a. 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 of significance were identified.
.2 Semi-Annual Trend Review
a. 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 January 2009 through June 2009,
although some examples expanded beyond those dates where the scope of the trend
warranted.
The review also included issues documented outside the normal CAP in major
equipment problem lists, repetitive and/or rework maintenance lists, departmental
problem/challenges lists, system health reports, quality assurance audit/surveillance
Enclosure
20
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. Assessment and Observations
No findings of significance were identified. The inspectors noted a trend in procedure
adherence and the work management process. In particular, adverse effects
had been identified on system performance. This was exemplified by the following
identified issues:
y Improper loosening of RPV reference leg connection, NCR# 322354
y Unit 2 interruption of Shutdown Cooling due to maintenance, NCR# 327475
y Rx Hydro core spray check valve high pressure test jumper failure, NCR#
329677
y Work accomplished with inadequate documentation, NCR# 330266
y Improperly performed procedure step during 0MST-PCIS41R, NCR# 331004
The inspectors concluded that while the licensee has been providing additional focus
and training to this area, more attention and follow-up is needed.
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.
b. Findings
No findings of significance were identified.
4OA6 Management Meetings
.1 Exit Meeting Summary
On July 16, 2009 the inspector presented the inspection results to Mr. Ben Waldrep and
other members of the licensee staff. The inspectors confirmed that proprietary
information was not provided or examined during the inspection period.
Enclosure
21
An exit meeting for the Heat Sink inspection was conducted on June 5, 2009 with
licensee management.
ATTACHMENT: SUPPLEMENTAL INFORMATION
Enclosure
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
M. Annacone, Director Site Operations
G. Atkinson, Supervisor - Licensing and Regulatory Affairs
L. Beller, Superintendent, Operations Training
M. Blew, Engineering
B. Brewer, Manager- Maintenance
A. Brittain, Manager - Security
B. Davis, Manager - Engineering
P. Dubrouillet, Supervisor - Plant Support Group
S. Gordy, Manager - Operations
L. Grzeck, Lead Engineer - Technical Support
K. Hamm, Intake and Circulating Water System Engineer
E. Harkcom, Service Water System Engineer
S. Howard, Manager - Outage and Scheduling
R. Ivey, Manager - Nuclear Oversight Section
J. Johnson, Manager - Environmental and Radiological Controls
S. Larson, ISI Coordinator
P. Mentel, Manager - Nuclear Support Services
W. Murray, Licensing Specialist
A. Pope, Manager - Station Recovery
T. Sherrill, Engineer - Technical Support
G. Spry, Welding Engineer
J. Titrington, Superintendent - Design Engineering
M. Turkal, Lead Engineer - Technical Support
J. Vincelli, Superintendent - Environmental and Radiological Controls
B. Waldrep, Site Vice President
M. Williams, Manager - Training Manager
E. Wills, Plant General Manager
B. Wilton, Engineering
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
05000324/2009003-01 NCV Failure to Follow Plant Procedures During
Performance of a Reactor Pressure Vessel
Hydrostatic Test (Section 1R20)
Attachment
LIST OF DOCUMENTS REVIEWED
Section 1R01: Adverse Weather Protection
0AOP-13.0, Operation during Hurricane, Flood Conditions, Tornado, or Earthquake
0A1-68, Brunswick Nuclear Plant Response to Severe Weather Warnings
0PEP-02.1, Initial Emergency Actions
0PEP-02.6, Severe Weather
0O1-01.03, Non-Routine Activities
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
1OP-16, Reactor Core Isolation Cooling System Operating Procedure
2OP-16, Reactor Core Isolation Cooling System Operating Procedure
1OP-19, High Pressure Cooling Injection System Operating Procedure
2OP-19, High Pressure Cooling Injection System Operating Procedure
Section 1R05: Fire Protection
0PFP-CB, Control Building Prefire Plans
0PFP-DG, Diesel Generator Building Prefire Plans
0PFP-PBAA, Power Block Auxiliary Areas Prefire Plans SW, RW, AOG, TY, EY
0PFP-013, General Fire Plan
1PFP-RB, Reactor Building Prefire Plans Unit 1
1PFP-TB, Turbine Building Prefire Plans Unit 1
2PFP-RB, Reactor Building Prefire Plans Unit 2
2PFP-TB, Turbine Building Prefire Plans Unit 2
0OP-41, Fire Protection and Well Water System
0PFP-MBPA, Miscellaneous Buildings Pre-Fire Plans - Protected Area
0PT-34.11.2.0, Portable Fire Extinguisher Inspection
Section 1R07: Heat Sink Performance
Procedures
EGR-NGGC-0008, Rev. 3, Engineering Program
OPM-ACU 500, Rev. 7, Inspection and Cleaning of the RHR/CORE Spray Room Aerofin Cooler
Air Filters and Coolers EPEG 02-04, Rev. 0, Service Water Reliability - Generic Letter 89-13
Program
TG-ESG 507B, Rev. 0, Cooling Water Reliability GL 89-13 Program Manager Training Guide
