ML032100780: Difference between revisions

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Duke Energy Corporation
Duke Energy Corporation
ATTN: Mr. R. A. Jones
ATTN: Mr. R. A. Jones
        Site Vice President
Site Vice President
        Oconee Nuclear Station
Oconee Nuclear Station
7800 Rochester Highway
7800 Rochester Highway
Seneca, SC 29672
Seneca, SC 29672
SUBJECT:       OCONEE NUCLEAR STATION - NRC INTEGRATED INSPECTION
SUBJECT:
                REPORT 05000269/2003003, 05000270/2003003, AND 05000287/2003003
OCONEE NUCLEAR STATION - NRC INTEGRATED INSPECTION              
REPORT 05000269/2003003, 05000270/2003003, AND 05000287/2003003
Dear Mr. Jones:
Dear Mr. Jones:
On June 28, 2003, the NRC completed an inspection at your Oconee Nuclear Station. The
On June 28, 2003, the NRC completed an inspection at your Oconee Nuclear Station. The
enclosed report documents the inspection findings which were discussed on July 1, 2003, with
enclosed report documents the inspection findings which were discussed on July 1, 2003, with
you and other members of your staff.
you and other members of your staff.
The inspection examined activities conducted under your licenses as they relate to safety and
The inspection examined activities conducted under your licenses as they relate to safety and
compliance with the Commissions rules and regulations and with the conditions of your
compliance with the Commissions rules and regulations and with the conditions of your
licenses. The inspectors reviewed selected procedures and records, observed activities, and
licenses. The inspectors reviewed selected procedures and records, observed activities, and
interviewed personnel.
interviewed personnel.
Based on the results of this inspection, there were four NRC-identified findings of very low
Based on the results of this inspection, there were four NRC-identified findings of very low
safety significance (Green). These findings were determined to involve violations of NRC
safety significance (Green). These findings were determined to involve violations of NRC
requirements. However, because of their very low safety significance and because they have
requirements. However, because of their very low safety significance and because they have
been entered into your corrective action program, the NRC is treating these issues as a non-
been entered into your corrective action program, the NRC is treating these issues as a non-
cited violations (NCVs), in accordance with Section VI.A.1 of the NRCs Enforcement Policy.
cited violations (NCVs), in accordance with Section VI.A.1 of the NRCs Enforcement Policy.  
Additionally, one licensee-identified NCV is listed in Section 4OA7 of this report. If you contest
Additionally, one licensee-identified NCV is listed in Section 4OA7 of this report. If you contest
any of the NCVs in this report, you should provide a response within 30 days of the date of this
any of the NCVs in this report, you should provide a response within 30 days of the date of this
inspection report, with the basis for your denial, to the United States Nuclear Regulatory
inspection report, with the basis for your denial, to the United States Nuclear Regulatory
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In accordance with 10 CFR 2.790 of the NRC's "Rules of Practice," a copy of this letter and its
In accordance with 10 CFR 2.790 of the NRC's "Rules of Practice," a copy of this letter and its
enclosure will be available electronically for public inspection in the NRC Public Document
enclosure will be available electronically for public inspection in the NRC Public Document
Room or from the Publicly Available Records (PARS) component of NRC's document system
Room or from the Publicly Available Records (PARS) component of NRC's document system  


DEC                                         2
DEC
(ADAMS). ADAMS is accessible from the NRC Web site at
2
http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
(ADAMS). ADAMS is accessible from the NRC Web site at  
                                          Sincerely,
http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
                                          /RA/
Sincerely,
                                          Robert Haag, Chief
/RA/
                                          Reactor Projects Branch 1
Robert Haag, Chief
                                          Division of Reactor Projects
Reactor Projects Branch 1
Division of Reactor Projects
Docket Nos.: 50-269, 50-270, 50-287
Docket Nos.: 50-269, 50-270, 50-287
License Nos.: DPR-38, DPR-47, DPR-55
License Nos.: DPR-38, DPR-47, DPR-55
Enclosure:     NRC Integrated Inspection Report 05000269/2003003, 05000270/2003003, and
Enclosure:
              05000287/2003003 w/Attachment - Supplemental Information
NRC Integrated Inspection Report 05000269/2003003, 05000270/2003003, and
cc w\encl.:
05000287/2003003 w/Attachment - Supplemental Information
L. E. Nicholson                                   R. Mike Gandy
cc w\\encl.:
Compliance Manager (ONS)                         Division of Radioactive Waste Mgmt.
L. E. Nicholson
Duke Energy Corporation                           S. C. Department of Health and
Compliance Manager (ONS)
Electronic Mail Distribution                      Environmental Control
Duke Energy Corporation
                                                  Electronic Mail Distribution
Electronic Mail Distribution
Lisa Vaughn
Lisa Vaughn
Legal Department (ECIIX)                         County Supervisor of
Legal Department (ECIIX)
Duke Energy Corporation                           Oconee County
Duke Energy Corporation
422 South Church Street                          415 S. Pine Street
422 South Church Street
Charlotte, NC 28242                               Walhalla, SC 29691-2145
Charlotte, NC 28242
Anne Cottingham                                   Lyle Graber, LIS
Anne Cottingham
Winston and Strawn                               NUS Corporation
Winston and Strawn
Electronic Mail Distribution                      Electronic Mail Distribution
Electronic Mail Distribution
Beverly Hall, Acting Director                     M. T. Cash, Manager
Beverly Hall, Acting Director
Division of Radiation Protection                 Nuclear Regulatory Licensing
Division of Radiation Protection
N. C. Department of Environmental                 Duke Energy Corporation
N. C. Department of Environmental
Health & Natural Resources                       526 S. Church Street
  Health & Natural Resources
Electronic Mail Distribution                     Charlotte, NC 28201-0006
Electronic Mail Distribution
Henry J. Porter, Director                         Peggy Force
Henry J. Porter, Director
Div. of Radioactive Waste Mgmt.                   Assistant Attorney General
Div. of Radioactive Waste Mgmt.
S. C. Department of Health and                   N. C. Department of Justice
S. C. Department of Health and
Environmental Control                           Electronic Mail Distribution
  Environmental Control
Electronic Mail Distribution
R. Mike Gandy
Division of Radioactive Waste Mgmt.
S. C. Department of Health and
  Environmental Control
Electronic Mail Distribution
County Supervisor of
  Oconee County
415 S. Pine Street
Walhalla, SC  29691-2145
Lyle Graber, LIS
NUS Corporation
Electronic Mail Distribution
M. T. Cash, Manager
Nuclear Regulatory Licensing
Duke Energy Corporation
526 S. Church Street
Charlotte, NC  28201-0006
Peggy Force
Assistant Attorney General
N. C. Department of Justice
Electronic Mail Distribution
Electronic Mail Distribution


        DEC                                                 3
DEC
        Distribution w/encl:
3
        L. Olshan, NRR
Distribution w/encl:
        A. Hiser, NRR
L. Olshan, NRR
        L. Slack, RII, EICS
A. Hiser, NRR
        RIDSNRRDIPMLIPB
L. Slack, RII, EICS
        PUBLIC
RIDSNRRDIPMLIPB
OFFICE             RII:DRP       RII:DRP       RII:DRP         RII:DRS       RII:DRS       RII:DRS       RII:DRS
PUBLIC  
SIGNATURE         MXS1         GAH2         ETR             MSL1 for     MSL1 for     MSL1 for     DWJ
OFFICE
NAME               MShannon     GHutto       ERiggs         SVias         MScott       JBlake       DJones
RII:DRP
DATE                   7/28/2003     7/28/2003     7/28/2003       7/24/2003     7/24/2003     7/24/2003     7/28/2003
RII:DRP
E-MAIL COPY?         YES      NO  YES       NO YES       NO   YES       NO YES       NO YES       NO YES       NO
RII:DRP
OFFICE             RII:DRS       RII:DRS       RII:DRS         RII:DRS
RII:DRS
SIGNATURE         GWL1         REC1         MSL1 for       MSL1 for
RII:DRS
NAME               GLaska       RCarroll     RMaxey         RCortes
RII:DRS
DATE                   7/24/2003     7/28/2003     7/24/2003       7/24/2003
RII:DRS
E-MAIL COPY?         YES      NO  YES       NO YES       NO   YES       NO YES       NO YES       NO YES       NO
SIGNATURE
PUBLIC DOCUMENT     YES     NO
MXS1
        OFFICIAL RECORD COPY       DOCUMENT NAME: C:\ORPCheckout\FileNET\ML032100780.wpd
GAH2
ETR
MSL1 for
MSL1 for
MSL1 for
DWJ
NAME
MShannon
GHutto  
ERiggs
SVias
MScott
JBlake
DJones
DATE
7/28/2003
7/28/2003
7/28/2003
7/24/2003
7/24/2003
7/24/2003
7/28/2003
E-MAIL COPY?
    YES
NO     YES
NO     YES
NO     YES
NO     YES
NO     YES
NO     YES
NO  
OFFICE
RII:DRS
RII:DRS
RII:DRS
RII:DRS
SIGNATURE
GWL1
REC1  
MSL1 for
MSL1 for
NAME
GLaska
RCarroll
RMaxey
RCortes
DATE
7/24/2003
7/28/2003
7/24/2003
7/24/2003
E-MAIL COPY?
    YES
NO     YES
NO     YES
NO     YES
NO     YES
NO     YES
NO     YES
NO  
PUBLIC DOCUMENT
    YES
NO  
OFFICIAL RECORD COPY           DOCUMENT NAME: C:\\ORPCheckout\\FileNET\\ML032100780.wpd


            U. S. NUCLEAR REGULATORY COMMISSION
U. S. NUCLEAR REGULATORY COMMISSION
                                REGION II
REGION II
Docket Nos:       50-269, 50-270, 50-287
Docket Nos:
License Nos:       DPR-38, DPR-47, DPR-55
50-269, 50-270, 50-287
Report No:         50-269/03-03, 50-270/03-03, 50-287/03-03
License Nos:
Licensee:         Duke Energy Corporation
DPR-38, DPR-47, DPR-55
Facility:         Oconee Nuclear Station, Units 1, 2, and 3
Report No:
Location:         7800 Rochester Highway
50-269/03-03, 50-270/03-03, 50-287/03-03
                  Seneca, SC 29672
Licensee:
Dates:             April 6, 2003 - June 28, 2003
Duke Energy Corporation
Inspectors:       M. Shannon, Senior Resident Inspector
Facility:
                  A. Hutto, Resident Inspector
Oconee Nuclear Station, Units 1, 2, and 3
                  E. Riggs, Resident Inspector
Location:
                  J. Blake, Senior Project Manager (Section 1R08)
7800 Rochester Highway
                  D. Jones, Senior Health Physicist (Section 4OA5.1D)
Seneca, SC 29672
                  G. Laska, Operator Licensing Examiner (Section 1R11.2)
Dates:
                  M. Scott, Senior Reactor Inspector (Sections 1R02 and 1R17)
April 6, 2003 - June 28, 2003
                  K. Maxey, Reactor Inspector (Sections 1R02 and 1R17)
Inspectors:
                  R. Cortes, Reactor Inspector (Sections 1R02 and 1R17)
M. Shannon, Senior Resident Inspector
                  S. Vias, Senior Reactor Inspector (Sections 1R02, 1R17 and
A. Hutto, Resident Inspector
                    40A5.1A-C)
E. Riggs, Resident Inspector
                  R. Carroll, Senior Project Inspector (Sections 1R20)
J. Blake, Senior Project Manager (Section 1R08)
Approved by:       Robert Haag, Chief
D. Jones, Senior Health Physicist (Section 4OA5.1D)
                  Reactor Projects Branch 1
G. Laska, Operator Licensing Examiner (Section 1R11.2)
                  Division of Reactor Projects
M. Scott, Senior Reactor Inspector (Sections 1R02 and 1R17)
                                                                Enclosure
K. Maxey, Reactor Inspector (Sections 1R02 and 1R17)
R. Cortes, Reactor Inspector (Sections 1R02 and 1R17)
S. Vias, Senior Reactor Inspector (Sections 1R02, 1R17 and
  40A5.1A-C)
R. Carroll, Senior Project Inspector (Sections 1R20)
Approved by:
Robert Haag, Chief
Reactor Projects Branch 1
Division of Reactor Projects
Enclosure


                                                      CONTENTS
CONTENTS
                                                                                                                                  Page
  Page
SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S1
SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S1
REACTOR SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
REACTOR SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
        1R02 Evaluation of Changes, Tests, or Experiments . . . . . . . . . . . . . . . . . . . . . . . . . 1
1R02
        1R04 Equipment Alignment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Evaluation of Changes, Tests, or Experiments
        1R05 Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
. . . . . . . . . . . . . . . . . . . . . . . . . 1
        1R07 Heat Sink Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
1R04
        1R08 Inservice Inspection Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Equipment Alignment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
        1R11 Licensed Operator Requalification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
1R05
        1R12 Maintenance Effectiveness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
        1R13 Maintenance Risk Assessments and Emergent Work Evaluations . . . . . . . . . 11
1R07
        1R14 Personnel Performance During Non-routine Plant Evolutions . . . . . . . . 12
Heat Sink Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
        1R15 Operability Evaluations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
1R08
        1R17 Permanent Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Inservice Inspection Activities
        1R19 Post-Maintenance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
        1R20 Refueling and Outage Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
1R11
        1R22 Surveillance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Licensed Operator Requalification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
        1EP6 Drill Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
1R12
OTHER ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .     21
Maintenance Effectiveness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
        4OA1 Performance Indicator Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .                 21
1R13
        4OA2 Identification and Resolution of Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . .                       21
Maintenance Risk Assessments and Emergent Work Evaluations
        4OA3 Event Followup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .         22
. . . . . . . . . 11
        4OA5 Other Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .     23
1R14 Personnel Performance During Non-routine Plant Evolutions  
        4OA6 Meetings, Including Exit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .           27
. . . . . . . . 12
        4OA7 Licensee-Identified Violations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .             27
1R15
ATTACHMENT: SUPPLEMENTAL INFORMATION
Operability Evaluations
Key Points of Contact . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .   A-1
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
List of Items Opened, Closed, and Discussed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .                 A-1
1R17
List of Documents Reviewed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .         A-2
Permanent Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
1R19
Post-Maintenance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
1R20
Refueling and Outage Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
1R22
Surveillance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
1EP6
Drill Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
OTHER ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
4OA1 Performance Indicator Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
4OA2 Identification and Resolution of Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
4OA3 Event Followup
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
4OA5 Other Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
4OA6 Meetings, Including Exit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
4OA7 Licensee-Identified Violations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
ATTACHMENT: SUPPLEMENTAL INFORMATION
Key Points of Contact . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1
List of Items Opened, Closed, and Discussed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1
List of Documents Reviewed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-2
List of Acronyms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-7
List of Acronyms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-7


                                    SUMMARY OF FINDINGS
SUMMARY OF FINDINGS
IR 05000269/2003-003, IR 05000270/2003-003, IR 05000287/2003-003; Duke Energy
IR 05000269/2003-003, IR 05000270/2003-003, IR 05000287/2003-003; Duke Energy
Corporation; 04/06/2003 - 06/28/2003; Oconee Nuclear Station; Maintenance Effectiveness,
Corporation; 04/06/2003 - 06/28/2003; Oconee Nuclear Station; Maintenance Effectiveness,
Personnel Performance During Non-routine Plant Evolutions, and Other Activities.
Personnel Performance During Non-routine Plant Evolutions, and Other Activities.
The inspection was conducted by the resident Inspectors and eight regional based inspectors:
The inspection was conducted by the resident Inspectors and eight regional based inspectors:  
one senior project manager; one senior project engineer; one senior health physicist; two senior
one senior project manager; one senior project engineer; one senior health physicist; two senior
reactor inspectors; one operator licensing examiner; and two reactor inspectors. The
reactor inspectors; one operator licensing examiner; and two reactor inspectors. The
inspectors identified four Green findings, which were identified as NCVs. The significance of
inspectors identified four Green findings, which were identified as NCVs. The significance of
most findings is indicated by their color (Green, White, Yellow, Red) using IMC 0609,
most findings is indicated by their color (Green, White, Yellow, Red) using IMC 0609,
Significance Determination Process (SDP). Findings for which the SDP does not apply may
Significance Determination Process (SDP). Findings for which the SDP does not apply may
be Green or be assigned a severity level after NRC management review. The NRC's program
be Green or be assigned a severity level after NRC management review. The NRC's program
for overseeing the safe operation of commercial nuclear power reactors is described in
for overseeing the safe operation of commercial nuclear power reactors is described in
NUREG-1649, Reactor Oversight Process, Revision 3, dated July 2000.
NUREG-1649, Reactor Oversight Process, Revision 3, dated July 2000.
A.     NRC Identified and Self-Revealing Findings
A.
NRC Identified and Self-Revealing Findings
Cornerstone: Mitigating Systems
Cornerstone: Mitigating Systems
*       Green. A non-cited violation (NCV) of 10CFR50, Appendix B, Criterion XVI, Corrective
*
        Action, was identified by the inspectors for failure to promptly identify the degraded
Green.   A non-cited violation (NCV) of 10CFR50, Appendix B, Criterion XVI, Corrective
        standby shutdown facility (SSF) diesel cooling water seals in the problem investigation
Action, was identified by the inspectors for failure to promptly identify the degraded
        process (PIP) program.
standby shutdown facility (SSF) diesel cooling water seals in the problem investigation
        This finding was considered to be more than minor based on the fact that subsequent
process (PIP) program.
        analysis of the grommets noted significant degradation and this analysis would likely not
This finding was considered to be more than minor based on the fact that subsequent
        have been performed without initiation of the PIP. Therefore, if the cause of the
analysis of the grommets noted significant degradation and this analysis would likely not
        degradation was left uncorrected, the mitigation systems cornerstone objective of
have been performed without initiation of the PIP. Therefore, if the cause of the
        ensuring the continued reliability of equipment needed to respond to initiating events
degradation was left uncorrected, the mitigation systems cornerstone objective of
        would be affected. In addition, continued degradation of the grommets would become a
ensuring the continued reliability of equipment needed to respond to initiating events
        more significant safety concern. This issue was considered to be of low safety
would be affected. In addition, continued degradation of the grommets would become a
        significance (Green) because the grommets were replaced during the SSF diesel
more significant safety concern. This issue was considered to be of low safety
        overhaul before they failed in service. (Section 1R12.2)
significance (Green) because the grommets were replaced during the SSF diesel
*       Green. A NCV of Technical Specification (TS) 5.4.1 and 10CFR50, Appendix B,
overhaul before they failed in service. (Section 1R12.2)
        Criterion XVII Quality Assurance Records, was identified by the inspectors for failure to
*
        maintain sufficient records [logs] to furnish evidence of activities affecting quality [TS
Green. A NCV of Technical Specification (TS) 5.4.1 and 10CFR50, Appendix B,
        Limiting Conditions for Operation (LCOs)]. Specifically, operator logs provided
Criterion XVII Quality Assurance Records, was identified by the inspectors for failure to
        insufficient data to reconstruct the activities related to the June 22, 2003, Unit 1
maintain sufficient records [logs] to furnish evidence of activities affecting quality [TS
        Engineered Safeguards (ES) power supply failure, which affected the Engineered
Limiting Conditions for Operation (LCOs)]. Specifically, operator logs provided
        Safeguards Protection System (ESPS) Digital Automatic Actuation Logic Channels 2, 4,
insufficient data to reconstruct the activities related to the June 22, 2003, Unit 1
        6, and 8.
Engineered Safeguards (ES) power supply failure, which affected the Engineered
        The ESPS automatic initiation of ES functions to mitigate accident conditions is
Safeguards Protection System (ESPS) Digital Automatic Actuation Logic Channels 2, 4,
        assumed in the accident analysis and is required to ensure that consequences of
6, and 8.  
        analyzed events do not exceed the accident analysis predictions. The failure to
The ESPS automatic initiation of ES functions to mitigate accident conditions is
        adequately document TS LCO entry and action times for the failed automatic ES
assumed in the accident analysis and is required to ensure that consequences of
        actuation circuitry was considered to be more than minor because it impacted the
analyzed events do not exceed the accident analysis predictions. The failure to
adequately document TS LCO entry and action times for the failed automatic ES
actuation circuitry was considered to be more than minor because it impacted the


                                                2
2
      operators ability to accurately implement the TS LCO action statements, and if left
operators ability to accurately implement the TS LCO action statements, and if left
      uncorrected, this type of improper documentation could become a more significant
uncorrected, this type of improper documentation could become a more significant
      safety concern. The finding was considered to be of very low safety significance based
safety concern. The finding was considered to be of very low safety significance based
      on the fact that the ES power supply was returned to service before any LCO condition
on the fact that the ES power supply was returned to service before any LCO condition
      would have required the unit to be in Mode 3. (Section 1R14b.(1))
would have required the unit to be in Mode 3. (Section 1R14b.(1))
*     Green. A NCV of TS 3.3.7 Condition A , Engineered Safeguards Protection System
*
      (ESPS) Digital Automatic Actuation Logic Channels, was identified by the inspectors
Green. A NCV of TS 3.3.7 Condition A , Engineered Safeguards Protection System
      when it was discovered that the licensee failed to declare a number of ES configured
(ESPS) Digital Automatic Actuation Logic Channels, was identified by the inspectors
      system components inoperable following the loss of ESPS digital channels 2, 4, 6, and
when it was discovered that the licensee failed to declare a number of ES configured
      8.
system components inoperable following the loss of ESPS digital channels 2, 4, 6, and
      The ESPS automatic initiation of ES functions to mitigate accident conditions is
8.
      assumed in the accident analysis and is required to ensure that consequences of
The ESPS automatic initiation of ES functions to mitigate accident conditions is
      analyzed events do not exceed the accident analysis predictions. Consequently, this
assumed in the accident analysis and is required to ensure that consequences of
      issue is more than minor, in that by not recognizing the importance of the lost automatic
analyzed events do not exceed the accident analysis predictions. Consequently, this
      ES initiation function and taking the compensatory actions of TS 3.3.7, the mitigating
issue is more than minor, in that by not recognizing the importance of the lost automatic
      systems cornerstone objective of ensuring the continued reliability of equipment needed
ES initiation function and taking the compensatory actions of TS 3.3.7, the mitigating
      to respond to initiating events was affected. However, this issue was determined to be
systems cornerstone objective of ensuring the continued reliability of equipment needed
      of very low safety significance, based on the fact that there was no loss of function of
to respond to initiating events was affected. However, this issue was determined to be
      the Low Pressure Service Water system or the Keowee Hydro Units resulting from the
of very low safety significance, based on the fact that there was no loss of function of
      loss of ESPS Digital Automatic Actuation Logic Channels 2, 4, 6, and 8. Additionally,
the Low Pressure Service Water system or the Keowee Hydro Units resulting from the
      the ES power supplies were restored and digital channels returned to service prior to
loss of ESPS Digital Automatic Actuation Logic Channels 2, 4, 6, and 8. Additionally,
      exceeding any TS allowed outage times for the affected components. (Section
the ES power supplies were restored and digital channels returned to service prior to
      1R14b.(2))
exceeding any TS allowed outage times for the affected components. (Section
Cornerstone: Initiating Events
1R14b.(2))
*     Green: A NCV of 10CFR50.55a(g)(4) and 10CFR50, Appendix B, Criterion VII was
Cornerstone: Initiating Events
      identified by the inspectors, in that measures taken to preclude the installation of non-
*
      conforming replacement parts and the ability to evaluate the suitability of replacement
Green: A NCV of 10CFR50.55a(g)(4) and 10CFR50, Appendix B, Criterion VII was
      during the Quality Assurance (QA) receipt inspection process were not adequate.
identified by the inspectors, in that measures taken to preclude the installation of non-
      Specifically, this was identified for inadequate QA review during receipt inspections that
conforming replacement parts and the ability to evaluate the suitability of replacement
      resulted in the licensee installing one non-conforming Control Rod Drive Mechanisms
during the Quality Assurance (QA) receipt inspection process were not adequate.
      (CRDM) (Split Nut) Flange Ring on Unit 2, and discovering, prior to the installation in
Specifically, this was identified for inadequate QA review during receipt inspections that
      Unit 3, 68 CRDMs and 552 CRDM Hold Down Bolts that did not meet the design and
resulted in the licensee installing one non-conforming Control Rod Drive Mechanisms
      procurement specifications.
(CRDM) (Split Nut) Flange Ring on Unit 2, and discovering, prior to the installation in
      This finding was more than minor because non-conforming material was actually
Unit 3, 68 CRDMs and 552 CRDM Hold Down Bolts that did not meet the design and
      installed in Unit 2. However, it was determined to be of very low safety significance
procurement specifications.
      because there was not a loss of system function. (Section 40A5.1C)
This finding was more than minor because non-conforming material was actually
B.   Licensee Identified Violations
installed in Unit 2. However, it was determined to be of very low safety significance
      One violation of very low safety significance, which was identified by the licensee has
because there was not a loss of system function. (Section 40A5.1C)
      been reviewed by the inspectors. Corrective actions taken or planned by the licensee
B.
      have been entered into the licensees corrective action program. This violation is listed
Licensee Identified Violations
      in Section 4OA7.
One violation of very low safety significance, which was identified by the licensee has
been reviewed by the inspectors. Corrective actions taken or planned by the licensee
have been entered into the licensees corrective action program. This violation is listed
in Section 4OA7.


                                          Report Details
Report Details
Summary of Plant Status:
Summary of Plant Status:
Unit 1 operated at 100 percent rated thermal power (RTP) during the inspection period except
Unit 1 operated at 100 percent rated thermal power (RTP) during the inspection period except
for one power reduction. The unit was reduced to approximately 50 percent RTP on May 17,
for one power reduction. The unit was reduced to approximately 50 percent RTP on May 17,
2003, following a safety group 4 dropped rod. The rod was recovered and the unit was
2003, following a safety group 4 dropped rod. The rod was recovered and the unit was
returned to 100 percent RTP on May 18, 2003.
returned to 100 percent RTP on May 18, 2003.
Unit 2 operated at 100 percent RTP during the inspection period except for two power
Unit 2 operated at 100 percent RTP during the inspection period except for two power
reductions. The unit was reduced to approximately 88 percent RTP on April 13, 2003, to
reductions. The unit was reduced to approximately 88 percent RTP on April 13, 2003, to
perform turbine valve movement testing. The unit was returned to 100 percent power later that
perform turbine valve movement testing. The unit was returned to 100 percent power later that
same day. On June 22, 2003, the unit was reduced to approximately 87 percent RTP to again
same day. On June 22, 2003, the unit was reduced to approximately 87 percent RTP to again
perform turbine valve movement testing. The unit was returned to 100 percent power later that
perform turbine valve movement testing. The unit was returned to 100 percent power later that
same day.
same day.
Unit 3 entered the report period at 93 percent RTP with an end of core life coastdown in
Unit 3 entered the report period at 93 percent RTP with an end of core life coastdown in
progress. The unit was shutdown on April 26, 2003, for a refueling outage. Following the
progress. The unit was shutdown on April 26, 2003, for a refueling outage. Following the
outage, the unit entered Mode 1 on June 14, 2003, and reached 100 percent RTP on June 18,
outage, the unit entered Mode 1 on June 14, 2003, and reached 100 percent RTP on June 18,  
2003. On June 28, 2003, the unit was reduced to 15 percent RTP and the turbine taken off-line
2003. On June 28, 2003, the unit was reduced to 15 percent RTP and the turbine taken off-line
for turbine balancing. The report period ended with the unit at 15 percent RTP.
for turbine balancing. The report period ended with the unit at 15 percent RTP.
1. REACTOR SAFETY
1. REACTOR SAFETY
    Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity
    Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity
1R02 Evaluations of Changes, Tests or Experiments
1R02
a.     Inspection Scope
Evaluations of Changes, Tests or Experiments
        The inspectors reviewed selected samples of evaluations to confirm that the licensee
  a.
        had appropriately considered the conditions under which changes to the facility,
Inspection Scope
        Updated Final Safety Analysis Report (UFSAR), or procedures may be made, and tests
        conducted, without prior NRC approval. The inspectors reviewed evaluations for nine
The inspectors reviewed selected samples of evaluations to confirm that the licensee
        changes and additional information, such as calculations, supporting analyses, the
had appropriately considered the conditions under which changes to the facility,
        UFSAR, and drawings to confirm that the licensee had appropriately concluded that the
Updated Final Safety Analysis Report (UFSAR), or procedures may be made, and tests
        changes could be accomplished without obtaining a license amendment. The nine
conducted, without prior NRC approval. The inspectors reviewed evaluations for nine
        evaluations reviewed are listed in the Attachment to this report.
changes and additional information, such as calculations, supporting analyses, the
        The inspectors also reviewed samples of changes such as design changes, UFSAR
UFSAR, and drawings to confirm that the licensee had appropriately concluded that the
        changes, commercial grade dedication packages, equipment problem issues, and like-
changes could be accomplished without obtaining a license amendment. The nine
        for-like evaluations for which the licensee had determined that evaluations were not
evaluations reviewed are listed in the Attachment to this report.
        required, to confirm that the licensees conclusions to screen out these changes were
The inspectors also reviewed samples of changes such as design changes, UFSAR
        correct and consistent with 10CFR50.59. The twenty-one screened out changes
changes, commercial grade dedication packages, equipment problem issues, and like-
        reviewed are listed in the List of Documents Reviewed.
for-like evaluations for which the licensee had determined that evaluations were not
        The inspectors also reviewed an audit of the 10CFR50.59 process and selected
required, to confirm that the licensees conclusions to screen out these changes were
        Problem Investigation Process reports (PIPs) to confirm that problems were identified at
correct and consistent with 10CFR50.59. The twenty-one screened out changes
reviewed are listed in the List of Documents Reviewed.
The inspectors also reviewed an audit of the 10CFR50.59 process and selected
Problem Investigation Process reports (PIPs) to confirm that problems were identified at


