IR 05000275/2007005: Difference between revisions
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====a. Inspection Scope==== | ====a. Inspection Scope==== | ||
The inspectors: (1) walked down portions of the below listed risk important system and reviewed plant procedures and documents to verify that critical portions of the selected | The inspectors: | ||
: (1) walked down portions of the below listed risk important system and reviewed plant procedures and documents to verify that critical portions of the selected | |||
system were correctly aligned; and, (2) compared deficiencies identified during the walk | system were correctly aligned; and, | ||
: (2) compared deficiencies identified during the walk | |||
down to the FSAR Update and corrective action program (CAP) to ensure problems | down to the FSAR Update and corrective action program (CAP) to ensure problems | ||
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condition of active and passive fire protection features and their operational lineup and | condition of active and passive fire protection features and their operational lineup and | ||
readiness. The inspectors: (1) verified that transient combustibles and hot work | readiness. The inspectors: | ||
: (1) verified that transient combustibles and hot work | |||
activities were controlled in accordance with plant procedures; (2) observed the | activities were controlled in accordance with plant procedures; | ||
: (2) observed the | |||
condition of fire detection devices to verify that they remained functional; (3) observed | condition of fire detection devices to verify that they remained functional; | ||
: (3) observed | |||
fire suppression systems to verify that they remained functional and that access to | fire suppression systems to verify that they remained functional and that access to | ||
-6-manual actuators was unobstructed; (4) verified that fire extinguishers and hose stations were provided at their designated locations and that they were in a satisfactory | -6-manual actuators was unobstructed; | ||
: (4) verified that fire extinguishers and hose stations were provided at their designated locations and that they were in a satisfactory | |||
condition; (5) verified that passive fire protection features (electrical raceway barriers, fire doors, fire dampers, steel fire proofing, penetration seals, and oil collection systems) | condition; | ||
: (5) verified that passive fire protection features (electrical raceway barriers, fire doors, fire dampers, steel fire proofing, penetration seals, and oil collection systems) | |||
were in a satisfactory material condition; (6) verified that adequate compensatory | were in a satisfactory material condition; | ||
: (6) verified that adequate compensatory | |||
measures were established for degraded or inoperable fire protection features and that | measures were established for degraded or inoperable fire protection features and that | ||
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the compensatory measures were commensurate with the significance of the deficiency; | the compensatory measures were commensurate with the significance of the deficiency; | ||
and, (7) reviewed the FSAR Update to determine if PG&E identified and corrected fire | and, | ||
: (7) reviewed the FSAR Update to determine if PG&E identified and corrected fire | |||
protection problems.*November 19, 2007: Unit 1, Fire Area 14-E, Component cooling water heat exchanger room*November 19, 2007: Unit 2, Fire Area 19-E, Component cooling water heat exchanger room*November 19, 2007: Unit 1, Fire Area 7-A, Cable spreading room | protection problems.*November 19, 2007: Unit 1, Fire Area 14-E, Component cooling water heat exchanger room*November 19, 2007: Unit 2, Fire Area 19-E, Component cooling water heat exchanger room*November 19, 2007: Unit 1, Fire Area 7-A, Cable spreading room | ||
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The inspectors reviewed PG&E's programs, verified performance against industry standards, and reviewed critical operating parameters and maintenance records for | The inspectors reviewed PG&E's programs, verified performance against industry standards, and reviewed critical operating parameters and maintenance records for | ||
Component Cooling Water Heat Exchangers 1-1 and 1-2. The inspectors verified that: | Component Cooling Water Heat Exchangers 1-1 and 1-2. The inspectors verified that: | ||
: (1) performance tests were satisfactorily conducted for heat exchangers/heat sinks and | |||
reviewed for problems or errors; | |||
: (2) PG&E utilized the periodic maintenance method | |||
reviewed for problems or errors; (2) PG&E utilized the periodic maintenance method | |||
outlined in EPRI NP-7552, "Heat Exchanger Performance Monitoring Guidelines;" | outlined in EPRI NP-7552, "Heat Exchanger Performance Monitoring Guidelines;" | ||
: (3) PG&E properly utilized biofouling controls; | |||
: (4) PG&E's heat exchanger inspections | |||
adequately assessed the state of cleanliness of their tubes, and, (5) the heat | adequately assessed the state of cleanliness of their tubes, and, | ||
: (5) the heat | |||
exchangers were correctly categorized under the Maintenance Rule. | exchangers were correctly categorized under the Maintenance Rule. | ||
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November 2007, and also a verification of reasonable model performance based on the | November 2007, and also a verification of reasonable model performance based on the | ||
current design of the plant. These tests were: | current design of the plant. These tests were: | ||
: (1) design basis loss of coolant accident | |||
with subsequent loss of off-site power transient test eight; (2) maximum size unisolable | with subsequent loss of off-site power transient test eight; | ||
: (2) maximum size unisolable | |||
main steam line rupture transient test nine; (3) slow primary system depressurization to | main steam line rupture transient test nine; | ||
: (3) slow primary system depressurization to | |||
saturation condition with pressurizer relief or safety valve stuck open (inhibit activation of | saturation condition with pressurizer relief or safety valve stuck open (inhibit activation of | ||
high pressure emergency core cooling system) transient test ten; (4) scenario-based test | high pressure emergency core cooling system) transient test ten; | ||
: (4) scenario-based test | |||
package for mid-loop operations; and, (5) discrepancy work closeout package for | package for mid-loop operations; and, | ||
: (5) discrepancy work closeout package for | |||
radiation monitor failures discovered during a loss of coolant accident scenario test. | radiation monitor failures discovered during a loss of coolant accident scenario test. | ||
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with NUREG-1021, Revision 9, Supplement 1, "Operator Licensing Examination | with NUREG-1021, Revision 9, Supplement 1, "Operator Licensing Examination | ||
Standards for Power Reactors."1R12Maintenance Effectiveness (71111.12) Routine Maintenance Effectiveness Inspection The inspectors reviewed the listed maintenance activities to: | Standards for Power Reactors."1R12Maintenance Effectiveness (71111.12) Routine Maintenance Effectiveness Inspection The inspectors reviewed the listed maintenance activities to: | ||
: (1) verify the appropriate handling of structure, system, and component (SSC) performance or condition problems; | |||
: (2) verify the appropriate handling of degraded SSC functional performance; | |||
: (3) evaluate | |||
the role of work practices and common cause problems; and, (4) evaluate the handling | the role of work practices and common cause problems; and, | ||
: (4) evaluate the handling | |||
of SSC issues reviewed under the requirements of the Maintenance Rule, 10 CFR | of SSC issues reviewed under the requirements of the Maintenance Rule, 10 CFR | ||
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====a. Inspection Scope==== | ====a. Inspection Scope==== | ||
The inspectors reviewed the listed assessment activities to verify: | The inspectors reviewed the listed assessment activities to verify: | ||
: (1) performance of risk assessments when required by 10 CFR 50.65(a)(4) and PG&E procedures prior to | |||
changes in plant configuration for maintenance activities and plant operations; (2) the | changes in plant configuration for maintenance activities and plant operations; | ||
: (2) the | |||
accuracy, adequacy, and completeness of the information considered in the risk | accuracy, adequacy, and completeness of the information considered in the risk | ||
assessment; (3) that PG&E recognizes, and/or enters as applicable, the appropriate risk | assessment; | ||
: (3) that PG&E recognizes, and/or enters as applicable, the appropriate risk | |||
category according to the risk assessment results and PG&E procedures; and (4) PG&E | category according to the risk assessment results and PG&E procedures; and | ||
: (4) PG&E | |||
-10-identified and corrected problems related to maintenance risk assessments.*October 9, 2007: Unit 1, Auxiliary Saltwater Pump 1-1 maintenance | -10-identified and corrected problems related to maintenance risk assessments.*October 9, 2007: Unit 1, Auxiliary Saltwater Pump 1-1 maintenance | ||
*October 17, 2007: Unit 1, Reactor coolant pump under voltage and under frequency relay calibration*November 6, 2007: Unit 2, Emergency Diesel Generator 2-1 maintenance outage | *October 17, 2007: Unit 1, Reactor coolant pump under voltage and under frequency relay calibration*November 6, 2007: Unit 2, Emergency Diesel Generator 2-1 maintenance outage | ||
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====a. Inspection Scope==== | ====a. Inspection Scope==== | ||
The inspectors: | The inspectors: | ||
: (1) verified that PG&E performed actions to minimize the probability of initiating events and maintained the functional capability of mitigating systems and | |||
barrier integrity systems; (2) verified that emergent work related activities such as | barrier integrity systems; | ||
: (2) verified that emergent work related activities such as | |||
troubleshooting, work planning/scheduling, establishing plant conditions, aligning | troubleshooting, work planning/scheduling, establishing plant conditions, aligning | ||
Line 457: | Line 483: | ||
equipment, tagging, temporary modifications, and equipment restoration did not place | equipment, tagging, temporary modifications, and equipment restoration did not place | ||
the plant in an unacceptable configuration; and, (3) reviewed the FSAR Update to | the plant in an unacceptable configuration; and, | ||
: (3) reviewed the FSAR Update to | |||
determine if PG&E identified and corrected risk assessment and emergent work control | determine if PG&E identified and corrected risk assessment and emergent work control | ||
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====a. Inspection Scope==== | ====a. Inspection Scope==== | ||
The inspectors: | The inspectors: | ||
: (1) reviewed plant status documents such as operator shift logs, emergent work documentation, deferred modifications, and standing orders to determine | |||
if an operability evaluation was warranted for degraded components; (2) referred to the | if an operability evaluation was warranted for degraded components; | ||
: (2) referred to the | |||
FSAR Update and design bases documents to review the technical adequacy of the | FSAR Update and design bases documents to review the technical adequacy of the | ||
operability evaluations; (3) evaluated compensatory measures associated with | operability evaluations; | ||
: (3) evaluated compensatory measures associated with | |||
operability evaluations; (4) determined degraded component impact on any TS; (5) used | operability evaluations; | ||
: (4) determined degraded component impact on any TS; | |||
: (5) used | |||
the Significance Determination Process to evaluate the risk significance of degraded or | the Significance Determination Process to evaluate the risk significance of degraded or | ||
inoperable equipment; and, (6) verified that PG&E has identified and implemented | inoperable equipment; and, | ||