Attachment
3
OENP-303, Rev. 7, RHR and Core Spray Room Cooler Performance
OENP-2704, Rev. 17, Administrative Control of NRC Generic Letter 89-13 Requirements
OPM-STU 501, Rev. 11, Circulating Water Intake Structure Silt Removal
Administrative Instruction (0AI)-81, Rev. 51, Water Chemistry Guidelines
0AI-82, Rev. 3, Closed Cooling Water Chemistry Guidelines
0AI-146, Rev. 1, Plant Response to Degraded Conditions at the Intake Structure
Environmental and Radiation Control (0E&RC)-3295, Rev. 22, Canal Monitoring
OPM-STU500, Rev. 18, Service Water Intake Structure Inspection and Cleaning
Calculations
OSW-0097, Rev. 0, RHR and Core Spray Room Cooler Performance
OSW-0096, Rev. 0, Calculation for Tube Plugging of Service Water Safety Related Heat
Exchangers
G0050A-04, Rev. 1, Design Basis Heat Loads from Vital Heat Exchangers
G0050A-16, Rev. 1, Service Water Single Failure Analysis
Corrective Action Documents - Nonconforming Report (NCR) or Action Reports (ARs)
NCR 249130, the Differential Pressure across the RHR 1A Heat Exchanger Was Measured at
200 Inches of Water
NCR 224737, A Significant Growth of Oyster Shells and Barnacles was Observed on the 24
Header That Supplies Conventional Service Water to the A Loop RHR SW Vital Header
Action Request (AR) 00247053, Shells in 1A RHR Room Cooler & Inlet Piping
AR 00271611, Adverse Trend in BNP Service Water Performance
- AR 00339272, Inadequate Equation Use for Calculating Heat Exchanger Efficiency
AR 00315056, Incorporate Inspection of Concrete Surfaces and Enhance the Structural
Inspection of the CW Intake Structure
- Documents created as a direct result of this inspection.
Other
Work Order (WO) 1121279 for Procedure OENP-2704, Service Water Safety Related Heat
Exchanger Cleaning/Inspection Data Sheet for 1A RHR Heat Exchanger, Dated April 5, 2008
WO 1121279-07, Ultrasonic Examination (UT) Inspection on Flange on RHR 1A Heat
Exchanger, Dated February 15, 2008
WO 1130955-01, Drain and Clean Tubes on RHR 1A Heat Exchanger, Dated October 4, 2007
WO 737124 (Procedure OENP-2704), Service Water Safety Related Heat Exchanger
Cleaning/Inspection Data Sheet for 2B RHR SW Pump Motor Cooler, Dated February 21, 2007
WO 1318238-1 (Procedure OENP-2704), Service Water Safety Related Heat Exchanger
Cleaning/Inspection Data Sheet for 2B RHR SW Pump Motor Cooler, Dated April 11, 2008
WO 1318238, Boroscope the #1 EDG Jacket Water Cooler, Dated April 11, 2008
System Health Report for System #4060, Service Water
Chlorine Residual Rate Measurements - Sample points, Analysis, and Sample dates from
March 1 to May 31, 2009
NGG Program Health Report for Cooling Water Reliability (89-13), Dated January 8, 2009
Service Water Trash Rack Monthly Inspection and Cleaning in March, April, and May, 2009
Attachment
4
Bi-Weekly Diversion Structure Inspection for Service Water Intake in March, April, and May,
2009
WO 01360507, Monthly Units Circulating Water Intake Trash Rack Inspection Cleaning, May
2009
WO 00973437, Yearly Unit 2 SW and SCW Pump Bay Silt and Biofouling Inspection and
Cleaning, February 2008
Service Water Safety Related Heat Exchanger Cleaning/Inspection Data Sheet for EDG #1
Jacket Water Cooler Flow Test, June 4, 2009
Flow Test Results for RHR 2B Heat Exchanger Dated April 8, 2007
Preliminary Eddy Current Inspection Report for Unit 2 Residual Heat Removal (RHR) Heat
Exchanger (Hx) 2B, dated March 9, 2009
Control Chart for differential pressure ( P) across the 1A RHR Hx since Spring 2002
Control Chart for temperature (T) across the # 2 Emergency Diesel Generator HX since
Spring 2008
Cooling Water System (89-13) Health Report, dated January 8, 2009
Cooling Water System (89-13) Health Report, dated July 24, 2008
WO 00647095-09, Perform HX Flow Test on the 2-MUD-JKT-WTR-CLR-1
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
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
NCR #329679, 2-DSA-PRV-1689 Failed Pmt
NRC #330193, Unexpected Trip of EDG#4
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
Attachment
5
Section 1R15: Operability Evaluations
OPS-NGGC-1305, Operability Determinations
OPS-NGGC-1307, Operational Decision making
NCR# 329545, EDG # 3 four day tank level indication
Section 1R18: Plant Modifications
EGR-NGGC-0005, Engineering Change
EGR-NGGC-0011, Engineering Product Quality
0SMP-MO003, Soft Electrical Backseating of AC Motor Operated Valves Using the Motor
Operator
Section 1R19: Post Maintenance Testing
0PLP-20, Post Maintenance Testing Program
Section 1R20: Outage Activities
1OP17, 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
0SMP-RPV502, Reactor Vessel Reassembly
0MMM-015, Operation and Inspection of Cranes and Material Handing Equipment
Section 4OA1: Performance Indicator Verification
Procedures
REG-NGGC-0009, NRC Performance Indicators and Monthly Operating Report Data
Records and Data
Monthly PI Reports, September 2007 - August 2008
Attachment