                                              2
2
    an appropriate threshold, were entered into the corrective action process, and
an appropriate threshold, were entered into the corrective action process, and
    appropriate corrective actions had been initiated.
appropriate corrective actions had been initiated.
b.   Findings
  b.
(1) Introduction: One Unresolved Item (URI) was identified in that potentially the air
Findings
    temperature inside of the units control room boards (vertical and unit boards) may reach
    (1)
    a higher than anticipated value than previously understood during design basis events.
Introduction: One Unresolved Item (URI) was identified in that potentially the air
    Description: During the review of an UFSAR change to Section 3.11.5, Loss of
temperature inside of the units control room boards (vertical and unit boards) may reach
    Ventilation, the inspectors observed the control room area temperature maximum was
a higher than anticipated value than previously understood during design basis events.  
    stated to be 120 degrees F. The section did not address control board interior
Description: During the review of an UFSAR change to Section 3.11.5, Loss of
    temperature rise nor did it discuss the maximum value that could be reached inside
Ventilation, the inspectors observed the control room area temperature maximum was
    boards for the discussed event. The inspectors realized that other events not discussed
stated to be 120 degrees F. The section did not address control board interior
    in the reviewed section could cause a loss of forced ventilation to the boards. When the
temperature rise nor did it discuss the maximum value that could be reached inside
    licensee was informed that the heat generating temperature sensitive electronics interior
boards for the discussed event. The inspectors realized that other events not discussed
    to the boards may see a higher temperature than the control room ambient temperature,
in the reviewed section could cause a loss of forced ventilation to the boards. When the
    PIP O-03-04052 was written on the issue. During normal operations, Technical
licensee was informed that the heat generating temperature sensitive electronics interior
    Specification (TS) 3.7.16 limits the control room general area temperature to 80
to the boards may see a higher temperature than the control room ambient temperature,
    degrees F.
PIP O-03-04052 was written on the issue. During normal operations, Technical
    The temperature difference between the ambient control room temperature and the
Specification (TS) 3.7.16 limits the control room general area temperature to 80
    interior temperature of the boards was not clearly documented. Forced ventilation to the
degrees F.
    boards and to the control room is postulated to be lost during such events as loss of
The temperature difference between the ambient control room temperature and the
    offsite power and seismic occurrences. There is a degraded control room ventilation
interior temperature of the boards was not clearly documented. Forced ventilation to the
    abnormal procedure. All related event and abnormal procedures do not address control
boards and to the control room is postulated to be lost during such events as loss of
    board interior temperatures nor do they have special instructions for reducing the interior
offsite power and seismic occurrences. There is a degraded control room ventilation
    temperature of the boards during the loss of forced ventilation cooling. With the loss of
abnormal procedure. All related event and abnormal procedures do not address control
    forced ventilation, a rise in temperature inside the board may occur and this rise may be
board interior temperatures nor do they have special instructions for reducing the interior
    greater than that experienced in the control room inhabited space where control room
temperature of the boards during the loss of forced ventilation cooling. With the loss of
    temperature is measured. Such a rise may be detrimental to critical electronic
forced ventilation, a rise in temperature inside the board may occur and this rise may be
    equipment operation.
greater than that experienced in the control room inhabited space where control room
    The aforementioned PIP stated that there was reasonable assurance that the equipment
temperature is measured. Such a rise may be detrimental to critical electronic
    inside of the control boards is operable during the event scenarios. This was based on
equipment operation.
    calculations that determined that the general area temperature rise after six hours would
The aforementioned PIP stated that there was reasonable assurance that the equipment
    be approximately 90 degrees F (calculation OSC-6667). The licensee stated that the
inside of the control boards is operable during the event scenarios. This was based on
    most limiting equipment in the boards has continuous duty temperature of 122 degrees
calculations that determined that the general area temperature rise after six hours would
    F, which is 32 degrees F higher than the six hour rise value. The event and abnormal
be approximately 90 degrees F (calculation OSC-6667). The licensee stated that the
    procedures are written to limit the time without forced ventilation. Further, the licencee
most limiting equipment in the boards has continuous duty temperature of 122 degrees
    indicated in PIP O-00-4643, that the time required to restore cooling following a loss of
F, which is 32 degrees F higher than the six hour rise value. The event and abnormal
    offsite power event was estimated to be less than 6 hours. PIP O-03-4052 indicated
procedures are written to limit the time without forced ventilation. Further, the licencee
    that an operability evaluation would be performed to further investigate the relationship
indicated in PIP O-00-4643, that the time required to restore cooling following a loss of
    between the temperature inside the main control boards and the control rooms on all
offsite power event was estimated to be less than 6 hours. PIP O-03-4052 indicated
    three units.
that an operability evaluation would be performed to further investigate the relationship
    The inspectors were aware that there are some passive vents and holes in the top of the
between the temperature inside the main control boards and the control rooms on all
    control boards and louvers on the side of the boards could possibly dissipate board
three units.
    interior heat buildup. Further, the inspectors were aware of procedures and equipment
The inspectors were aware that there are some passive vents and holes in the top of the
control boards and louvers on the side of the boards could possibly dissipate board  
interior heat buildup. Further, the inspectors were aware of procedures and equipment


                                              3
3
    in other locations that could be relied upon for safe shutdown purposes should the
in other locations that could be relied upon for safe shutdown purposes should the
    abandonment of the control room be required.
abandonment of the control room be required.
    However, the following issues require additional review by the licensee: an
However, the following issues require additional review by the licensee: an
    understanding of the peak temperature reached in each unique control cabinet in each
understanding of the peak temperature reached in each unique control cabinet in each
    control room space; the critical electronic components needed for plant operation during
control room space; the critical electronic components needed for plant operation during
    the postulated events; the suitability of equipment in the control boards to withstand
the postulated events; the suitability of equipment in the control boards to withstand
    environmental temperature such as records documenting the component vendors
environmental temperature such as records documenting the component vendors
    continuous duty temperatures for the considered critical parts; and, critical components
continuous duty temperatures for the considered critical parts; and, critical components
    locations relative to possible warm spots on the boards should also be understood
locations relative to possible warm spots on the boards should also be understood
    (board thermal profile relative to component location).
(board thermal profile relative to component location).
    Until the licensee can demonstrate a clear understanding of the thermal effects on
Until the licensee can demonstrate a clear understanding of the thermal effects on
    control room board components during a postulated loss of control board forced cooling
control room board components during a postulated loss of control board forced cooling
    occurrence, this issue will be identified as URI 05000269,270,287/2003003-001:
occurrence, this issue will be identified as URI 05000269,270,287/2003003-001:  
    Control Room Board Component Thermal Reliability.
Control Room Board Component Thermal Reliability.
(2) Introduction: An URI was identified concerning Oconee UFSAR Section 3.6.1.3 that was
    changed on May 17, 2001, under the old 50.59 program revision. During a review of the
    (2)
    change, the inspectors were concerned that the change may involve an unreviewed
Introduction: An URI was identified concerning Oconee UFSAR Section 3.6.1.3 that was
    safety question (USQ) under the old rule or a departure from a method of evaluation
changed on May 17, 2001, under the old 50.59 program revision. During a review of the
    under the new rule.
change, the inspectors were concerned that the change may involve an unreviewed
    Discussion: The UFSAR change was associated with high energy line break (HELB) on
safety question (USQ) under the old rule or a departure from a method of evaluation
    a main feedwater line. The escaping water/steam is assumed to disable the 4160 Volt
under the new rule.
    breakers for at least the motor driven emergency feedwater (EFW) pumps and for the
Discussion: The UFSAR change was associated with high energy line break (HELB) on
    high pressure injection HPI pumps. The change increased the time allowed for initiation
a main feedwater line. The escaping water/steam is assumed to disable the 4160 Volt
    of EFW and (HPI) after the HELB from 15 minutes to 30 minutes and from 1 hour to 8
breakers for at least the motor driven emergency feedwater (EFW) pumps and for the
    hours, respectively.
high pressure injection HPI pumps. The change increased the time allowed for initiation
    The 1998 UFSAR version used RETRAN program analysis and the lower equipment
of EFW and (HPI) after the HELB from 15 minutes to 30 minutes and from 1 hour to 8
    recovery times that kept the reactor coolant system (RCS) subcooled and capable of
hours, respectively.  
    natural circulation (minimally voided) due to the small amount of water loss. Under the
The 1998 UFSAR version used RETRAN program analysis and the lower equipment
    May 2001 revision, the licensee used RELAP 5 program and extended times for
recovery times that kept the reactor coolant system (RCS) subcooled and capable of
    equipment recovery of EFW and HPI. This results in significant voiding in the RCS, loss
natural circulation (minimally voided) due to the small amount of water loss. Under the
    of subcooling, increased number of cycles of the pressurizer safety valves, loss of
May 2001 revision, the licensee used RELAP 5 program and extended times for
    natural circulation, and reliance on the boiler/condenser mode (BCM) of decay heat
equipment recovery of EFW and HPI. This results in significant voiding in the RCS, loss
    removal for up to 8 hours without safety injection. Under BCM, the expansion and
of subcooling, increased number of cycles of the pressurizer safety valves, loss of
    collapsing of the RCS remaining volume would cause some pressure spikes within the
natural circulation, and reliance on the boiler/condenser mode (BCM) of decay heat
    RCS. This evaluation was based on licensee calculation OSC-7299, Revision 1. Page
removal for up to 8 hours without safety injection. Under BCM, the expansion and
    4 of the 10 CFR 50.59 evaluation discusses RELAP5 in that:
collapsing of the RCS remaining volume would cause some pressure spikes within the
        The analytical model utilized to evaluate these effects was changed from RETRAN
RCS. This evaluation was based on licensee calculation OSC-7299, Revision 1. Page
        to RELAP5 because of the significant RCS voiding that will occur and the
4 of the 10 CFR 50.59 evaluation discusses RELAP5 in that:
        importance of boiler condenser mode of decay heat removal. The version of
The analytical model utilized to evaluate these effects was changed from RETRAN
        RELAP5 used is similar [to] a version approved by the NRC for use by Frametone
to RELAP5 because of the significant RCS voiding that will occur and the
        Technologies in small break loss of coolant accident (SBLOCA) UFSAR analysis of
importance of boiler condenser mode of decay heat removal. The version of
        OTSG plants. Additionally, the NRC has approved this version for use by Duke
RELAP5 used is similar [to] a version approved by the NRC for use by Frametone
Technologies in small break loss of coolant accident (SBLOCA) UFSAR analysis of
OTSG plants. Additionally, the NRC has approved this version for use by Duke


                                                4
4
          Power Company in both SBLOCA and large break loss of coolant accident
Power Company in both SBLOCA and large break loss of coolant accident
          (LBLOCA) mass and energy release analysis. The additional delays in EFW and
(LBLOCA) mass and energy release analysis. The additional delays in EFW and
          HPI restoration result in a transient that is essentially a small break LOCA.
HPI restoration result in a transient that is essentially a small break LOCA.
      The inspectors were concerned that this change appears to represent an USQ, as
The inspectors were concerned that this change appears to represent an USQ, as
      defined by the previous version of 10 CFR 50.59. (The evaluation was completed under
defined by the previous version of 10 CFR 50.59. (The evaluation was completed under
      the old 10 CFR 50.59 rule on May 17, 2001, and the licensee implemented the revised
the old 10 CFR 50.59 rule on May 17, 2001, and the licensee implemented the revised
      rule on July 2, 2001). In this scenario, the pressurizer safety valves are challenged to lift
rule on July 2, 2001). In this scenario, the pressurizer safety valves are challenged to lift
      and reseat multiple times while passing steam and then water until EFW is recovered.
and reseat multiple times while passing steam and then water until EFW is recovered.  
      The licensee did not consider that the increased number of cycles of these valves would
The licensee did not consider that the increased number of cycles of these valves would
      increase the probability of a malfunction (i.e., sticking open) and create the possibility of
increase the probability of a malfunction (i.e., sticking open) and create the possibility of
      an accident of a different type (loss of coolant). With a stuck open valve and no safety
an accident of a different type (loss of coolant). With a stuck open valve and no safety
      injection, core damage would result. The licensees evaluation states that RELAP 5 has
injection, core damage would result. The licensees evaluation states that RELAP 5 has
      been approval for LOCA analysis, but it is not clear as to the acceptability of this method
been approval for LOCA analysis, but it is not clear as to the acceptability of this method
      of evaluation for HELB. Furthermore the concept of allowing the RCS to become
of evaluation for HELB. Furthermore the concept of allowing the RCS to become
      significantly voided, saturated, without natural circulation, without HPI for eight hours,
significantly voided, saturated, without natural circulation, without HPI for eight hours,
      and reliance on BCM for decay heat removal, appears to be a departure from a method
and reliance on BCM for decay heat removal, appears to be a departure from a method
      of evaluation as described in the UFSAR, which would require prior NRC approval under
of evaluation as described in the UFSAR, which would require prior NRC approval under
      the current regulation. Until the NRC completes its review of the above issue, it will be
the current regulation. Until the NRC completes its review of the above issue, it will be
      identified as URI
identified as URI
      05000269,270,287/2003003-002: HELB Accident Scenario Review.
05000269,270,287/2003003-002: HELB Accident Scenario Review.
1R04 Equipment Alignment
1R04
.1   Partial Walkdown
Equipment Alignment
  a. Inspection Scope
.1
      The inspectors conducted partial equipment alignment walkdowns to evaluate the
Partial Walkdown
      operability of selected redundant trains or backup systems while the other train or
    a.
      system was inoperable or out of service. The walkdowns included, as appropriate,
Inspection Scope
      reviews of plant procedures and other documents to determine correct system lineups
The inspectors conducted partial equipment alignment walkdowns to evaluate the
      and verification of critical components to identify any discrepancies which could affect
operability of selected redundant trains or backup systems while the other train or
      operability of the redundant train or backup system. The following systems were
system was inoperable or out of service. The walkdowns included, as appropriate,
      included in this review:
reviews of plant procedures and other documents to determine correct system lineups
      *   Unit 2 HPI trains 2A and 2B while the 2C HPI pump was out of service for preventive
and verification of critical components to identify any discrepancies which could affect
          maintenance
operability of the redundant train or backup system. The following systems were
      *   Unit 2 train A low pressure injection (LPI) while the B train of LPI was out of service
included in this review:
          for maintenance
*
      *   Units 1 and 2 primary instrument air system with the backup instrument air
Unit 2 HPI trains 2A and 2B while the 2C HPI pump was out of service for preventive
          compressor out of service for preventive maintenance
maintenance
  b. Findings
*
      No findings of significance were identified.
Unit 2 train A low pressure injection (LPI) while the B train of LPI was out of service
for maintenance
*
Units 1 and 2 primary instrument air system with the backup instrument air
compressor out of service for preventive maintenance
    b.
Findings
No findings of significance were identified.


                                                  5
5
.2     Complete System Walkdown.
.2
   a. Inspection Scope
Complete System Walkdown.  
      The inspectors conducted a detailed review of the alignment and condition of the Unit 3
   a.
      component cooling (CC) system. The inspectors utilized licensee procedures and other
Inspection Scope
      documents listed in the Attachment to verify proper system alignment.
The inspectors conducted a detailed review of the alignment and condition of the Unit 3
      The inspectors also verified electrical power requirements, labeling, hangers, support
component cooling (CC) system. The inspectors utilized licensee procedures and other
      installation, and associated support system status. The operating pump was examined
documents listed in the Attachment to verify proper system alignment.
      to ensure that any noticeable vibration was not excessive, bearings were not hot to the
The inspectors also verified electrical power requirements, labeling, hangers, support
      touch, and the pump was adequately ventilated. The walkdown also included an
installation, and associated support system status. The operating pump was examined
      evaluation of the system piping and supports against the following considerations:
to ensure that any noticeable vibration was not excessive, bearings were not hot to the
      *   Piping and pipe supports did not show evidence of water hammer
touch, and the pump was adequately ventilated. The walkdown also included an
      *   Hangers were properly sized and were within the setpoints
evaluation of the system piping and supports against the following considerations:
      *   Piping insulation was adequate and showed no evidence of prior system leaks
*
      *   Component foundations were not degraded
Piping and pipe supports did not show evidence of water hammer
      A review of PIPs and maintenance work orders was performed to verify that material
*
      condition deficiencies did not significantly affect the ability of the CC system to perform
Hangers were properly sized and were within the setpoints
      its design functions and that appropriate corrective action was being taken by the
*
      licensee.
Piping insulation was adequate and showed no evidence of prior system leaks
      The inspectors also held discussions with the system and design engineers on
*
      temporary modifications, future modifications, and operator workarounds to ensure that
Component foundations were not degraded
      the impact on the equipment functionality was properly evaluated.
A review of PIPs and maintenance work orders was performed to verify that material
     b. Findings
condition deficiencies did not significantly affect the ability of the CC system to perform
      No findings of significance were identified.
its design functions and that appropriate corrective action was being taken by the
1R05 Fire Protection
licensee.
     a.   Inspection Scope
The inspectors also held discussions with the system and design engineers on
      The inspectors conducted tours in thirteen areas of the plant to verify that combustibles
temporary modifications, future modifications, and operator workarounds to ensure that
      and ignition sources were properly controlled, and that fire detection and suppression
the impact on the equipment functionality was properly evaluated.
      capabilities were intact. The inspectors selected the areas based on a review of the
     b.  
      licensees safe shutdown analysis and the probabilistic risk assessment based
Findings
      sensitivity studies for fire related core damage sequences. Inspection of the following
No findings of significance were identified.
      areas were conducted during this inspection period:
1R05
      *   Units 1 and 2 and Unit 3 HPI Rooms (2)
Fire Protection
      *   Units 1, 2 and 3 Equipment Rooms (3)
     a.     Inspection Scope
The inspectors conducted tours in thirteen areas of the plant to verify that combustibles
and ignition sources were properly controlled, and that fire detection and suppression
capabilities were intact. The inspectors selected the areas based on a review of the
licensees safe shutdown analysis and the probabilistic risk assessment based
sensitivity studies for fire related core damage sequences. Inspection of the following
areas were conducted during this inspection period:
*
Units 1 and 2 and Unit 3 HPI Rooms (2)
*
Units 1, 2 and 3 Equipment Rooms (3)


                                                6
6
      *   Units 1, 2 and 3 LPI/RBS Rooms (5)
*
      *   Keowee Hydro Units (2)
Units 1, 2 and 3 LPI/RBS Rooms (5)
      *   Unit 2 Turbine Building Switchgear Area (1)
*
     b. Findings
Keowee Hydro Units (2)
      No findings of significance were identified.
*
1R07 Heat Sink Performance
Unit 2 Turbine Building Switchgear Area (1)
  .1   Unit 3 Low Pressure Injection System Cooler Test
     b.
   a. Inspection Scope
Findings
      The inspectors reviewed TT/3/A/0150/061, Unit 3 Low Pressure Injection System Cooler
No findings of significance were identified.
      Test, used to gather data for the LPI cooler performance evaluation. This testing was
1R07
      performed to ensure that the cooler is able to meet TS and design basis requirements.
Heat Sink Performance
      The inspection focused on compliance with the procedure requirements and appropriate
  .1
      data collection during the testing. The inspectors also reviewed design calculation
Unit 3 Low Pressure Injection System Cooler Test
      OSC - 4338 Revision 7, to ensure that the LPI heat exchanger, based on the test data,
   a.
      was capable of performing its design function per the calculation.
Inspection Scope
   b. Findings
The inspectors reviewed TT/3/A/0150/061, Unit 3 Low Pressure Injection System Cooler
      No findings of significance were identified.
Test, used to gather data for the LPI cooler performance evaluation. This testing was
.2     Unit 1 Reactor Building Cooling Units (RBCU) Performance Test
performed to ensure that the cooler is able to meet TS and design basis requirements.  
   a. Inspection Scope
The inspection focused on compliance with the procedure requirements and appropriate
      The inspectors reviewed Unit 1 RBCU Performance Test, PT/0/A/0160/006, used to
data collection during the testing. The inspectors also reviewed design calculation
      gather data for the RBCU performance evaluation. This testing was performed to verify
OSC - 4338 Revision 7, to ensure that the LPI heat exchanger, based on the test data,
      that the RBCU cooling capacity meets TS and design basis requirements. The
was capable of performing its design function per the calculation.
      inspection focused on compliance with the procedure requirements and appropriate
   b.
      data collection during the testing. The inspectors also reviewed design calculation
Findings
      OSC - 5665, Attachment 27, which calculated the RBCU capacity factors from the
No findings of significance were identified.
      obtained test data.
.2
   b. Findings
Unit 1 Reactor Building Cooling Units (RBCU) Performance Test
      No findings of significance were identified.
   a.
Inspection Scope
The inspectors reviewed Unit 1 RBCU Performance Test, PT/0/A/0160/006, used to
gather data for the RBCU performance evaluation. This testing was performed to verify
that the RBCU cooling capacity meets TS and design basis requirements. The
inspection focused on compliance with the procedure requirements and appropriate
data collection during the testing. The inspectors also reviewed design calculation  
OSC - 5665, Attachment 27, which calculated the RBCU capacity factors from the
obtained test data.
   b.
Findings
No findings of significance were identified.


                                                  7
7
1R08 Inservice Inspection (ISI) Activities
1R08 Inservice Inspection (ISI) Activities
   a. Inspection Scope
   a.
      Unit 3 Steam Generator (SG) Inspection
Inspection Scope
      The inspectors reviewed the implementation of the licensees program for monitoring the
Unit 3 Steam Generator (SG) Inspection
      performance of the U3 once-through steam generators (OTSG). The inspector
The inspectors reviewed the implementation of the licensees program for monitoring the
      observed examinations and reviewed selected inspection records for:
performance of the U3 once-through steam generators (OTSG). The inspector
      -   Eddy current examination (ET) data for eleven OTSG tubes.
observed examinations and reviewed selected inspection records for:  
      -   Tube plugging operations including quality control verification of tube locations.
-  
      -   In-situ pressure testing data used to evaluate SG tube structural and leak tight
Eddy current examination (ET) data for eleven OTSG tubes.
          integrity of thirteen SG tubes (twelve in SG A and one in SG B)
-  
      -   Certifications for ten Quality Assurance (QA) Level III Eddy Current Data Analysts
Tube plugging operations including quality control verification of tube locations.
      -   SG tube repair (plugging) lists generated as a result of the Unit 3 SG ET inspection.
-  
      The above activities and records were compared to the TS, License Amendments, and
In-situ pressure testing data used to evaluate SG tube structural and leak tight
      applicable industry established performance criteria to verify compliance. Documents
integrity of thirteen SG tubes (twelve in SG A and one in SG B)
      reviewed are listed in the Attachment to this report.
-  
   b. Findings
Certifications for ten Quality Assurance (QA) Level III Eddy Current Data Analysts
      No findings of significance were identified.
-  
1R11 Licensed Operator Requalification
SG tube repair (plugging) lists generated as a result of the Unit 3 SG ET inspection.
.1   Simulator Scenarios
The above activities and records were compared to the TS, License Amendments, and
   a. Inspection Scope
applicable industry established performance criteria to verify compliance. Documents
      The inspectors observed licensed operator simulator training on June 27, 2003. The
reviewed are listed in the Attachment to this report.
      scenario involved a dropped rod, a reactor trip, a steam generator tube leak in the 1B
   b.
      steam generator, and a main steam line break. The inspectors also observed entry into
Findings
      the emergency action levels (Unusual Event and Alert). The inspectors observed crew
No findings of significance were identified.  
      performance in terms of: communications; ability to take timely and proper actions;
1R11
      prioritizing, interpreting, and verifying alarms; correct use and implementation of
Licensed Operator Requalification
      procedures, including the alarm response procedures; timely control board operation
.1
      and manipulation, including high-risk operator actions; and oversight and direction
Simulator Scenarios
      provided by the shift supervisor, including the ability to identify and implement
   a.
      appropriate TS actions.
Inspection Scope
The inspectors observed licensed operator simulator training on June 27, 2003. The
scenario involved a dropped rod, a reactor trip, a steam generator tube leak in the 1B
steam generator, and a main steam line break. The inspectors also observed entry into
the emergency action levels (Unusual Event and Alert). The inspectors observed crew
performance in terms of: communications; ability to take timely and proper actions;
prioritizing, interpreting, and verifying alarms; correct use and implementation of
procedures, including the alarm response procedures; timely control board operation
and manipulation, including high-risk operator actions; and oversight and direction
provided by the shift supervisor, including the ability to identify and implement
appropriate TS actions.


                                                  8
8
   b. Findings
   b.
      No findings of significance were identified.
Findings
.2   Annual Operating Test Results
No findings of significance were identified.
   a. Inspection Scope
.2
      Following the completion of the annual operating examination testing cycle, which ended
Annual Operating Test Results
      on May 9, 2003, the inspectors reviewed the overall pass/fail results of the biennial
   a.
      written examination, the individual Job Performance Measure operating tests, and the
Inspection Scope
      simulator operating tests administered by the licensee during the operator licensing
Following the completion of the annual operating examination testing cycle, which ended
      requalification cycle. These results were compared to the thresholds established in
on May 9, 2003, the inspectors reviewed the overall pass/fail results of the biennial
      Manual Chapter 609 Appendix I, Operator Requalification Human Performance
written examination, the individual Job Performance Measure operating tests, and the
      Significance Determination Process.
simulator operating tests administered by the licensee during the operator licensing
   b. Findings
requalification cycle. These results were compared to the thresholds established in
      No findings of significance were identified.
Manual Chapter 609 Appendix I, Operator Requalification Human Performance
1R12 Maintenance Effectiveness
Significance Determination Process.
.1   Routine Maintenance Effectiveness Reviews
   a. Inspection Scope
   b.
      The inspectors reviewed the licensees effectiveness in performing routine maintenance
Findings
      activities. This review included an assessment of the licensees practices pertaining to
No findings of significance were identified.
      the identification, scoping, and handling of degraded equipment conditions, as well as
1R12
      common cause failure evaluations. For each item selected the inspectors performed a
Maintenance Effectiveness
      detailed review of the problem history and surrounding circumstances, evaluated the
.1  
      extent of condition reviews as required, and reviewed the generic implications of the
Routine Maintenance Effectiveness Reviews
      equipment and/or work practice problem. For those systems, structures, and
   a.
      components (SSCs) scoped in the maintenance rule per 10 CFR 50.65, the inspectors
Inspection Scope
      verified that reliability and unavailability were properly monitored and that 10 CFR 50.65
The inspectors reviewed the licensees effectiveness in performing routine maintenance
      (a)(1) and (a)(2) classifications were justified in light of the reviewed degraded
activities. This review included an assessment of the licensees practices pertaining to
      equipment condition. The inspectors reviewed the following item:
the identification, scoping, and handling of degraded equipment conditions, as well as
      PIP O-03-02888, Turbine Driven Emergency Feedwater Pump Steam Nozzle Bolt
common cause failure evaluations. For each item selected the inspectors performed a
      Failure Issue
detailed review of the problem history and surrounding circumstances, evaluated the
   b. Findings
extent of condition reviews as required, and reviewed the generic implications of the
      No findings of significance were identified.
equipment and/or work practice problem. For those systems, structures, and
components (SSCs) scoped in the maintenance rule per 10 CFR 50.65, the inspectors
verified that reliability and unavailability were properly monitored and that 10 CFR 50.65
(a)(1) and (a)(2) classifications were justified in light of the reviewed degraded
equipment condition. The inspectors reviewed the following item:
PIP O-03-02888, Turbine Driven Emergency Feedwater Pump Steam Nozzle Bolt
Failure Issue
   b.
Findings
No findings of significance were identified.


                                                  9
9
.2   Effectiveness of Standby Shutdown Diesel Preventive Maintenance and Problem
.2
      Identification
Effectiveness of Standby Shutdown Diesel Preventive Maintenance and Problem
   a. Inspection Scope
Identification
      The inspectors observed the 10-year overhaul of the Standby Shutdown Facility (SSF)
   a.
      diesel, and selected for further review, those problems which were identified by outside
Inspection Scope
      contractors. Specifically, the inspectors reviewed problems being identified by Engine
The inspectors observed the 10-year overhaul of the Standby Shutdown Facility (SSF)
      Service, Inc. contractors who were contracted by the licensee to provide technical
diesel, and selected for further review, those problems which were identified by outside
      oversight for the 10-year overhaul of the SSF diesel engines and to assist with the
contractors. Specifically, the inspectors reviewed problems being identified by Engine
      maintenance activities. For this inspection activity, the inspectors reviewed the daily
Service, Inc. contractors who were contracted by the licensee to provide technical
      field service reports provided by the contractors to the licensee to evaluate the
oversight for the 10-year overhaul of the SSF diesel engines and to assist with the
      adequacy of previous maintenance activities and to verify that problems identified by the
maintenance activities. For this inspection activity, the inspectors reviewed the daily
      contractors were being appropriately documented in the licensees corrective action
field service reports provided by the contractors to the licensee to evaluate the
      program.
adequacy of previous maintenance activities and to verify that problems identified by the
   b. Findings
contractors were being appropriately documented in the licensees corrective action
      Introduction: Two separate issues were identified as a result of this inspection:
program.
      (1) A Green non-cited violation (NCV) was identified by the inspectors for failure to
   b.
          promptly identify degraded SSF diesel cooling water seals in the PIP program.
Findings
      (2) An URI was identified, in that the licensee failed to implement the 6-year
Introduction: Two separate issues were identified as a result of this inspection:
          recommended diesel manufacturer (EMD) preventive maintenance grommet
(1) A Green non-cited violation (NCV) was identified by the inspectors for failure to
          replacements. Consequently, at 10 years some of the grommets were found to be
promptly identify degraded SSF diesel cooling water seals in the PIP program.
          at or near failure. Failure of the grommets could have led to diesel coolant leaks
(2) An URI was identified, in that the licensee failed to implement the 6-year
          and loss of cooling to the diesel. This issue will remain unresolved pending
recommended diesel manufacturer (EMD) preventive maintenance grommet
          completion of a Phase 3 risk review.
replacements. Consequently, at 10 years some of the grommets were found to be
      Description: During the June 2002, SSF diesel overhaul, the inspectors discussed
at or near failure. Failure of the grommets could have led to diesel coolant leaks
      diesel equipment problems with the maintenance contractors from Engine Systems, Inc.
and loss of cooling to the diesel. This issue will remain unresolved pending
      (ESI) who were providing technical oversight for the SSF diesel overhaul. The day shift
completion of a Phase 3 risk review.
      ESI contractor noted that the SSF diesel coolant grommets, located on the cylinder
Description: During the June 2002, SSF diesel overhaul, the inspectors discussed
      heads (power packs), had been found degraded. He informed the inspectors that this
diesel equipment problems with the maintenance contractors from Engine Systems, Inc.
      adverse condition would be provided to the licensee in a daily field service report. The
(ESI) who were providing technical oversight for the SSF diesel overhaul. The day shift
      inspectors subsequently discussed the degraded grommet condition with maintenance
ESI contractor noted that the SSF diesel coolant grommets, located on the cylinder
      management to ensure that they were aware of the potential problem. The June 18,
heads (power packs), had been found degraded. He informed the inspectors that this
      2002, ESI daily field service report documented that Cylinder 7 on Engine B, had
adverse condition would be provided to the licensee in a daily field service report. The
      deformed grommets on the cylinder head, unable to determine if the deformities were
inspectors subsequently discussed the degraded grommet condition with maintenance
      from overheating or from installation damage. The June 19, 2002, ESI daily field
management to ensure that they were aware of the potential problem. The June 18,
      service report documented that Cylinder 8 on Engine A, had deformed head
2002, ESI daily field service report documented that Cylinder 7 on Engine B, had
      grommets.
deformed grommets on the cylinder head, unable to determine if the deformities were
      On June 27, 2002, prior to returning the diesel to service and after noting that a PIP
from overheating or from installation damage. The June 19, 2002, ESI daily field
      report had not been initiated, the inspectors discussed the deformed grommet issue with
service report documented that Cylinder 8 on Engine A, had deformed head
      licensee management. On June 28, 2002, PIP O-02-03526 was initiated to capture the
grommets.
      potential degraded grommet condition.
On June 27, 2002, prior to returning the diesel to service and after noting that a PIP
report had not been initiated, the inspectors discussed the deformed grommet issue with
licensee management. On June 28, 2002, PIP O-02-03526 was initiated to capture the
potential degraded grommet condition.