: (6) verified that PG&E has identified and implemented | |||
appropriate corrective actions associated with degraded components.*October 9, 2007: Unit 1, Emergency Diesel Generator 1-3 oil leak | appropriate corrective actions associated with degraded components.*October 9, 2007: Unit 1, Emergency Diesel Generator 1-3 oil leak | ||
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The inspectors selected the listed postmaintenance test activities of risk significant | The inspectors selected the listed postmaintenance test activities of risk significant | ||
systems or components. For each item, the inspectors: (1) reviewed the applicable | systems or components. For each item, the inspectors: | ||
: (1) reviewed the applicable | |||
licensing basis and/or design basis documents to determine the safety functions; | licensing basis and/or design basis documents to determine the safety functions; | ||
: (2) evaluated the safety functions that may have been affected by the maintenance | |||
activity; and, | |||
: (3) reviewed the test procedure to ensure it adequately tested the safety | |||
activity; and, (3) reviewed the test procedure to ensure it adequately tested the safety | |||
function that may have been affected. The inspectors either witnessed or reviewed the | function that may have been affected. The inspectors either witnessed or reviewed the | ||
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or reviewed the test data to verify that the following significant surveillance test attributes | or reviewed the test data to verify that the following significant surveillance test attributes | ||
were adequate: | were adequate: | ||
: (1) preconditioning; | |||
: (2) evaluation of testing impact on the plant; | |||
: (3) acceptance criteria; | |||
: (4) test equipment; | |||
: (5) procedures; | |||
: (6) jumpers; | |||
: (7) test data; | |||
: (8) testing frequency and method demonstrated TS operability; | |||
: (9) test equipment | |||
removal; | |||
: (10) restoration of plant systems; | |||
: (11) fulfillment of American Society of | |||
( | Mechanical Engineers Code requirements; | ||
: (12) updating of performance indicator data; | |||
: (13) engineering evaluations, root causes, and bases for returning tested SSCs not | |||
meeting the test acceptance criteria were correct; | |||
: (14) reference setting data; and, | |||
: (15) annunciators and alarm setpoints. The inspectors also verified that PG&E identified | |||
meeting the test acceptance criteria were correct; (14) reference setting data; and, (15) annunciators and alarm setpoints. The inspectors also verified that PG&E identified | |||
and implemented any needed corrective actions associated with the surveillance testing.*October 9, 2007: Unit 1, Check valve inspections, inservice test | and implemented any needed corrective actions associated with the surveillance testing.*October 9, 2007: Unit 1, Check valve inspections, inservice test | ||
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====a. Inspection Scope==== | ====a. Inspection Scope==== | ||
The inspectors reviewed the FSAR Update, plant drawings, procedure requirements, and TSs to ensure that listed temporary modi fications were properly implemented. The inspectors: | The inspectors reviewed the FSAR Update, plant drawings, procedure requirements, and TSs to ensure that listed temporary modi fications were properly implemented. The inspectors: | ||
: (1) verified that the modifications did not have an effect on system | |||
operability/availability; (2) verified that the installation was consistent with modification | operability/availability; | ||
: (2) verified that the installation was consistent with modification | |||
documents; (3) ensured that the postinstallation test results were satisfactory and that | documents; | ||
: (3) ensured that the postinstallation test results were satisfactory and that | |||
the impact of the temporary modifications on permanently installed SSCs were | the impact of the temporary modifications on permanently installed SSCs were | ||
supported by the test; (4) verified that the modifications were identified on control room | supported by the test; | ||
: (4) verified that the modifications were identified on control room | |||
drawings and that appropriate identification tags were placed on the affected drawings; | drawings and that appropriate identification tags were placed on the affected drawings; | ||
and (5) verified that appropriate safety evaluations were completed. The inspectors | and | ||
: (5) verified that appropriate safety evaluations were completed. The inspectors | |||
verified that PG&E identified and implemented any needed corrective actions associated | verified that PG&E identified and implemented any needed corrective actions associated | ||
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====a. Inspection Scope==== | ====a. Inspection Scope==== | ||
For the listed drill contributing to Drill/Exercise Performance and Emergency Response Organization Performance Indicators, the inspectors: | For the listed drill contributing to Drill/Exercise Performance and Emergency Response Organization Performance Indicators, the inspectors: | ||
: (1) observed the training evolution | |||
to identify any weaknesses and deficiencies in the emergency response organization; | to identify any weaknesses and deficiencies in the emergency response organization; | ||
: (2) compared the identified weaknesses and deficiencies against PG&E identified | |||
findings to determine whether PG&E is properly identifying failures; and | |||
: (3) determined | |||
findings to determine whether PG&E is properly identifying failures; and (3) determined | |||
whether PG&E performance is in accordance with the guidance of the NEI 99-02, "Voluntary Submission of Performance Indicator Data," acceptance criteria.*July 25, 2007, Units 1 and 2, full emergency drill | whether PG&E performance is in accordance with the guidance of the NEI 99-02, "Voluntary Submission of Performance Indicator Data," acceptance criteria.*July 25, 2007, Units 1 and 2, full emergency drill | ||
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inspectors attended the condition adverse to quality screening meeting. The inspectors: | inspectors attended the condition adverse to quality screening meeting. The inspectors: | ||
: (1) verified that equipment, human performance, and program issues were being | |||
(1) verified that equipment, human performance, and program issues were being | |||
identified by PG&E at an appropriate threshold and that the issues were entered into the | identified by PG&E at an appropriate threshold and that the issues were entered into the | ||
corrective action program; (2) verified that corrective actions were commensurate with | corrective action program; | ||
: (2) verified that corrective actions were commensurate with | |||
the significance of the issue; and, (3) identified conditions that might warrant additional | the significance of the issue; and, | ||
: (3) identified conditions that might warrant additional | |||
follow-up through other baseline inspection procedures. | follow-up through other baseline inspection procedures. | ||
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In addition to the daily screening, the inspectors conducted an in-depth review of the listed issues. The inspectors considered the following during the review of PG&E's | In addition to the daily screening, the inspectors conducted an in-depth review of the listed issues. The inspectors considered the following during the review of PG&E's | ||
actions: | actions: | ||
: (1) complete and accurate identification of the problem in a timely manner; | |||
(2) evaluation and disposition of operability/reportability issues; (3) consideration of | : (2) evaluation and disposition of operability/reportability issues; | ||
: (3) consideration of | |||
extent of condition, generic implications, common cause, and previous occurrences; | extent of condition, generic implications, common cause, and previous occurrences; | ||
: (4) classification and prioritization of the resolution of the problem; | |||
: (5) identification of | |||
root and contributing causes of the problem; | |||
: (6) identification of corrective actions; and, | |||
root and contributing causes of the problem; (6) identification of corrective actions; and, (7) completion of corrective actions in a timely manner.*A0710652, November 21, 2007, Discrepancies associated with ultrasonic flow monitor nozzle fouling factor input into secondary system heat balance | : (7) completion of corrective actions in a timely manner.*A0710652, November 21, 2007, Discrepancies associated with ultrasonic flow monitor nozzle fouling factor input into secondary system heat balance | ||
calculations*A0712404, November 20, 2007, Evaluate if licensee bases impact evaluation screen for less than adequate reactor water storage tank level required a license | calculations*A0712404, November 20, 2007, Evaluate if licensee bases impact evaluation screen for less than adequate reactor water storage tank level required a license | ||
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operation. On this basis, the item impacts the Mitigating System Cornerstone and | operation. On this basis, the item impacts the Mitigating System Cornerstone and | ||
screens to GREEN using IMC 0609, Phase 1 SDP Evaluation, Appendix A, because (a) the finding is not a design or qualification deficiency, (b) there is no loss of safety | screens to GREEN using IMC 0609, Phase 1 SDP Evaluation, Appendix A, because | ||
: (a) the finding is not a design or qualification deficiency, | |||
: (b) there is no loss of safety | |||
function for a mitigating system and, (c) there are no seismic, fire, flooding or severe | function for a mitigating system and, | ||
: (c) there are no seismic, fire, flooding or severe | |||
weather initiating implications associated with the finding. This finding has a | weather initiating implications associated with the finding. This finding has a |
Revision as of 18:30, 20 September 2018
ML080360630 | |
Person / Time | |
---|---|
Site: | Diablo Canyon ![]() |
Issue date: | 02/05/2008 |
From: | Vincent Gaddy NRC/RGN-IV/DRP/RPB-B |
To: | Keenan J S Pacific Gas & Electric Co |
References | |
FOIA/PA-2011-0221 IR-07-001 | |
Download: ML080360630 (42) | |
Text
February 5, 2008
John Senior Vice President - Generation
and Chief Nuclear Officer
Pacific Gas and Electric Company
P.O. Box 770000
Mail Code B32
San Francisco, CA 94177-0001
SUBJECT: DIABLO CANYON POWER PLANT - NRC INTEGRATED INSPECTION REPORT 05000275/2007005; 05000323/2007005 AND 07200026/2007001
Dear Mr. Keenan:
On December 31, 2007, the U.S. Nuclear Regulatory Commission completed an inspection at your Diablo Canyon Power Plant, Units 1 and 2, facility. The enclosed integrated report
documents the inspection findings that were discussed on January 9, 2008, with John Conway
and members of your staff.
This inspection examined activities conducted under your licenses as they relate to safety and compliance with the Commission's rules and regulations, and with the conditions of your
license. The inspectors reviewed selected procedures and records, observed activities, and
interviewed personnel.
There was one NRC-identified finding of very low safety significance (Green) and one Severity Level IV violation identified in this report. These findings involved violations of NRC
requirements. However, because of their very low risk significance and because they are
entered into your corrective action program, the NRC is treating these two findings as noncited
violations (NCVs) consistent with Section VI.A of the NRC Enforcement Policy. If you contest any NCV 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 U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional
Administrator, U.S. Nuclear Regulatory Commission, Region IV, 611 Ryan Plaza Drive, Suite
400, Arlington, Texas 76011-4005; the Director, Office of Enforcement, U.S. Nuclear Regulatory
Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Diablo
Canyon Power Plant.
Pacific Gas and Electric Company-2-
In accordance with 10 CFR 2.390 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 (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/Vince G. Gaddy, Chief Project Branch B
Division of Reactor Projects Dockets: 50-275 50-323 72-026 Licenses: DPR-80
DPR-82 SNM-2511
Enclosure:
NRC Inspection Report 05000275/2007005, 05000323/2007005, and 07200026/2007001
w/attachment:
Supplemental Information cc w/enclosure:
Sierra Club San Lucia Chapter
ATTN: Andrew Christie
P.O. Box 15755
San Luis Obispo, CA 93406 Nancy Culver San Luis Obispo
Mothers for Peace
P.O. Box 164
Pismo Beach, CA 93448 Chairman San Luis Obispo County Board of
Supervisors
County Government Building
1055 Monterey Street, Suite D430
San Luis Obispo, CA 93408 Pacific Gas and Electric Company-3-
Truman Burns\Robert Kinosian California Public Utilities Commission
505 Van Ness Ave., Rm. 4102
San Francisco, CA 94102-3298 Diablo Canyon Independent Safety Committee Robert R. Wellington, Esq.
Legal Counsel
857 Cass Street, Suite D
Monterey, CA 93940 Director, Radiological Health Branch State Department of Health Services
P.O. Box 997414 (MS 7610)
Sacramento, CA 95899-7414 Jennifer Post, Esq.
Pacific Gas and Electric Company
P.O. Box 7442
San Francisco, CA 94120 City Editor The Tribune
3825 South Higuera Street
P.O. Box 112
San Luis Obispo, CA 93406-0112 James D. Boyd, Commissioner California Energy Commission
1516 Ninth Street (MS 34)
Sacramento, CA 95814 James R. Becker, Vice President Diablo Canyon Operations and
Station Director, Pacific Gas and
Electric Company
Diablo Canyon Power Plant
P.O. Box 56
Avila Beach, CA 93424 Jennifer Tang Field Representative
United States Senator Barbara Boxer
1700 Montgomery Street, Suite 240
San Francisco, CA 94111 John T. Conway Pacific Gas and Electric Company-4-
Site Vice President Diablo Canyon Power Plant
P.O. Box 56
Avila Beach, CA 93424 Chief, Radiological Emergency Preparedness Section National Preparedness Directorate
Technological Hazards Division
Department of Homeland Security
1111 Broadway, Suite 1200
Oakland, CA 94607-4052 Pacific Gas and Electric Company-5-
Electronic distribution by RIV:
Regional Administrator (EEC)DRP Director (DDC)DRS Director (RJC1)DRS Deputy Director (ACC)Senior Resident Inspector (MSP)Branch Chief, DRP/B (VGG)Senior Project Engineer, DRP/E (RWD)Team Leader, DRP/TSS (CJP)RITS Coordinator (MSH3)DRS STA (DAP)V. Dricks, PAO (VLD)A. Powell, OCA Region IV Coordinator (AXP10)D. Pelton, OEDO RIV Coordinator (DLP)ROPreports DC Site Secretary (AWC1)D. Spitzberg. FCDB/B (DBS)
SUNSI Review Completed: __VGG__ADAMS: Yes G No Initials: _VGG
_ Publicly Available G Non-Publicly Available G Sensitive Non-SensitiveR:\REACTORS\_DC\2007\DC2007-05-MSP-VGG.wpdADAMS ML080360630RIV:RI:DRP/BSRI:DRP/BC:DRS/EB1C:DRP/PSC:DRS/OB MABrownMSPeckRLBywaterMPShannonRELantz
/RA VGG for//RA VGG for//RA//RA//RA/01/ 31/0801/31/0801/17/0801/22/0801/17/08C:DRS/EB2DNMSDNMSC:DRP/BLJSmithRLKellarBSpitzbergVGGaddy
/RA NFO for//RA DBS for//RA//RA/01/31/0801/29/0801/29/0802/5/08OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax Enclosure-1-U.S. NUCLEAR REGULATORY COMMISSION REGION IVDockets:50-275, 50-323,72-026 Licenses:DPR-80, DPR-82, SNM-2511 Report:05000275/2007005 05000323/2007005
07200026/2007001Licensee:Pacific Gas and Electric Company Facility:Diablo Canyon Power Plant, Units 1 and 2 Location:7 1/2 miles NW of Avila Beach Avila Beach, CaliforniaDates:October 1 through December 31, 2007 Inspectors:M. Peck, Senior Resident Inspector M. Brown, Resident Inspector
K. Clayton, Senior Operations Engineer
D. Stearns, Health Physicist, Plant Support Branch
R. Kellar, Health PhysicistApproved By:V. G. Gaddy, Chief, Projects Branch B Division of Reactor Projects Enclosure-2-
SUMMARY OF FINDINGS
IR 05000275/2007-005, 05000323/2007-005; 10/1/07 - 12/31/07; Diablo Canyon Power Plant
Unit 1; Surveillance Testing, Identification and Resolution of Problems.
This report covered a 13-week period of inspection by resident inspectors and announced inspections on operator licensing and radiation protection. One NRC-identified, Green, noncited violation and one NRC-identified Severity Level IV noncited violation were identified. The significance of most findings is indicated by their color (Green, White, Yellow, or Red) using
Inspection Manual Chapter 0609 "Significance Determination Process." Findings for which the
Significance Determination Process does not apply may be Green or be assigned a severity level after NRC management review. The 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.
The inspectors identified a noncited violation of 10 CFR 50, Appendix B, "Corrective Action," after Pacific Gas and Electric failed to identify a degraded emergency diesel generator. On October 15, 2007, the inspectors identified a buildup of black soot on the Emergency Diesel Generator 1-1 exhaust manifold.
Licensee personnel subsequently identified that one of the four fasteners connecting the exhaust manifold to the turbo charger was missing. The licensee declared the diesel generator inoperable based on the potential reduction of electrical power output due to exhaust gas bypassing the turbo charger and the adverse affect of the missing fastener on seismic qualification. Plant operators determined that overall plant risk was significantly degraded (Orange) due to the combination of the unavailable diesel generator and other plant equipment removed from service at the time. The licensee had prior opportunity to identify the degraded diesel generator during operator rounds between September 23 and October 15, 2007.
This finding is greater than minor because, if left uncorrected, continued failure to perform adequate operator rounds would become a more significant safety concern. This finding affected the mitigating systems cornerstone because the issue involved an emergency diesel generator. Using the Inspection Manual
Chapter 0609, "Significance Determination Process," Phase 1 worksheet, this finding was determined to have very low safety significance because it did not result in a loss of operability of a single train, for greater than Technical
Specification allowed outage time, did not result in the loss of safety function, and was not potentially risk significant from a seismic, flooding or severe weather perspective. This finding has a crosscutting aspect in the area of problem identification and resolution associated with the corrective action program component because plant operators did not maintain a low threshold for identifying issues P.1(a). This issue was entered into the licensee's corrective action program as Action Request A0710082 (Section 4OA2.1).
Enclosure-4-*SL IV. The inspectors identified a noncited Severity Level IV violation of 10 CFR 50.59 after Pacific Gas and Electric failed to perform an adequate safety evaluation of Unit 1 containment sump modifications. As a result, the licensee failed to obtain prior NRC approval for a change to the technical specifications incorporated in the license. On March 6, 2007, the licensee identified that the current refueling water storage tank minimum technical specification level was not adequate to ensure that the new containment sump would perform the required safety function. On April 20, 2007, Pacific Gas and Electric completed a 10 CFR 50.59, "Licensing Basis Impact Evaluation Screen of the Containment
Sump Modification." The licensee concluded that the modification did not involve a change to the plant technical specifications and that the required refueling water storage tank level was unaffected by the modification. On May 25, 2007,
Pacific Gas and Electric placed Unit 1 into Mode 4 without an approved technical specification change.
The inspectors concluded that the finding was more than minor because the modification required prior NRC approval. Because the issue affected the NRC's ability to perform its regulatory function, this finding was evaluated using the traditional enforcement process. The issue was classified as Severity Level IV because the violation of 10 CFR 50.59 involved conditions evaluated as having very low safety significance by the Significance Determination Process. The finding was determined to be of very low safety significance because the safety function was maintained since Pacific Gas and Electric had administratively maintained the refueling water storage tank at an adequate level during plant operation. On this basis, the item impacts the mitigating systems cornerstone and screens to Green, using the Inspection Manual Chapter 0609, "Significance
Determination Process," Phase 1 evaluation, Appendix A, because (a) the finding is not a design or qualification deficiency, (b) there is no loss of safety function for the mitigating system; and, (c) there are no seismic, fire, flooding or severe weather initiating implications associated with the finding. This finding has a crosscutting aspect in the area of problem identification and resolution associated with the corrective action program component because the licensee did not appropriately prioritize and evaluate the problem of an inadequate refueling water storage tank level after the problem was entered into the corrective action program, P.1(c). This issue was entered into the licensee's corrective action program as Action Request A07145625 (Section 4OA2.2).
REPORT DETAILS
Summary of Plant Status
At the beginning of the inspection period, Pacific Gas and Electric Company (PG&E) was operating both units at Diablo Canyon at full power. On December 3, 2007, PG&E reduced both
units to 24 percent power to mitigate high storm seas. The licensee returned Unit 1 to full
power on December 5 and Unit 2 to full power on December 8, 2007. PG&E operated both
units at full power for the remainder of the inspection period.1.REACTOR SAFETY Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity1R04Equipment Alignments (71111.04)
Partial System Walkdowns
a. Inspection Scope
The inspectors:
- (1) walked down portions of the below listed risk important system and reviewed plant procedures and documents to verify that critical portions of the selected
system were correctly aligned; and,
- (2) compared deficiencies identified during the walk
down to the FSAR Update and corrective action program (CAP) to ensure problems
were being identified and corrected. *October 15, 2007, Unit 1, Emergency Diesel Generator 1-1
The inspectors reviewed Procedure STP M-9A, "Diesel Generator Routine Surveillance,"
and Drawings 106721, "Diesel Engine Generator" for the inspection.
The inspectors completed one sample.
b. Findings
No findings of significance were identified.