                                          10
10
Subsequent discussions with engineering noted that some of the deformed grommets
Subsequent discussions with engineering noted that some of the deformed grommets
were going to be sent off for analysis. At this time, the inspectors also noted that the
were going to be sent off for analysis. At this time, the inspectors also noted that the
grommets from Cylinder 7 on Engine B and Cylinder 8 on Engine A had not been
grommets from Cylinder 7 on Engine B and Cylinder 8 on Engine A had not been
segregated from the grommets from the other 26 cylinders. It was also noted that the
segregated from the grommets from the other 26 cylinders. It was also noted that the
licensee could not account for all of the replaced grommets, in that only 282 of the 336
licensee could not account for all of the replaced grommets, in that only 282 of the 336
replaced grommets could be located.
replaced grommets could be located.  
During various discussions regarding the grommets, the licensee noted that the diesel
During various discussions regarding the grommets, the licensee noted that the diesel
manufacturer (EMD) had recommended a 6-year replacement interval for these
manufacturer (EMD) had recommended a 6-year replacement interval for these
grommets. However, the grommets were being replaced on a 10-year interval and the
grommets. However, the grommets were being replaced on a 10-year interval and the
EMD owners group was discussing the possibility of EMD changing the replacement
EMD owners group was discussing the possibility of EMD changing the replacement
interval to 12 years.
interval to 12 years.
In October 2002, the remaining 282 grommets were sent off to ESI for analysis. On
In October 2002, the remaining 282 grommets were sent off to ESI for analysis. On
May 8, 2003, the results of the ESI analysis were received by the licensee. The report
May 8, 2003, the results of the ESI analysis were received by the licensee. The report
noted that Diesel engines used in standby service see thermal cycling which
noted that Diesel engines used in standby service see thermal cycling which
contributes to the hardening of these grommets. Therefore, the recommended
contributes to the hardening of these grommets. Therefore, the recommended
replacement interval is on a 6 year calendar basis. ESIs analysis concluded the
replacement interval is on a 6 year calendar basis. ESIs analysis concluded the
following: 31 grommets were approaching the end of life; 6 grommets had been torn
following: 31 grommets were approaching the end of life; 6 grommets had been torn
during removal and that a new grommet cannot be readily torn by hand, the ability to
during removal and that a new grommet cannot be readily torn by hand, the ability to
Line 615: Line 794:
their sealing function, and the state of brittleness and separation they exhibit indicates
their sealing function, and the state of brittleness and separation they exhibit indicates
they have exceeded their useful life; and last 19 grommets were distorted into a D
they have exceeded their useful life; and last 19 grommets were distorted into a D
shape, considered to be classic examples of cylinder combustion leaks and with no
shape, considered to be classic examples of cylinder combustion leaks and with no
reported leaks, it must be assumed they performed their sealing function; however,
reported leaks, it must be assumed they performed their sealing function; however,
these grommets have exceeded their useful life. EMD went on to state that Continued
these grommets have exceeded their useful life. EMD went on to state that Continued
operation with grommets exposed to combustion gases will lead to failure and coolant
operation with grommets exposed to combustion gases will lead to failure and coolant
leaks.
leaks.
EMD concluded the analysis with the following: Many of the components examined in
EMD concluded the analysis with the following: Many of the components examined in
this investigation were at or near failure, and although no coolant leaks were reported,
this investigation were at or near failure, and although no coolant leaks were reported,
combustion leaks were definitely occurring in some cylinders. Coolant leaks were likely
combustion leaks were definitely occurring in some cylinders. Coolant leaks were likely
to follow, as those cylinders grommets exposed to combustion gases would have
to follow, as those cylinders grommets exposed to combustion gases would have
continued to decay until their sealing ability was exhausted. EMD also stated that
continued to decay until their sealing ability was exhausted. EMD also stated that
Diesel engines in standby service experience more severe thermal cycling at each
Diesel engines in standby service experience more severe thermal cycling at each
surveillance run as compared to engines in continuous duty. This thermal cycling
surveillance run as compared to engines in continuous duty. This thermal cycling
promotes age-hardening in these seals, and the recommended 6-year maintenance
promotes age-hardening in these seals, and the recommended 6-year maintenance
interval is a preventive maintenance practice that must be adhered to for continued
interval is a preventive maintenance practice that must be adhered to for continued
Line 634: Line 813:
was considered to be greater than minor based on the fact that subsequent analysis of
was considered to be greater than minor based on the fact that subsequent analysis of
the grommets noted significant degradation and this analysis would likely not have been
the grommets noted significant degradation and this analysis would likely not have been
performed without initiation of the PIP. Therefore, if the cause of the degradation was
performed without initiation of the PIP. Therefore, if the cause of the degradation was


                                                11
11
    left uncorrected, the mitigation systems objective of ensuring the continued reliability of
left uncorrected, the mitigation systems objective of ensuring the continued reliability of
    equipment needed to respond to initiating events would be affected. In addition,
equipment needed to respond to initiating events would be affected. In addition,
    continued degradation of the grommets would become a more significant safety
continued degradation of the grommets would become a more significant safety
    concern. This issue was considered to be of low safety significance (Green) because
concern. This issue was considered to be of low safety significance (Green) because
    the grommets were replaced during the SSF diesel overhaul before they failed in
the grommets were replaced during the SSF diesel overhaul before they failed in
    service.
service.
    The issue of not performing the recommended grommet replacements was considered
The issue of not performing the recommended grommet replacements was considered
    to be more than minor in that the degraded grommets affected the equipment reliability
to be more than minor in that the degraded grommets affected the equipment reliability
    of a mitigation system (i.e., the SSF diesel). The finding was first evaluated in the
of a mitigation system (i.e., the SSF diesel). The finding was first evaluated in the
    Phase 1 SDP based on the degraded reliability of a mitigating system under the Reactor
Phase 1 SDP based on the degraded reliability of a mitigating system under the Reactor
    Safety Cornerstone. Based on the manufacturers conclusion that the grommets had
Safety Cornerstone. Based on the manufacturers conclusion that the grommets had
    exceeded their useful life and that continued operation with grommets exposed to
exceeded their useful life and that continued operation with grommets exposed to
    combustion gases would lead to failure and coolant leaks, it was assumed that the
combustion gases would lead to failure and coolant leaks, it was assumed that the
    finding represented an actual loss of safety function of the SSF diesel, as the loss of
finding represented an actual loss of safety function of the SSF diesel, as the loss of
    coolant could preclude operation of the diesel for its 72 hour mission time. Since this
coolant could preclude operation of the diesel for its 72 hour mission time. Since this
    system was designated as a risk significant system per 10 CFR 50.65, a Phase 2
system was designated as a risk significant system per 10 CFR 50.65, a Phase 2
    analysis was performed. The Phase 2 analysis indicated that the issue could be greater
analysis was performed. The Phase 2 analysis indicated that the issue could be greater
    than Green; therefore, a Phase 3 analysis was required. Pending completion of the
than Green; therefore, a Phase 3 analysis was required. Pending completion of the
    Phase 3 analysis, the issue of not implementing the manufacturers recommendations
Phase 3 analysis, the issue of not implementing the manufacturers recommendations
    for replacement of the SSF diesel coolant grommets will be identified as URI
for replacement of the SSF diesel coolant grommets will be identified as URI
    05000269,270,287/2003003-03: Failure to Implement Manufacturers Recommendations
05000269,270,287/2003003-03: Failure to Implement Manufacturers Recommendations
    for Replacement of SSF Diesel Coolant Grommets. This issue is in the licensees
for Replacement of SSF Diesel Coolant Grommets. This issue is in the licensees
    corrective action program as PIP O-02-03526.
corrective action program as PIP O-02-03526.
    Enforcement
Enforcement
    10 CFR 50, Appendix B, Criterion XVI, requires that measures shall be established to
10 CFR 50, Appendix B, Criterion XVI, requires that measures shall be established to
    assure that conditions adverse to quality, such as...deficiencies, deviations, defective
assure that conditions adverse to quality, such as...deficiencies, deviations, defective
    material and equipment, and non-conformances are promptly identified. The licensees
material and equipment, and non-conformances are promptly identified. The licensees
    quality assurance (QA) program implements this requirement through Nuclear Station
quality assurance (QA) program implements this requirement through Nuclear Station
    Directive 208, Problem Investigation Process, Revision 22. Section 208.6, Problem
Directive 208, Problem Investigation Process, Revision 22. Section 208.6, Problem
    Identification, states that a PIP should be initiated within 24 hours of recognition of the
Identification, states that a PIP should be initiated within 24 hours of recognition of the
    issue. Contrary to 10 CFR 50 Appendix B, Criterion XVI, following the June 19, 2002,
issue. Contrary to 10 CFR 50 Appendix B, Criterion XVI, following the June 19, 2002,
    identification of the degraded grommets which could be the result of improper
identification of the degraded grommets which could be the result of improper
    installation, a PIP was not initiated until June 28, 2002, which was after all of the SSF
installation, a PIP was not initiated until June 28, 2002, which was after all of the SSF
    diesel grommets had been replaced. This inadequate corrective action issue is being
diesel grommets had been replaced. This inadequate corrective action issue is being
    treated as an NCV, consistent with Section VI.A.1 of the enforcement policy and is
treated as an NCV, consistent with Section VI.A.1 of the enforcement policy and is
    identified as NCV 05000269,270,287/2003003-04: Failure to Identify the SSF Degraded
identified as NCV 05000269,270,287/2003003-04: Failure to Identify the SSF Degraded
    Grommets as a Deficient Condition in the PIP Corrective Action Program. This issue is
Grommets as a Deficient Condition in the PIP Corrective Action Program. This issue is
    in the licensees corrective action program as PIP O-02-03526.
in the licensees corrective action program as PIP O-02-03526.
1R13 Maintenance Risk Assessment and Emergent Work Evaluations
1R13
a. Inspection Scope
Maintenance Risk Assessment and Emergent Work Evaluations
    The inspectors evaluated, as appropriate for the selected SSCs listed below: (1) the
  a.
    effectiveness of the risk assessments performed before maintenance activities were
Inspection Scope
    conducted; (2) the management of risk; (3) that, upon identification of an unforseen
The inspectors evaluated, as appropriate for the selected SSCs listed below: (1) the
effectiveness of the risk assessments performed before maintenance activities were
conducted; (2) the management of risk; (3) that, upon identification of an unforseen


                                              12
12
    situation, necessary steps were taken to plan and control the resulting emergent work
situation, necessary steps were taken to plan and control the resulting emergent work
    activities; and (4) that maintenance risk assessments and emergent work problems
activities; and (4) that maintenance risk assessments and emergent work problems
    were adequately identified and resolved.
were adequately identified and resolved.
    *   PIP O-03-3584, Unexpected Closure of 1HP-5 Letdown Isolation Valve, caused by
*
        failure of an improperly installed control air solenoid
PIP O-03-3584, Unexpected Closure of 1HP-5 Letdown Isolation Valve, caused by
    *   IP/0/A/2005/003, Keowee Hydro Station Westinghouse Voltage Regulator Test,
failure of an improperly installed control air solenoid
        performed as part of troubleshooting for failed voltage regulator
*
    *   PIP O-03-2925, Increased HPI Motor Cable Insulation Leakage
IP/0/A/2005/003, Keowee Hydro Station Westinghouse Voltage Regulator Test,
    *   Preventive Maintenance on Unit 2 Electro Hydraulic Control (EHC) System per Work
performed as part of troubleshooting for failed voltage regulator
        Orders 98592430 and 98592429
*
    *   PIP O-03-3800, Unit 3 RC-4 Power Operated Relief Valve (PORV) Block Valve
PIP O-03-2925, Increased HPI Motor Cable Insulation Leakage
        Leakage and Repair
*
    *   PIP O-03-02381, 3MS -155 (Main Steam Line B Atmospheric Vent) could not be
Preventive Maintenance on Unit 2 Electro Hydraulic Control (EHC) System per Work
        opened when attempting to depressurize the steam generator
Orders 98592430 and 98592429
    *   PIP O-03-04140, Identification of Risk Assessment Error for Previous Repair of
*
        3RC-4. Credit was inappropriately given for availability of the steam generators
PIP O-03-3800, Unit 3 RC-4 Power Operated Relief Valve (PORV) Block Valve
        although the RCS loops were not filled.
Leakage and Repair
  b. Findings
*
    No findings of significance were identified.
PIP O-03-02381, 3MS -155 (Main Steam Line B Atmospheric Vent) could not be
1R14 Personnel Performance During Non-routine Plant Evolutions
opened when attempting to depressurize the steam generator
a. Inspection Scope
*
    The inspectors reviewed, the operating crews performance during selected non-routine
PIP O-03-04140, Identification of Risk Assessment Error for Previous Repair of
    events and/or transient operations to determine if the response was appropriate to the
3RC-4. Credit was inappropriately given for availability of the steam generators
    event. As appropriate, the inspectors: (1) reviewed operator logs, plant computer data,
although the RCS loops were not filled.  
    or strip charts to determine what occurred and how the operators responded;
    b.
    (2) determined if operator responses were in accordance with the response required by
Findings
    procedures and training; (3) evaluated the occurrence and subsequent personnel
No findings of significance were identified.
    response using the SDP; and (4) confirmed that personnel performance deficiencies
1R14
    were captured in the licensees corrective action program. The non-routine evolution
Personnel Performance During Non-routine Plant Evolutions
    reviewed during this inspection period included the following:
  a.
    *   Loss of 700 Gallons of RCS in Unit 3 Due to Over-pressurization of LPI Suction (PIP
Inspection Scope
        O-03-02362)
The inspectors reviewed, the operating crews performance during selected non-routine
    *   Unit 1 Dropped Rod and Subsequent Recovery
events and/or transient operations to determine if the response was appropriate to the
    *   Failure of the Unit 1 Channel B Engineered Safeguards (ES) Power Supply
event. As appropriate, the inspectors: (1) reviewed operator logs, plant computer data,
or strip charts to determine what occurred and how the operators responded;
(2) determined if operator responses were in accordance with the response required by
procedures and training; (3) evaluated the occurrence and subsequent personnel
response using the SDP; and (4) confirmed that personnel performance deficiencies
were captured in the licensees corrective action program. The non-routine evolution
reviewed during this inspection period included the following:
*
Loss of 700 Gallons of RCS in Unit 3 Due to Over-pressurization of LPI Suction (PIP
O-03-02362)
*
Unit 1 Dropped Rod and Subsequent Recovery
*
Failure of the Unit 1 Channel B Engineered Safeguards (ES) Power Supply


                                                13
13
b.   Findings
  b.
(1) Introduction: A Green NCV was identified by the inspectors for failure to maintain
Findings
    sufficient records [logs] to furnish evidence of activities affecting quality [TS Limiting
    (1)
    Conditions In Operations (LCOs)].
Introduction:   A Green NCV was identified by the inspectors for failure to maintain
    Description: On June 22, 2003, the Unit 1 ES channel B power supply failed. This
sufficient records [logs] to furnish evidence of activities affecting quality [TS Limiting
    failure, caused a loss of power to the Engineered Safeguards Protection System (ESPS)
Conditions In Operations (LCOs)].  
    Digital Automatic Logic Channels 2, 4, 6, and 8. Subsequently, the inspectors reviewed
Description: On June 22, 2003, the Unit 1 ES channel B power supply failed. This
    the licensees operator logs and TS tracking systems. The inspectors noted that the
failure, caused a loss of power to the Engineered Safeguards Protection System (ESPS)
    operator logs provided insufficient data to reconstruct the activities related to the ES
Digital Automatic Logic Channels 2, 4, 6, and 8. Subsequently, the inspectors reviewed
    power supply failure. The inspectors noted that the documented time for declaring the
the licensees operator logs and TS tracking systems. The inspectors noted that the
    components related to ES channels 2, 4, 6, and 8 per TS 3.3.7, had been improperly
operator logs provided insufficient data to reconstruct the activities related to the ES
    changed and backdated from 9:55 a.m. to 9:15 a.m. In addition, the time of discovery
power supply failure. The inspectors noted that the documented time for declaring the
    of the failed power supply was backdated to 8:15 a.m., although the ES channel B
components related to ES channels 2, 4, 6, and 8 per TS 3.3.7, had been improperly
    power supply was functioning properly at that time. The logs did not provide any
changed and backdated from 9:55 a.m. to 9:15 a.m. In addition, the time of discovery
    justification for this change. Also, the inspectors noted that the logs indicated the
of the failed power supply was backdated to 8:15 a.m., although the ES channel B
    control room operators were informed of the loss of power to the ES digital channels at
power supply was functioning properly at that time. The logs did not provide any
    8:51 a.m.; however, the TS tracking documents noted that the ES digital channels
justification for this change. Also, the inspectors noted that the logs indicated the
    became inoperable at 8:55 a.m. The various times were considered to be important
control room operators were informed of the loss of power to the ES digital channels at
    because they provided evidence for activities associated with meeting the 1 hour action
8:51 a.m.; however, the TS tracking documents noted that the ES digital channels
    statement of TS 3.3.7 for placing the associated components in their ES positions or
became inoperable at 8:55 a.m. The various times were considered to be important
    declaring the components inoperable.
because they provided evidence for activities associated with meeting the 1 hour action
    Analysis: The ESPS automatic initiation of ES functions to mitigate accident conditions
statement of TS 3.3.7 for placing the associated components in their ES positions or
    is assumed in the accident analysis and is required to ensure that consequences of
declaring the components inoperable.
    analyzed events do not exceed the accident analysis predictions. The failure to
Analysis: The ESPS automatic initiation of ES functions to mitigate accident conditions
    adequately document TS LCO entry and action times for the failed automatic ES
is assumed in the accident analysis and is required to ensure that consequences of
    actuation circuitry was considered to be more than minor because it impacted the
analyzed events do not exceed the accident analysis predictions. The failure to
    operators ability to accurately implement the TS LCO action statements, and if left
adequately document TS LCO entry and action times for the failed automatic ES
    uncorrected, this type of improper documentation could become a more significant
actuation circuitry was considered to be more than minor because it impacted the
    safety concern. The finding was considered to be of very low safety significance
operators ability to accurately implement the TS LCO action statements, and if left
    (Green) based on the fact that the ES power supply was returned to service before any
uncorrected, this type of improper documentation could become a more significant
    LCO condition would have required the unit to be in Mode 3. This observation was
safety concern. The finding was considered to be of very low safety significance
    based on the inspectors review of the associated completed surveillances and use of
(Green) based on the fact that the ES power supply was returned to service before any
    computer alarm summaries as a basis for the initial failure time.
LCO condition would have required the unit to be in Mode 3. This observation was
    Enforcement: TS 5.4.1 requires that written procedures be established, implemented,
based on the inspectors review of the associated completed surveillances and use of
    and maintained covering activities related to procedures recommended in Regulatory
computer alarm summaries as a basis for the initial failure time.
    Guide 1.33 Rev. 2, Appendix A, 1978. Regulatory Guide 1.33, Section 1(g),
Enforcement: TS 5.4.1 requires that written procedures be established, implemented,
    Administrative Procedures, requires log entries. 10 CFR 50, Appendix B, Criterion XVII,
and maintained covering activities related to procedures recommended in Regulatory
    Quality Assurance Records, requires that sufficient records shall be maintained to
Guide 1.33 Rev. 2, Appendix A, 1978. Regulatory Guide 1.33, Section 1(g),
    furnish evidence of activities affecting quality. Contrary to the above, sufficient
Administrative Procedures, requires log entries. 10 CFR 50, Appendix B, Criterion XVII,
    logkeeping and TS tracking records were not sufficiently maintained to furnish evidence
Quality Assurance Records, requires that sufficient records shall be maintained to
    of activities related to TS LCO action statements. Because the finding is of very low
furnish evidence of activities affecting quality. Contrary to the above, sufficient
    safety significance and has been entered into the corrective action program as PIP O-
logkeeping and TS tracking records were not sufficiently maintained to furnish evidence
    03-04408, this violation is being treated as NCV 05000269/2003003-05: Failure to
of activities related to TS LCO action statements. Because the finding is of very low
    Maintain Sufficient Records (logs) to Furnish Evidence of Activities Affecting Quality (TS
safety significance and has been entered into the corrective action program as PIP O-
    LCOs).
03-04408, this violation is being treated as NCV 05000269/2003003-05: Failure to
Maintain Sufficient Records (logs) to Furnish Evidence of Activities Affecting Quality (TS
LCOs).  


                                              14
14
(2) Introduction: A Green NCV of TS 3.3.7 Condition A , Engineered Safeguards Protection
    (2)
    System (ESPS) Digital Automatic Actuation Logic Channels, was identified by the
Introduction: A Green NCV of TS 3.3.7 Condition A , Engineered Safeguards Protection
    inspectors when it was discovered that the licensee failed to declare a number of ES
System (ESPS) Digital Automatic Actuation Logic Channels, was identified by the
    configured system components inoperable following the loss of ES digital channels 2, 4,
inspectors when it was discovered that the licensee failed to declare a number of ES
    6, and 8 as required.
configured system components inoperable following the loss of ES digital channels 2, 4,
    Description: As indicated in (1) above, the June 22, 2003, power supply failure of Unit 1
6, and 8 as required.  
    ES Analog Channel B resulted in the subsequent loss of Unit 1 ES Digital Actuation
Description: As indicated in (1) above, the June 22, 2003, power supply failure of Unit 1
    Channels 2, 4, 6, and 8. Upon declaring one or more ES digital automatic actuation
ES Analog Channel B resulted in the subsequent loss of Unit 1 ES Digital Actuation
    logic channels inoperable, TS LCO 3.3.7 Condition A .1, requires that ES configured
Channels 2, 4, 6, and 8. Upon declaring one or more ES digital automatic actuation
    components associated with that channel be placed in their ES configuration, or
logic channels inoperable, TS LCO 3.3.7 Condition A .1, requires that ES configured
    Condition A.2 requires that the components associated with that channel be declared
components associated with that channel be placed in their ES configuration, or
    inoperable. The inspectors determined that the licensee failed to either place the
Condition A.2 requires that the components associated with that channel be declared
    affected components in their ES configuration or declare them inoperable within one
inoperable. The inspectors determined that the licensee failed to either place the
    hour as required by the TS. Since placing the affected components in their ES
affected components in their ES configuration or declare them inoperable within one
    configuration would in this case violate unit safety or operational considerations, the
hour as required by the TS. Since placing the affected components in their ES
    licensee was required to declare the components inoperable within one hour and enter
configuration would in this case violate unit safety or operational considerations, the
    the associated component TS LCO. Specifically, the licensee failed to enter TS 3.3.17
licensee was required to declare the components inoperable within one hour and enter
    Condition A, one channel of the emergency power switching logic (EPSL) automatic
the associated component TS LCO. Specifically, the licensee failed to enter TS 3.3.17
    transfer function inoperable [channel B from ES channel 2], TS 3.3.21 Condition A, one
Condition A, one channel of the emergency power switching logic (EPSL) automatic
    channel of the EPSL Keowee Hydro Unit (KHU) emergency start function inoperable
transfer function inoperable [channel B from ES channel 2], TS 3.3.21 Condition A, one
    [channel B from ES channel 2], and TS 3.7.7 Condition A, one required low pressure
channel of the EPSL Keowee Hydro Unit (KHU) emergency start function inoperable
    service water (LPSW) pump inoperable [LPSW pump B from ES channel 4].
[channel B from ES channel 2], and TS 3.7.7 Condition A, one required low pressure
    Analysis: The ESPS automatic initiation of ES functions to mitigate accident conditions
service water (LPSW) pump inoperable [LPSW pump B from ES channel 4].
    is assumed in the accident analysis and is required to ensure that consequences of
Analysis: The ESPS automatic initiation of ES functions to mitigate accident conditions
    analyzed events do not exceed the accident analysis predictions. Consequently, this
is assumed in the accident analysis and is required to ensure that consequences of
    issue is more than minor, in that by not recognizing the importance of the lost automatic
analyzed events do not exceed the accident analysis predictions. Consequently, this
    ES initiation function and taking the compensatory actions of TS 3.3.7, the mitigating
issue is more than minor, in that by not recognizing the importance of the lost automatic
    systems cornerstone objective was affected. However, this issue was determined to be
ES initiation function and taking the compensatory actions of TS 3.3.7, the mitigating
    of very low safety significance (Green), based on the fact that there was no loss of
systems cornerstone objective was affected. However, this issue was determined to be
    function of the LPSW system or the KHUs resulting from the loss of ESPS Digital
of very low safety significance (Green), based on the fact that there was no loss of
    Automatic Actuation Logic Channels 2, 4, 6, and 8. Additionally, the ES power supplies
function of the LPSW system or the KHUs resulting from the loss of ESPS Digital
    were restored and digital channels returned to service prior to exceeding any TS allowed
Automatic Actuation Logic Channels 2, 4, 6, and 8. Additionally, the ES power supplies
    outage times for the affected components.
were restored and digital channels returned to service prior to exceeding any TS allowed
    Enforcement: TS 3.3.7 Condition A .1 requires that ES configured components
outage times for the affected components.
    associated with an inoperable ESPS Digital Automatic Actuation Logic Channel be
Enforcement: TS 3.3.7 Condition A .1 requires that ES configured components
    placed in their ES configuration, or TS 3.3.7 Condition A.2 requires that the components
associated with an inoperable ESPS Digital Automatic Actuation Logic Channel be
    associated with the inoperable channel be declared inoperable. Contrary to the above,
placed in their ES configuration, or TS 3.3.7 Condition A.2 requires that the components
    the licensee failed to place all effected ES components in their ES configuration or
associated with the inoperable channel be declared inoperable. Contrary to the above,
    declare the associated components inoperable following the loss of ES digital channels
the licensee failed to place all effected ES components in their ES configuration or
    2, 4, 6, and 8. Because this finding is of very low safety significance and has been
declare the associated components inoperable following the loss of ES digital channels
    entered into the corrective action program as PIP O-03-04408, this violation is being
2, 4, 6, and 8. Because this finding is of very low safety significance and has been
    treated as a NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy. It will
entered into the corrective action program as PIP O-03-04408, this violation is being
    be identified as NCV 05000269/2003003-06: Failure to Declare ES Configured
treated as a NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy. It will
    Components Inoperable per TS.
be identified as NCV 05000269/2003003-06: Failure to Declare ES Configured
Components Inoperable per TS.


                                                15
15
1R15 Operability Evaluations
1R15
      Quarterly Operability Evaluations
Operability Evaluations
     a. Inspection Scope
Quarterly Operability Evaluations
      The inspectors reviewed selected operability evaluations affecting risk significant
     a.
      mitigating systems, to assess, as appropriate: (1) the technical adequacy of the
Inspection Scope
      evaluations; (2) whether continued system operability was warranted; (3) whether other
The inspectors reviewed selected operability evaluations affecting risk significant
      existing degraded conditions were considered; (4) if compensatory measures were
mitigating systems, to assess, as appropriate: (1) the technical adequacy of the
      involved, whether the compensatory measures were in place, would work as intended,
evaluations; (2) whether continued system operability was warranted; (3) whether other
      and were appropriately controlled; and (5) where continued operability was considered
existing degraded conditions were considered; (4) if compensatory measures were
      unjustified, the impact on TS LCO. The inspectors reviewed the following items for
involved, whether the compensatory measures were in place, would work as intended,
      operability evaluations:
and were appropriately controlled; and (5) where continued operability was considered
      *   PIP O-03-02132, Unit 2 Installed Control Rod Drive Mechanism (CRDM) Split Ring
unjustified, the impact on TS LCO. The inspectors reviewed the following items for
          Flange Assembly Does Not Meet ASME Requirements
operability evaluations:
      *   PIP O-03-03042 Increased Containment Sump Leakage in Unit 1 From RCS and
*
          LPSW Leakage
PIP O-03-02132, Unit 2 Installed Control Rod Drive Mechanism (CRDM) Split Ring
      *   PIP O-03-02226, 2B and 1C HPI Motor Vibration Increase Following New Pump
Flange Assembly Does Not Meet ASME Requirements
          Installations
*
      *   PIP O-03-3183, Increased Leakage From the 1B1 RCP Seal
PIP O-03-03042 Increased Containment Sump Leakage in Unit 1 From RCS and
      *   PIP O-03-02492, Unit 1 RCS Leakage From Incore Instrument Tank
LPSW Leakage
      *   PIP O-03-3036, The 1A LPI Motor Space Heaters Have Not Functioned Since June
*
          2001
PIP O-03-02226, 2B and 1C HPI Motor Vibration Increase Following New Pump
      *   PIP O-03-02569, Evidence of Borated Water Leakage Down Inside Primary Shield
Installations
          Walls Below the Unit 3 Reactor Vessel
*
      *   PIP O-03-02268, Indications of Increased RCS Leakage in Unit 1
PIP O-03-3183, Increased Leakage From the 1B1 RCP Seal
     b. Findings
*
      No findings of significance were identified.
PIP O-03-02492, Unit 1 RCS Leakage From Incore Instrument Tank
1R17 Permanent Plant Modifications
*
.1     Feedwater Whip Restraint Modification
PIP O-03-3036, The 1A LPI Motor Space Heaters Have Not Functioned Since June
   a. Inspection Scope
2001
      The inspectors reviewed minor modification (ONOE) -17539, Modify Two Pipe Whip
*
      Restraints on Unit 3 Main Feedwater Piping, to verify that the feedwater whip restraints
PIP O-03-02569, Evidence of Borated Water Leakage Down Inside Primary Shield
Walls Below the Unit 3 Reactor Vessel
*
PIP O-03-02268, Indications of Increased RCS Leakage in Unit 1
     b.
Findings
No findings of significance were identified.
1R17
Permanent Plant Modifications
.1
Feedwater Whip Restraint Modification
   a.
Inspection Scope
The inspectors reviewed minor modification (ONOE) -17539, Modify Two Pipe Whip
Restraints on Unit 3 Main Feedwater Piping, to verify that the feedwater whip restraints  


                                              16
16
      had been properly adjusted as per the design drawings following replacement of the
had been properly adjusted as per the design drawings following replacement of the
      bolting material and clevises.
bolting material and clevises.
      The inspectors observed work in progress during the removal and replacement of the
The inspectors observed work in progress during the removal and replacement of the
      whip restraints and reviewed the work documentation for setting the whip restraints
whip restraints and reviewed the work documentation for setting the whip restraints
      following return to normal operating temperatures of the feedwater piping.
following return to normal operating temperatures of the feedwater piping.
      The inspectors reviewed the following documents during the inspection:
The inspectors reviewed the following documents during the inspection:
      *   NSM ONOE-17539
*
      *   MP/O/A/3019/004, Revision 53, Hangers - QA Condition 1 and 4 - Removal,
NSM ONOE-17539
          Installation or Modification
*
      *   Work Request/Work Orders 98590970 (11) making final adjustments hot
MP/O/A/3019/004, Revision 53, Hangers - QA Condition 1 and 4 - Removal,
      *   Design Drawing O-494, Main Feedwater Pipe Whip Restraint
Installation or Modification
      *   PIP O-01-01408, Adequacy of Existing Feedwater Pipe Rupture Restraints,
*
          Corrective Action 7
Work Request/Work Orders 98590970 (11) making final adjustments hot
      In addition, the inspectors discussed with engineering the adjustments made to the whip
*
      restraints once hot temperature operations were reached.
Design Drawing O-494, Main Feedwater Pipe Whip Restraint
   b. Findings
*
      No findings of significance were identified.
PIP O-01-01408, Adequacy of Existing Feedwater Pipe Rupture Restraints,
.2   Biennial Plant Modification Review
Corrective Action 7
   a. Inspection Scope
In addition, the inspectors discussed with engineering the adjustments made to the whip
      The inspectors evaluated design change packages for nine modifications in the Barrier
restraints once hot temperature operations were reached.
      Integrity and Mitigating Systems cornerstone areas, to evaluate the modifications for
   b.
      adverse affects on system availability, reliability, and functional capability. The
Findings
      modifications and the associated attributes reviewed are as follows:
No findings of significance were identified.
      ONOE- 10642, Upgrade Seismic Supports and Add Isolation Valve 3N-305 to Nitrogen
.2
      Line
Biennial Plant Modification Review
      6 Materials/Replacement Components
   a.
      6 Flowpaths
Inspection Scope
      6 Pressure Boundary
The inspectors evaluated design change packages for nine modifications in the Barrier
      6 Structural
Integrity and Mitigating Systems cornerstone areas, to evaluate the modifications for
      6 Process Medium
adverse affects on system availability, reliability, and functional capability. The
      6 Failure Modes
modifications and the associated attributes reviewed are as follows:
      ONOE- 12107, Upgrade Discharge LPSW Piping from the Motor Driven EFW coolers to
ONOE- 10642, Upgrade Seismic Supports and Add Isolation Valve 3N-305 to Nitrogen
      1LPSW-527
Line
      6 Materials/Replacement Components

Materials/Replacement Components  

Flowpaths

Pressure Boundary

Structural

Process Medium

Failure Modes
ONOE- 12107, Upgrade Discharge LPSW Piping from the Motor Driven EFW coolers to
1LPSW-527  

Materials/Replacement Components  


                                      17
17
Structural

Process Medium
Structural

Process Medium
ONOE- 15414, Replace Valve 2LP-15 with Item DMV-1296, 2A LPI Discharge to RBS
ONOE- 15414, Replace Valve 2LP-15 with Item DMV-1296, 2A LPI Discharge to RBS
Pump Spray and HPI Suction
Pump Spray and HPI Suction
6 Materials/Replacement Components

6 Pressure Boundary
Materials/Replacement Components
6 Structural

Pressure Boundary

Structural  
ONOE- 12094, Modification of Unit 2 RC Vent System Supports/Restraints
ONOE- 12094, Modification of Unit 2 RC Vent System Supports/Restraints
6 Materials/Replacement Components

6 Structural
Materials/Replacement Components

Structural  
ONOE- 12800, Provide Clearance Between the Valve Body of 2SF-101 and SSF RC
ONOE- 12800, Provide Clearance Between the Valve Body of 2SF-101 and SSF RC
Makeup Pump Discharge Piping
Makeup Pump Discharge Piping
6 Materials/Replacement Components

6 Pressure Boundary
Materials/Replacement Components
6 Structural

Pressure Boundary

Structural  
ONOE- 17011, Upgrade 3-CCW-269 to Meet EQ Requirements
ONOE- 17011, Upgrade 3-CCW-269 to Meet EQ Requirements
6 Materials/Replacement Components

Materials/Replacement Components
Nuclear Station Modification (NSM) 33090, Add RBCU Time Delay Relays
Nuclear Station Modification (NSM) 33090, Add RBCU Time Delay Relays
6      Energy needs

6      Seismic qualification
Energy needs  
6      Response time

6      Operations procedures
Seismic qualification
6      Modes bounded by the existing analysis

Response time

Operations procedures

Modes bounded by the existing analysis
NSM 23053, Automatic Feedwater Isolation System
NSM 23053, Automatic Feedwater Isolation System
6      Environmental Qualification

6      Response Time - Testing
Environmental Qualification
6      Modes bounded by existing analysis

Response Time - Testing

Modes bounded by existing analysis  
NSM 23092, 600 V MCC and Load Center
NSM 23092, 600 V MCC and Load Center
6      Energy Needs

6      Seismic qualification
Energy Needs
6      Control signals appropriate under accident conditions

6      Failure modes bounded by the existing analysis
Seismic qualification  

Control signals appropriate under accident conditions

Failure modes bounded by the existing analysis
For selected modification packages, the inspectors observed the as-built configuration.
For selected modification packages, the inspectors observed the as-built configuration.
Documents reviewed included procedures, engineering calculations, modifications
Documents reviewed included procedures, engineering calculations, modifications
design and implementation packages, work orders, site drawings, corrective action
design and implementation packages, work orders, site drawings, corrective action
documents, applicable sections of the UFSAR, supporting analyses, TS, and design
documents, applicable sections of the UFSAR, supporting analyses, TS, and design
basis information. Documents reviewed are listed in the Attachment to this report.
basis information. Documents reviewed are listed in the Attachment to this report.
The inspectors also reviewed selected PIPs associated with modifications to confirm
The inspectors also reviewed selected PIPs associated with modifications to confirm
that problems were identified at an appropriate threshold, were entered into the
that problems were identified at an appropriate threshold, were entered into the
corrective action process, and appropriate corrective actions had been initiated.
corrective action process, and appropriate corrective actions had been initiated.