1R05 Fire Protection
Quarterly Inspection
a. Inspection Scope
The inspectors walked down the below listed plant areas to assess the material
condition of active and passive fire protection features and their operational lineup and
readiness. The inspectors:
- (1) verified that transient combustibles and hot work
activities were controlled in accordance with plant procedures;
- (2) observed the
condition of fire detection devices to verify that they remained functional;
- (3) observed
fire suppression systems to verify that they remained functional and that access to
-6-manual actuators was unobstructed;
- (4) verified that fire extinguishers and hose stations were provided at their designated locations and that they were in a satisfactory
condition;
- (5) verified that passive fire protection features (electrical raceway barriers, fire doors, fire dampers, steel fire proofing, penetration seals, and oil collection systems)
were in a satisfactory material condition;
- (6) verified that adequate compensatory
measures were established for degraded or inoperable fire protection features and that
the compensatory measures were commensurate with the significance of the deficiency;
and,
protection problems.*November 19, 2007: Unit 1, Fire Area 14-E, Component cooling water heat exchanger room*November 19, 2007: Unit 2, Fire Area 19-E, Component cooling water heat exchanger room*November 19, 2007: Unit 1, Fire Area 7-A, Cable spreading room
- November 19, 2007: Unit 2, Fire Area 7-B, Cable spreading room
- November 23, 2007: Unit 1, Fire Area 3-Q-2, Motor driven auxiliary feedwater pump*November 23, 2007: Unit 2, Fire Area 3-T-2, Motor driven auxiliary feedwater pump*December 14, 2007: Unit 2, Fire Area 1-A, Containment annular area
- December 14, 2007: Unit 2, Fire Area 1-C, Containment operating deck
Documents reviewed by the inspectors included:
- Diablo Canyon Power Plant Units 1 and 2 FSAR Update, Appendix 9.5A, "Fire Hazards Analysis," Revision 17*Diablo Canyon Power Plant Fire Protection Pre-Plan, May 14, 2003
The inspectors completed eight samples.
b. Findings
No findings of significance were identified.
-7-1R07Heat Sink Performance (71111.07)
a. Inspection Scope
The inspectors reviewed PG&E's programs, verified performance against industry standards, and reviewed critical operating parameters and maintenance records for
Component Cooling Water Heat Exchangers 1-1 and 1-2. The inspectors verified that:
- (1) performance tests were satisfactorily conducted for heat exchangers/heat sinks and
reviewed for problems or errors;
- (2) PG&E utilized the periodic maintenance method
outlined in EPRI NP-7552, "Heat Exchanger Performance Monitoring Guidelines;"
- (3) PG&E properly utilized biofouling controls;
- (4) PG&E's heat exchanger inspections
adequately assessed the state of cleanliness of their tubes, and,
- (5) the heat
exchangers were correctly categorized under the Maintenance Rule.
The inspectors reviewed Diablo Canyon Power Plant Component Cooling Water 1-1 and 1-2 Heat Exchanger Test, Pre-1R14, May 2007, and Procedure PEP M-234, "Component Cooling Water Heat Exchanger Performance Test," Revision 9, for the
inspection.
The inspectors completed one sample.
b. Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification (71111.11)
.1 Quarterly Inspection
a. Inspection Scope
On October 30, 2007, the inspectors observed a seismic event with anticipated transient without scram evaluation on the plant simulator. The inspectors observed the evaluation
to identify any deficiencies and discrepancies in the training to assess operator
performance and the evaluator's critique.
Documents reviewed by the inspectors in cluded Lesson FRS1-A, "Seismic Event with ATWS," Revision 15.
The inspectors completed one sample.
b. Findings
No findings of significance were identified.
-8-
.2 Biennial Inspection
a. Inspection Scope
The inspectors reviewed the licensee's simulator activities using Inspection Procedure 71111.11, "Licensed Operator Requalification Program," and 10 CFR 55.46, "Simulation Facilities," as acceptance criteria. The purpose of this review was to
determine if the simulator was capable of supporting initial examinations, supporting
requalification training required for all licensed operators on shift, and supporting
reactivity and control manipulations for initial license applications. The inspectors reviewed the simulator annual performance test book for 2007, in which most of the annual tests were conducted between September and November 2007, using ANS/ANSI 3.5-998, "Nuclear Power Plant Simulators for Use in Operator Training
and Examination," as committed to by PG&E in the Simulator Testing Procedure "Configuration Management Plan for the Operator Training Simulator," CF2.DC1, Revision 4. Because the licensee informed the inspectors that the simulator would be
used for reactivity manipulation credits on the next initial examination scheduled for June 2008, several core performance test documents were reviewed in order to assess
the adequacy of the simulator in supporting reactivity and control manipulations as
documented on NRC Form 398, "Personal Qualification Statement." While the simulator
use for reactivity and control manipulation is permitted by 10 CFR 55.46, the simulator
must meet the appropriate standards of fidelity, as required by 10 CFR 55.46(c)(2). The
inspectors reviewed the criteria in 10 CFR 55.46(c)(2) against the core performance test
document samples and the Cycle 15 test data from the plant. The simulator was using
the Cycle 15 core load for the current training cycle and no issues were found. Three transient tests, one scenario-based test package, and a work package closeout test were run on the simulator in order to verify that the data collected from the previous
tests was an accurate representation of the test data run during the testing in
November 2007, and also a verification of reasonable model performance based on the
current design of the plant. These tests were:
- (1) design basis loss of coolant accident
with subsequent loss of off-site power transient test eight;
- (2) maximum size unisolable
main steam line rupture transient test nine;
- (3) slow primary system depressurization to
saturation condition with pressurizer relief or safety valve stuck open (inhibit activation of
high pressure emergency core cooling system) transient test ten;
- (4) scenario-based test
package for mid-loop operations; and,
- (5) discrepancy work closeout package for
radiation monitor failures discovered during a loss of coolant accident scenario test.
As part of this review, the inspectors interviewed one instructor, one evaluator, two reactor operators, two senior reactor operators, one simulator engineer, and the
simulator support supervisor. The interviews were performed to collect feedback
regarding the fidelity of the simulator, the simulator discrepancy reporting system
effectiveness, and training on differences between the simulator and the plant. The
inspectors reviewed several program documents that describe the overall simulator
program. One item specifically related to this review was how management groups, such as the simulator review board, coordinate discrepancy priorities and subsequent
repair decisions. These items were reviewed in order to satisfy the requirements of
10 CFR 55.46(d) for continued assurance of simulator fidelity through problem
-9-identification and resolution, proper reporting, root cause evaluations, and a planned schedule for implementing timely corrective actions with proper content.
Documents reviewed by the inspectors are listed in the attachment.
b. Findings
The inspectors confirmed that the licensee's simulator was adequate for reactivity manipulation credits on the next initial licensi ng examination provided that they continue to maintain the simulator core model on the most recent core load as the plant for which
licenses are being sought and the core testing program and results are maintained for
the examiners to review on the respective examination validation week in accordance
with NUREG-1021, Revision 9, Supplement 1, "Operator Licensing Examination
Standards for Power Reactors."1R12Maintenance Effectiveness (71111.12) Routine Maintenance Effectiveness Inspection The inspectors reviewed the listed maintenance activities to:
- (1) verify the appropriate handling of structure, system, and component (SSC) performance or condition problems;
- (2) verify the appropriate handling of degraded SSC functional performance;
- (3) evaluate
the role of work practices and common cause problems; and,
- (4) evaluate the handling
of SSC issues reviewed under the requirements of the Maintenance Rule, 10 CFR
Part 50, Appendix B, and the Technical Specifications:*October 26, 2007: Unit 1 and Unit 2, Plant process computer failures *December 5, 2007: Unit 2, Containment Air Particulate Monitor RM-11 failures Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed two samples.
b. Findings
No findings of significance were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)
.1 Risk Assessments and Management of Risk
a. Inspection Scope
The inspectors reviewed the listed assessment activities to verify:
- (1) performance of risk assessments when required by 10 CFR 50.65(a)(4) and PG&E procedures prior to
changes in plant configuration for maintenance activities and plant operations;
- (2) the
accuracy, adequacy, and completeness of the information considered in the risk
assessment;
- (3) that PG&E recognizes, and/or enters as applicable, the appropriate risk
category according to the risk assessment results and PG&E procedures; and
- (4) PG&E
-10-identified and corrected problems related to maintenance risk assessments.*October 9, 2007: Unit 1, Auxiliary Saltwater Pump 1-1 maintenance
- October 17, 2007: Unit 1, Reactor coolant pump under voltage and under frequency relay calibration*November 6, 2007: Unit 2, Emergency Diesel Generator 2-1 maintenance outage
- November 20, 2007: Unit 1, Component Cooling Water Heat Exchanger 1-2 and Auxiliary Saltwater Pump 1-2*December 14, 2007: Unit 2, Steam generator replacement project controls and plans to minimize adverse impact on the Unit 1 and common systems Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed five samples.
b. Findings
No findings of significance were identified.
.2 Emergent Work
a. Inspection Scope
The inspectors:
- (1) verified that PG&E performed actions to minimize the probability of initiating events and maintained the functional capability of mitigating systems and
barrier integrity systems;
- (2) verified that emergent work related activities such as
troubleshooting, work planning/scheduling, establishing plant conditions, aligning
equipment, tagging, temporary modifications, and equipment restoration did not place
the plant in an unacceptable configuration; and,
- (3) reviewed the FSAR Update to
determine if PG&E identified and corrected risk assessment and emergent work control
problems.*October 17, 2007; Unit 1 Emergency Diesel Generator 1-1, unplanned outage to repair exhaust manifold Documents reviewed by the inspectors included Procedure AD7.DC6, "On-line Maintenance Risk Management," Revision 9.
The inspectors completed one sample.
b. Findings
No findings of significance were identified.
1R15 Operability Evaluations (71111.15)
-11-
a. Inspection Scope
The inspectors:
- (1) reviewed plant status documents such as operator shift logs, emergent work documentation, deferred modifications, and standing orders to determine
if an operability evaluation was warranted for degraded components;
- (2) referred to the
FSAR Update and design bases documents to review the technical adequacy of the
operability evaluations;
- (3) evaluated compensatory measures associated with
operability evaluations;
- (4) determined degraded component impact on any TS;
- (5) used
the Significance Determination Process to evaluate the risk significance of degraded or
inoperable equipment; and,
- (6) verified that PG&E has identified and implemented
appropriate corrective actions associated with degraded components.*October 9, 2007: Unit 1, Emergency Diesel Generator 1-3 oil leak
- October 31, 2007: Unit 2, Battery charger soldering deficiencies
- November 19, 2007: Unit 2, Emergency Diesel Generator 2-1 lube oil filter leak
- December 3, 2007: Unit 2, Auxilia ry building ventilation system damper maintenance*December 4, 2007: Unit 1, Turbine Driven AFW Pump Steam Supply Valve FCV-95 incorrect valve stem lubrication*December 31, 2007: Unit 2, Seismic degradation of control room panels
Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed six samples.
b. Findings
No findings of significance were identified.
1R19 Postmaintenance Testing (71111.19)
a. Inspection Scope
The inspectors selected the listed postmaintenance test activities of risk significant
systems or components. For each item, the inspectors:
- (1) reviewed the applicable
licensing basis and/or design basis documents to determine the safety functions;
- (2) evaluated the safety functions that may have been affected by the maintenance
activity; and,
- (3) reviewed the test procedure to ensure it adequately tested the safety
function that may have been affected. The inspectors either witnessed or reviewed the
test data to verify that acceptance criteria were met, plant impacts were evaluated, test
equipment was calibrated, procedures were followed, jumpers were properly controlled, the test data results were complete and accurate, the test equipment was removed, the
system was properly realigned, and deficiencies during testing were documented. The
inspectors also reviewed the FSAR Update to determine if PG&E identified and
-12-corrected problems related to postmaintenance testing:*October 10, 2007: Unit 1 Auxiliary Saltwater Pump 1-1 preventive maintenance
- October 15 and 16, 2007: Unit 1 Diesel Generator 1-1 preventive maintenance
- November 1, 2007: Unit 2, Safety Injection Pump Motor 2-1 preventive maintenance*November 2, 2007: Unit 2 Safety Injection Pump 2-1 preventive maintenance
- November 11, 2007: Unit 2 Emergency Diesel Generator 2-1 preventive maintenance*December 4, 2007: Residual Heat Removal Pump 1-1 preventive maintenance
- December 9, 2007: Unit 2, Turbine Driven Auxiliary Feedwater Pump 2-1 preventive maintenance*December 10, 2007: Unit 1 Fuel Handling Building Ventilation System Exhaust Fan E-6 preventive maintenance Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed eight samples.
b. Findings
No findings of significance were identified.
1R22 Surveillance Testing (71111.22)
a. Inspection Scope
The inspectors reviewed the FSAR Update, procedure requirements, and TS to ensure that the below listed surveillance activities demonstrated that the SSCs tested were
capable of performing their intended safety functions. The inspectors either witnessed
or reviewed the test data to verify that the following significant surveillance test attributes
were adequate:
- (1) preconditioning;
- (2) evaluation of testing impact on the plant;
- (3) acceptance criteria;
- (4) test equipment;
- (5) procedures;
- (6) jumpers;
- (7) test data;
- (8) testing frequency and method demonstrated TS operability;
- (9) test equipment
removal;
- (10) restoration of plant systems;
- (11) fulfillment of American Society of
Mechanical Engineers Code requirements;
- (12) updating of performance indicator data;
- (13) engineering evaluations, root causes, and bases for returning tested SSCs not
meeting the test acceptance criteria were correct;
- (14) reference setting data; and,
- (15) annunciators and alarm setpoints. The inspectors also verified that PG&E identified
and implemented any needed corrective actions associated with the surveillance testing.*October 9, 2007: Unit 1, Check valve inspections, inservice test
-13-*October 23, 2007: Unit 1, Containment Air Particulate Radiation Detector RM-11*November 1, 2007: Unit 2, Emergency Dies el Generator 2-3 room carbon dioxide fire system test*November 21, 2007: Unit 2, Emergency core cooling venting
- December 9, 2007: Unit 2, Inservice te st of turbine driven Auxiliary Feedwater Steam Stop Valve FCV-95*December 9, 2007: Unit 2, Inservice test of steam supply to turbine driven Auxiliary Feedwater Turbine FCV-37 and FCV-38*December 9, 2007: Unit 2, Inservice test of Auxiliary FeedwaterPump Discharge Valves LCV-106, 107, 108, and 109 *December 23, 2007: Unit 1, Reactor coolant system water inventory balance
Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed one RCS leak detection, three routine, and four inservice testsamples.
b. Findings
No findings of significance were identified.
1R23 Temporary Plant Modifications (71111.23)
a. Inspection Scope
The inspectors reviewed the FSAR Update, plant drawings, procedure requirements, and TSs to ensure that listed temporary modi fications were properly implemented. The inspectors:
- (1) verified that the modifications did not have an effect on system
operability/availability;
- (2) verified that the installation was consistent with modification
documents;
- (3) ensured that the postinstallation test results were satisfactory and that
the impact of the temporary modifications on permanently installed SSCs were
supported by the test;
- (4) verified that the modifications were identified on control room
drawings and that appropriate identification tags were placed on the affected drawings;
and
- (5) verified that appropriate safety evaluations were completed. The inspectors
verified that PG&E identified and implemented any needed corrective actions associated
with temporary modifications. *October 29, 2007: Unauthorized temporary modification installing 480 volt power in the Unit 1 component cooling water heat exchanger room*November 15, 2007: Unit 1, 12kV Bus E potential transformer temporary connection
-14-*December 13, 2007: Unit 2, Steam generator replacement project engineering design, modification, and analysis associated with steam generator lifting and
rigging Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed three samples.
b. Findings
No findings of significance were identified.
Cornerstone:
Emergency Preparedness1EP6Emergency Preparedness Evaluation (71114.06)
a. Inspection Scope
For the listed drill contributing to Drill/Exercise Performance and Emergency Response Organization Performance Indicators, the inspectors:
- (1) observed the training evolution
to identify any weaknesses and deficiencies in the emergency response organization;
- (2) compared the identified weaknesses and deficiencies against PG&E identified
findings to determine whether PG&E is properly identifying failures; and
- (3) determined
whether PG&E performance is in accordance with the guidance of the NEI 99-02, "Voluntary Submission of Performance Indicator Data," acceptance criteria.*July 25, 2007, Units 1 and 2, full emergency drill
Documents reviewed by the inspectors included the Diablo Canyon Power Plant Emergency Plan, Revision 4.
The inspectors completed one sample.2.RADIATION SAFETY
Cornerstone:
Occupational Radiation Safety2OS1Access Control To Radiologically Significant Areas (71121.01)
a. Inspection Scope
The inspectors assessed the licensee's performance in implementing physical and administrative controls for airborne radioactivity areas, radiation areas, high radiation
areas, and worker adherence to these controls. The inspectors used the requirements
in 10 CFR Part 20, the TSs, and the licensee's procedures required by the TSs as
criteria for determining compliance. During the inspection, the inspectors interviewed
the radiation protection manager, radiation protection supervisors, and radiation workers.
-15-The inspectors performed independent radiation dose rate measurements and reviewed the following:*Performance indicator events and associated documentation packages reported by PG&E in the occupational radiation safety cornerstone*Controls (surveys, posting, and barricades) of three radiation, high radiation, or airborne radioactivity areas
- Barrier integrity and performance of engineering controls in airborne radioactivity areas*Adequacy of the licensee's internal dose assessment for any actual internal exposure greater than 50 millirem committed effective dose equivalent *Self-assessments, audits, licensee event reports, and special reports related to the access control program since the last inspection*Corrective action documents related to access controls
- Radiation work permit briefings and worker instructions
- Posting and locking of entrances to all accessible high dose rate - high radiation areas and very high radiation areas*Radiation worker and radiation protection technician performance with respect to radiation protection work requirements Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed 13 samples.
b. Findings
No findings of significance were identified.2OS2As Low As is Reasonably Achievable (ALARA) Planning and Controls (71121.02)
a. Inspection Scope
The inspectors assessed PG&E's performance with respect to maintaining individual and collective radiation exposures as low as is reasonably achievable (ALARA). The
inspectors used the requirements in 10 CFR Part 20 and the licensee's procedures
required by TSs as criteria for determining compliance. The inspectors interviewed
PG&E personnel and reviewed:*Current 3-year rolling average collective exposure
- Site-specific trends in collective exposures, plant historical data, and source-term measurements*Site-specific ALARA procedures
-16-*Five work activities of highest exposure significance completed during the last outage *ALARA work activity evaluations, exposure estimates, and exposure mitigation requirements*Intended versus actual work activity doses and the reasons for any inconsistencies *Person-hour estimates provided by maintenance planning and other groups to the radiation protection group with the actual work activity time requirements *Post-job (work activity) reviews
- Method for adjusting exposure estimates, or replanning work, when unexpected changes in scope or emergent work were encountered*Exposures of individuals from selected work groups*Radiation worker and radiation protection technician performance during work activities in radiation areas, airborne radioactivity areas, or high radiation areas *Self-assessments, audits, and special reports related to the ALARA program since the last inspection*Resolution through the corrective action process of problems identified through post-job reviews and post-outage ALARA report critiques*Corrective action documents related to the ALARA program and followup activities, such as initial problem identification, characterization, and tracking Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed 14 samples.
b. Findings
No findings of significance were identified.4.
OTHER ACTIVITIES
4OA1 Performance Indicator Verification
.1 Cornerstone:
a. Inspection Scope
The inspectors sampled PG&E submittals for the two performance indicators listed below for the period from September 2006 to September 2007, for Units 1 and 2. The
definitions and guidance of NEI 99-02, "Regulatory Assessment Indicator Guideline,"
Revision 4, were used to verify PG&E's basis for reporting each data element in order to
verify the accuracy of PI data reported during the assessment period.
-17-*RCS Specific Activity*RCS Leakage The inspectors completed two samples.
b. Findings
No findings of significance were identified.
.2 Cornerstone:
a. Inspection Scope
The inspectors reviewed licensee documents from April 1 through September 30, 2007, in regards to occupational exposure control effectiveness. The review included
corrective action documentation that identified occurrences in locked high radiation
areas (as defined in the licensee's technical specifications), very high radiation areas (as
defined in 10 CFR 20.1003), and unplanned personnel exposures (as defined in Nuclear
Energy Institute (NEI) 99-02, "Regulatory Assessment Indicator Guideline," Revision 5).
Additional records reviewed included ALARA records and whole body counts of selected
individual exposures. The inspectors interviewed PG&E personnel that were
accountable for collecting and evaluating the performance indicator data. In addition, the inspectors toured plant areas to verify that high radiation, locked high radiation, and
very high radiation areas were properly controlled. Performance indicator definitions and
guidance contained in NEI 99-02, Revision 5, were used to verify the basis in reporting
for each data element.