                                                18
18
b. Findings
  b.
    No findings of significance were identified.
Findings
1R19 Post-Maintenance Testing (PMT)
No findings of significance were identified.
a. Inspection Scope
1R19
    The inspectors reviewed PMT procedures and/or test activities, as appropriate, for
Post-Maintenance Testing (PMT)
    selected risk significant mitigating systems to assess whether: (1) the effect of testing
  a.
    on the plant had been adequately addressed by control room and/or engineering
Inspection Scope
    personnel; (2) testing was adequate for the maintenance performed; (3) acceptance
The inspectors reviewed PMT procedures and/or test activities, as appropriate, for
    criteria were clear and adequately demonstrated operational readiness consistent with
selected risk significant mitigating systems to assess whether: (1) the effect of testing
    design and licensing basis documents; (4) test instrumentation had current calibrations,
on the plant had been adequately addressed by control room and/or engineering
    range, and accuracy consistent with the application; (5) tests were performed as written
personnel; (2) testing was adequate for the maintenance performed; (3) acceptance
    with applicable prerequisites satisfied; (6) jumpers installed or leads lifted were properly
criteria were clear and adequately demonstrated operational readiness consistent with
    controlled; (7) test equipment was removed following testing; and (8) equipment was
design and licensing basis documents; (4) test instrumentation had current calibrations,
    returned to the status required to perform its safety function. The inspectors observed
range, and accuracy consistent with the application; (5) tests were performed as written
    testing and/or reviewed the results of the following tests:
with applicable prerequisites satisfied; (6) jumpers installed or leads lifted were properly
    *       PT/2/A/0202/11, 2C High Pressure Injection Pump Inservice Testing (IST)
controlled; (7) test equipment was removed following testing; and (8) equipment was
              Following Mechanical Seal Cleaning and Inspection
returned to the status required to perform its safety function. The inspectors observed
    *       PIP O-03-02797, Anderson Greenwood Relief Valves 3MS-52 and 3MS-70
testing and/or reviewed the results of the following tests:
              Failed to Lift as Specified Pressure During IST
*
    *       PIP O-03-02864, 3HP-25, BWST Supply to LPI Suction, Failed IST Stroke Test
PT/2/A/0202/11, 2C High Pressure Injection Pump Inservice Testing (IST)
    *       PIP O-03-02831, 3HP23, Letdown Storage Tank Outlet Isolation, Failed IST
Following Mechanical Seal Cleaning and Inspection
              Stroke Test
*
    *       PT/3/A/0152/007, Core Flood System valve Stroke Test, IST Stroke Test
PIP O-03-02797, Anderson Greenwood Relief Valves 3MS-52 and 3MS-70
              Following Inadvertent Backseating of Core Flood Isolation Valve 2CF-2 During
Failed to Lift as Specified Pressure During IST
              Maintenance per PIP O-03-03061
*
    *       IP/0/A/0203/001A, Low Pressure Injection System Borated Water Storage Tank
PIP O-03-02864, 3HP-25, BWST Supply to LPI Suction, Failed IST Stroke Test
              Level Instrument Calibration, calibration of level instrument reviewed following
*
              indication of false level reading per PIP O-03-0316
PIP O-03-02831, 3HP23, Letdown Storage Tank Outlet Isolation, Failed IST
    *       TT/3/A/0600/022, Turbine Driven Emergency Feedwater (TDEFW) Pump Speed
Stroke Test
              Response During AFIS Initiation Test, Following AFIS Modification
*
    *       PIP O-03-02955, Following Maintenance the Unit 3 TDEFW Pump Lube Oil
PT/3/A/0152/007, Core Flood System valve Stroke Test, IST Stroke Test
              Cooler Developed a Water Leak
Following Inadvertent Backseating of Core Flood Isolation Valve 2CF-2 During
b. Findings
Maintenance per PIP O-03-03061
    No findings of significance were identified.
*
IP/0/A/0203/001A, Low Pressure Injection System Borated Water Storage Tank
Level Instrument Calibration, calibration of level instrument reviewed following
indication of false level reading per PIP O-03-0316
*
TT/3/A/0600/022, Turbine Driven Emergency Feedwater (TDEFW) Pump Speed
Response During AFIS Initiation Test, Following AFIS Modification
*
PIP O-03-02955, Following Maintenance the Unit 3 TDEFW Pump Lube Oil
Cooler Developed a Water Leak
  b.
Findings
No findings of significance were identified.


                                                19
19
1R20 Refueling and Outage Activities
1R20
a. Inspection Scope
Refueling and Outage Activities
    The inspectors conducted reviews and observations for selected licensee outage
  a.
    activities to ensure that: (1) the licensee considered risk in developing the outage plan;
Inspection Scope
    (2) the licensee adhered to the outage plan to control plant configuration based on risk;
The inspectors conducted reviews and observations for selected licensee outage
    (3) that mitigation strategies were in place for losses of key safety functions; and (4) the
activities to ensure that: (1) the licensee considered risk in developing the outage plan;
    licensee adhered to operating license and TS requirements. Between April 26, 2003,
(2) the licensee adhered to the outage plan to control plant configuration based on risk;
    and June 15, 2003, the following activities related to the Unit 3 refueling outage were
(3) that mitigation strategies were in place for losses of key safety functions; and (4) the
    reviewed for conformance to the applicable procedure and selected activities associated
licensee adhered to operating license and TS requirements. Between April 26, 2003,
    with each evaluation were witnessed:
and June 15, 2003, the following activities related to the Unit 3 refueling outage were
    *       defueled (no Mode) operations
reviewed for conformance to the applicable procedure and selected activities associated
    *       refueling operations
with each evaluation were witnessed:
    *       reduced inventory and mid-loop conditions for installation and removal of steam
*
              generator nozzle dams
defueled (no Mode) operations
    *       activities involving the reactor vessel head replacement
*
    *       reactor startup
refueling operations
    *       Mode changes from Mode 6 (Refueling) to Mode 1 (Power Operation)
*
    *       system lineups during major outage activities and Mode changes
reduced inventory and mid-loop conditions for installation and removal of steam
    *       final containment walkdown prior to startup
generator nozzle dams
b. Findings
*
    No findings of significance were identified.
activities involving the reactor vessel head replacement
1R22 Surveillance Testing
*
a. Inspection Scope
reactor startup
    The inspectors witnessed surveillance tests and/or reviewed test data of the selected
*
    risk-significant SSCs listed below, to assess, as appropriate, whether the SSCs met TS,
Mode changes from Mode 6 (Refueling) to Mode 1 (Power Operation)
    UFSAR, and licensee procedure requirements. In addition, the inspectors determined if
*
    the testing effectively demonstrated that the SSCs were ready and capable of
system lineups during major outage activities and Mode changes
    performing their intended safety functions.
*
    *       PT /1/A/0600/013, 1A Motor Driven Emergency Feedwater Pump Test [IST]
final containment walkdown prior to startup
    *       PT/3/A/0151/20, Penetration 20 Leak Rate Test (3PR-1 and 3PR-2) [local leak
  b.
              rate test (LLRT)]
Findings
No findings of significance were identified.
1R22
Surveillance Testing
  a.
Inspection Scope
The inspectors witnessed surveillance tests and/or reviewed test data of the selected
risk-significant SSCs listed below, to assess, as appropriate, whether the SSCs met TS,
UFSAR, and licensee procedure requirements. In addition, the inspectors determined if
the testing effectively demonstrated that the SSCs were ready and capable of
performing their intended safety functions.
*
PT /1/A/0600/013, 1A Motor Driven Emergency Feedwater Pump Test [IST]
*
PT/3/A/0151/20, Penetration 20 Leak Rate Test (3PR-1 and 3PR-2) [local leak
rate test (LLRT)]


                                                20
20
      *       PT/3/A/0151/019, Penetration 19 Leak Rate Test (3PR-5 and 3PR-6) [LLRT]
*
      *       PT/0/A/0600/021, Standby Shutdown Facility Diesel Generator Operation
PT/3/A/0151/019, Penetration 19 Leak Rate Test (3PR-5 and 3PR-6) [LLRT]
      *       PT2/A0202/011, 2B HPI Pump test [IST]
*
      *       PT/3/A/0251/019, Main Steam Atmosphere Dump Valve Functional Test
PT/0/A/0600/021, Standby Shutdown Facility Diesel Generator Operation
      *       1P/0/A/0305/001P, Reactor Protective System Channel D RC Pressure
*
              Instrument Calibration
PT2/A0202/011, 2B HPI Pump test [IST]
      *       IP/A/0380/004C, SSF D/G Water Expansion Tank Level Instrument Calibration
*
      *       IP/0/A/305/0005D Reactor Building High Pressure Trip Channel D
PT/3/A/0251/019, Main Steam Atmosphere Dump Valve Functional Test
b.   Findings
*
      No findings of significance were identified.
1P/0/A/0305/001P, Reactor Protective System Channel D RC Pressure
  Cornerstone: Emergency Preparedness
Instrument Calibration
1EP6 Drill Evaluation
*
  a. Inspection Scope
IP/A/0380/004C, SSF D/G Water Expansion Tank Level Instrument Calibration
      The inspectors observed and evaluated the licensees conduct of a simulator based
*
      emergency preparedness drill held on June 10, 2003. The drill scenario involved
IP/0/A/305/0005D Reactor Building High Pressure Trip Channel D
      tornado damage to the Unit 1 turbine building with a subsequent loss of all AC power.
  b.
      Additionally, Unit 3 developed a steam generator tube leak as part of the drill scenario.
Findings
      The inspectors observed the scenario from the simulator control room and the Technical
No findings of significance were identified.
      Support Center. The inspectors observed performance of the licensees ability to
    Cornerstone: Emergency Preparedness
      correctly classify the event and notify state and county authorities. For this drill, the
1EP6
      scenario progressed to a site area emergency. The drill scenario did not provide an
Drill Evaluation
      opportunity for the emergency response organization to make protective action
    a.
      recommendations. The inspectors also reviewed the post-drill critique that was
Inspection Scope
      conducted by the licensee evaluators.
The inspectors observed and evaluated the licensees conduct of a simulator based
  b. Findings
emergency preparedness drill held on June 10, 2003. The drill scenario involved
      No findings of significance were identified.
tornado damage to the Unit 1 turbine building with a subsequent loss of all AC power.  
Additionally, Unit 3 developed a steam generator tube leak as part of the drill scenario.
The inspectors observed the scenario from the simulator control room and the Technical
Support Center. The inspectors observed performance of the licensees ability to
correctly classify the event and notify state and county authorities. For this drill, the
scenario progressed to a site area emergency. The drill scenario did not provide an
opportunity for the emergency response organization to make protective action  
recommendations. The inspectors also reviewed the post-drill critique that was
conducted by the licensee evaluators.
    b.
Findings
 
No findings of significance were identified.  


                                                21
21
4. OTHER ACTIVITIES
4. OTHER ACTIVITIES
4OA1 Performance Indicator (PI) Verification
4OA1 Performance Indicator (PI) Verification
.1   Initiating Events, Mitigating Systems, and Barrier Integrity Cornerstones
.1
   a. Inspection Scope
Initiating Events, Mitigating Systems, and Barrier Integrity Cornerstones
      The inspectors reviewed the PIs listed in the table below (for all three units), to deter-
   a.
      mine their accuracy and completeness against requirements in Nuclear Energy Institute
Inspection Scope
      (NEI) 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 2.
The inspectors reviewed the PIs listed in the table below (for all three units), to deter-
                                    Cornerstone: Initiating Events
mine their accuracy and completeness against requirements in Nuclear Energy Institute
            Performance Indicator         Verification Period         Records Reviewed
(NEI) 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 2.
      Unplanned Scrams                                       *     Licensee Event Reports
Cornerstone: Initiating Events
                                                              *     NRC Inspection Reports
Performance Indicator
                                              3rd and 4th
Verification Period
                                                              *      Monthly Operating
Records Reviewed
      Scrams with Loss of Normal           quarter, 2002,
Unplanned Scrams
                                                                      Reports
3rd and 4th
                Heat Removal                     and
quarter, 2002,
                                                              *      operator logs
and
                                          1st quarter, 2003
1st quarter, 2003
      Unplanned Power Changes                                 *      licensee power history
*
                                                                      curves
Licensee Event Reports
                                    Cornerstone: Barrier Integrity
*
            Performance Indicator         Verification Period         Records Reviewed
NRC Inspection Reports  
      Reactor Coolant System                                 *      daily plant chemistry
*
                Specific Activity             3rd and 4th             data
Monthly Operating
                                            quarter, 2002,
Reports
      Reactor Coolant System                     and          *     daily status reports
*
                Leakage                  1st quarter, 2003    *     operator logs
operator logs
                                                              *     PIPs
*
   b. Findings
licensee power history
      No findings of significance were identified.
curves
Scrams with Loss of Normal
Heat Removal
Unplanned Power Changes
Cornerstone: Barrier Integrity
Performance Indicator
Verification Period
Records Reviewed
Reactor Coolant System
Specific Activity
3rd and 4th  
quarter, 2002,
and
1st quarter, 2003
*
daily plant chemistry
data
Reactor Coolant System
Leakage
*
daily status reports
*
operator logs
*
PIPs
   b.
Findings
No findings of significance were identified.
4OA2 Identification and Resolution of Problems
4OA2 Identification and Resolution of Problems
   a. Inspection Scope
   a.
      The inspectors performed an in-depth review of issues entered into the licensees
Inspection Scope
      corrective action program. The samples selected were within the cornerstone of
The inspectors performed an in-depth review of issues entered into the licensees
      mitigating systems and involved risk significant systems. The inspectors reviewed the
corrective action program. The samples selected were within the cornerstone of
      actions taken to determine if the licensee had adequately addressed the following
mitigating systems and involved risk significant systems. The inspectors reviewed the
      attributes:
actions taken to determine if the licensee had adequately addressed the following
attributes:


                                                22
22
      * Complete, accurate, and timely identification of the problem
* Complete, accurate, and timely identification of the problem
      * Evaluation and disposition of operability and reportability issues
* Evaluation and disposition of operability and reportability issues
      * Consideration of previous failures, extent of condition, generic or common cause
* Consideration of previous failures, extent of condition, generic or common cause
        implications
implications
      * Prioritization and resolution of the issue commensurate with the safety significance
* Prioritization and resolution of the issue commensurate with the safety significance
      * Identification of the root cause and contributing causes of the problem
* Identification of the root cause and contributing causes of the problem
      * Identification and implementation of corrective actions commensurate with the safety
* Identification and implementation of corrective actions commensurate with the safety
        significance of the issue
significance of the issue
      The following issue and corrective actions were reviewed:
The following issue and corrective actions were reviewed:
      * PIP O-03-02482, Darkened Oil Found in the 2C LPI Pump Bearing
* PIP O-03-02482, Darkened Oil Found in the 2C LPI Pump Bearing  
   b. Findings
   b.
      No findings of significance were identified.
Findings
No findings of significance were identified.
4OA3 Event Followup
4OA3 Event Followup
.1   Unit 1 Dropped Rod
.1
      On May 17, 2003, Unit 1 dropped Safety Group 4, Rod 9 during rod movement
Unit 1 Dropped Rod
      verification surveillance testing at 100 percent RTP. The dropped rod was a result of a
On May 17, 2003, Unit 1 dropped Safety Group 4, Rod 9 during rod movement
      blown fuse on one of the control rod drive motor phases. The operators reduced power
verification surveillance testing at 100 percent RTP. The dropped rod was a result of a
      to less than 55 percent as a result of the dropped rod. The inspectors responded to the
blown fuse on one of the control rod drive motor phases. The operators reduced power
      site and verified that TS and core operating limits report requirements were met by the
to less than 55 percent as a result of the dropped rod. The inspectors responded to the
      licensee for quadrant power tilt ratio, axial flux, and rod alignment. The inspectors also
site and verified that TS and core operating limits report requirements were met by the
      verified that the appropriate abnormal operating procedures were implemented by the
licensee for quadrant power tilt ratio, axial flux, and rod alignment. The inspectors also
      operators. Repairs were made, the rod was subsequently recovered, and the unit was
verified that the appropriate abnormal operating procedures were implemented by the
      returned to 100 percent power on May 18, 2003.
operators. Repairs were made, the rod was subsequently recovered, and the unit was
.2   Standby Shutdown Facility Cable Routing
returned to 100 percent power on May 18, 2003.
      The inspectors followed up on a 10 CFR 50.72, eight hour notification made by the
.2
      licensee for an unanalyzed condition relating to the licensee's discovery of safe
Standby Shutdown Facility Cable Routing
      shutdown cabling routed through an Appendix R, III.G.3 area. These cables included
The inspectors followed up on a 10 CFR 50.72, eight hour notification made by the
      control and indication wiring for several valves that isolate the reactor coolant system
licensee for an unanalyzed condition relating to the licensee's discovery of safe
      from potential leakage paths during safe shutdown. The inspectors walked down the
shutdown cabling routed through an Appendix R, III.G.3 area. These cables included
      cabling to verify the licensees assessment of the condition and reviewed the adequacy
control and indication wiring for several valves that isolate the reactor coolant system
      of the compensatory measures put in place.
from potential leakage paths during safe shutdown. The inspectors walked down the
.3   Failure of the Engineered Safeguards Channel B Power Supply
cabling to verify the licensees assessment of the condition and reviewed the adequacy
      The inspectors reviewed the licensees response to the failure of the engineered
of the compensatory measures put in place.
.3
Failure of the Engineered Safeguards Channel B Power Supply
The inspectors reviewed the licensees response to the failure of the engineered


                                              23
23
      safeguards channel B power supply. The failure resulted in multiple TS LCO entries
safeguards channel B power supply. The failure resulted in multiple TS LCO entries
      and included a loss of the digital engineered safeguards digital actuation circuits. In
and included a loss of the digital engineered safeguards digital actuation circuits. In
      addition, multiple alarms were received in the control room. Following the initial loss,
addition, multiple alarms were received in the control room. Following the initial loss,
      discussions were conducted with the licensee concerning the failure of the power
discussions were conducted with the licensee concerning the failure of the power
      supply, the various TS LCO entries, and ongoing repair efforts. Followup of the ES
supply, the various TS LCO entries, and ongoing repair efforts. Followup of the ES
      power supply failure is discussed further in Section 1R14 of this report.
power supply failure is discussed further in Section 1R14 of this report.
4OA5 Other Activities
4OA5 Other Activities  
.1   Unit 3 Reactor Vessel Head Replacement Project (RVHRP)
.1
  A.   Engineering Preparation and Implementation for the RVHRP
Unit 3 Reactor Vessel Head Replacement Project (RVHRP)  
   a. Inspection Scope
  A.
      The inspectors reviewed engineering preparations including: selected Design
Engineering Preparation and Implementation for the RVHRP
      Modification Packages, engineering calculations, analyses, and drawings for the
   a.
      Oconee RVHRP, in order to assess adequacy and completeness. To obtain a greater
Inspection Scope
      understanding of the entire project scope, the inspectors also held discussions with
The inspectors reviewed engineering preparations including: selected Design
      project management. To determine that proper Code Sections and Editions were
Modification Packages, engineering calculations, analyses, and drawings for the
      applicable for this RVHRP, the inspectors also reviewed applicable sections of the
Oconee RVHRP, in order to assess adequacy and completeness. To obtain a greater
      Oconee Final Safety Analysis Report and various scope documents.
understanding of the entire project scope, the inspectors also held discussions with
   b. Findings
project management. To determine that proper Code Sections and Editions were
      No findings of significance were identified.
applicable for this RVHRP, the inspectors also reviewed applicable sections of the
  B.   Review of RVHRP Lifting and Transportation Program Activities
Oconee Final Safety Analysis Report and various scope documents.
   a. Inspection Scope
   b.
      The inspectors reviewed the adequacy of the RVHRP lifting program as described in
Findings
      Modification Package ON-33112, Part AS1, Reactor Vessel Head Rigging and
No findings of significance were identified.
      Handling, assuring that it was prepared in accordance with regulatory requirements,
  B.
      appropriate industrial codes and standards, and verified that the maximum anticipated
Review of RVHRP Lifting and Transportation Program Activities
      loads to be lifted would not exceed the capacity of the lifting equipment and supporting
   a.
      structures.
Inspection Scope
      The inspectors examined the RVHRP lifting equipment including the Polar Crane, a
The inspectors reviewed the adequacy of the RVHRP lifting program as described in
      down-ender placed inside the Reactor Building, three four-point lift systems, three skid
Modification Package ON-33112, Part AS1, Reactor Vessel Head Rigging and
      systems and a Self Propelled Modular Transport.
Handling, assuring that it was prepared in accordance with regulatory requirements,
      The inspectors reviewed the adequacy of the transport programs, procedures, work
appropriate industrial codes and standards, and verified that the maximum anticipated  
      packages, and load test records, to assure that they had been prepared and/or tested in
loads to be lifted would not exceed the capacity of the lifting equipment and supporting
      accordance with regulatory requirements, appropriate industrial codes, and standards.
structures.
      The inspectors also reviewed the licensee's analyses for buried piping located beneath
The inspectors examined the RVHRP lifting equipment including the Polar Crane, a
      the transport path as documented in Modification Package ON-53112, Part AS4,
down-ender placed inside the Reactor Building, three four-point lift systems, three skid
      Reactor Vessel Head Transport, to ensure that piping would not be damaged.
systems and a Self Propelled Modular Transport.
The inspectors reviewed the adequacy of the transport programs, procedures, work
packages, and load test records, to assure that they had been prepared and/or tested in
accordance with regulatory requirements, appropriate industrial codes, and standards.
The inspectors also reviewed the licensee's analyses for buried piping located beneath
the transport path as documented in Modification Package ON-53112, Part AS4,
Reactor Vessel Head Transport, to ensure that piping would not be damaged.


                                              24
24
b. Findings
  b.
    No findings of significance were identified.
Findings
C. Quality Assurance (QA) Oversight
No findings of significance were identified.
a. Inspection Scope
C.
    The inspectors reviewed licensee procedures relative to QA oversight of contractor
Quality Assurance (QA) Oversight
    activities for the RVHRP replacement. In addition, the inspectors discussed
  a.
    procurement and quality control inspection of various parts, including the Control Rod
Inspection Scope
    Drive Mechanisms (CRDM), Hold Down Bolts, and CRDM (Split Nut) Flange Ring that
The inspectors reviewed licensee procedures relative to QA oversight of contractor
    were utilized in the attachment of the CRDMs to the Reactor Vessel CRDM flanges.
activities for the RVHRP replacement. In addition, the inspectors discussed
    The inspectors also reviewed a sample of PIPs, non-conformance reports, Purchase
procurement and quality control inspection of various parts, including the Control Rod
    Orders, and Receiving Inspection Reports (Form SCD-311A) pertaining to the above
Drive Mechanisms (CRDM), Hold Down Bolts, and CRDM (Split Nut) Flange Ring that
    parts. The inspectors also reviewed the Unit 3 Reactor Vessel Head Penetration
were utilized in the attachment of the CRDMs to the Reactor Vessel CRDM flanges.  
    Preservice Inspection conducted in February 2003. The Unit 3 Oconee replacement
The inspectors also reviewed a sample of PIPs, non-conformance reports, Purchase
    reactor vessel head contains sixty-nine alloy 690 penetration tubes that are shrunk fit in
Orders, and Receiving Inspection Reports (Form SCD-311A) pertaining to the above
    the reactor vessel head and attached with alloy 152/52 partial penetration J-groove
parts. The inspectors also reviewed the Unit 3 Reactor Vessel Head Penetration
    welds. The inspectors reviewed aspects of the inspection program that provided a
Preservice Inspection conducted in February 2003.   The Unit 3 Oconee replacement
    baseline of the condition of the accessible outside diameter and inside diameter
reactor vessel head contains sixty-nine alloy 690 penetration tubes that are shrunk fit in
    surfaces of the vessel head penetration tubes and the partial penetration J-groove welds
the reactor vessel head and attached with alloy 152/52 partial penetration J-groove
    attaching the penetration tubes to the reactor vessel head. The review included Scope
welds.   The inspectors reviewed aspects of the inspection program that provided a
    of Work, Procedures, Personnel Certifications, Equipment Certifications, and
baseline of the condition of the accessible outside diameter and inside diameter  
    examination results.
surfaces of the vessel head penetration tubes and the partial penetration J-groove welds
b. Findings
attaching the penetration tubes to the reactor vessel head. The review included Scope
    Introduction: The inspectors identified a Green NCV of 10CFR50.55a(g)(4), which
of Work, Procedures, Personnel Certifications, Equipment Certifications, and
    requires meeting the ASME Boiler and Pressure Vessel Code, Section XI, IWA-7000,
examination results.
    Replacement, and of 10 CFR 50, Appendix B, Criterion VII, Control of Purchased
  b.
    Material, Equipment, and Services. This resulted in the licensee installing one non-
Findings
    conforming CRDM (Split Nut) Flange Ring on Unit 2, assembly #18, and discovering
 
    prior to the installation in Unit 3, 68 CRDM (Split Nut) Flange Rings and 552 CRDM Hold
Introduction: The inspectors identified a Green NCV of 10CFR50.55a(g)(4), which
    Down Bolts that did not meet the design and procurement specifications.
requires meeting the ASME Boiler and Pressure Vessel Code, Section XI, IWA-7000,
     Description: In April 2003, while the licensee was performing an inspection during the
Replacement, and of 10 CFR 50, Appendix B, Criterion VII, Control of Purchased
    replacement of the reactor vessel head project, they determined that the CRDM Hold
Material, Equipment, and Services. This resulted in the licensee installing one non-
    Down Bolts, and CRDM (Split Nut) Flange Rings did not receive proper QA reviews of
conforming CRDM (Split Nut) Flange Ring on Unit 2, assembly #18, and discovering
    the mechanical/chemical properties and non-destructive examinations (NDE) as
prior to the installation in Unit 3, 68 CRDM (Split Nut) Flange Rings and 552 CRDM Hold
    specified in the procurement and design specifications. These reviews and testing were
Down Bolts that did not meet the design and procurement specifications.
    conducted during the initial mechanical/chemical and NDE testing performed by
      
    independent testing facilities, and subsequently during the receipt inspections performed
Description: In April 2003, while the licensee was performing an inspection during the
    by Framatome ANP, who was acting as the contractor for the RVHRP project, and
replacement of the reactor vessel head project, they determined that the CRDM Hold
    finally the licensee.
Down Bolts, and CRDM (Split Nut) Flange Rings did not receive proper QA reviews of
    While performing Supply Chain Directive, SACD311, Rev. 1, Receipt Inspection &
the mechanical/chemical properties and non-destructive examinations (NDE) as
    Testing of QA Condition Items, the licensee failed to identify that the CRDM (Split Nut)
specified in the procurement and design specifications. These reviews and testing were
    Flange Rings did not meet the required design and procurement specifications (i.e., a
conducted during the initial mechanical/chemical and NDE testing performed by
independent testing facilities, and subsequently during the receipt inspections performed
by Framatome ANP, who was acting as the contractor for the RVHRP project, and
finally the licensee.
While performing Supply Chain Directive, SACD311, Rev. 1, Receipt Inspection &
Testing of QA Condition Items, the licensee failed to identify that the CRDM (Split Nut)
Flange Rings did not meet the required design and procurement specifications (i.e., a


                                          25
25
yield strength of 100 ksi and a tensile strength of 125 ksi) for material quality as stated
yield strength of 100 ksi and a tensile strength of 125 ksi) for material quality as stated
in the Certificate of Compliance and as defined by ASME SA-320, Grade L43. The
in the Certificate of Compliance and as defined by ASME SA-320, Grade L43. The
CRDM (split nut) flange rings also did not meet the NDE ultrasonic testing (UT) as
CRDM (split nut) flange rings also did not meet the NDE ultrasonic testing (UT) as
described in ASME Section III, Sub-Article NB-2580 Examination of Bolts, Nuts and
described in ASME Section III, Sub-Article NB-2580 Examination of Bolts, Nuts and
Studs, specifically NB-2586 Ultrasonic Examination for Sizes Over 4 in., requiring the
Studs, specifically NB-2586 Ultrasonic Examination for Sizes Over 4 in., requiring the
examination be performed at a nominal frequency of 2.25 Mhz. Also the 552 CRDM
examination be performed at a nominal frequency of 2.25 Mhz. Also the 552 CRDM
Hold Down Bolts for Unit 3 did not meet the same NDE-UT testing as described in
Hold Down Bolts for Unit 3 did not meet the same NDE-UT testing as described in
ASME Section III, Sub-Article NB-2580 Examination of Bolts, Nuts and Studs. Although
ASME Section III, Sub-Article NB-2580 Examination of Bolts, Nuts and Studs. Although
not a code requirement, the examination was called for by the design and procurement
not a code requirement, the examination was called for by the design and procurement
specification.
specification.
Line 1,189: Line 1,521:
on Unit 2 during the Unit 2 U2EOC19 RFO in the fall of 2002, and removal of 68
on Unit 2 during the Unit 2 U2EOC19 RFO in the fall of 2002, and removal of 68
uninstalled, non-conforming CRDM (Split Nut) Flange Rings from the site for failure to
uninstalled, non-conforming CRDM (Split Nut) Flange Rings from the site for failure to
meet the mechanical property requirements of the components. This non-conforming
meet the mechanical property requirements of the components. This non-conforming
condition was not identified during the Unit 2 EOC19 RFO.
condition was not identified during the Unit 2 EOC19 RFO.
Based on the discovery that one non-conforming CRDM (Split Nut) Flange Ring was
Based on the discovery that one non-conforming CRDM (Split Nut) Flange Ring was
installed on Unit 2, the licensee performed an engineering evaluation that is
installed on Unit 2, the licensee performed an engineering evaluation that is
documented in Framatome ANP Document 32-5027297-00, Operability Assessment of
documented in Framatome ANP Document 32-5027297-00, Operability Assessment of
CRDM Nut Ring with Reduced Tensile Strength Material. The one CRDM (Split Nut)
CRDM Nut Ring with Reduced Tensile Strength Material. The one CRDM (Split Nut)
Flange Ring installed on Unit 2 was declared to be operable, but degraded, and could
Flange Ring installed on Unit 2 was declared to be operable, but degraded, and could
remain in place until the end of the current Unit 2 operating cycle (which is scheduled to
remain in place until the end of the current Unit 2 operating cycle (which is scheduled to
end in the spring of 2004) when the reactor vessel head will be replaced. New CRDM
end in the spring of 2004) when the reactor vessel head will be replaced. New CRDM
(Split Nut) Flange Rings with different heat numbers were procured and installed on the
(Split Nut) Flange Rings with different heat numbers were procured and installed on the
Unit 3 head. The inspectors reviewed the methodology utilized in the engineering
Unit 3 head. The inspectors reviewed the methodology utilized in the engineering
evaluation for the non-conforming flange ring and found that the review was thorough.
evaluation for the non-conforming flange ring and found that the review was thorough.  
The evaluation involved the redoing of all the ASME Code-required calculations for the
The evaluation involved the redoing of all the ASME Code-required calculations for the
connection using the actual strength of the material supplied rather than the minimum
connection using the actual strength of the material supplied rather than the minimum
strength required by the material specification.
strength required by the material specification.
Analysis: The inspectors determined that this finding was associated with an inadequate
Analysis: The inspectors determined that this finding was associated with an inadequate
receipt inspection for the above parts. The finding was more than minor because
receipt inspection for the above parts. The finding was more than minor because
non-conforming material was actually installed in Unit 2. This deficiency was evaluated
non-conforming material was actually installed in Unit 2. This deficiency was evaluated
under the SDP. Since there was no loss of function, the Initiating Events and Mitigation
under the SDP. Since there was no loss of function, the Initiating Events and Mitigation
Systems cornerstones were not impacted. The SDP Phase 1 RCS Barrier cornerstone
Systems cornerstones were not impacted. The SDP Phase 1 RCS Barrier cornerstone
required an evaluation under SDP Phase 2. A regional senior reactor analyst performed
required an evaluation under SDP Phase 2. A regional senior reactor analyst performed
a SDP Phase 3 analysis and determined that since there was not a loss of function of
a SDP Phase 3 analysis and determined that since there was not a loss of function of
the system, there was no increase in risk. The finding was evaluated as Green (very
the system, there was no increase in risk. The finding was evaluated as Green (very
low safety significance).
low safety significance).
Enforcement: 10CFR50.55a(g)(4) specifies in part that components classified as ASME
   
Enforcement: 10CFR50.55a(g)(4) specifies in part that components classified as ASME
Code Class 1, Class 2, and Class 3 meet the requirements set forth in Section XI of the
Code Class 1, Class 2, and Class 3 meet the requirements set forth in Section XI of the
ASME Boiler and Pressure Vessel Code. The ASME Boiler and Pressure Vessel Code,
ASME Boiler and Pressure Vessel Code. The ASME Boiler and Pressure Vessel Code,
Section XI, 1989 Edition, with no Addenda, subsection IWA-7220, states in part that
Section XI, 1989 Edition, with no Addenda, subsection IWA-7220, states in part that
Prior to authorizing the installation of an item to be used for replacement, the Owner
Prior to authorizing the installation of an item to be used for replacement, the Owner
shall conduct an evaluation of the suitability of that item.
shall conduct an evaluation of the suitability of that item.