Document reviewed by the inspectors included the Action Request A 0696907.The inspectors completed one inspection sample.
b. Findings
No findings of significance were identified.
.3 Cornerstone:
Public Radiation Safety The inspectors reviewed licensee documents from April 1 through September 30, 2007, in regards to radiological effluent technical specification/offsite dose calculation manual
radiological effluent occurrences. The review included corrective action documentation
that identified occurrences for liquid or gaseous effluent releases that exceeded
performance indicator thresholds and those reported to the NRC. The inspectors
interviewed PG&E personnel that were accountable for collecting and evaluating the
performance indicator data. Performance indicator definitions and guidance contained
in NEI 99-02, Revision 5, were used to verify the basis in reporting for each data
element.The inspectors completed one sample in this cornerstone.
b. Findings
No findings of significance were identified.
-18-4OA2Identification and Resolution of Problems (71152)
.1 Routine Review of Identification and Resolution of Problems
a. Inspection Scope
The inspectors performed a daily screening of items entered into the corrective action program. This assessment was accomplished by reviewing action requests and event
trend reports, and attending daily operational meetings. On November 5, 2007, the
inspectors attended the condition adverse to quality screening meeting. The inspectors:
- (1) verified that equipment, human performance, and program issues were being
identified by PG&E at an appropriate threshold and that the issues were entered into the
corrective action program;
- (2) verified that corrective actions were commensurate with
the significance of the issue; and,
- (3) identified conditions that might warrant additional
follow-up through other baseline inspection procedures.
b. Findings
Introduction.
The inspectors identified a Green noncited violation of 10 CFR 50, Appendix B, "Corrective Action," after PG&E failed to identify a degraded emergency
diesel generator.
Description.
On October 15, 2007, the inspectors identified black soot on the Emergency Diesel Generator 1-1 exhaust manifold. Licensee personnel subsequently
identified that one of four fasteners connecting the exhaust manifold to the turbo charger
was missing. The licensee declared the diesel generator inoperable based on the
potential reduction of electrical power output due to exhaust gas bypassing the turbo
charger and the adverse affect of the missing fastener on seismic qualification. Plant
operators determined that overall plant ri sk elevated to significantly degraded (Orange)due the combination of the unavailable diesel generator and other plant equipment
removed from service at the time. The licensee repaired and returned the diesel
generator to service on October 19, 2007. Plant engineering personnel subsequently
concluded that the loss of the fastener would not have prevented the diesel generator
from performing the required safety function. The soot buildup was present since the
last previous operation of the diesel generator on September 23, 2007. The licensee
had prior opportunity to identify the degraded diesel generator. Plant operators
performed at least one inspection of the diesel generator each shift in accordance with
Procedure OP1.DC3, "Operator Routine Plant Equipment Inspections," Revision 8.
Operations Policy A-22, "Expectations for Nuclear Operator Watchstanders,"
November 16, 2004, required operators to maintain an awareness of equipment
condition and to report problems in a timely manner.
Analysis.
Failure of PG&E operations personnel to identify the degraded diesel generator during operator rounds was a performance deficiency. This finding is greater
than minor because, if left uncorrected, continued failure to perform adequate operator
rounds would become a more significant safety concern. This finding involved an
emergency diesel generator and affected the mitigating systems cornerstone. Using the
Manual Chapter 0609, "Significance Determination Process," Phase 1 worksheet, this
finding was determined to have very low safety significance because it did not result in a
loss of operability of a single train, for greater than Technical Specification allowed
outage time, did not result in the loss of safety function, and was not potentially risk
significant from a seismic, flooding or severe weather perspective. This finding has a
-19-crosscutting aspect in the area of problem identification and resolution associated with the corrective action program component because plant operators did not maintain a low
threshold for identifying issues, P.1(a).
Enforcement.
Title 10 of the Code of Federal Regulations, Part 50, Appendix B,Criterion XVI, "Corrective Action," requires that measures be taken to assure that
conditions adverse to quality are promptly identified and corrected. Contrary to the
above, the licensee failed to identify a condition adverse to quality. Specifically, between
September 23 and October 15, 2007, plant operators did not identify the degraded
Emergency Diesel Generator 1-1 exhaust. Because this finding is of very low safety
significance and was entered into the corrective action program as Action Request
A0710082, this violation is being treated as a noncited violation in accordance with
Section VI.A.1 of the Enforcement Policy: NCV 05000275/2007005-01, "Plant Operators
Failed to Identify a Degraded Emergency Diesel Generator."
.2 Selected Issue Follow-Up Inspection
a. Inspection Scope
In addition to the daily screening, the inspectors conducted an in-depth review of the listed issues. The inspectors considered the following during the review of PG&E's
actions:
- (1) complete and accurate identification of the problem in a timely manner;
- (2) evaluation and disposition of operability/reportability issues;
- (3) consideration of
extent of condition, generic implications, common cause, and previous occurrences;
- (4) classification and prioritization of the resolution of the problem;
- (5) identification of
root and contributing causes of the problem;
- (6) identification of corrective actions; and,
- (7) completion of corrective actions in a timely manner.*A0710652, November 21, 2007, Discrepancies associated with ultrasonic flow monitor nozzle fouling factor input into secondary system heat balance
calculations*A0712404, November 20, 2007, Evaluate if licensee bases impact evaluation screen for less than adequate reactor water storage tank level required a license
amendment Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed two in-depth review samples.
b. Findings
Introduction.
The inspectors identified a noncited Severity Level IV violation of 10 CFR 50.59 after PG&E failed to perform an adequate safety evaluation of Unit 1
containment sump modifications. As a result, the licensee failed to obtained prior NRC
approval for a change to the technical specifications incorporated in the license.
Description.
PG&E modified the Unit 1 containment sump during the Spring 2007 refueling outage. Technical Specification 3.5.4, "Refueling Water Storage Tank,"
required 81.5 percent indicated level (400,000 gallons). This technical specification
ensured enough water was provided during accident mitigation to ensure the residual
heat removal pump net positive suction head during the transition from cold leg injection
-20-mode to cold leg recirculation mode emergency core cooling. After the containment sump modification, 93.6 percent level in the refueling water storage tank (RWST) was
required to ensure residual heat removal pump net positive suction head. On
March 6, 2007, the licensee identified that the current RWST minimum technical
specification level was not adequate to ensure the new containment sump would
perform the required safety function. This was entered into the corrective action
program as Action Request A0690337. On April 20, 2007, PG&E completed a
10 CFR 50.59 Licensing Basis Impact Evaluation Screen of the containment sump
modification. The licensee concluded that the modification did not involve a change to
the technical specifications and that the RWST Technical Specification was unaffected
by the modification. On May 25, 2007, PG&E placed Unit 1 into Mode 4 without an
approved technical specification change. On October 2, 2007, the licensee submitted a
License Amendment Request to raise the RWST technical specification minimum level to meet the new sump design requirements. Plant operators had administratively
maintained the Unit 1 RWST at the higher level since entry into Mode 4.
Analysis.
The failure of PG&E to perform an adequate safety evaluation of the containment sump modification, to identify that prior NRC approval was required, is a
performance deficiency. The inspectors concluded that the finding was more than minor
because the modification required NRC prior review and approval. Because the issue
affected the NRC's ability to perform its regulatory function, this finding was evaluated
using the traditional enforcement process. The issue was classified as Severity Level IV
because the violation of 10 CFR 50.59 involved conditions evaluated as having very low
safety significance by the SDP. The finding was determined to be of very low safety
significance because the safety function was maintained since PG&E had
administratively maintained the RWST at least 93.6 percent indicated level during plant
operation. On this basis, the item impacts the Mitigating System Cornerstone and
screens to GREEN using IMC 0609, Phase 1 SDP Evaluation, Appendix A, because
- (a) the finding is not a design or qualification deficiency,
- (b) there is no loss of safety
function for a mitigating system and,
- (c) there are no seismic, fire, flooding or severe
weather initiating implications associated with the finding. This finding has a
crosscutting aspect in the area of problem identification and resolution associated with
the corrective action program component because the licensee did not appropriately
prioritize and evaluate the problem of an inadequate refueling water storage tank level
after the problem was entered into the corrective action program, P.1(c).
Enforcement.
Title 10 of the Code of Federal Regulations, Part 50.59(c)(1) requires, in part, that a licensee may make changes in the facility as described in the final safety
analysis report without obtaining a license amendment only if a change to the technical
specifications incorporated in the license is not required. Title 10 CFR 50.36 requires, in
part, that a technical specification limiting condition for operation of a nuclear reactor
must be established for a structure, system, or component that is part of the primary
success path and which functions or actuates to mitigate a design basis accident or
transient that either assumes the failure of or presents a challenge to the integrity of a
fission product barrier. Contrary to the above, on May 25, 2007, PG&E made changes
to the facility as described in the final safety analysis report without obtaining a license
amendment when a change to the technical specifications incorporated in the license
was required. Specifically, PG&E changed the containment sump design such that
additional minimum Technical Specification level was required to ensure the design
basis accident primary success path. Because this finding is of very low safety
significance and was entered into the corrective action program as Action
Request A0715625, this violation is being treated as a noncited violation in accordance
-21-with Section VI.A.1 of the Enforcement Policy: NCV 05000275/2007005-02, "Inadequate 50.59 Evaluation for Unit 1 Containment Sump Modification."
.3 Semiannual Trend Review
a. Inspection Scope
The inspectors completed a semiannual trend review of repetitive or closely related issues that were documented in action requests, maintenance rule reports, system
health reports, problem lists, and performance indicators to identify trends that might
indicate the existence of more safety significant issues. The inspectors' review
consisted of the six-month period from July to December 2007. When warranted, some
of the samples expanded beyond those dates to fully assess the issue. Corrective
actions associated with a sample of the issues identified in PG&E's trend report were
reviewed for adequacy.
b. Findings
Continued Adverse Trend in Plant Equipment Material Condition The inspectors concluded that the adverse trend in plant material condition, discussed in Diablo Canyon Power Plant Integrated Inspection Report 05000275/2007003 and
05000323/2007003, continued through the inspection period. Current examples of poor
material condition identified by the inspectors included:*A0710082, Diesel Generator 1-1 Exhaust Leak
- A0710921, Control room air conditioner condenser missing nine fasteners
- A0706792, Control Room Air Conditioner CR-38 corrosion
- A0710807, Component Cooling Water Heat Exchanger Saltwater Inlet Valve FCV-603 corrosion*A0710817, Oil seeping from Component Cooling Water Valve 1-21
- A0719815 and A0710809, Component cooling water corroded conduits
- A0710801, Corrosion on Component Cooling Water Valve FCV-602
- A0710987, Component Cooling Water gasket for ASW to S/Gs
PG&E capture this adverse trend in the corrective action program as Action Request A0711113.