                                            26
26
    Also, 10CFR50, Appendix B, Criterion VII, Control of Purchased Material, Equipment,
Also, 10CFR50, Appendix B, Criterion VII, Control of Purchased Material, Equipment,
    and Services, states that Measures shall be established to assure that purchased
and Services, states that Measures shall be established to assure that purchased
    material, equipment, and services, whether purchased directly or through contractors
material, equipment, and services, whether purchased directly or through contractors
    and subcontractors, conform to the procurement documents. These measures shall
and subcontractors, conform to the procurement documents. These measures shall
    include provisions, as appropriate, for source evaluation and selection, objective
include provisions, as appropriate, for source evaluation and selection, objective
    evidence of quality furnished by the contractor or subcontractor, inspection at the
evidence of quality furnished by the contractor or subcontractor, inspection at the
    contractor or subcontractor source, and examination of products upon delivery.
contractor or subcontractor source, and examination of products upon delivery.
    Contrary to the above, during the Unit 2 EOC19 RFO in the fall of 2002, measures taken
Contrary to the above, during the Unit 2 EOC19 RFO in the fall of 2002, measures taken
    to evaluate the suitability of replacement parts were not adequate in that they did not
to evaluate the suitability of replacement parts were not adequate in that they did not
    preclude the installation of one non-conforming CRDM (Split Nut) Flange Ring on CRDM
preclude the installation of one non-conforming CRDM (Split Nut) Flange Ring on CRDM
    Assembly #18 on Unit 2. The same QA reviews of the remainder of the 68 CRDM (Split
Assembly #18 on Unit 2. The same QA reviews of the remainder of the 68 CRDM (Split
    Nut) Flange Rings and 552 CRDM Hold Down Bolts in the warehouse did not identify the
Nut) Flange Rings and 552 CRDM Hold Down Bolts in the warehouse did not identify the
    non-conforming parts prior to the attempt to install them on the Unit 3 reactor vessel
non-conforming parts prior to the attempt to install them on the Unit 3 reactor vessel
    head. Because the finding is of very low safety significance and because the issue is in
head. Because the finding is of very low safety significance and because the issue is in
    the licensees corrective action program under PIPs O-03-2211, O-03-2132, O-03-2177
the licensees corrective action program under PIPs O-03-2211, O-03-2132, O-03-2177
    and O-03-2171, it is being treated as an NCV, consistent with Section VI.A.1 of the NRC
and O-03-2171, it is being treated as an NCV, consistent with Section VI.A.1 of the NRC
    Enforcement Policy. Accordingly, it will be identified as NCV 05000270,287/2003003-
Enforcement Policy. Accordingly, it will be identified as NCV 05000270,287/2003003-
    07: Failure to Detect Non-Conforming Parts During Receipt Inspections.
07: Failure to Detect Non-Conforming Parts During Receipt Inspections.
D. Radiation Protection
D.
a. Inspection Scope
Radiation Protection
    Radiation safety controls for removal of the Unit 3 reactor vessel head and preparation
  a.
    of the head for temporary storage were reviewed and evaluated. Licensee procedures
Inspection Scope
    for posting, surveying, and controlling access to radiologically significant areas were
Radiation safety controls for removal of the Unit 3 reactor vessel head and preparation
    assessed for adequacy. During tours of the Auxiliary Building and the Unit 3
of the head for temporary storage were reviewed and evaluated. Licensee procedures
    Containment Building, the inspectors evaluated radiological postings and barricades
for posting, surveying, and controlling access to radiologically significant areas were
    against current radiological surveys and procedurally established radiological controls.
assessed for adequacy. During tours of the Auxiliary Building and the Unit 3
    Radiation Work Permits (RWPs) issued for the RVHRP were reviewed for incorporation
Containment Building, the inspectors evaluated radiological postings and barricades
    of established access controls. RWP specified alarm setpoints for electronic dosimeters
against current radiological surveys and procedurally established radiological controls.  
    were also evaluated against current radiological surveys. Health Physics Technician
Radiation Work Permits (RWPs) issued for the RVHRP were reviewed for incorporation
    (HPT) proficiency in providing job coverage and occupational workers adherence to
of established access controls. RWP specified alarm setpoints for electronic dosimeters
    RWP requirements were evaluated through worker interviews, work area tours and job
were also evaluated against current radiological surveys. Health Physics Technician
    site observations. The inspectors observed radiation dose rates measured by an HPT in
(HPT) proficiency in providing job coverage and occupational workers adherence to
    the work areas adjacent to the vessel head after it was placed on the head stand. The
RWP requirements were evaluated through worker interviews, work area tours and job
    observed work area dose rates were compared to the licensees most current
site observations. The inspectors observed radiation dose rates measured by an HPT in
    documented survey results.
the work areas adjacent to the vessel head after it was placed on the head stand. The
    As Low As Reasonably Achievable (ALARA) planning and controls for the RVHRP were
observed work area dose rates were compared to the licensees most current
    reviewed and evaluated for consistency with Section IV, ALARA Planning, of the
documented survey results.
    licensees System ALARA Manual. ALARA Planning Worksheets, ALARA controls,
As Low As Reasonably Achievable (ALARA) planning and controls for the RVHRP were
    dose estimates, dose tracking, exposure controls including temporary shielding,
reviewed and evaluated for consistency with Section IV, ALARA Planning, of the
    contamination and airborne radioactivity controls, project staffing and training,
licensees System ALARA Manual. ALARA Planning Worksheets, ALARA controls,
    emergency contingencies, and temporary storage of the original reactor head assembly
dose estimates, dose tracking, exposure controls including temporary shielding,
    were reviewed and discussed with the licensee. RWPs issued for the RVHRP and their
contamination and airborne radioactivity controls, project staffing and training,
    associated ALARA job briefing packages were examined for incorporation of the ALARA
emergency contingencies, and temporary storage of the original reactor head assembly
    controls established for the project. Worker adherence to those controls was assessed
were reviewed and discussed with the licensee. RWPs issued for the RVHRP and their
associated ALARA job briefing packages were examined for incorporation of the ALARA
controls established for the project. Worker adherence to those controls was assessed


                                              27
27
      through job site observations during the movement of original reactor head assembly to
through job site observations during the movement of original reactor head assembly to
      the head stand.
the head stand.
      Through the above reviews and observations, the licensees radiation safety program
Through the above reviews and observations, the licensees radiation safety program
      implementation and practices for the RVHRP were evaluated by the inspectors for
implementation and practices for the RVHRP were evaluated by the inspectors for
      consistency with 10 CFR 20 requirements and approved licensee procedures. Licensee
consistency with 10 CFR 20 requirements and approved licensee procedures. Licensee
      plans, procedures, and records reviewed during the inspection are listed in the
plans, procedures, and records reviewed during the inspection are listed in the
      Attachment to this report.
Attachment to this report.
  b. Findings
    b.
      No findings of significance were identified.
Findings
.2   Institute of Nuclear Power Operations (INPO) Report Review
No findings of significance were identified.
      The inspectors reviewed the final report issued by INPO on April 28, 2003, for the
.2
      evaluation that was conducted at the Oconee facility during the weeks of August 5,
Institute of Nuclear Power Operations (INPO) Report Review
      2002, and August 12, 2002. The inspectors did not identify any safety issues in the
The inspectors reviewed the final report issued by INPO on April 28, 2003, for the
      INPO report that either warranted further NRC followup or that had not already been
evaluation that was conducted at the Oconee facility during the weeks of August 5,
      addressed by the NRC.
2002, and August 12, 2002. The inspectors did not identify any safety issues in the
INPO report that either warranted further NRC followup or that had not already been
addressed by the NRC.
4OA6 Management Meetings
4OA6 Management Meetings
      Exit Meeting Summary
Exit Meeting Summary
      The inspectors presented the inspection results to Mr. Ron Jones, Site Vice President,
The inspectors presented the inspection results to Mr. Ron Jones, Site Vice President,  
      and other members of licensee management at the conclusion of the inspection on
and other members of licensee management at the conclusion of the inspection on
      July 1, 2003. The licensee acknowledged the findings presented.
July 1, 2003. The licensee acknowledged the findings presented.
      The inspectors asked the licensee whether any of the material examined during the
The inspectors asked the licensee whether any of the material examined during the
      inspection should be considered proprietary. No proprietary information was identified
inspection should be considered proprietary. No proprietary information was identified
4OA7 Licensee Identified Violation
4OA7 Licensee Identified Violation
      The following violation of very low safety significance (Green) was identified by the
The following violation of very low safety significance (Green) was identified by the
      licensee and is a violation of NRC requirements, which meets the criteria of Section VI
licensee and is a violation of NRC requirements, which meets the criteria of Section VI
      of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a NCV.
of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a NCV.
      C TS Surveillance Requirement (SR) 3.4.12.5 specifies, in part, the required channel
 TS Surveillance Requirement (SR) 3.4.12.5 specifies, in part, the required channel
        functional test frequency of the PORV to be within 12 hours after decreasing RCS
functional test frequency of the PORV to be within 12 hours after decreasing RCS
        temperature to less than or equal to 325 degrees F. On June 8, 2003, at 4:25 p.m.,
temperature to less than or equal to 325 degrees F. On June 8, 2003, at 4:25 p.m.,
        RCS temperature was lowered to less than 325 degrees F. On June 9, 2003, at 4:00
RCS temperature was lowered to less than 325 degrees F. On June 9, 2003, at 4:00
        p.m., it was discovered that the channel functional test of the Unit 3 PORV had not
p.m., it was discovered that the channel functional test of the Unit 3 PORV had not
        been completed. The functional test was subsequently completed satisfactorily at
been completed. The functional test was subsequently completed satisfactorily at
        3:26 a.m., on June 10, 2003. The circumstances involving this missed surveillance
3:26 a.m., on June 10, 2003. The circumstances involving this missed surveillance
        are described in PIP O-03-03840. Because the subsequent performance of the
are described in PIP O-03-03840. Because the subsequent performance of the
        missed TS SR was satisfactorily, this violation is of very low safety significance, and is
missed TS SR was satisfactorily, this violation is of very low safety significance, and is
        being treated as a NCV.
being treated as a NCV.


                                  SUPPLEMENTAL INFORMATION
Attachment
                                      KEY POINTS OF CONTACT
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
Licensee
S. Batson, Mechanical/Civil Engineering Manager
S. Batson, Mechanical/Civil Engineering Manager
J. Batton, Oconee Steam Generator Engineer
J. Batton, Oconee Steam Generator Engineer  
D. Baxter, Engineering Manager
D. Baxter, Engineering Manager
N. Constance, Operations Training Manager
N. Constance, Operations Training Manager
Line 1,333: Line 1,671:
B. Haag, Chief, Branch 1, Division of Reactor Projects, Region II
B. Haag, Chief, Branch 1, Division of Reactor Projects, Region II
C. Carpenter, Chief, Inspection Program Branch, NRR
C. Carpenter, Chief, Inspection Program Branch, NRR
L. Olshan, Project Manager
L. Olshan, Project Manager
                            ITEMS OPENED, CLOSED, AND DISCUSSED
ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
Opened
05000269,270,287/2003           URI         Control Room Board Component Thermal
05000269,270,287/2003
003-01                                        Reliability (Section 1R02b.(1))
003-01
05000269,270,287/2003           URI         HELB Accident Scenario Review (Section
URI
003-02                                      1R02b.(2))
      Control Room Board Component Thermal
                                                                              Attachment
      Reliability (Section 1R02b.(1))
05000269,270,287/2003
003-02
URI
      HELB Accident Scenario Review (Section
    1R02b.(2))


                                            2
2
  05000269,270,287/2003       URI         Failure to Implement Manufacturers
05000269,270,287/2003
  003-03                                    Recommendations for Replacement of
003-03
                                            SSF Diesel Coolant Grommets (Section
URI
                                            1R12.2)
      Failure to Implement Manufacturers
      Recommendations for Replacement of      
      SSF Diesel Coolant Grommets (Section    
      1R12.2)
Opened and Closed
Opened and Closed
  05000269,270,287/2003       NCV         Failure to Identify the SSF Degraded
05000269,270,287/2003
  003-04                                    Grommets as a Deficient Condition in
003-04
                                            the PIP Corrective Action Program
NCV
                                            (Section 1R12.2)
Failure to Identify the SSF Degraded
  05000269/2003003-05         NCV         Failure to Maintain Sufficient Records
Grommets as a Deficient Condition in
                                            (logs) to Furnish Evidence of Activities
the PIP Corrective Action Program
                                            Affecting Quality (TS LCOs) (Section
(Section 1R12.2)  
                                            1R14b.(1))
05000269/2003003-05
  05000269/2003003-06         NCV         Failure to Declare ES Configured
NCV
                                            Components Inoperable per TS (Section
Failure to Maintain Sufficient Records
                                            1R14b.(2))
(logs) to Furnish Evidence of Activities
  05000270,287/2003003-07     NCV         Failure to Detect Non-Conforming Parts
Affecting Quality (TS LCOs) (Section
                                            during Receipt Inspections (Section
1R14b.(1))
                                            40A5.1C)
05000269/2003003-06
NCV
Failure to Declare ES Configured
Components Inoperable per TS (Section
1R14b.(2))
05000270,287/2003003-07
NCV
Failure to Detect Non-Conforming Parts
during Receipt Inspections (Section
40A5.1C)
Items Discussed
Items Discussed
  None
None
                              LIST OF DOCUMENTS REVIEWED
LIST OF DOCUMENTS REVIEWED
(Sections 1R02 and 1R17)
(Sections 1R02 and 1R17)
Screened Out Items
Screened Out Items
Line 1,371: Line 1,726:
NSM 53065, UFSAR revision Section 9.5.1.4.3 Cable Splicing
NSM 53065, UFSAR revision Section 9.5.1.4.3 Cable Splicing
ONOE- 10642, Upgrade Seismic Supports and Add Isolation Valve 3N-305 to Nitrogen
ONOE- 10642, Upgrade Seismic Supports and Add Isolation Valve 3N-305 to Nitrogen
  Line
    Line
ONOE- 12107, Upgrade Discharge LPSW Piping from the MDEFDWPM coolers to
ONOE- 12107, Upgrade Discharge LPSW Piping from the MDEFDWPM coolers to
  1LPSW-527 ONOE- 15414, Replace Valve 2LP-15 with Item DMV-1296 2A LPI
    1LPSW-527 ONOE- 15414, Replace Valve 2LP-15 with Item DMV-1296 2A LPI
  Discharge to RBS Pump Spray and HPI Suction
    Discharge to RBS Pump Spray and HPI Suction
ONOE- 12094, Modification of Unit 2 RC Vent system Supports/Restraints
ONOE- 12094, Modification of Unit 2 RC Vent system Supports/Restraints
ONOE- 12800 ,Provide Clearance Between the Valve Body of 2SF-101 and SSF RC
ONOE- 12800 ,Provide Clearance Between the Valve Body of 2SF-101 and SSF RC
  Makeup Pump Discharge Piping
    Makeup Pump Discharge Piping


                                              3
3
ONOE- 17011, Upgrade 3-CCW-269 to Meet EQ Requirements
ONOE- 17011, Upgrade 3-CCW-269 to Meet EQ Requirements
ONOE-16856, Revise OSS-0254.00-00-1028
ONOE-16856, Revise OSS-0254.00-00-1028  
ONOE-16872, UST TAC Sheets
ONOE-16872, UST TAC Sheets
ONOE-16876, Revise Controlled Documents for RM-23A Module
ONOE-16876, Revise Controlled Documents for RM-23A Module
ONOE-16990, Revise Test Acceptance Criteria Sheets for ECCW
ONOE-16990, Revise Test Acceptance Criteria Sheets for ECCW  
ONOE-17068, Adjustable Trip Setting Correction for MCCs
ONOE-17068, Adjustable Trip Setting Correction for MCCs  
NSM 23092, 600/208 VAC Load Capacity, Rev. 0
NSM 23092, 600/208 VAC Load Capacity, Rev. 0
ONOE 11721, Include Alarm Setpoints of Stations Transformers in EDB and the OAC, 1
ONOE 11721, Include Alarm Setpoints of Stations Transformers in EDB and the OAC, 1
Line 1,392: Line 1,747:
ONOE 15256, Upgrade of Red Bus x/y Metering Transformers
ONOE 15256, Upgrade of Red Bus x/y Metering Transformers
ONOE-16712, Revise Maintenance Rule Design Basis Document to Add Reactor Building
ONOE-16712, Revise Maintenance Rule Design Basis Document to Add Reactor Building
  Ventilation Functions
  Ventilation Functions  
Evaluations
Evaluations
NSM 33090, Voltage Adequacy Project NSM-ON-33090/AL3 (RBCU Three Minute Delay),
NSM 33090, Voltage Adequacy Project NSM-ON-33090/AL3 (RBCU Three Minute Delay),  
NSM-23053, Automatic Feedwater Isolation System
NSM-23053, Automatic Feedwater Isolation System
Calculation OSC-5325, ECCW Lake Level Verification
Calculation OSC-5325, ECCW Lake Level Verification
EP 3A 1800-01, Revision 39, Turbine Building Flooding [emergency operating porcedure]
EP 3A 1800-01, Revision 39, Turbine Building Flooding [emergency operating porcedure]
NSM 13058, MSLB Leak Detection Circuitry
NSM 13058, MSLB Leak Detection Circuitry
Line 1,414: Line 1,769:
Audits
Audits
Assessment Report Number GO-02-01(NPA)(50.59)(ALL), Applicability Determination and 10
Assessment Report Number GO-02-01(NPA)(50.59)(ALL), Applicability Determination and 10
  CFR 50.59 Process Evaluation, Assessment Dates 2/4/02 - 2/7/02
  CFR 50.59 Process Evaluation, Assessment Dates 2/4/02 - 2/7/02
PIP-O-03-01300, Level II Assessment of Frametome ANP Compliance to Oconee Contractor
PIP-O-03-01300, Level II Assessment of Frametome ANP Compliance to Oconee Contractor
  Agreements, 2/18/03 - 2/18/03
  Agreements, 2/18/03 - 2/18/03
PIP-O-03-01736, Level II Assessment 2MOD03001, Review of ONS Temporary Mod Process
PIP-O-03-01736, Level II Assessment 2MOD03001, Review of ONS Temporary Mod Process


                                              4
4
Calculations
Calculations
OSC-5267, Flow from UST to Hotwell - MSN-291
OSC-5267, Flow from UST to Hotwell - MSN-291
Line 1,429: Line 1,784:
Drawings
Drawings
OFD-114A-1.4, Units 1 & 3 Flow Diagram of CC System (Drain Tank), Revision 5
OFD-114A-1.4, Units 1 & 3 Flow Diagram of CC System (Drain Tank), Revision 5
OFD-144A-3.1, Unit 3 Flow Diagram of CC System (Supply and Return),
OFD-144A-3.1, Unit 3 Flow Diagram of CC System (Supply and Return),  
Revision 7
  Revision 7
OFD-144A-3.2, Unit 3 Flow Diagram of CC System (Reactor Building and Heat Exchangers),
OFD-144A-3.2, Unit 3 Flow Diagram of CC System (Reactor Building and Heat Exchangers),
Revision 11
  Revision 11
OFD-144A-3.3, Unit 3 Flow Diagram of CC System (Control Rod Drive Service Structure and
OFD-144A-3.3, Unit 3 Flow Diagram of CC System (Control Rod Drive Service Structure and
Filters), Revision 6
  Filters), Revision 6
Procedures
Procedures
Selected Licensee Commitment 16.9.10, CC and HPI Seal Injection to Reactor Coolant
Selected Licensee Commitment 16.9.10, CC and HPI Seal Injection to Reactor Coolant    
Pumps (RCP)
  Pumps (RCP)
AP/3/1700/014, Loss of Normal HPI Makeup and/or RCP Seal Injection
AP/3/1700/014, Loss of Normal HPI Makeup and/or RCP Seal Injection
AP/3/1700/016, Abnormal Reactor Coolant Pump Operation
AP/3/1700/016, Abnormal Reactor Coolant Pump Operation
Line 1,443: Line 1,798:
UFSAR
UFSAR
Section 6.2.3, Containment Isolation System
Section 6.2.3, Containment Isolation System
Section 9.2.1, Component Cooling System
Section 9.2.1, Component Cooling System  
(Section 1R08)
(Section 1R08)
Procedures
Procedures
Framatome Technologies Procedure 54-ISI-400-11, Multifrequency Eddy Current Examination
Framatome Technologies Procedure 54-ISI-400-11, Multifrequency Eddy Current Examination
of Tubing, (with Procedure Qualification 54-PQ-400) and Change Notice 30-5027221-00 for
  of Tubing, (with Procedure Qualification 54-PQ-400) and Change Notice 30-5027221-00 for
Oconee Unit 3 EOC20 Requirements, dated April 22, 2003
  Oconee Unit 3 EOC20 Requirements, dated April 22, 2003
Eddy Current Acquisition Guidelines for Duke Power Companys Once-Through Steam
Eddy Current Acquisition Guidelines for Duke Power Companys Once-Through Steam
Generators (OTSG), Rev. 9, April 22, 2003
  Generators (OTSG), Rev. 9, April 22, 2003
Data Management Guidelines, Rev. 0, April 23, 2003
Data Management Guidelines, Rev. 0, April 23, 2003
Eddy Current Analysis Guidelines for Duke Power Companys Once-Through Steam
Eddy Current Analysis Guidelines for Duke Power Companys Once-Through Steam
Generators (OTSG), Rev. 6, April 22, 2003
  Generators (OTSG), Rev. 6, April 22, 2003


                                              5
5
Other Documents
Other Documents
Framatome ANP Engineering Information Record 51-5028238-00, In-Situ Pressure Test
Framatome ANP Engineering Information Record 51-5028238-00, In-Situ Pressure Test
Line 1,464: Line 1,819:
Procedures
Procedures
Procedure QEP 07.12-3,10CFR50.65(a)(4) Assessment
Procedure QEP 07.12-3,10CFR50.65(a)(4) Assessment
Procedure QEP 07-12, 10CFR50.59 Evaluations and 10CFR50.65 Assessments
Procedure QEP 07-12, 10CFR50.59 Evaluations and 10CFR50.65 Assessments  
NSD 403, Shutdown Risk Management (Modes 4, 5, 6, and No-Mode) per 10CFR 50.65 (a)(4),
NSD 403, Shutdown Risk Management (Modes 4, 5, 6, and No-Mode) per 10CFR 50.65 (a)(4),
  Rev. 11.
    Rev. 11.
NSD 415, Operational Risk Management (Modes 1, 2, 3) per 10CFR 50.65 (a)(4), Rev. 1.
NSD 415, Operational Risk Management (Modes 1, 2, 3) per 10CFR 50.65 (a)(4), Rev. 1.
NSD 209, 10CFR50.59 Process, Rev. 9.
NSD 209, 10CFR50.59 Process, Rev. 9.
Mcinnes Steel Company Ultrasonic Test (UT) Procedure No. UT-SA388-95, Rev. 0
Mcinnes Steel Company Ultrasonic Test (UT) Procedure No. UT-SA388-95, Rev. 0
General Nuclear Corporation, Magnetic Particle Examination, Wet Continuous Method GNC-
General Nuclear Corporation, Magnetic Particle Examination, Wet Continuous Method GNC-
  054, Rev. 1
    054, Rev. 1
Supply Chain Directive, SACD311, Rev. 1, Receipt Inspection & Testing of QA Condition Items
Supply Chain Directive, SACD311, Rev. 1, Receipt Inspection & Testing of QA Condition Items
Other Documents
Other Documents
Modification Package - RV Head Components Modification, Modification #33112, Part No. AM7,
Modification Package - RV Head Components Modification, Modification #33112, Part No. AM7,
  Rev. 0.
    Rev. 0.
Reactor Vessel Closure Head Replacement Project, Oconee Nuclear Power Plant Units 1, 2, &
Reactor Vessel Closure Head Replacement Project, Oconee Nuclear Power Plant Units 1, 2, &
    3, Input Document for Replacement RVCHA Licensing and Safety Evaluation April 2003.
    3, Input Document for Replacement RVCHA Licensing and Safety Evaluation April 2003.
Modification Package - Reactor Vessel Head Rigging and Handling, Modification # ON33112,
Modification Package - Reactor Vessel Head Rigging and Handling, Modification # ON33112,
    Part No. AS1, Rev. 1.
    Part No. AS1, Rev. 1.
Modification Package Review - Replacement of Reactor Vessel Closure Head, Service
Modification Package Review - Replacement of Reactor Vessel Closure Head, Service
    Structure and Associated Components, Modification # ON33112, Part No. 000, Rev. 0
    Structure and Associated Components, Modification # ON33112, Part No. 000, Rev. 0
    (including 10CFR50.59 Screen).
    (including 10CFR50.59 Screen).
Specification for Reactor Vessel for Duke Power Company, March 19, 1973
Specification for Reactor Vessel for Duke Power Company, March 19, 1973
Oconee Unit 3, Rector Vessel Head Penetration Preservice Inspection, February 2003
Oconee Unit 3, Rector Vessel Head Penetration Preservice Inspection, February 2003
Input Document for Replacement RVCHA Licensing and Safety Evaluation, April 2003
Input Document for Replacement RVCHA Licensing and Safety Evaluation, April 2003
Oconee Unit 3 Reactor Vessel Head Penetration Preservice Inspection - February 2003, Final
Oconee Unit 3 Reactor Vessel Head Penetration Preservice Inspection - February 2003, Final
    Report
    Report
Various site engineering drawings including Head Movement Drawings from Mammoet
Various site engineering drawings including Head Movement Drawings from Mammoet
Various FANP calcs and NCRs
Various FANP calcs and NCRs
Framatome ANP Document 32-5027297-00, Operability Assessment of CRDM Nut Ring with
Framatome ANP Document 32-5027297-00, Operability Assessment of CRDM Nut Ring with
    Reduced Tensile Strength Material
    Reduced Tensile Strength Material
PIPs: O-03-2132, O-03-2211, O-03-2177, O-03-2171, O-03-2922, O-03-2998, O-03-2844, O-
PIPs: O-03-2132, O-03-2211, O-03-2177, O-03-2171, O-03-2922, O-03-2998, O-03-2844, O-
    03-1218, O-03-2898
    03-1218, O-03-2898
Framatome ANP NCRs: 6025753, 32-5027297-00, 6024468, 6024579, 6025325
Framatome ANP NCRs: 6025753, 32-5027297-00, 6024468, 6024579, 6025325
Purchase Orders (POs): NS146-001, NS146-002, ON52461, ON13513
Purchase Orders (POs): NS146-001, NS146-002, ON52461, ON13513
Line 1,499: Line 1,854:
Corrective Action Reports (CARs): 6025777-00
Corrective Action Reports (CARs): 6025777-00


                                            6
6
(Section 40A5.1D)
(Section 40A5.1D)
Procedures, Plans, and Manuals
Procedures, Plans, and Manuals
Standard Health Physics Procedure (SH) SH/0/B/2000/005, Posting of Radiation Control
Standard Health Physics Procedure (SH) SH/0/B/2000/005, Posting of Radiation Control
  Zones, Revision (Rev.) 1
  Zones, Revision (Rev.) 1
SH/0/B/2000/012, Access Controls for High, Extra High, and Very High Radiation Areas,
SH/0/B/2000/012, Access Controls for High, Extra High, and Very High Radiation Areas,
  Rev. 1
  Rev. 1
Duke Power Company System ALARA Manual, Section IV, ALARA Planning, Rev. 15,
Duke Power Company System ALARA Manual, Section IV, ALARA Planning, Rev. 15,
  10/15/02
  10/15/02
Radiation Protection (RP) Job Coverage Plan, Rev. 1, 4/9/03
Radiation Protection (RP) Job Coverage Plan, Rev. 1, 4/9/03
RP-012, Surveillance Plan, Rev. 0, 4/15/03
RP-012, Surveillance Plan, Rev. 0, 4/15/03
Records
Records
ALARA Planning Worksheet - Unit 3 Reactor Head Replacement - Install and Remove
ALARA Planning Worksheet - Unit 3 Reactor Head Replacement - Install and Remove
  Scaffolding (Equipment Chase Area and Reactor Head Stand)
  Scaffolding (Equipment Chase Area and Reactor Head Stand)
ALARA Planning Worksheet - Unit 3 RHRP Install Shielding, Encapsulate Reactor Head and
ALARA Planning Worksheet - Unit 3 RHRP Install Shielding, Encapsulate Reactor Head and
  Decon Activities
  Decon Activities
ALARA Planning Worksheet - Unit 3 Reactor Head Replacement - Remove and Install
ALARA Planning Worksheet - Unit 3 Reactor Head Replacement - Remove and Install  
  Interferences in Equipment Chase Area
  Interferences in Equipment Chase Area
ALARA Planning Worksheet - Unit 3 Reactor Head Replacemant - Electrical/Mechanical
ALARA Planning Worksheet - Unit 3 Reactor Head Replacemant - Electrical/Mechanical  
        Disconnects and Reconnects, Remove/Install Interferences, CRD Remmoval
Disconnects and Reconnects, Remove/Install Interferences, CRD Remmoval
ALARA Planning Worksheet - Unit 3 Reactor Head Replacement - Install and Remove
ALARA Planning Worksheet - Unit 3 Reactor Head Replacement - Install and Remove
  Lifting Equipment, Remove ORVH and Install RRVH
  Lifting Equipment, Remove ORVH and Install RRVH
Radiation Survey Report 050603-30, Reactor Vessel Head, 5/6/03
Radiation Survey Report 050603-30, Reactor Vessel Head, 5/6/03
Radiation Survey Report 050703-1, Reactor Vessel Head, 5/6/03
Radiation Survey Report 050703-1, Reactor Vessel Head, 5/6/03
ALARA Briefing Packages for Radiation Work Permits 6375, 6376, 6377, 6378, 6379,
ALARA Briefing Packages for Radiation Work Permits 6375, 6376, 6377, 6378, 6379,
  and 6380
  and 6380
Daily Exposure reports for 5/6 & 7/03
Daily Exposure reports for 5/6 & 7/03
Radiation Work Permits (RWPs)
Radiation Work Permits (RWPs)
RWP 6375, U3 Rx Bldg - RHRP - Install and Remove Scaffolding, Rev. 0, 02/06/03
RWP 6375, U3 Rx Bldg - RHRP - Install and Remove Scaffolding, Rev. 0, 02/06/03
RWP 6376, U3 Rx Bldg - RHRP - Install Shielding, Encapsulate Rx Head, and Decon
RWP 6376, U3 Rx Bldg - RHRP - Install Shielding, Encapsulate Rx Head, and Decon  
  Activities, Rev. 0, 02/06/03
  Activities, Rev. 0, 02/06/03
RWP 6377, U3 Rx Bldg - RHRP - Remove and Install Interferences in the Equipment
RWP 6377, U3 Rx Bldg - RHRP - Remove and Install Interferences in the Equipment  
  Chase Area, Rev. 0, 02/06/03
  Chase Area, Rev. 0, 02/06/03
RWP 6378, U3 Rx Bldg - RHRP - Remove and Install Rx Head Interferrences, Piping, and
RWP 6378, U3 Rx Bldg - RHRP - Remove and Install Rx Head Interferrences, Piping, and
  all CRDM Work, Rev. 0, 02/06/03
    all CRDM Work, Rev. 0, 02/06/03
RWP 6379, U3 Rx Bldg - RHRP - Install and Remove Lifting Equipment, Remove Original
RWP 6379, U3 Rx Bldg - RHRP - Install and Remove Lifting Equipment, Remove Original  
  Reactor Head Assembly (RHA) and Install Replacement RHA, Rev. 0, 02/06/03
    Reactor Head Assembly (RHA) and Install Replacement RHA, Rev. 0, 02/06/03
RWP 6380, U3 Rx Bldg - RHRP - Load, Transport and Store Original RHA, Incluses All
RWP 6380, U3 Rx Bldg - RHRP - Load, Transport and Store Original RHA, Incluses All
  Outside Work, Rev. 0, 02/06/03
  Outside Work, Rev. 0, 02/06/03


                                  7
7
                            LIST OF ACRONYMS
LIST OF ACRONYMS
ADAMS - Agencywide Documents Access and Management System
ADAMS
ALARA - As Low As Reasonably Achievable
-
ASME   - American Society of Mechanical Engineers
Agencywide Documents Access and Management System
BCM   - Boiler/Condenser Mode
ALARA
BWST   - Borated Water Storage Tanks
-
CC     - Component Cooling
As Low As Reasonably Achievable
CFR   - Code of Federal Regulations
ASME
COLR   - Core Operating Limits Report
-
CRDM   - Control Rod Drive Mechanism
American Society of Mechanical Engineers
DEC   - Duke Energy Corporation
BCM
DPC   - Duke Power Company
EFW   - Emergency Feedwater
-
EHC   - Electro-Hydraulic Control
Boiler/Condenser Mode
EOC   - End of Cycle
BWST
ES     - Engineered Safeguards
-
ESI   - Engine Systems, Inc
Borated Water Storage Tanks
ET     - Eddy Current Testing
CC
FSAR   - Final Safety Analysis Report
-
HELB   - High Energy Line Break
Component Cooling
HPI   - High Pressure Injection
CFR
HPT   - Health Physics Technician
-
INPO   - Institute of Nuclear Power Operations
Code of Federal Regulations
IR     - Inspection Report
COLR
IST   - Inservice Testing
-
LBLOCA - Large Break Loss of Coolant Accident
Core Operating Limits Report
LCO   - Limiting Condition for Operation
CRDM
LLRT   - Local Leak Rate Test
-
LPI   - Low Pressure Injection
Control Rod Drive Mechanism
LPSW   - Low Pressure Service Water
DEC
NCV   - Non-Cited Violation
-
NDE   - Non-Destructive Examination
Duke Energy Corporation
NRC   - Nuclear Regulatory Commission
DPC
NRR   - Nuclear Reactor Regulation
-
NSM   - Nuclear Station Modification
Duke Power Company
OFD   - Oconee Flow Diagram
EFW
ONOE   - Minor Modification
-
ONS   - Oconee Nuclear Station
Emergency Feedwater
OTSG   - Once-Through Steam Generator
EHC
PI     - Performance Indicators
-
PIP   - Problem Investigation Process (report)
Electro-Hydraulic Control
PT     - Performance Test
EOC
PMT   - Post-Maintenance Testing
-
PORV   - Power Operated Relief Valve
End of Cycle
QA     - Quality Assurance
ES
QC     - Quality Control
-
RBCU   - Reactor Building Cooling Unit
Engineered Safeguards
RBS   - Reactor Building Spray
ESI
-
Engine Systems, Inc
ET
-
Eddy Current Testing
FSAR
-
Final Safety Analysis Report
HELB
-
High Energy Line Break
HPI
-
High Pressure Injection
HPT
-
Health Physics Technician
INPO
-
Institute of Nuclear Power Operations
IR
-
Inspection Report
IST
-
Inservice Testing
LBLOCA
-
Large Break Loss of Coolant Accident
LCO
-
Limiting Condition for Operation
LLRT
-
Local Leak Rate Test
LPI
-
Low Pressure Injection
LPSW
-
Low Pressure Service Water
NCV
-
Non-Cited Violation
NDE
-
Non-Destructive Examination  
NRC
-
Nuclear Regulatory Commission
NRR
-
Nuclear Reactor Regulation
NSM
-
Nuclear Station Modification
OFD
-
Oconee Flow Diagram
ONOE
-
Minor Modification
ONS
-
Oconee Nuclear Station
OTSG
-
Once-Through Steam Generator
PI
-
Performance Indicators
PIP
-
Problem Investigation Process (report)
PT
-
Performance Test
PMT
-
Post-Maintenance Testing
PORV
-
Power Operated Relief Valve
QA
-
Quality Assurance
QC
-
Quality Control
RBCU
-
Reactor Building Cooling Unit
RBS
-
Reactor Building Spray


                                  8
8
RCP   - Reactor Coolant Pump
RCP
RCS   - Reactor Coolant System
-
RFO   - Refueling Outage
Reactor Coolant Pump
RTP   - Rated Thermal Power
RCS
RVHRP - Reactor Vessel Head Replacement Project
-
RWP   - Radiation Work Permit
Reactor Coolant System
SBLOCA - Small Break Loss of Coolant Accident
RFO
SDP   - Significance Determination Process
-
SG     - Steam Generator
Refueling Outage
SR     - Surveillance Requirement
RTP
SSC   - Structure, System and Component
-
SSF   - Standby Shutdown Facility
Rated Thermal Power
TDEFW - Turbine Driven Emergency Feedwater
RVHRP
TS     - Technical Specification
-
UFSAR - Updated Final Safety Analysis Report
Reactor Vessel Head Replacement Project
URI   - Unresolved Item
RWP
UT     - Ultrasonic Testing
-
Radiation Work Permit
SBLOCA
-
Small Break Loss of Coolant Accident  
SDP
-
Significance Determination Process
SG
-
Steam Generator
SR
-
Surveillance Requirement
SSC
-
Structure, System and Component
SSF
-
Standby Shutdown Facility
TDEFW
-
Turbine Driven Emergency Feedwater
TS
-
Technical Specification
UFSAR
-
Updated Final Safety Analysis Report
URI
-
Unresolved Item
UT
-
Ultrasonic Testing
}}
}}

Latest revision as of 08:26, 16 January 2025

IR 05000269-03-003, IR 05000270-03-003, IR 05000287-03-003, on 04/06 - 06/28/2003, Duke Energy Corp; Oconee Nuclear Station; Maintenance Effectiveness, Personnel Performance During Non-routine Plant Evolutions, and Other Activities
ML032100780
Person / Time
Site: Oconee  Duke Energy icon.png
Issue date: 07/28/2003
From: Haag R
NRC/RGN-II/DRP/RPB1
To: Rosalyn Jones
Duke Energy Corp
References
IR-03-003
Download: ML032100780 (42)


See also: IR 05000269/2003003

Text

July 28, 2003

Duke Energy Corporation

ATTN: Mr. R. A. Jones

Site Vice President

Oconee Nuclear Station

7800 Rochester Highway

Seneca, SC 29672

SUBJECT:

OCONEE NUCLEAR STATION - NRC INTEGRATED INSPECTION

REPORT 05000269/2003003, 05000270/2003003, AND 05000287/2003003

Dear Mr. Jones:

On June 28, 2003, the NRC completed an inspection at your Oconee Nuclear Station. The

enclosed report documents the inspection findings which were discussed on July 1, 2003, with

you and other members of your staff.

The inspection examined activities conducted under your licenses as they relate to safety and

compliance with the Commissions rules and regulations and with the conditions of your

licenses. The inspectors reviewed selected procedures and records, observed activities, and

interviewed personnel.

Based on the results of this inspection, there were four NRC-identified findings of very low

safety significance (Green). These findings were determined to involve violations of NRC

requirements. However, because of their very low safety significance and because they have

been entered into your corrective action program, the NRC is treating these issues as a non-

cited violations (NCVs), in accordance with Section VI.A.1 of the NRCs Enforcement Policy.

Additionally, one licensee-identified NCV is listed in Section 4OA7 of this report. If you contest

any of the NCVs in this report, you should provide a response within 30 days of the date of this

inspection report, with the basis for your denial, to the United States 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

Oconee facility.

In accordance with 10 CFR 2.790 of the NRC's "Rules of Practice," a copy of this letter and its

enclosure will be available electronically for public inspection in the NRC Public Document

Room or from the Publicly Available Records (PARS) component of NRC's document system

DEC

2

(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/

Robert Haag, Chief

Reactor Projects Branch 1

Division of Reactor Projects

Docket Nos.: 50-269, 50-270, 50-287

License Nos.: DPR-38, DPR-47, DPR-55

Enclosure:

NRC Integrated Inspection Report 05000269/2003003, 05000270/2003003, and

05000287/2003003 w/Attachment - Supplemental Information

cc w\\encl.:

L. E. Nicholson

Compliance Manager (ONS)

Duke Energy Corporation

Electronic Mail Distribution

Lisa Vaughn

Legal Department (ECIIX)

Duke Energy Corporation

422 South Church Street

Charlotte, NC 28242

Anne Cottingham

Winston and Strawn

Electronic Mail Distribution

Beverly Hall, Acting Director

Division of Radiation Protection

N. C. Department of Environmental

Health & Natural Resources

Electronic Mail Distribution

Henry J. Porter, Director

Div. of Radioactive Waste Mgmt.

S. C. Department of Health and

Environmental Control

Electronic Mail Distribution

R. Mike Gandy

Division of Radioactive Waste Mgmt.

S. C. Department of Health and

Environmental Control

Electronic Mail Distribution

County Supervisor of

Oconee County

415 S. Pine Street

Walhalla, SC 29691-2145

Lyle Graber, LIS

NUS Corporation

Electronic Mail Distribution

M. T. Cash, Manager

Nuclear Regulatory Licensing

Duke Energy Corporation

526 S. Church Street

Charlotte, NC 28201-0006

Peggy Force

Assistant Attorney General

N. C. Department of Justice

Electronic Mail Distribution

DEC

3

Distribution w/encl:

L. Olshan, NRR

A. Hiser, NRR

L. Slack, RII, EICS

RIDSNRRDIPMLIPB

PUBLIC

OFFICE

RII:DRP

RII:DRP

RII:DRP

RII:DRS

RII:DRS

RII:DRS

RII:DRS

SIGNATURE

MXS1

GAH2

ETR

MSL1 for

MSL1 for

MSL1 for

DWJ

NAME

MShannon

GHutto

ERiggs

SVias

MScott

JBlake

DJones

DATE

7/28/2003

7/28/2003

7/28/2003

7/24/2003

7/24/2003

7/24/2003

7/28/2003

E-MAIL COPY?

YES

NO YES

NO YES

NO YES

NO YES

NO YES

NO YES

NO

OFFICE

RII:DRS

RII:DRS

RII:DRS

RII:DRS

SIGNATURE

GWL1

REC1

MSL1 for

MSL1 for

NAME

GLaska

RCarroll

RMaxey

RCortes

DATE

7/24/2003

7/28/2003

7/24/2003

7/24/2003

E-MAIL COPY?

YES

NO YES

NO YES

NO YES

NO YES

NO YES

NO YES

NO

PUBLIC DOCUMENT

YES

NO

OFFICIAL RECORD COPY DOCUMENT NAME: C:\\ORPCheckout\\FileNET\\ML032100780.wpd

U. S. NUCLEAR REGULATORY COMMISSION

REGION II

Docket Nos:

50-269, 50-270, 50-287

License Nos:

DPR-38, DPR-47, DPR-55

Report No:

50-269/03-03, 50-270/03-03, 50-287/03-03

Licensee:

Duke Energy Corporation

Facility:

Oconee Nuclear Station, Units 1, 2, and 3

Location:

7800 Rochester Highway

Seneca, SC 29672

Dates:

April 6, 2003 - June 28, 2003

Inspectors:

M. Shannon, Senior Resident Inspector

A. Hutto, Resident Inspector

E. Riggs, Resident Inspector

J. Blake, Senior Project Manager (Section 1R08)

D. Jones, Senior Health Physicist (Section 4OA5.1D)

G. Laska, Operator Licensing Examiner (Section 1R11.2)

M. Scott, Senior Reactor Inspector (Sections 1R02 and 1R17)

K. Maxey, Reactor Inspector (Sections 1R02 and 1R17)

R. Cortes, Reactor Inspector (Sections 1R02 and 1R17)

S. Vias, Senior Reactor Inspector (Sections 1R02, 1R17 and

40A5.1A-C)

R. Carroll, Senior Project Inspector (Sections 1R20)

Approved by:

Robert Haag, Chief

Reactor Projects Branch 1

Division of Reactor Projects

Enclosure

CONTENTS

Page

SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S1

REACTOR SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

1R02

Evaluation of Changes, Tests, or Experiments

. . . . . . . . . . . . . . . . . . . . . . . . . 1

1R04

Equipment Alignment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

1R05

Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

1R07

Heat Sink Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

1R08

Inservice Inspection Activities

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

1R11

Licensed Operator Requalification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

1R12

Maintenance Effectiveness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

1R13

Maintenance Risk Assessments and Emergent Work Evaluations

. . . . . . . . . 11

1R14 Personnel Performance During Non-routine Plant Evolutions

. . . . . . . . 12

1R15

Operability Evaluations

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

1R17

Permanent Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

1R19

Post-Maintenance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

1R20

Refueling and Outage Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

1R22

Surveillance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

1EP6

Drill Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

OTHER ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

4OA1 Performance Indicator Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

4OA2 Identification and Resolution of Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

4OA3 Event Followup

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

4OA5 Other Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

4OA6 Meetings, Including Exit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

4OA7 Licensee-Identified Violations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

ATTACHMENT: SUPPLEMENTAL INFORMATION

Key Points of Contact . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1

List of Items Opened, Closed, and Discussed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1

List of Documents Reviewed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-2

List of Acronyms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-7

SUMMARY OF FINDINGS

IR 05000269/2003-003, IR 05000270/2003-003, IR 05000287/2003-003; Duke Energy

Corporation; 04/06/2003 - 06/28/2003; Oconee Nuclear Station; Maintenance Effectiveness,

Personnel Performance During Non-routine Plant Evolutions, and Other Activities.

The inspection was conducted by the resident Inspectors and eight regional based inspectors:

one senior project manager; one senior project engineer; one senior health physicist; two senior

reactor inspectors; one operator licensing examiner; and two reactor inspectors. The

inspectors identified four Green findings, which were identified as NCVs. The significance of

most findings is indicated by their color (Green, White, Yellow, Red) using IMC 0609,

Significance Determination Process (SDP). Findings for which the SDP does not apply may

be Green or be assigned a severity level after NRC management review. The NRC's program

for overseeing the safe operation of commercial nuclear power reactors is described in

NUREG-1649, Reactor Oversight Process, Revision 3, dated July 2000.

A.

NRC Identified and Self-Revealing Findings

Cornerstone: Mitigating Systems

Green. A non-cited violation (NCV) of 10CFR50, Appendix B, Criterion XVI, Corrective

Action, was identified by the inspectors for failure to promptly identify the degraded

standby shutdown facility (SSF) diesel cooling water seals in the problem investigation

process (PIP) program.

This finding was considered to be more than minor based on the fact that subsequent

analysis of the grommets noted significant degradation and this analysis would likely not

have been performed without initiation of the PIP. Therefore, if the cause of the

degradation was left uncorrected, the mitigation systems cornerstone objective of

ensuring the continued reliability of equipment needed to respond to initiating events

would be affected. In addition, continued degradation of the grommets would become a

more significant safety concern. This issue was considered to be of low safety

significance (Green) because the grommets were replaced during the SSF diesel

overhaul before they failed in service. (Section 1R12.2)

Green. A NCV of Technical Specification (TS) 5.4.1 and 10CFR50, Appendix B,

Criterion XVII Quality Assurance Records, was identified by the inspectors for failure to

maintain sufficient records [logs] to furnish evidence of activities affecting quality [TS

Limiting Conditions for Operation (LCOs)]. Specifically, operator logs provided

insufficient data to reconstruct the activities related to the June 22, 2003, Unit 1

Engineered Safeguards (ES) power supply failure, which affected the Engineered

Safeguards Protection System (ESPS) Digital Automatic Actuation Logic Channels 2, 4,

6, and 8.

The ESPS automatic initiation of ES functions to mitigate accident conditions is

assumed in the accident analysis and is required to ensure that consequences of

analyzed events do not exceed the accident analysis predictions. The failure to

adequately document TS LCO entry and action times for the failed automatic ES

actuation circuitry was considered to be more than minor because it impacted the

2

operators ability to accurately implement the TS LCO action statements, and if left

uncorrected, this type of improper documentation could become a more significant

safety concern. The finding was considered to be of very low safety significance based

on the fact that the ES power supply was returned to service before any LCO condition

would have required the unit to be in Mode 3. (Section 1R14b.(1))

Green. A NCV of TS 3.3.7 Condition A , Engineered Safeguards Protection System

(ESPS) Digital Automatic Actuation Logic Channels, was identified by the inspectors

when it was discovered that the licensee failed to declare a number of ES configured

system components inoperable following the loss of ESPS digital channels 2, 4, 6, and

8.

The ESPS automatic initiation of ES functions to mitigate accident conditions is

assumed in the accident analysis and is required to ensure that consequences of

analyzed events do not exceed the accident analysis predictions. Consequently, this

issue is more than minor, in that by not recognizing the importance of the lost automatic

ES initiation function and taking the compensatory actions of TS 3.3.7, the mitigating

systems cornerstone objective of ensuring the continued reliability of equipment needed

to respond to initiating events was affected. However, this issue was determined to be

of very low safety significance, based on the fact that there was no loss of function of

the Low Pressure Service Water system or the Keowee Hydro Units resulting from the

loss of ESPS Digital Automatic Actuation Logic Channels 2, 4, 6, and 8. Additionally,

the ES power supplies were restored and digital channels returned to service prior to

exceeding any TS allowed outage times for the affected components. (Section

1R14b.(2))

Cornerstone: Initiating Events

Green: A NCV of 10CFR50.55a(g)(4) and 10CFR50, Appendix B, Criterion VII was

identified by the inspectors, in that measures taken to preclude the installation of non-

conforming replacement parts and the ability to evaluate the suitability of replacement

during the Quality Assurance (QA) receipt inspection process were not adequate.

Specifically, this was identified for inadequate QA review during receipt inspections that

resulted in the licensee installing one non-conforming Control Rod Drive Mechanisms

(CRDM) (Split Nut) Flange Ring on Unit 2, and discovering, prior to the installation in

Unit 3, 68 CRDMs and 552 CRDM Hold Down Bolts that did not meet the design and

procurement specifications.

This finding was more than minor because non-conforming material was actually

installed in Unit 2. However, it was determined to be of very low safety significance

because there was not a loss of system function. (Section 40A5.1C)

B.

Licensee Identified Violations

One violation of very low safety significance, which was identified by the licensee has

been reviewed by the inspectors. Corrective actions taken or planned by the licensee

have been entered into the licensees corrective action program. This violation is listed

in Section 4OA7.

Report Details

Summary of Plant Status:

Unit 1 operated at 100 percent rated thermal power (RTP) during the inspection period except

for one power reduction. The unit was reduced to approximately 50 percent RTP on May 17,

2003, following a safety group 4 dropped rod. The rod was recovered and the unit was

returned to 100 percent RTP on May 18, 2003.

Unit 2 operated at 100 percent RTP during the inspection period except for two power

reductions. The unit was reduced to approximately 88 percent RTP on April 13, 2003, to

perform turbine valve movement testing. The unit was returned to 100 percent power later that

same day. On June 22, 2003, the unit was reduced to approximately 87 percent RTP to again

perform turbine valve movement testing. The unit was returned to 100 percent power later that

same day.

Unit 3 entered the report period at 93 percent RTP with an end of core life coastdown in

progress. The unit was shutdown on April 26, 2003, for a refueling outage. Following the

outage, the unit entered Mode 1 on June 14, 2003, and reached 100 percent RTP on June 18,

2003. On June 28, 2003, the unit was reduced to 15 percent RTP and the turbine taken off-line

for turbine balancing. The report period ended with the unit at 15 percent RTP.

1. REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R02

Evaluations of Changes, Tests or Experiments

a.

Inspection Scope

The inspectors reviewed selected samples of evaluations to confirm that the licensee

had appropriately considered the conditions under which changes to the facility,

Updated Final Safety Analysis Report (UFSAR), or procedures may be made, and tests

conducted, without prior NRC approval. The inspectors reviewed evaluations for nine

changes and additional information, such as calculations, supporting analyses, the

UFSAR, and drawings to confirm that the licensee had appropriately concluded that the

changes could be accomplished without obtaining a license amendment. The nine

evaluations reviewed are listed in the Attachment to this report.

The inspectors also reviewed samples of changes such as design changes, UFSAR

changes, commercial grade dedication packages, equipment problem issues, and like-

for-like evaluations for which the licensee had determined that evaluations were not

required, to confirm that the licensees conclusions to screen out these changes were

correct and consistent with 10CFR50.59. The twenty-one screened out changes

reviewed are listed in the List of Documents Reviewed.

The inspectors also reviewed an audit of the 10CFR50.59 process and selected

Problem Investigation Process reports (PIPs) to confirm that problems were identified at

2

an appropriate threshold, were entered into the corrective action process, and

appropriate corrective actions had been initiated.

b.

Findings

(1)

Introduction: One Unresolved Item (URI) was identified in that potentially the air

temperature inside of the units control room boards (vertical and unit boards) may reach

a higher than anticipated value than previously understood during design basis events.

Description: During the review of an UFSAR change to Section 3.11.5, Loss of

Ventilation, the inspectors observed the control room area temperature maximum was

stated to be 120 degrees F. The section did not address control board interior

temperature rise nor did it discuss the maximum value that could be reached inside

boards for the discussed event. The inspectors realized that other events not discussed

in the reviewed section could cause a loss of forced ventilation to the boards. When the

licensee was informed that the heat generating temperature sensitive electronics interior

to the boards may see a higher temperature than the control room ambient temperature,

PIP O-03-04052 was written on the issue. During normal operations, Technical Specification (TS) 3.7.16 limits the control room general area temperature to 80

degrees F.

The temperature difference between the ambient control room temperature and the

interior temperature of the boards was not clearly documented. Forced ventilation to the

boards and to the control room is postulated to be lost during such events as loss of

offsite power and seismic occurrences. There is a degraded control room ventilation

abnormal procedure. All related event and abnormal procedures do not address control

board interior temperatures nor do they have special instructions for reducing the interior

temperature of the boards during the loss of forced ventilation cooling. With the loss of

forced ventilation, a rise in temperature inside the board may occur and this rise may be

greater than that experienced in the control room inhabited space where control room

temperature is measured. Such a rise may be detrimental to critical electronic

equipment operation.

The aforementioned PIP stated that there was reasonable assurance that the equipment

inside of the control boards is operable during the event scenarios. This was based on

calculations that determined that the general area temperature rise after six hours would

be approximately 90 degrees F (calculation OSC-6667). The licensee stated that the

most limiting equipment in the boards has continuous duty temperature of 122 degrees

F, which is 32 degrees F higher than the six hour rise value. The event and abnormal

procedures are written to limit the time without forced ventilation. Further, the licencee

indicated in PIP O-00-4643, that the time required to restore cooling following a loss of

offsite power event was estimated to be less than 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. PIP O-03-4052 indicated

that an operability evaluation would be performed to further investigate the relationship

between the temperature inside the main control boards and the control rooms on all

three units.

The inspectors were aware that there are some passive vents and holes in the top of the

control boards and louvers on the side of the boards could possibly dissipate board

interior heat buildup. Further, the inspectors were aware of procedures and equipment

3

in other locations that could be relied upon for safe shutdown purposes should the

abandonment of the control room be required.

However, the following issues require additional review by the licensee: an

understanding of the peak temperature reached in each unique control cabinet in each

control room space; the critical electronic components needed for plant operation during

the postulated events; the suitability of equipment in the control boards to withstand

environmental temperature such as records documenting the component vendors

continuous duty temperatures for the considered critical parts; and, critical components

locations relative to possible warm spots on the boards should also be understood

(board thermal profile relative to component location).

Until the licensee can demonstrate a clear understanding of the thermal effects on

control room board components during a postulated loss of control board forced cooling

occurrence, this issue will be identified as URI 05000269,270,287/2003003-001:

Control Room Board Component Thermal Reliability.

(2)

Introduction: An URI was identified concerning Oconee UFSAR Section 3.6.1.3 that was

changed on May 17, 2001, under the old 50.59 program revision. During a review of the

change, the inspectors were concerned that the change may involve an unreviewed

safety question (USQ) under the old rule or a departure from a method of evaluation

under the new rule.

Discussion: The UFSAR change was associated with high energy line break (HELB) on

a main feedwater line. The escaping water/steam is assumed to disable the 4160 Volt

breakers for at least the motor driven emergency feedwater (EFW) pumps and for the

high pressure injection HPI pumps. The change increased the time allowed for initiation

of EFW and (HPI) after the HELB from 15 minutes to 30 minutes and from 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to 8

hours, respectively.

The 1998 UFSAR version used RETRAN program analysis and the lower equipment

recovery times that kept the reactor coolant system (RCS) subcooled and capable of

natural circulation (minimally voided) due to the small amount of water loss. Under the

May 2001 revision, the licensee used RELAP 5 program and extended times for

equipment recovery of EFW and HPI. This results in significant voiding in the RCS, loss

of subcooling, increased number of cycles of the pressurizer safety valves, loss of

natural circulation, and reliance on the boiler/condenser mode (BCM) of decay heat

removal for up to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> without safety injection. Under BCM, the expansion and

collapsing of the RCS remaining volume would cause some pressure spikes within the

RCS. This evaluation was based on licensee calculation OSC-7299, Revision 1. Page

4 of the 10 CFR 50.59 evaluation discusses RELAP5 in that:

The analytical model utilized to evaluate these effects was changed from RETRAN

to RELAP5 because of the significant RCS voiding that will occur and the

importance of boiler condenser mode of decay heat removal. The version of

RELAP5 used is similar [to] a version approved by the NRC for use by Frametone

Technologies in small break loss of coolant accident (SBLOCA) UFSAR analysis of

OTSG plants. Additionally, the NRC has approved this version for use by Duke

4

Power Company in both SBLOCA and large break loss of coolant accident

(LBLOCA) mass and energy release analysis. The additional delays in EFW and

HPI restoration result in a transient that is essentially a small break LOCA.

The inspectors were concerned that this change appears to represent an USQ, as

defined by the previous version of 10 CFR 50.59. (The evaluation was completed under

the old 10 CFR 50.59 rule on May 17, 2001, and the licensee implemented the revised

rule on July 2, 2001). In this scenario, the pressurizer safety valves are challenged to lift

and reseat multiple times while passing steam and then water until EFW is recovered.

The licensee did not consider that the increased number of cycles of these valves would

increase the probability of a malfunction (i.e., sticking open) and create the possibility of

an accident of a different type (loss of coolant). With a stuck open valve and no safety

injection, core damage would result. The licensees evaluation states that RELAP 5 has

been approval for LOCA analysis, but it is not clear as to the acceptability of this method

of evaluation for HELB. Furthermore the concept of allowing the RCS to become

significantly voided, saturated, without natural circulation, without HPI for eight hours,

and reliance on BCM for decay heat removal, appears to be a departure from a method

of evaluation as described in the UFSAR, which would require prior NRC approval under

the current regulation. Until the NRC completes its review of the above issue, it will be

identified as URI

05000269,270,287/2003003-002: HELB Accident Scenario Review.

1R04

Equipment Alignment

.1

Partial Walkdown

a.