NRC Identified Adverse Trend in Managing Maintenance Risk The inspectors identified that the maintenance risk management thresholds established by the licensee were considerably below thre sholds established in the industry guidance provided in NUMARC 93-01, "Nuclear Energy Institute, Industry Guideline for Monitoring
the Effectiveness of Maintenance at Nuclear Power Plants," Revision 3. Because of low
threshold, PG&E typically entered elevated "Yellow Risk" (Integral Core Damage
-22-Probability 1x10
-6 to 1x10-5 ) an average of 12 times per week. The licensee also entered elevated "Orange Risk" (Integral Core Damage Probability greater than 1x10
-5 )several times during the inspection. The inspectors concluded that routine and repetitive
declaration of elevated plant maintenance risk resulted in plant of personal desensitized
to the subsequent risk management actions.
Examples included:*A0711074, Failure to control access to redundant equipment following removal of a Unit 2 component cooling water pump during declared "Yellow Risk."*A0711107, October 31, 2007, Removal of protective area around Unit 2 main feed water pumps while Diesel Generator 2-3 was planned to be removed from
service for fire protection testing, during declared "Yellow Risk." *A07164454, November 6, 2007, Unit 1 Shift Foreman was unaware of risk management actions following removal of a control room ventilation system
during declared "Yellow Risk."*A0711876, Unit 2 did not document entry into "Orange risk."
The inspectors concluded that each example was minor because actual industry risk threshold values for the required risk management actions were not exceeded. The
licensee entered this adverse trend into the corrective action program as Action
Request A0711061.
Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed one sample in this inspection.
.4 Operator Workaround Review
The inspectors conducted a review to verify that the licensee is identifying operator workaround problems at an appropriate threshold, entered these issues into the
corrective action program and that the licensee has proposed or implemented
appropriate corrective actions. The inspectors reviewed the November 9, 2007, Operator
Workaround and Control Room Deficiency Report.
The inspectors completed one workaround sample.
.5 Occupational Radiation Safety
a. Inspection Scope
The inspectors evaluated the effectiveness of PG&E's problem identification and resolution process with respect to the following inspection areas:*Access Control to Radiologically Significant Areas (Section 2OS1)*ALARA Planning and Controls (Section 2OS2)
b. Findings
No findings of significance were identified.
-23-4OA3Event Followup (71153)
.1 (Closed) Licensee Event Report 05000275/2007001-00, Emergency Diesel Generator
Auto-start on Loss of Offsite 230kV Startup Power On May 12, 2007, offsite startup power was lost to both units at Diablo Canyon after a Morro Bay-Diablo Canyon 230 kV line transmission failed. The Unit 1 reactor was
defueled at the time and powered by the startup bus. Diesel Generators 1-1 and 1-2
automatically started and powered vital buses per plant design. This event was
previously discussed in Diablo Canyon Power Plant Integrated Inspection Report
323/2007003. No violation of NRC requirements was identified in this LER. This LER is
closed.
.2 (Closed) Licensee Event Report 05000275/2007002-00, Manual Reactor Trips During
Mode 3 Rod Testing Due to Crud Related Rod On May 27, 2007, Control Rod N-13 slipped from 42 steps to 24 steps while operators
were performing Surveillance Test Procedure STP R-1C, "Digital Rod Position Indicator
Functional Test," Revision 16, while Unit 1 was in Mode 3. Plant operators manually
tripped the reactor. The licensee concluded that the rod slippage was due to the crud
buildup on the control rod drive shaft. The vendor recommended that operators exercise
Control Bank 'C' out and back in five times in order to remove the crud from the drive
shaft. During the sequence of five rod exercises, Control Rod N-13 slipped three more
times, with each sequential slip occurring at higher steps out of the core. Operators
exercised Control Bank 'C' five more times without any additional control rod slippage.
PG&E staff subsequently concluded that the crud on the Control Rod N-13 drive shaft
had been removed to the reactor coolant syst em. This event was previously discussed in Diablo Canyon Power Plant Integrated Inspection Report 05000323/2007003. No
violation of NRC requirements was identified in this LER. This LER is closed.
.3 (Closed) Licensee Event Report 05000275/2007003-00, Emergency Diesel Generator
Actuation Due to a Transient Undervoltage Condition On May 28, 2007, an unplanned automatic start of Diesel Generator 1-2 occurred due to degraded bus voltage after Circulating Water Pump 1-2 was started. Plant operators
had transferred all plant electrical loads from the auxiliary power supply to startup power
in preparation of paralleling the main generator to the electric grid. Once all plant
electrical loads were connected to the startup power, operators started Circulating Water
Pump 1-2. Due to the large in-rush current required to start the pump, voltage degraded
on all plant electrical buses, including the vital 4 kV buses. The voltage on the vital 4 kV
buses degraded to the point that the second-level undervoltage relays actuated and
began the time delay sequence. The voltage on Vital 4 kV Buses F and H recovered
prior to the end of the time sequence. However, the voltage on Vital Bus G did not
sufficiently recover resulting in a trip of the startup power supply breaker and an
automatic start of the diesel generator. Plant engineering personnel determined that the
large circulating water pump motor in-rush current along with low startup power supply
margin resulted in the degraded voltage on the vital buses. The inspectors reviewed the
event sequence, equipment performance, operator actions, and plant electrical design
as they relate to this event. No violation of NRC requirements was identified in the LER.
This LER is closed.
-24-4OA5Other.1 Onsite Fabrication of Components and Construction of an Independent Spent Fuel Storage Installation (ISFSI) (60853)
a. Inspection Scope
The inspectors witnessed the final portion of the vertical cask transporter (VCT)functional testing performed at Diablo Canyon and completed reviews of documentation
from tests that had been conducted at the fabricator facility. The VCT is classified as
Important to Safety (ITS) and used to transport the loaded multi-purpose canister (MPC)
inside the HI-TRAC transfer cask from the fuel building to the ISFSI. The VCT is
seismically qualified and has redundant drop protection features in accordance with the
applicable guidelines of NUREG-0612, "Control of Heavy Loads at Nuclear Power
Plants." The VCT will also serve as the cask transfer facility (CTF) to lower the MPC into
the HI-STORM concrete overpack.
The NRC performed an inspection of the VCT fabrication at Lift Systems, Inc., located at Moline, Illinois, in January 22-26, 2007 (ML070400122). The factory acceptance testing
called for a 100 percent functional test, 125 percent static load test, 150 percent MPC
downloader test, 125 percent test of the seismic restraint lugs and an inclined functional
test. Overall, the fabrication activities were found to be in compliance with
10 CFR Part 72 regulations and the NRC approved Holtec QA program. The MPC
downloader test and nondestructive examinations of the critical welds were performed
after the NRC inspection. The inclined functional test was scheduled to be performed
after the VCT was delivered to Diablo Canyon.
Holtec provided a copy of the completed factory acceptance testing Holtec Project Procedure (HPP) 1073-6, Revision 2, which documented the successful 150 percent
load test of the MPC downloader. The MPC downloader is used to transfer the loaded
MPC from the HI-TRAC transfer cask into the HI-STORM overpack. The MPC
downloader test documentation stated that a test load of 67.5 tons (+10 tons/-0 tons)
had been used to perform the load test and the test load had been held for at least
10 minutes. A list of the VCT critical welds which were examined by nondestructive
examination following the load tests was provided by Holtec. The welds were classified
as critical per Section 3.4 of Holtec Standard Procedure HSP 187, "Interface Procedure
for Manufacturing of ITS B Transporters at Lift Systems," Revision 3, as a weld on an
essential component whose failure would directly lead to an uncontrolled lowering of the
lifted load or failure of other critical design function. The classification was stated to
conform to the evaluation criteria contained in NUREG-0612, Section 5.1, and the
definition of a critical load per ANSI N14.6, Section 3.4. The inspectors reviewed the
visual and magnetic particle test reports for selected welds that were classified as
critical. No discrepancies were found during the review. The VCT cask restraint system
design and fabrication were documented to meet the requirements of the ASME NF
Code. NUREG-0612 does not address horizontal loads such as those associated with
the cask restraint system. The spent fuel storage and transportation staff determined
that meeting the design and fabrication requirements of the ASME NF Code would be
sufficient to ensure that the cask restraint system operated safely.
The VCT was shipped to Diablo Canyon to perform the inclined functional test. The inclined functional test utilized the HI-TRAC transfer cask with an MPC that included
sufficient weight (82,500 pounds) to simulate a fully loaded MPC. The inclined functional
-25-test consisted of transporting the HI-TRAC and MPC from the entrance of the radiological controlled area (RCA) down the 8.5 percent grade and up the nominal
6 percent grade to the CTF. The distance of the transport path was approximately
1.2 miles in length.
The transport path or roadway from the fuel building to the ISFSI was designed and constructed to meet AASHTO H-20 loadings. The licensee had recently discovered that
the loadings imposed by the VCT tracks exceeded the H-20 design loadings. Minor
modification package AT-MM A0710693 was originated to evaluate the impact upon
embedded structures located beneath the roadway from the actual loads that were
exerted by the VCT along the route affected by the inclined function test. The minor
modification package verified that there were no safety related components located
underneath the portion of the roadway used for the inclined functional test. However, several portions of the roadway were required to be reinforced and minimum stand-off
distances were specified from the VCT to several of the boxes/vaults located along the
transport route. The licensee noted that the use of the roadway for movement of spent
fuel (including the area inside the RCA) will be addressed by a separate design change
package.The inclined functional load test was conducted after 1800 on Monday, December 10, 2007. The HI-TRAC with the simulated weight MPC was lifted by the VCT and secured
by the cask restraint system. The VCT was taken inside the protected area of the plant
up to the RCA fence. The VCT then traversed down the 8.5 percent grade and across
the relatively flat area of the plant site. Prior to beginning the trip up the nominal
6 percent grade, the 50 gallon fuel tank was refilled and the VCT then negotiated the
nominal 6 percent incline to the CTF.