Inspection Scope

The inspectors conducted partial equipment alignment walkdowns to evaluate the

operability of selected redundant trains or backup systems while the other train or

system was inoperable or out of service. The walkdowns included, as appropriate,

reviews of plant procedures and other documents to determine correct system lineups

and verification of critical components to identify any discrepancies which could affect

operability of the redundant train or backup system. The following systems were

included in this review:

Unit 2 HPI trains 2A and 2B while the 2C HPI pump was out of service for preventive

maintenance

Unit 2 train A low pressure injection (LPI) while the B train of LPI was out of service

for maintenance

Units 1 and 2 primary instrument air system with the backup instrument air

compressor out of service for preventive maintenance

b.

Findings

No findings of significance were identified.

5

.2

Complete System Walkdown.

a.

Inspection Scope

The inspectors conducted a detailed review of the alignment and condition of the Unit 3

component cooling (CC) system. The inspectors utilized licensee procedures and other

documents listed in the Attachment to verify proper system alignment.

The inspectors also verified electrical power requirements, labeling, hangers, support

installation, and associated support system status. The operating pump was examined

to ensure that any noticeable vibration was not excessive, bearings were not hot to the

touch, and the pump was adequately ventilated. The walkdown also included an

evaluation of the system piping and supports against the following considerations:

Piping and pipe supports did not show evidence of water hammer

Hangers were properly sized and were within the setpoints

Piping insulation was adequate and showed no evidence of prior system leaks

Component foundations were not degraded

A review of PIPs and maintenance work orders was performed to verify that material

condition deficiencies did not significantly affect the ability of the CC system to perform

its design functions and that appropriate corrective action was being taken by the

licensee.

The inspectors also held discussions with the system and design engineers on

temporary modifications, future modifications, and operator workarounds to ensure that

the impact on the equipment functionality was properly evaluated.

b.

Findings

No findings of significance were identified.

1R05

Fire Protection

a. Inspection Scope

The inspectors conducted tours in thirteen areas of the plant to verify that combustibles

and ignition sources were properly controlled, and that fire detection and suppression

capabilities were intact. The inspectors selected the areas based on a review of the

licensees safe shutdown analysis and the probabilistic risk assessment based

sensitivity studies for fire related core damage sequences. Inspection of the following

areas were conducted during this inspection period:

Units 1 and 2 and Unit 3 HPI Rooms (2)

Units 1, 2 and 3 Equipment Rooms (3)

6

Units 1, 2 and 3 LPI/RBS Rooms (5)

Keowee Hydro Units (2)

Unit 2 Turbine Building Switchgear Area (1)

b.

Findings

No findings of significance were identified.

1R07

Heat Sink Performance

.1

Unit 3 Low Pressure Injection System Cooler Test

a.

Inspection Scope

The inspectors reviewed TT/3/A/0150/061, Unit 3 Low Pressure Injection System Cooler

Test, used to gather data for the LPI cooler performance evaluation. This testing was

performed to ensure that the cooler is able to meet TS and design basis requirements.

The inspection focused on compliance with the procedure requirements and appropriate

data collection during the testing. The inspectors also reviewed design calculation

OSC - 4338 Revision 7, to ensure that the LPI heat exchanger, based on the test data,

was capable of performing its design function per the calculation.

b.

Findings

No findings of significance were identified.

.2

Unit 1 Reactor Building Cooling Units (RBCU) Performance Test

a.

Inspection Scope

The inspectors reviewed Unit 1 RBCU Performance Test, PT/0/A/0160/006, used to

gather data for the RBCU performance evaluation. This testing was performed to verify

that the RBCU cooling capacity meets TS and design basis requirements. The

inspection focused on compliance with the procedure requirements and appropriate

data collection during the testing. The inspectors also reviewed design calculation

OSC - 5665, Attachment 27, which calculated the RBCU capacity factors from the

obtained test data.

b.

Findings

No findings of significance were identified.

7

1R08 Inservice Inspection (ISI) Activities

a.

Inspection Scope

Unit 3 Steam Generator (SG) Inspection

The inspectors reviewed the implementation of the licensees program for monitoring the

performance of the U3 once-through steam generators (OTSG). The inspector

observed examinations and reviewed selected inspection records for:

-

Eddy current examination (ET) data for eleven OTSG tubes.

-

Tube plugging operations including quality control verification of tube locations.

-

In-situ pressure testing data used to evaluate SG tube structural and leak tight

integrity of thirteen SG tubes (twelve in SG A and one in SG B)

-

Certifications for ten Quality Assurance (QA) Level III Eddy Current Data Analysts

-

SG tube repair (plugging) lists generated as a result of the Unit 3 SG ET inspection.

The above activities and records were compared to the TS, License Amendments, and

applicable industry established performance criteria to verify compliance. Documents

reviewed are listed in the Attachment to this report.

b.

Findings

No findings of significance were identified.

1R11

Licensed Operator Requalification

.1

Simulator Scenarios

a.

Inspection Scope

The inspectors observed licensed operator simulator training on June 27, 2003. The

scenario involved a dropped rod, a reactor trip, a steam generator tube leak in the 1B

steam generator, and a main steam line break. The inspectors also observed entry into

the emergency action levels (Unusual Event and Alert). The inspectors observed crew

performance in terms of: communications; ability to take timely and proper actions;

prioritizing, interpreting, and verifying alarms; correct use and implementation of

procedures, including the alarm response procedures; timely control board operation

and manipulation, including high-risk operator actions; and oversight and direction

provided by the shift supervisor, including the ability to identify and implement

appropriate TS actions.

8

b.

Findings

No findings of significance were identified.

.2

Annual Operating Test Results

a.

Inspection Scope

Following the completion of the annual operating examination testing cycle, which ended

on May 9, 2003, the inspectors reviewed the overall pass/fail results of the biennial

written examination, the individual Job Performance Measure operating tests, and the

simulator operating tests administered by the licensee during the operator licensing

requalification cycle. These results were compared to the thresholds established in

Manual Chapter 609 Appendix I, Operator Requalification Human Performance

Significance Determination Process.

b.

Findings

No findings of significance were identified.

1R12

Maintenance Effectiveness

.1

Routine Maintenance Effectiveness Reviews

a.

Inspection Scope

The inspectors reviewed the licensees effectiveness in performing routine maintenance

activities. This review included an assessment of the licensees practices pertaining to

the identification, scoping, and handling of degraded equipment conditions, as well as

common cause failure evaluations. For each item selected the inspectors performed a

detailed review of the problem history and surrounding circumstances, evaluated the

extent of condition reviews as required, and reviewed the generic implications of the

equipment and/or work practice problem. For those systems, structures, and

components (SSCs) scoped in the maintenance rule per 10 CFR 50.65, the inspectors

verified that reliability and unavailability were properly monitored and that 10 CFR 50.65

(a)(1) and (a)(2) classifications were justified in light of the reviewed degraded

equipment condition. The inspectors reviewed the following item:

PIP O-03-02888, Turbine Driven Emergency Feedwater Pump Steam Nozzle Bolt

Failure Issue

b.

Findings

No findings of significance were identified.

9

.2

Effectiveness of Standby Shutdown Diesel Preventive Maintenance and Problem

Identification

a.

Inspection Scope

The inspectors observed the 10-year overhaul of the Standby Shutdown Facility (SSF)

diesel, and selected for further review, those problems which were identified by outside

contractors. Specifically, the inspectors reviewed problems being identified by Engine

Service, Inc. contractors who were contracted by the licensee to provide technical

oversight for the 10-year overhaul of the SSF diesel engines and to assist with the

maintenance activities. For this inspection activity, the inspectors reviewed the daily

field service reports provided by the contractors to the licensee to evaluate the

adequacy of previous maintenance activities and to verify that problems identified by the

contractors were being appropriately documented in the licensees corrective action

program.

b.

Findings

Introduction: Two separate issues were identified as a result of this inspection:

(1) A Green non-cited violation (NCV) was identified by the inspectors for failure to

promptly identify degraded SSF diesel cooling water seals in the PIP program.

(2) An URI was identified, in that the licensee failed to implement the 6-year

recommended diesel manufacturer (EMD) preventive maintenance grommet

replacements. Consequently, at 10 years some of the grommets were found to be

at or near failure. Failure of the grommets could have led to diesel coolant leaks

and loss of cooling to the diesel. This issue will remain unresolved pending

completion of a Phase 3 risk review.

Description: During the June 2002, SSF diesel overhaul, the inspectors discussed

diesel equipment problems with the maintenance contractors from Engine Systems, Inc.

(ESI) who were providing technical oversight for the SSF diesel overhaul. The day shift

ESI contractor noted that the SSF diesel coolant grommets, located on the cylinder

heads (power packs), had been found degraded. He informed the inspectors that this

adverse condition would be provided to the licensee in a daily field service report. The

inspectors subsequently discussed the degraded grommet condition with maintenance

management to ensure that they were aware of the potential problem. The June 18,

2002, ESI daily field service report documented that Cylinder 7 on Engine B, had

deformed grommets on the cylinder head, unable to determine if the deformities were

from overheating or from installation damage. The June 19, 2002, ESI daily field

service report documented that Cylinder 8 on Engine A, had deformed head

grommets.

On June 27, 2002, prior to returning the diesel to service and after noting that a PIP

report had not been initiated, the inspectors discussed the deformed grommet issue with

licensee management. On June 28, 2002, PIP O-02-03526 was initiated to capture the

potential degraded grommet condition.

10

Subsequent discussions with engineering noted that some of the deformed grommets

were going to be sent off for analysis. At this time, the inspectors also noted that the

grommets from Cylinder 7 on Engine B and Cylinder 8 on Engine A had not been

segregated from the grommets from the other 26 cylinders. It was also noted that the

licensee could not account for all of the replaced grommets, in that only 282 of the 336

replaced grommets could be located.

During various discussions regarding the grommets, the licensee noted that the diesel

manufacturer (EMD) had recommended a 6-year replacement interval for these

grommets. However, the grommets were being replaced on a 10-year interval and the

EMD owners group was discussing the possibility of EMD changing the replacement

interval to 12 years.

In October 2002, the remaining 282 grommets were sent off to ESI for analysis. On

May 8, 2003, the results of the ESI analysis were received by the licensee. The report

noted that Diesel engines used in standby service see thermal cycling which

contributes to the hardening of these grommets. Therefore, the recommended

replacement interval is on a 6 year calendar basis. ESIs analysis concluded the

following: 31 grommets were approaching the end of life; 6 grommets had been torn

during removal and that a new grommet cannot be readily torn by hand, the ability to

tear these grommets indicates their pliability has been compromised, likely due to aging

and their brittle nature indicates they were near the end of life; 43 grommets show a

high degree of brittleness and degradation, these are considered abnormal to a typical

reseal interval, It can be assumed these grommets were still capable of performing

their sealing function, and the state of brittleness and separation they exhibit indicates

they have exceeded their useful life; and last 19 grommets were distorted into a D

shape, considered to be classic examples of cylinder combustion leaks and with no

reported leaks, it must be assumed they performed their sealing function; however,

these grommets have exceeded their useful life. EMD went on to state that Continued

operation with grommets exposed to combustion gases will lead to failure and coolant

leaks.

EMD concluded the analysis with the following: Many of the components examined in

this investigation were at or near failure, and although no coolant leaks were reported,

combustion leaks were definitely occurring in some cylinders. Coolant leaks were likely

to follow, as those cylinders grommets exposed to combustion gases would have

continued to decay until their sealing ability was exhausted. EMD also stated that

Diesel engines in standby service experience more severe thermal cycling at each

surveillance run as compared to engines in continuous duty. This thermal cycling

promotes age-hardening in these seals, and the recommended 6-year maintenance

interval is a preventive maintenance practice that must be adhered to for continued

reliability.

Analysis

The issue of not initially writing a PIP to capture the ESI identified grommet degradation

was considered to be greater than minor based on the fact that subsequent analysis of

the grommets noted significant degradation and this analysis would likely not have been

performed without initiation of the PIP. Therefore, if the cause of the degradation was

11

left uncorrected, the mitigation systems objective of ensuring the continued reliability of

equipment needed to respond to initiating events would be affected. In addition,

continued degradation of the grommets would become a more significant safety

concern. This issue was considered to be of low safety significance (Green) because

the grommets were replaced during the SSF diesel overhaul before they failed in

service.

The issue of not performing the recommended grommet replacements was considered

to be more than minor in that the degraded grommets affected the equipment reliability

of a mitigation system (i.e., the SSF diesel). The finding was first evaluated in the

Phase 1 SDP based on the degraded reliability of a mitigating system under the Reactor

Safety Cornerstone. Based on the manufacturers conclusion that the grommets had

exceeded their useful life and that continued operation with grommets exposed to

combustion gases would lead to failure and coolant leaks, it was assumed that the

finding represented an actual loss of safety function of the SSF diesel, as the loss of

coolant could preclude operation of the diesel for its 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> mission time. Since this

system was designated as a risk significant system per 10 CFR 50.65, a Phase 2

analysis was performed. The Phase 2 analysis indicated that the issue could be greater

than Green; therefore, a Phase 3 analysis was required. Pending completion of the

Phase 3 analysis, the issue of not implementing the manufacturers recommendations

for replacement of the SSF diesel coolant grommets will be identified as URI

05000269,270,287/2003003-03: Failure to Implement Manufacturers Recommendations

for Replacement of SSF Diesel Coolant Grommets. This issue is in the licensees

corrective action program as PIP O-02-03526.

Enforcement

10 CFR 50, Appendix B, Criterion XVI, requires that measures shall be established to

assure that conditions adverse to quality, such as...deficiencies, deviations, defective

material and equipment, and non-conformances are promptly identified. The licensees

quality assurance (QA) program implements this requirement through Nuclear Station

Directive 208, Problem Investigation Process, Revision 22. Section 208.6, Problem

Identification, states that a PIP should be initiated within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of recognition of the

issue. Contrary to 10 CFR 50 Appendix B, Criterion XVI, following the June 19, 2002,

identification of the degraded grommets which could be the result of improper

installation, a PIP was not initiated until June 28, 2002, which was after all of the SSF

diesel grommets had been replaced. This inadequate corrective action issue is being

treated as an NCV, consistent with Section VI.A.1 of the enforcement policy and is

identified as NCV 05000269,270,287/2003003-04: Failure to Identify the SSF Degraded

Grommets as a Deficient Condition in the PIP Corrective Action Program. This issue is

in the licensees corrective action program as PIP O-02-03526.

1R13

Maintenance Risk Assessment and Emergent Work Evaluations

a.

Inspection Scope

The inspectors evaluated, as appropriate for the selected SSCs listed below: (1) the

effectiveness of the risk assessments performed before maintenance activities were

conducted; (2) the management of risk; (3) that, upon identification of an unforseen

12

situation, necessary steps were taken to plan and control the resulting emergent work

activities; and (4) that maintenance risk assessments and emergent work problems

were adequately identified and resolved.

PIP O-03-3584, Unexpected Closure of 1HP-5 Letdown Isolation Valve, caused by

failure of an improperly installed control air solenoid

IP/0/A/2005/003, Keowee Hydro Station Westinghouse Voltage Regulator Test,

performed as part of troubleshooting for failed voltage regulator

PIP O-03-2925, Increased HPI Motor Cable Insulation Leakage

Preventive Maintenance on Unit 2 Electro Hydraulic Control (EHC) System per Work

Orders 98592430 and 98592429

PIP O-03-3800, Unit 3 RC-4 Power Operated Relief Valve (PORV) Block Valve

Leakage and Repair

PIP O-03-02381, 3MS -155 (Main Steam Line B Atmospheric Vent) could not be

opened when attempting to depressurize the steam generator

PIP O-03-04140, Identification of Risk Assessment Error for Previous Repair of

3RC-4. Credit was inappropriately given for availability of the steam generators

although the RCS loops were not filled.

b.

Findings

No findings of significance were identified.

1R14

Personnel Performance During Non-routine Plant Evolutions

a.

Inspection Scope

The inspectors reviewed, the operating crews performance during selected non-routine

events and/or transient operations to determine if the response was appropriate to the

event. As appropriate, the inspectors: (1) reviewed operator logs, plant computer data,

or strip charts to determine what occurred and how the operators responded;

(2) determined if operator responses were in accordance with the response required by

procedures and training; (3) evaluated the occurrence and subsequent personnel

response using the SDP; and (4) confirmed that personnel performance deficiencies

were captured in the licensees corrective action program. The non-routine evolution

reviewed during this inspection period included the following:

Loss of 700 Gallons of RCS in Unit 3 Due to Over-pressurization of LPI Suction (PIP

O-03-02362)

Unit 1 Dropped Rod and Subsequent Recovery

Failure of the Unit 1 Channel B Engineered Safeguards (ES) Power Supply

13

b.

Findings

(1)

Introduction: A Green NCV was identified by the inspectors for failure to maintain

sufficient records [logs] to furnish evidence of activities affecting quality [TS Limiting

Conditions In Operations (LCOs)].

Description: On June 22, 2003, the Unit 1 ES channel B power supply failed. This

failure, caused a loss of power to the Engineered Safeguards Protection System (ESPS)

Digital Automatic Logic Channels 2, 4, 6, and 8. Subsequently, the inspectors reviewed

the licensees operator logs and TS tracking systems. The inspectors noted that the

operator logs provided insufficient data to reconstruct the activities related to the ES

power supply failure. The inspectors noted that the documented time for declaring the

components related to ES channels 2, 4, 6, and 8 per TS 3.3.7, had been improperly

changed and backdated from 9:55 a.m. to 9:15 a.m. In addition, the time of discovery

of the failed power supply was backdated to 8:15 a.m., although the ES channel B

power supply was functioning properly at that time. The logs did not provide any

justification for this change. Also, the inspectors noted that the logs indicated the

control room operators were informed of the loss of power to the ES digital channels at

8:51 a.m.; however, the TS tracking documents noted that the ES digital channels

became inoperable at 8:55 a.m. The various times were considered to be important

because they provided evidence for activities associated with meeting the 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> action

statement of TS 3.3.7 for placing the associated components in their ES positions or

declaring the components inoperable.

Analysis: The ESPS automatic initiation of ES functions to mitigate accident conditions

is assumed in the accident analysis and is required to ensure that consequences of

analyzed events do not exceed the accident analysis predictions. The failure to

adequately document TS LCO entry and action times for the failed automatic ES

actuation circuitry was considered to be more than minor because it impacted the

operators ability to accurately implement the TS LCO action statements, and if left

uncorrected, this type of improper documentation could become a more significant

safety concern. The finding was considered to be of very low safety significance

(Green) based on the fact that the ES power supply was returned to service before any

LCO condition would have required the unit to be in Mode 3. This observation was

based on the inspectors review of the associated completed surveillances and use of

computer alarm summaries as a basis for the initial failure time.

Enforcement: TS 5.4.1 requires that written procedures be established, implemented,

and maintained covering activities related to procedures recommended in Regulatory

Guide 1.33 Rev. 2, Appendix A, 1978. Regulatory Guide 1.33, Section 1(g),

Administrative Procedures, requires log entries. 10 CFR 50, Appendix B, Criterion XVII,

Quality Assurance Records, requires that sufficient records shall be maintained to

furnish evidence of activities affecting quality. Contrary to the above, sufficient

logkeeping and TS tracking records were not sufficiently maintained to furnish evidence

of activities related to TS LCO action statements. Because the finding is of very low

safety significance and has been entered into the corrective action program as PIP O-

03-04408, this violation is being treated as NCV 05000269/2003003-05: Failure to

Maintain Sufficient Records (logs) to Furnish Evidence of Activities Affecting Quality (TS

LCOs).

14

(2)

Introduction: A Green NCV of TS 3.3.7 Condition A , Engineered Safeguards Protection

System (ESPS) Digital Automatic Actuation Logic Channels, was identified by the

inspectors when it was discovered that the licensee failed to declare a number of ES

configured system components inoperable following the loss of ES digital channels 2, 4,

6, and 8 as required.

Description: As indicated in (1) above, the June 22, 2003, power supply failure of Unit 1

ES Analog Channel B resulted in the subsequent loss of Unit 1 ES Digital Actuation

Channels 2, 4, 6, and 8. Upon declaring one or more ES digital automatic actuation

logic channels inoperable, TS LCO 3.3.7 Condition A .1, requires that ES configured

components associated with that channel be placed in their ES configuration, or

Condition A.2 requires that the components associated with that channel be declared

inoperable. The inspectors determined that the licensee failed to either place the

affected components in their ES configuration or declare them inoperable within one

hour as required by the TS. Since placing the affected components in their ES

configuration would in this case violate unit safety or operational considerations, the

licensee was required to declare the components inoperable within one hour and enter

the associated component TS LCO. Specifically, the licensee failed to enter TS 3.3.17

Condition A, one channel of the emergency power switching logic (EPSL) automatic

transfer function inoperable [channel B from ES channel 2], TS 3.3.21 Condition A, one

channel of the EPSL Keowee Hydro Unit (KHU) emergency start function inoperable

[channel B from ES channel 2], and TS 3.7.7 Condition A, one required low pressure

service water (LPSW) pump inoperable [LPSW pump B from ES channel 4].

Analysis: The ESPS automatic initiation of ES functions to mitigate accident conditions

is assumed in the accident analysis and is required to ensure that consequences of

analyzed events do not exceed the accident analysis predictions. Consequently, this

issue is more than minor, in that by not recognizing the importance of the lost automatic

ES initiation function and taking the compensatory actions of TS 3.3.7, the mitigating

systems cornerstone objective was affected. However, this issue was determined to be

of very low safety significance (Green), based on the fact that there was no loss of

function of the LPSW system or the KHUs resulting from the loss of ESPS Digital

Automatic Actuation Logic Channels 2, 4, 6, and 8. Additionally, the ES power supplies

were restored and digital channels returned to service prior to exceeding any TS allowed

outage times for the affected components.

Enforcement: TS 3.3.7 Condition A .1 requires that ES configured components

associated with an inoperable ESPS Digital Automatic Actuation Logic Channel be

placed in their ES configuration, or TS 3.3.7 Condition A.2 requires that the components

associated with the inoperable channel be declared inoperable. Contrary to the above,

the licensee failed to place all effected ES components in their ES configuration or

declare the associated components inoperable following the loss of ES digital channels

2, 4, 6, and 8. Because this finding is of very low safety significance and has been

entered into the corrective action program as PIP O-03-04408, this violation is being

treated as a NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy. It will

be identified as NCV 05000269/2003003-06: Failure to Declare ES Configured

Components Inoperable per TS.

15

1R15

Operability Evaluations

Quarterly Operability Evaluations

a.

Inspection Scope

The inspectors reviewed selected operability evaluations affecting risk significant

mitigating systems, to assess, as appropriate: (1) the technical adequacy of the

evaluations; (2) whether continued system operability was warranted; (3) whether other

existing degraded conditions were considered; (4) if compensatory measures were

involved, whether the compensatory measures were in place, would work as intended,

and were appropriately controlled; and (5) where continued operability was considered

unjustified, the impact on TS LCO. The inspectors reviewed the following items for

operability evaluations:

PIP O-03-02132, Unit 2 Installed Control Rod Drive Mechanism (CRDM) Split Ring

Flange Assembly Does Not Meet ASME Requirements

PIP O-03-03042 Increased Containment Sump Leakage in Unit 1 From RCS and

LPSW Leakage

PIP O-03-02226, 2B and 1C HPI Motor Vibration Increase Following New Pump

Installations

PIP O-03-3183, Increased Leakage From the 1B1 RCP Seal

PIP O-03-02492, Unit 1 RCS Leakage From Incore Instrument Tank

PIP O-03-3036, The 1A LPI Motor Space Heaters Have Not Functioned Since June

2001

PIP O-03-02569, Evidence of Borated Water Leakage Down Inside Primary Shield

Walls Below the Unit 3 Reactor Vessel

PIP O-03-02268, Indications of Increased RCS Leakage in Unit 1

b.

Findings

No findings of significance were identified.

1R17

Permanent Plant Modifications

.1

Feedwater Whip Restraint Modification

a.

Inspection Scope

The inspectors reviewed minor modification (ONOE) -17539, Modify Two Pipe Whip

Restraints on Unit 3 Main Feedwater Piping, to verify that the feedwater whip restraints

16

had been properly adjusted as per the design drawings following replacement of the

bolting material and clevises.

The inspectors observed work in progress during the removal and replacement of the

whip restraints and reviewed the work documentation for setting the whip restraints

following return to normal operating temperatures of the feedwater piping.

The inspectors reviewed the following documents during the inspection:

NSM ONOE-17539

MP/O/A/3019/004, Revision 53, Hangers - QA Condition 1 and 4 - Removal,

Installation or Modification

Work Request/Work Orders 98590970 (11) making final adjustments hot

Design Drawing O-494, Main Feedwater Pipe Whip Restraint

PIP O-01-01408, Adequacy of Existing Feedwater Pipe Rupture Restraints,

Corrective Action 7

In addition, the inspectors discussed with engineering the adjustments made to the whip

restraints once hot temperature operations were reached.

b.

Findings

No findings of significance were identified.

.2

Biennial Plant Modification Review

a.

Inspection Scope

The inspectors evaluated design change packages for nine modifications in the Barrier

Integrity and Mitigating Systems cornerstone areas, to evaluate the modifications for

adverse affects on system availability, reliability, and functional capability. The

modifications and the associated attributes reviewed are as follows:

ONOE- 10642, Upgrade Seismic Supports and Add Isolation Valve 3N-305 to Nitrogen

Line



Materials/Replacement Components



Flowpaths



Pressure Boundary



Structural



Process Medium



Failure Modes

ONOE- 12107, Upgrade Discharge LPSW Piping from the Motor Driven EFW coolers to

1LPSW-527



Materials/Replacement Components

17



Structural



Process Medium

ONOE- 15414, Replace Valve 2LP-15 with Item DMV-1296, 2A LPI Discharge to RBS

Pump Spray and HPI Suction



Materials/Replacement Components



Pressure Boundary



Structural

ONOE- 12094, Modification of Unit 2 RC Vent System Supports/Restraints



Materials/Replacement Components



Structural

ONOE- 12800, Provide Clearance Between the Valve Body of 2SF-101 and SSF RC

Makeup Pump Discharge Piping



Materials/Replacement Components



Pressure Boundary



Structural

ONOE- 17011, Upgrade 3-CCW-269 to Meet EQ Requirements



Materials/Replacement Components

Nuclear Station Modification (NSM) 33090, Add RBCU Time Delay Relays



Energy needs



Seismic qualification



Response time



Operations procedures



Modes bounded by the existing analysis

NSM 23053, Automatic Feedwater Isolation System



Environmental Qualification



Response Time - Testing



Modes bounded by existing analysis

NSM 23092, 600 V MCC and Load Center



Energy Needs



Seismic qualification



Control signals appropriate under accident conditions



Failure modes bounded by the existing analysis

For selected modification packages, the inspectors observed the as-built configuration.

Documents reviewed included procedures, engineering calculations, modifications

design and implementation packages, work orders, site drawings, corrective action

documents, applicable sections of the UFSAR, supporting analyses, TS, and design

basis information. Documents reviewed are listed in the Attachment to this report.

The inspectors also reviewed selected PIPs associated with modifications to confirm

that problems were identified at an appropriate threshold, were entered into the

corrective action process, and appropriate corrective actions had been initiated.

18

b.

Findings

No findings of significance were identified.

1R19

Post-Maintenance Testing (PMT)

a.

Inspection Scope

The inspectors reviewed PMT procedures and/or test activities, as appropriate, for

selected risk significant mitigating systems to assess whether: (1) the effect of testing

on the plant had been adequately addressed by control room and/or engineering

personnel; (2) testing was adequate for the maintenance performed; (3) acceptance

criteria were clear and adequately demonstrated operational readiness consistent with

design and licensing basis documents; (4) test instrumentation had current calibrations,

range, and accuracy consistent with the application; (5) tests were performed as written

with applicable prerequisites satisfied; (6) jumpers installed or leads lifted were properly

controlled; (7) test equipment was removed following testing; and (8) equipment was

returned to the status required to perform its safety function. The inspectors observed

testing and/or reviewed the results of the following tests:

PT/2/A/0202/11, 2C High Pressure Injection Pump Inservice Testing (IST)

Following Mechanical Seal Cleaning and Inspection

PIP O-03-02797, Anderson Greenwood Relief Valves 3MS-52 and 3MS-70

Failed to Lift as Specified Pressure During IST

PIP O-03-02864, 3HP-25, BWST Supply to LPI Suction, Failed IST Stroke Test

PIP O-03-02831, 3HP23, Letdown Storage Tank Outlet Isolation, Failed IST

Stroke Test

PT/3/A/0152/007, Core Flood System valve Stroke Test, IST Stroke Test

Following Inadvertent Backseating of Core Flood Isolation Valve 2CF-2 During

Maintenance per PIP O-03-03061

IP/0/A/0203/001A, Low Pressure Injection System Borated Water Storage Tank

Level Instrument Calibration, calibration of level instrument reviewed following

indication of false level reading per PIP O-03-0316

TT/3/A/0600/022, Turbine Driven Emergency Feedwater (TDEFW) Pump Speed

Response During AFIS Initiation Test, Following AFIS Modification

PIP O-03-02955, Following Maintenance the Unit 3 TDEFW Pump Lube Oil

Cooler Developed a Water Leak

b.

Findings

No findings of significance were identified.

19

1R20

Refueling and Outage Activities

a.

Inspection Scope

The inspectors conducted reviews and observations for selected licensee outage

activities to ensure that: (1) the licensee considered risk in developing the outage plan;

(2) the licensee adhered to the outage plan to control plant configuration based on risk;

(3) that mitigation strategies were in place for losses of key safety functions; and (4) the

licensee adhered to operating license and TS requirements. Between April 26, 2003,

and June 15, 2003, the following activities related to the Unit 3 refueling outage were

reviewed for conformance to the applicable procedure and selected activities associated

with each evaluation were witnessed:

defueled (no Mode) operations

refueling operations

reduced inventory and mid-loop conditions for installation and removal of steam

generator nozzle dams

activities involving the reactor vessel head replacement

reactor startup

Mode changes from Mode 6 (Refueling) to Mode 1 (Power Operation)

system lineups during major outage activities and Mode changes

final containment walkdown prior to startup

b.

Findings

No findings of significance were identified.

1R22

Surveillance Testing

a.

Inspection Scope

The inspectors witnessed surveillance tests and/or reviewed test data of the selected

risk-significant SSCs listed below, to assess, as appropriate, whether the SSCs met TS,

UFSAR, and licensee procedure requirements. In addition, the inspectors determined if

the testing effectively demonstrated that the SSCs were ready and capable of

performing their intended safety functions.

PT /1/A/0600/013, 1A Motor Driven Emergency Feedwater Pump Test [IST]

PT/3/A/0151/20, Penetration 20 Leak Rate Test (3PR-1 and 3PR-2) [local leak

rate test (LLRT)]

20

PT/3/A/0151/019, Penetration 19 Leak Rate Test (3PR-5 and 3PR-6) [LLRT]

PT/0/A/0600/021, Standby Shutdown Facility Diesel Generator Operation

PT2/A0202/011, 2B HPI Pump test [IST]

PT/3/A/0251/019, Main Steam Atmosphere Dump Valve Functional Test

1P/0/A/0305/001P, Reactor Protective System Channel D RC Pressure

Instrument Calibration

IP/A/0380/004C, SSF D/G Water Expansion Tank Level Instrument Calibration

IP/0/A/305/0005D Reactor Building High Pressure Trip Channel D

b.

Findings

No findings of significance were identified.

Cornerstone: Emergency Preparedness

1EP6

Drill Evaluation

a.

Inspection Scope

The inspectors observed and evaluated the licensees conduct of a simulator based

emergency preparedness drill held on June 10, 2003. The drill scenario involved

tornado damage to the Unit 1 turbine building with a subsequent loss of all AC power.

Additionally, Unit 3 developed a steam generator tube leak as part of the drill scenario.

The inspectors observed the scenario from the simulator control room and the Technical

Support Center. The inspectors observed performance of the licensees ability to

correctly classify the event and notify state and county authorities. For this drill, the

scenario progressed to a site area emergency. The drill scenario did not provide an

opportunity for the emergency response organization to make protective action

recommendations. The inspectors also reviewed the post-drill critique that was

conducted by the licensee evaluators.

b.

Findings

No findings of significance were identified.

21

4. OTHER ACTIVITIES

4OA1 Performance Indicator (PI) Verification

.1

Initiating Events, Mitigating Systems, and Barrier Integrity Cornerstones

a.

Inspection Scope

The inspectors reviewed the PIs listed in the table below (for all three units), to deter-

mine their accuracy and completeness against requirements in Nuclear Energy Institute

(NEI) 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 2.

Cornerstone: Initiating Events

Performance Indicator

Verification Period

Records Reviewed

Unplanned Scrams

3rd and 4th

quarter, 2002,

and

1st quarter, 2003

Licensee Event Reports

NRC Inspection Reports

Monthly Operating

Reports

operator logs

licensee power history

curves

Scrams with Loss of Normal

Heat Removal

Unplanned Power Changes

Cornerstone: Barrier Integrity

Performance Indicator

Verification Period

Records Reviewed

Reactor Coolant System

Specific Activity

3rd and 4th

quarter, 2002,

and

1st quarter, 2003

daily plant chemistry

data

Reactor Coolant System

Leakage

daily status reports

operator logs

PIPs

b.

Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

a.

Inspection Scope

The inspectors performed an in-depth review of issues entered into the licensees

corrective action program. The samples selected were within the cornerstone of

mitigating systems and involved risk significant systems. The inspectors reviewed the

actions taken to determine if the licensee had adequately addressed the following

attributes:

22

  • Complete, accurate, and timely identification of the problem
  • Evaluation and disposition of operability and reportability issues
  • Consideration of previous failures, extent of condition, generic or common cause

implications

  • Prioritization and resolution of the issue commensurate with the safety significance
  • Identification of the root cause and contributing causes of the problem
  • Identification and implementation of corrective actions commensurate with the safety

significance of the issue

The following issue and corrective actions were reviewed:

  • PIP O-03-02482, Darkened Oil Found in the 2C LPI Pump Bearing

b.

Findings

No findings of significance were identified.

4OA3 Event Followup

.1

Unit 1 Dropped Rod

On May 17, 2003, Unit 1 dropped Safety Group 4, Rod 9 during rod movement

verification surveillance testing at 100 percent RTP. The dropped rod was a result of a

blown fuse on one of the control rod drive motor phases. The operators reduced power

to less than 55 percent as a result of the dropped rod. The inspectors responded to the

site and verified that TS and core operating limits report requirements were met by the

licensee for quadrant power tilt ratio, axial flux, and rod alignment. The inspectors also

verified that the appropriate abnormal operating procedures were implemented by the

operators. Repairs were made, the rod was subsequently recovered, and the unit was

returned to 100 percent power on May 18, 2003.

.2

Standby Shutdown Facility Cable Routing

The inspectors followed up on a 10 CFR 50.72, eight hour notification made by the

licensee for an unanalyzed condition relating to the licensee's discovery of safe

shutdown cabling routed through an Appendix R, III.G.3 area. These cables included

control and indication wiring for several valves that isolate the reactor coolant system

from potential leakage paths during safe shutdown. The inspectors walked down the

cabling to verify the licensees assessment of the condition and reviewed the adequacy

of the compensatory measures put in place.

.3

Failure of the Engineered Safeguards Channel B Power Supply

The inspectors reviewed the licensees response to the failure of the engineered

23

safeguards channel B power supply. The failure resulted in multiple TS LCO entries

and included a loss of the digital engineered safeguards digital actuation circuits. In

addition, multiple alarms were received in the control room. Following the initial loss,

discussions were conducted with the licensee concerning the failure of the power

supply, the various TS LCO entries, and ongoing repair efforts. Followup of the ES

power supply failure is discussed further in Section 1R14 of this report.

4OA5 Other Activities

.1

Unit 3 Reactor Vessel Head Replacement Project (RVHRP)

A.

Engineering Preparation and Implementation for the RVHRP

a.

Inspection Scope

The inspectors reviewed engineering preparations including: selected Design

Modification Packages, engineering calculations, analyses, and drawings for the

Oconee RVHRP, in order to assess adequacy and completeness. To obtain a greater

understanding of the entire project scope, the inspectors also held discussions with

project management. To determine that proper Code Sections and Editions were

applicable for this RVHRP, the inspectors also reviewed applicable sections of the

Oconee Final Safety Analysis Report and various scope documents.

b.

Findings

No findings of significance were identified.

B.

Review of RVHRP Lifting and Transportation Program Activities

a.

Inspection Scope

The inspectors reviewed the adequacy of the RVHRP lifting program as described in

Modification Package ON-33112, Part AS1, Reactor Vessel Head Rigging and

Handling, assuring that it was prepared in accordance with regulatory requirements,

appropriate industrial codes and standards, and verified that the maximum anticipated

loads to be lifted would not exceed the capacity of the lifting equipment and supporting

structures.

The inspectors examined the RVHRP lifting equipment including the Polar Crane, a

down-ender placed inside the Reactor Building, three four-point lift systems, three skid

systems and a Self Propelled Modular Transport.

The inspectors reviewed the adequacy of the transport programs, procedures, work

packages, and load test records, to assure that they had been prepared and/or tested in

accordance with regulatory requirements, appropriate industrial codes, and standards.

The inspectors also reviewed the licensee's analyses for buried piping located beneath

the transport path as documented in Modification Package ON-53112, Part AS4,

Reactor Vessel Head Transport, to ensure that piping would not be damaged.

24

b.

Findings

No findings of significance were identified.

C.

Quality Assurance (QA) Oversight

a.

Inspection Scope

The inspectors reviewed licensee procedures relative to QA oversight of contractor

activities for the RVHRP replacement. In addition, the inspectors discussed

procurement and quality control inspection of various parts, including the Control Rod

Drive Mechanisms (CRDM), Hold Down Bolts, and CRDM (Split Nut) Flange Ring that

were utilized in the attachment of the CRDMs to the Reactor Vessel CRDM flanges.

The inspectors also reviewed a sample of PIPs, non-conformance reports, Purchase

Orders, and Receiving Inspection Reports (Form SCD-311A) pertaining to the above

parts. The inspectors also reviewed the Unit 3 Reactor Vessel Head Penetration

Preservice Inspection conducted in February 2003. The Unit 3 Oconee replacement

reactor vessel head contains sixty-nine alloy 690 penetration tubes that are shrunk fit in

the reactor vessel head and attached with alloy 152/52 partial penetration J-groove

welds. The inspectors reviewed aspects of the inspection program that provided a

baseline of the condition of the accessible outside diameter and inside diameter

surfaces of the vessel head penetration tubes and the partial penetration J-groove welds

attaching the penetration tubes to the reactor vessel head. The review included Scope

of Work, Procedures, Personnel Certifications, Equipment Certifications, and

examination results.

b.

Findings

Introduction: The inspectors identified a Green NCV of 10CFR50.55a(g)(4), which

requires meeting the ASME Boiler and Pressure Vessel Code,Section XI, IWA-7000,

Replacement, and of 10 CFR 50, Appendix B, Criterion VII, Control of Purchased

Material, Equipment, and Services. This resulted in the licensee installing one non-

conforming CRDM (Split Nut) Flange Ring on Unit 2, assembly #18, and discovering

prior to the installation in Unit 3, 68 CRDM (Split Nut) Flange Rings and 552 CRDM Hold

Down Bolts that did not meet the design and procurement specifications.

Description: In April 2003, while the licensee was performing an inspection during the

replacement of the reactor vessel head project, they determined that the CRDM Hold

Down Bolts, and CRDM (Split Nut) Flange Rings did not receive proper QA reviews of

the mechanical/chemical properties and non-destructive examinations (NDE) as

specified in the procurement and design specifications. These reviews and testing were

conducted during the initial mechanical/chemical and NDE testing performed by

independent testing facilities, and subsequently during the receipt inspections performed

by Framatome ANP, who was acting as the contractor for the RVHRP project, and

finally the licensee.

While performing Supply Chain Directive, SACD311, Rev. 1, Receipt Inspection &

Testing of QA Condition Items, the licensee failed to identify that the CRDM (Split Nut)

Flange Rings did not meet the required design and procurement specifications (i.e., a

25

yield strength of 100 ksi and a tensile strength of 125 ksi) for material quality as stated

in the Certificate of Compliance and as defined by ASME SA-320, Grade L43. The

CRDM (split nut) flange rings also did not meet the NDE ultrasonic testing (UT) as

described in ASME Section III, Sub-Article NB-2580 Examination of Bolts, Nuts and

Studs, specifically NB-2586 Ultrasonic Examination for Sizes Over 4 in., requiring the

examination be performed at a nominal frequency of 2.25 Mhz. Also the 552 CRDM

Hold Down Bolts for Unit 3 did not meet the same NDE-UT testing as described in

ASME Section III, Sub-Article NB-2580 Examination of Bolts, Nuts and Studs. Although

not a code requirement, the examination was called for by the design and procurement

specification.

A QA review, performed prior to installation of the components during Unit 3 End of

Cycle (EOC) 20 refueling outage (RFO) in the spring of 2003, led to the identification of

of one non-conforming CRDM (Split Nut) Flange Ring for CRDM Assembly #18 installed

on Unit 2 during the Unit 2 U2EOC19 RFO in the fall of 2002, and removal of 68

uninstalled, non-conforming CRDM (Split Nut) Flange Rings from the site for failure to

meet the mechanical property requirements of the components. This non-conforming

condition was not identified during the Unit 2 EOC19 RFO.

Based on the discovery that one non-conforming CRDM (Split Nut) Flange Ring was

installed on Unit 2, the licensee performed an engineering evaluation that is

documented in Framatome ANP Document 32-5027297-00, Operability Assessment of

CRDM Nut Ring with Reduced Tensile Strength Material. The one CRDM (Split Nut)

Flange Ring installed on Unit 2 was declared to be operable, but degraded, and could

remain in place until the end of the current Unit 2 operating cycle (which is scheduled to

end in the spring of 2004) when the reactor vessel head will be replaced. New CRDM

(Split Nut) Flange Rings with different heat numbers were procured and installed on the

Unit 3 head. The inspectors reviewed the methodology utilized in the engineering

evaluation for the non-conforming flange ring and found that the review was thorough.

The evaluation involved the redoing of all the ASME Code-required calculations for the

connection using the actual strength of the material supplied rather than the minimum

strength required by the material specification.

Analysis: The inspectors determined that this finding was associated with an inadequate

receipt inspection for the above parts. The finding was more than minor because

non-conforming material was actually installed in Unit 2. This deficiency was evaluated

under the SDP. Since there was no loss of function, the Initiating Events and Mitigation

Systems cornerstones were not impacted. The SDP Phase 1 RCS Barrier cornerstone

required an evaluation under SDP Phase 2. A regional senior reactor analyst performed

a SDP Phase 3 analysis and determined that since there was not a loss of function of

the system, there was no increase in risk. The finding was evaluated as Green (very

low safety significance).

Enforcement: 10CFR50.55a(g)(4) specifies in part that components classified as ASME

Code Class 1, Class 2, and Class 3 meet the requirements set forth in Section XI of the

ASME Boiler and Pressure Vessel Code. The ASME Boiler and Pressure Vessel Code,

Section XI, 1989 Edition, with no Addenda, subsection IWA-7220, states in part that

Prior to authorizing the installation of an item to be used for replacement, the Owner

shall conduct an evaluation of the suitability of that item.

26

Also, 10CFR50, Appendix B, Criterion VII, Control of Purchased Material, Equipment,

and Services, states that Measures shall be established to assure that purchased

material, equipment, and services, whether purchased directly or through contractors

and subcontractors, conform to the procurement documents. These measures shall

include provisions, as appropriate, for source evaluation and selection, objective

evidence of quality furnished by the contractor or subcontractor, inspection at the

contractor or subcontractor source, and examination of products upon delivery.

Contrary to the above, during the Unit 2 EOC19 RFO in the fall of 2002, measures taken

to evaluate the suitability of replacement parts were not adequate in that they did not

preclude the installation of one non-conforming CRDM (Split Nut) Flange Ring on CRDM

Assembly #18 on Unit 2. The same QA reviews of the remainder of the 68 CRDM (Split

Nut) Flange Rings and 552 CRDM Hold Down Bolts in the warehouse did not identify the

non-conforming parts prior to the attempt to install them on the Unit 3 reactor vessel

head. Because the finding is of very low safety significance and because the issue is in

the licensees corrective action program under PIPs O-03-2211, O-03-2132, O-03-2177

and O-03-2171, it is being treated as an NCV, consistent with Section VI.A.1 of the NRC

Enforcement Policy. Accordingly, it will be identified as NCV 05000270,287/2003003-

07: Failure to Detect Non-Conforming Parts During Receipt Inspections.

D.

Radiation Protection

a.

Inspection Scope

Radiation safety controls for removal of the Unit 3 reactor vessel head and preparation

of the head for temporary storage were reviewed and evaluated. Licensee procedures

for posting, surveying, and controlling access to radiologically significant areas were

assessed for adequacy. During tours of the Auxiliary Building and the Unit 3

Containment Building, the inspectors evaluated radiological postings and barricades

against current radiological surveys and procedurally established radiological controls.

Radiation Work Permits (RWPs) issued for the RVHRP were reviewed for incorporation

of established access controls. RWP specified alarm setpoints for electronic dosimeters

were also evaluated against current radiological surveys. Health Physics Technician

(HPT) proficiency in providing job coverage and occupational workers adherence to

RWP requirements were evaluated through worker interviews, work area tours and job

site observations. The inspectors observed radiation dose rates measured by an HPT in

the work areas adjacent to the vessel head after it was placed on the head stand. The

observed work area dose rates were compared to the licensees most current

documented survey results.

As Low As Reasonably Achievable (ALARA) planning and controls for the RVHRP were

reviewed and evaluated for consistency with Section IV, ALARA Planning, of the

licensees System ALARA Manual. ALARA Planning Worksheets, ALARA controls,

dose estimates, dose tracking, exposure controls including temporary shielding,

contamination and airborne radioactivity controls, project staffing and training,

emergency contingencies, and temporary storage of the original reactor head assembly

were reviewed and discussed with the licensee. RWPs issued for the RVHRP and their

associated ALARA job briefing packages were examined for incorporation of the ALARA

controls established for the project. Worker adherence to those controls was assessed

27

through job site observations during the movement of original reactor head assembly to

the head stand.

Through the above reviews and observations, the licensees radiation safety program

implementation and practices for the RVHRP were evaluated by the inspectors for

consistency with 10 CFR 20 requirements and approved licensee procedures. Licensee

plans, procedures, and records reviewed during the inspection are listed in the

Attachment to this report.

b.

Findings

No findings of significance were identified.

.2

Institute of Nuclear Power Operations (INPO) Report Review

The inspectors reviewed the final report issued by INPO on April 28, 2003, for the

evaluation that was conducted at the Oconee facility during the weeks of August 5,

2002, and August 12, 2002. The inspectors did not identify any safety issues in the

INPO report that either warranted further NRC followup or that had not already been

addressed by the NRC.

4OA6 Management Meetings

Exit Meeting Summary

The inspectors presented the inspection results to Mr. Ron Jones, Site Vice President,

and other members of licensee management at the conclusion of the inspection on

July 1, 2003. The licensee acknowledged the findings presented.

The inspectors asked the licensee whether any of the material examined during the

inspection should be considered proprietary. No proprietary information was identified

4OA7 Licensee Identified Violation

The following violation of very low safety significance (Green) was identified by the

licensee and is a violation of NRC requirements, which meets the criteria of Section VI

of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a NCV.

 TS Surveillance Requirement (SR) 3.4.12.5 specifies, in part, the required channel

functional test frequency of the PORV to be within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after decreasing RCS

temperature to less than or equal to 325 degrees F. On June 8, 2003, at 4:25 p.m.,

RCS temperature was lowered to less than 325 degrees F. On June 9, 2003, at 4:00

p.m., it was discovered that the channel functional test of the Unit 3 PORV had not

been completed. The functional test was subsequently completed satisfactorily at

3:26 a.m., on June 10, 2003. The circumstances involving this missed surveillance

are described in PIP O-03-03840. Because the subsequent performance of the

missed TS SR was satisfactorily, this violation is of very low safety significance, and is

being treated as a NCV.

Attachment

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

S. Batson, Mechanical/Civil Engineering Manager

J. Batton, Oconee Steam Generator Engineer

D. Baxter, Engineering Manager

N. Constance, Operations Training Manager

C. Curry, Maintenance Manager

T. Curtis, Reactor & Electrical Systems Manager

D. Covar, Training Instructor

C. Eflin, Requalification Supervisor

W. Foster, Safety Assurance Manager

P. Fowler, Access Services Manager, Duke Power

T. Gillespie, Operations Manager

B. Hamilton, Station Manager

B. Jones, Training Manager

R. Jones, Site Vice President

T. King, Security Manager

B. Lowrey, Steam Generator Engineer

L. Nicholson, Regulatory Compliance Manager

R. Repko, Superintendent of Operations

J. Smith, Regulatory Affairs

J. Twiggs, Manager, Radiation Protection

J. Weast, Regulatory Compliance

NRC

L. Reyes, Regional Administrator, Region II

V. McCree, Deputy Director, Division of Reactor Projects, Region II

B. Haag, Chief, Branch 1, Division of Reactor Projects, Region II

C. Carpenter, Chief, Inspection Program Branch, NRR

L. Olshan, Project Manager

ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000269,270,287/2003

003-01

URI

Control Room Board Component Thermal

Reliability (Section 1R02b.(1))

05000269,270,287/2003

003-02

URI

HELB Accident Scenario Review (Section

1R02b.(2))

2

05000269,270,287/2003

003-03

URI

Failure to Implement Manufacturers

Recommendations for Replacement of

SSF Diesel Coolant Grommets (Section

1R12.2)

Opened and Closed

05000269,270,287/2003

003-04

NCV

Failure to Identify the SSF Degraded

Grommets as a Deficient Condition in

the PIP Corrective Action Program

(Section 1R12.2)05000269/2003003-05

NCV

Failure to Maintain Sufficient Records

(logs) to Furnish Evidence of Activities

Affecting Quality (TS LCOs) (Section

1R14b.(1))05000269/2003003-06

NCV

Failure to Declare ES Configured

Components Inoperable per TS (Section

1R14b.(2))

05000270,287/2003003-07

NCV

Failure to Detect Non-Conforming Parts

during Receipt Inspections (Section

40A5.1C)

Items Discussed

None

LIST OF DOCUMENTS REVIEWED

(Sections 1R02 and 1R17)

Screened Out Items

NSM 12995, Temporary Wiring Procedure

NSM 23092, 600 V MCC and Load Center

NSM 53065, UFSAR revision Section 9.5.1.4.3 Cable Splicing

ONOE- 10642, Upgrade Seismic Supports and Add Isolation Valve 3N-305 to Nitrogen

Line

ONOE- 12107, Upgrade Discharge LPSW Piping from the MDEFDWPM coolers to

1LPSW-527 ONOE- 15414, Replace Valve 2LP-15 with Item DMV-1296 2A LPI

Discharge to RBS Pump Spray and HPI Suction

ONOE- 12094, Modification of Unit 2 RC Vent system Supports/Restraints

ONOE- 12800 ,Provide Clearance Between the Valve Body of 2SF-101 and SSF RC

Makeup Pump Discharge Piping

3

ONOE- 17011, Upgrade 3-CCW-269 to Meet EQ Requirements

ONOE-16856, Revise OSS-0254.00-00-1028

ONOE-16872, UST TAC Sheets

ONOE-16876, Revise Controlled Documents for RM-23A Module

ONOE-16990, Revise Test Acceptance Criteria Sheets for ECCW

ONOE-17068, Adjustable Trip Setting Correction for MCCs

NSM 23092, 600/208 VAC Load Capacity, Rev. 0

ONOE 11721, Include Alarm Setpoints of Stations Transformers in EDB and the OAC, 1

ONOE 14030, Modify Keowee Auxiliary Power Alignment Circuitry

ONOE 14409, Add fuses Between QA1 and Non-QA1 LPI Pump Circuits

ONOE 15256, Upgrade of Red Bus x/y Metering Transformers

ONOE-16712, Revise Maintenance Rule Design Basis Document to Add Reactor Building

Ventilation Functions

Evaluations

NSM 33090, Voltage Adequacy Project NSM-ON-33090/AL3 (RBCU Three Minute Delay),

NSM-23053, Automatic Feedwater Isolation System

Calculation OSC-5325, ECCW Lake Level Verification

EP 3A 1800-01, Revision 39, Turbine Building Flooding [emergency operating porcedure]

NSM 13058, MSLB Leak Detection Circuitry

ONOE 15735, Removed ESF Signal to 3LP-21 and 22

UFSAR Section 3.11.5, Loss of Ventilation

PIPS

PIP O-99-0204

PIP O-91-0121

PIP O-96-0387

PIP O-00-1845

PIP O-98-3062

PIP O-98-2221

PIP-O-01-04635

PIP-O-02-02669

PIP-O-02-00619

PIP-O-02-00054

Audits

Assessment Report Number GO-02-01(NPA)(50.59)(ALL), Applicability Determination and 10

CFR 50.59 Process Evaluation, Assessment Dates 2/4/02 - 2/7/02

PIP-O-03-01300, Level II Assessment of Frametome ANP Compliance to Oconee Contractor

Agreements, 2/18/03 - 2/18/03

PIP-O-03-01736, Level II Assessment 2MOD03001, Review of ONS Temporary Mod Process

4

Calculations

OSC-5267, Flow from UST to Hotwell - MSN-291

OSC-6901, Determination of Average Reactor Building Temperature (Type IV), Rev. 3

04158901-1SP, 12VDC Power Supply, SE P/N 50015966-001

Other Documents Reviewed

MARF #79

(Section 1R04)

Drawings

OFD-114A-1.4, Units 1 & 3 Flow Diagram of CC System (Drain Tank), Revision 5

OFD-144A-3.1, Unit 3 Flow Diagram of CC System (Supply and Return),

Revision 7

OFD-144A-3.2, Unit 3 Flow Diagram of CC System (Reactor Building and Heat Exchangers),

Revision 11

OFD-144A-3.3, Unit 3 Flow Diagram of CC System (Control Rod Drive Service Structure and

Filters), Revision 6

Procedures

Selected Licensee Commitment 16.9.10, CC and HPI Seal Injection to Reactor Coolant

Pumps (RCP)

AP/3/1700/014, Loss of Normal HPI Makeup and/or RCP Seal Injection

AP/3/1700/016, Abnormal Reactor Coolant Pump Operation

AP/3/1700/020, Loss of Component Cooling

UFSAR

Section 6.2.3, Containment Isolation System

Section 9.2.1, Component Cooling System

(Section 1R08)

Procedures

Framatome Technologies Procedure 54-ISI-400-11, Multifrequency Eddy Current Examination

of Tubing, (with Procedure Qualification 54-PQ-400) and Change Notice 30-5027221-00 for

Oconee Unit 3 EOC20 Requirements, dated April 22, 2003

Eddy Current Acquisition Guidelines for Duke Power Companys Once-Through Steam

Generators (OTSG), Rev. 9, April 22, 2003

Data Management Guidelines, Rev. 0, April 23, 2003

Eddy Current Analysis Guidelines for Duke Power Companys Once-Through Steam

Generators (OTSG), Rev. 6, April 22, 2003

5

Other Documents

Framatome ANP Engineering Information Record 51-5028238-00, In-Situ Pressure Test

Summary for Oconee Unit 3 (May 2003)

Duke Power Steam Generator Management Program SGMEP 105, OTSG Specific Assessment

of Potential Degradation Mechanisms for Oconee Unit 3 EOC 20, April 28, 2003

(Sections 40A5.1A-C)

Procedures

Procedure QEP 07.12-3,10CFR50.65(a)(4) Assessment

Procedure QEP 07-12, 10CFR50.59 Evaluations and 10CFR50.65 Assessments

NSD 403, Shutdown Risk Management (Modes 4, 5, 6, and No-Mode) per 10CFR 50.65 (a)(4),

Rev. 11.

NSD 415, Operational Risk Management (Modes 1, 2, 3) per 10CFR 50.65 (a)(4), Rev. 1.

NSD 209, 10CFR50.59 Process, Rev. 9.

Mcinnes Steel Company Ultrasonic Test (UT) Procedure No. UT-SA388-95, Rev. 0

General Nuclear Corporation, Magnetic Particle Examination, Wet Continuous Method GNC-

054, Rev. 1

Supply Chain Directive, SACD311, Rev. 1, Receipt Inspection & Testing of QA Condition Items

Other Documents

Modification Package - RV Head Components Modification, Modification #33112, Part No. AM7,

Rev. 0.

Reactor Vessel Closure Head Replacement Project, Oconee Nuclear Power Plant Units 1, 2, &

3, Input Document for Replacement RVCHA Licensing and Safety Evaluation April 2003.

Modification Package - Reactor Vessel Head Rigging and Handling, Modification # ON33112,

Part No. AS1, Rev. 1.

Modification Package Review - Replacement of Reactor Vessel Closure Head, Service

Structure and Associated Components, Modification # ON33112, Part No. 000, Rev. 0

(including 10CFR50.59 Screen).

Specification for Reactor Vessel for Duke Power Company, March 19, 1973

Oconee Unit 3, Rector Vessel Head Penetration Preservice Inspection, February 2003

Input Document for Replacement RVCHA Licensing and Safety Evaluation, April 2003

Oconee Unit 3 Reactor Vessel Head Penetration Preservice Inspection - February 2003, Final

Report

Various site engineering drawings including Head Movement Drawings from Mammoet

Various FANP calcs and NCRs

Framatome ANP Document 32-5027297-00, Operability Assessment of CRDM Nut Ring with

Reduced Tensile Strength Material

PIPs: O-03-2132, O-03-2211, O-03-2177, O-03-2171, O-03-2922, O-03-2998, O-03-2844, O-

03-1218, O-03-2898

Framatome ANP NCRs: 6025753, 32-5027297-00, 6024468, 6024579, 6025325

Purchase Orders (POs): NS146-001, NS146-002, ON52461, ON13513

Receipt Inspection Reports for: PO NS146-001, PO NS146-002, PO ON52461, PO ON13513

Corrective Action Reports (CARs): 6025777-00

6

(Section 40A5.1D)

Procedures, Plans, and Manuals

Standard Health Physics Procedure (SH) SH/0/B/2000/005, Posting of Radiation Control

Zones, Revision (Rev.) 1

SH/0/B/2000/012, Access Controls for High, Extra High, and Very High Radiation Areas,

Rev. 1

Duke Power Company System ALARA Manual,Section IV, ALARA Planning, Rev. 15,

10/15/02

Radiation Protection (RP) Job Coverage Plan, Rev. 1, 4/9/03

RP-012, Surveillance Plan, Rev. 0, 4/15/03

Records

ALARA Planning Worksheet - Unit 3 Reactor Head Replacement - Install and Remove

Scaffolding (Equipment Chase Area and Reactor Head Stand)

ALARA Planning Worksheet - Unit 3 RHRP Install Shielding, Encapsulate Reactor Head and

Decon Activities

ALARA Planning Worksheet - Unit 3 Reactor Head Replacement - Remove and Install

Interferences in Equipment Chase Area

ALARA Planning Worksheet - Unit 3 Reactor Head Replacemant - Electrical/Mechanical

Disconnects and Reconnects, Remove/Install Interferences, CRD Remmoval

ALARA Planning Worksheet - Unit 3 Reactor Head Replacement - Install and Remove

Lifting Equipment, Remove ORVH and Install RRVH

Radiation Survey Report 050603-30, Reactor Vessel Head, 5/6/03

Radiation Survey Report 050703-1, Reactor Vessel Head, 5/6/03

ALARA Briefing Packages for Radiation Work Permits 6375, 6376, 6377, 6378, 6379,

and 6380

Daily Exposure reports for 5/6 & 7/03

Radiation Work Permits (RWPs)

RWP 6375, U3 Rx Bldg - RHRP - Install and Remove Scaffolding, Rev. 0, 02/06/03

RWP 6376, U3 Rx Bldg - RHRP - Install Shielding, Encapsulate Rx Head, and Decon

Activities, Rev. 0, 02/06/03

RWP 6377, U3 Rx Bldg - RHRP - Remove and Install Interferences in the Equipment

Chase Area, Rev. 0, 02/06/03

RWP 6378, U3 Rx Bldg - RHRP - Remove and Install Rx Head Interferrences, Piping, and

all CRDM Work, Rev. 0, 02/06/03

RWP 6379, U3 Rx Bldg - RHRP - Install and Remove Lifting Equipment, Remove Original

Reactor Head Assembly (RHA) and Install Replacement RHA, Rev. 0, 02/06/03

RWP 6380, U3 Rx Bldg - RHRP - Load, Transport and Store Original RHA, Incluses All

Outside Work, Rev. 0, 02/06/03

7

LIST OF ACRONYMS

ADAMS

-

Agencywide Documents Access and Management System

ALARA

-

As Low As Reasonably Achievable

ASME

-

American Society of Mechanical Engineers

BCM

-

Boiler/Condenser Mode

BWST

-

Borated Water Storage Tanks

CC

-

Component Cooling

CFR

-

Code of Federal Regulations

COLR

-

Core Operating Limits Report

CRDM

-

Control Rod Drive Mechanism

DEC

-

Duke Energy Corporation

DPC

-

Duke Power Company

EFW

-

Emergency Feedwater

EHC

-

Electro-Hydraulic Control

EOC

-

End of Cycle

ES

-

Engineered Safeguards

ESI

-

Engine Systems, Inc

ET

-

Eddy Current Testing

FSAR

-

Final Safety Analysis Report

HELB

-

High Energy Line Break

HPI

-

High Pressure Injection

HPT

-

Health Physics Technician

INPO

-

Institute of Nuclear Power Operations

IR

-

Inspection Report

IST

-

Inservice Testing

LBLOCA

-

Large Break Loss of Coolant Accident

LCO

-

Limiting Condition for Operation

LLRT

-

Local Leak Rate Test

LPI

-

Low Pressure Injection

LPSW

-

Low Pressure Service Water

NCV

-

Non-Cited Violation

NDE

-

Non-Destructive Examination

NRC

-

Nuclear Regulatory Commission

NRR

-

Nuclear Reactor Regulation

NSM

-

Nuclear Station Modification

OFD

-

Oconee Flow Diagram

ONOE

-

Minor Modification

ONS

-

Oconee Nuclear Station

OTSG

-

Once-Through Steam Generator

PI

-

Performance Indicators

PIP

-

Problem Investigation Process (report)

PT

-

Performance Test

PMT

-

Post-Maintenance Testing

PORV

-

Power Operated Relief Valve

QA

-

Quality Assurance

QC

-

Quality Control

RBCU

-

Reactor Building Cooling Unit

RBS

-

Reactor Building Spray

8

RCP

-

Reactor Coolant Pump

RCS

-

Reactor Coolant System

RFO

-

Refueling Outage

RTP

-

Rated Thermal Power

RVHRP

-

Reactor Vessel Head Replacement Project

RWP

-

Radiation Work Permit

SBLOCA

-

Small Break Loss of Coolant Accident

SDP

-

Significance Determination Process

SG

-

Steam Generator

SR

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Surveillance Requirement

SSC

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Structure, System and Component

SSF

-

Standby Shutdown Facility

TDEFW

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Turbine Driven Emergency Feedwater

TS

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Technical Specification

UFSAR

-

Updated Final Safety Analysis Report

URI

-

Unresolved Item

UT

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Ultrasonic Testing