A minor delay was experienced when hydraulic fluid was discovered leaking from an "O" ring fitting. The VCT inclined functional load
test was completed satisfactorily without any safety significant findings.
Diablo Canyon Technical Specification 4.3.1.c required that the cask transporter be designed, fabricated, inspected, maintained, operated, and tested in accordance with
the applicable guidelines of NUREG 0612. The staff reviewed the cask transporter
documentation to determine if the cask transporter met the applicable guidelines of
NUREG 0612. During this review, two questions were raised by the staff that required
additional clarification from the licensee.
The first question was associated with how the licensee had determined the testing requirements for the transporter load/lift links, which were part of the VCT lifting
mechanism. The load/lift links had been designed to meet the increased design stress
factors of 6 for yield and 10 for ultimate strength as required by ANSI N14.6. The load
testing of the load/lift links had been performed at 125 percent of the VCT rated load as
required by ASME B30.2, "Overhead and Gantry Cranes." The licensee stated that this
methodology was based on the previously appr oved use of similar lifting devices that were required to meet multiple criteria of NUREG 0612. The staff determined that the
licensee testing of the VCT load/lift links met the applicable portions of NUREG 0612.
The second question raised by the staff was how the requirements of NUREG 0612, Section 5.1.1(6) which specified that the crane (transporter) be inspected, tested, and
maintained in accordance with Chapter 2-2 of ASME B30.2 was to be achieved. The
vendor had provided a maintenance manual for the transporter. However, the
maintenance manual did not specify any frequent or periodic inspections for the VCT
which would parallel the inspection requirements that were contained in Chapter 2-2 of
-26-ASME B30.2. The licensee committed to providing additional instructions in the maintenance manual that would meet the inspection and maintenance recommendations
contained in NUREG 0612, Section 5.1.1(6) and instructions for meeting the
specifications contained in ANSI N14.6 for the MPC downloader. The revised VCT
maintenance manual will be reviewed during a future inspection.
b. Findings
No findings of significance were identified.4OA6Meetings, Including Exit
Exit Meeting Summary
On November 8, 2007, the inspectors presented the occupational radiation safety inspection results to Mr. John Conway, Site Vice President, and other members of his
staff who acknowledged the findings.
On December 11, 2007, the inspectors presented the independent spent fuel storage installation inspection results to Mr. John Conway, Site Vice President, and other
members of his staff.
On December 12, 2007, the inspectors discussed the inspection results of the simulator fidelity portion of the licensed operator biennial requalification inspection with
Mr. Jim Welsch, Operations Manager, and other members of his staff.
On January 9, 2008, the resident inspection results were presented to Mr. John Conway, Site Vice President and other members of PG&E management. PG&E acknowledged
the findings presented.
In each case, the inspectors asked PG&E whether any materials examined during the inspection should be considered proprietary. Proprietary information was reviewed by
the inspectors and left with PG&E at the end of the inspection.
ATTACHMENT:
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
PG&E personnel
- J. Becker, Vice President - Diablo Canyon Operations and Station Director
- S. Hamilton, Supervisor, Regulatory Services
- R. Hite, Manager, Radiation Protection
- D. Jacobs, Vice President - Nuclear Services
- S. Ketelsen, Manager, Regulatory Services
- K. Langdon, Director, Operations Services
- R. Lovell, Senior Nuclear Engineer
- M. Meko, Director, Site Services
- K. Peters, Director, Engineering Services
- J. Purkis, Director, Maintenance Services
- P. Roller, Director, Performance Improvement
- M. Somerville, Manager, Radiation Protection
- D. Taggart, Manager, Quality Verification
- R. Waltos, Manager, Emergency Preparedness
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened and Closed
05000275/2007005-01NCV
Plant Operators Failed to Identify a Degraded Emergency
Diesel Generator (Section 4OA2.1)05000275/2007005-02NCV
Inadequate 50.59 Evaluation for Unit 1 Containment Sump
Modification (Section 4OA2.2)
Closed
- 05000275/LER-2007-001-00LEREmergency Diesel Generator Auto-start on Loss of Offsite
- 230kV Startup Power (Section 4OA3.1)
- 05000275/LER-2007-002-00LERManual Reactor Trips During Mode 3 Rod Testing Due to
- Crud Related Rod Slippage (Section 4OA3.2)
- 05000275/LER-2007-003-00LEREmergency Diesel Generator Actuation Due To A Transient
- Undervoltage Condition (Section 4OA3.3)
LIST OF DOCUMENTS REVIEWED
Section 1R11:
- Licensed Operator Requalification (71111.11)
- Biennial Inspection
Procedures
- Number Title RevisionCF2.DC1Configuration Management Plan for the Operator Training Simulator 4SQA 99-2Operator Training Simulator Software Quality Assurance Plan 0STP R7-ADetermination of Moderator Temperature Coefficient at
- HZP,
- BOL 15STP R31Rod Worth Measurements Using Rod Swap Method12
Other Documents
- Simulator Scenario for Mid-Loop Operations, R075S1, Rev. 0
- Open Simulator discrepancy report (all)
- Closed Simulator discrepancy report from November 2005 thru November, 2007
- Annual Operability Test packages*Steady state power test (83% and 25%)*Transients Reviewed (All 11)
- Core test package for cycle 15
- Simulator versus Plant differences list
- Work package closeout and post-test for simulator SCR # 04-062, where high radiation alarms during a Loss of Coolant Accident scenario failed to work
Section 1R12:
- Maintenance Effectiveness (71111.12)
- Action RequestsA0595654A0684348A0692558A0702988A0671226A0697363A0709074A0709405A0712454A0712518
Procedures
- Number Title RevisionSTP I-100AContainment Air Particulate/Gas Radiation Monitor RM-
- 11/RM-12 Functional Test
Other Documents
- Title
- Date/Revision System Report Details, System 43A "Plant Process Computer"7/1 - 9/30/2007System Report Details, System 39A/B "Rad. Monitoring System"10/1 - 12/31/2007
Section 1R13:
- Maintenance Risk Assessments and Emergent Work Control (71111.13)
- Action RequestsA0711265A0711289A0711270
Procedures
- Number Title RevisionAD7.DC6On-Line Maintenance Risk Management10OP J-6B:IXDiesel Generator Extended On-Line Maintenance1
- AD8.ID1Outage Planning and Management9
- TP 22.0Risk Management Task Plan0
- OP
- AP-9Loss of Instrument Air23
- OP AP
- SD-4Loss of Component Cooling Water16
Section 1R15:
- Operability Evaluations (71111.15)
- Action RequestsA0691325A0697545A0709245A0710347A0710345A0710346A0690663A0710353A0712157A0454787A0711781A0664398
- A0712272A0712386A0715324
Procedures
- Number Title RevisionMP I-2.17-1Guidelines for Printed Circuit Board Repair and Inspection
3OM4 .ID3Assessment of Industry Operating Experience12STP
- M-21-ENG.1Diesel Engine Generator Procedure (Every Refueling Outage)8 Other Documents Title
- Date/RevisionWork Order,
- C0216111 "DEG 2-1 Repair (Lube Oil Filter Housing Leak)"11/17/2007
Section 1R19:
- Postmaintenance Testing (71111.19)
- Action RequestsA0712336A0712337A0701654A0711712
Procedures
- Number Title RevisionSTP M-9ADiesel Engine Generator Routine Surveillance Test74STP M-9XDiesel generator Operability Verification20
- STP M-9D1Diesel Generator Full Load Rejection Test12
- STP P-SIP-21Routine Surveillance test of Safety Injection Pump 2-120
- MP M-17.9Auxiliary Salt Water Pump Maintenance20
- STP M-5Surveillance Test of the Fuel Handling Building Ventilation System
Other Documents
- Title
- Date/RevisionWork Order, R0285110, "RHR PP 1-1 Discharge Miniflow Control"11/30/2007Work Order, R0285591, "4KV RHR PP 1-1"11/29/2007
- Work Order, R0299925, "RHR Pump 1"11/21/2007
- Work Order, R0306079, "Residual Heat Removal Pump 1-1"11/21/2007
- Design Criteria
- Memorandum S-10, "Residual Heat Removal System"15
- Work Order, R0295991, "E-6 Motor: Clean, Inspect, and Test"12/6/2007
Section 1R22:
- Surveillance Testing (71111.22)
- Action RequestsA0710155A0711107A0691531
Procedures
- Number Title RevisionSTP I-100AContainment Air Particulate/Gas Radiation Monitor RM-
- 11/RM-12 Functional Test
- 14STP M-39A3Routine Surveillance Test of Diesel Generator 1-3 (2-3)
- Room Carbon Dioxide Fire System Operation
- 2STP M-89Unit 2, ECCS System Venting37STP R-10CReactor Coolant System Water Inventory Balance34
- STP V-3P5Exercising Valves
- LCV-106, 107, 108, and 109 Auxiliary Feedwater pump Discharge
- 20STP V-18MCheck Valve Inspections - High Maintenance Valves10
- STP-V-3R5Exercising Steam Supply to AFW Pump Turbine Stop Valve 19STP-V-3R6Exercising Steam Supply to AFW Pump Turbine Isolation Valves 10
Drawings
- Number Title Revision663227-55Air Flow Diagram -
- RE 11/RE 124102931-11Instrument Schematic - Radiation Instruments57
Section 1R23: Temporary Plant Modifications (71111.23)
Action Requests
- AR0711967 Procedures Number Title RevisionCF4.ID7Temporalty Modifications 19TP
- TD-070312kV Bus "E" Potential Transformer Repair at Power0
- TS3.ID2Licensing Basis Impact Evaluation22
Drawings
- Number Title Revision437612-1Unit 1 Electrical Schematic Diagram Bus Potential &
- Synchronizing 12kV System
Other Documents
- Title Date/Revision Design Change Package
- C-050743, "SGRP - Rigging and Handling Inside Containment" Design Change Package
- C-050745, "SGRP - Rigging and Handling Outside Containment" Calculation # 52.15.141, "SGRP Load Path Evaluation - Impact on Elev.
- 140' Auxiliary Building Area GE and K Response Spectra due to
- Movement of New/Old Steam Generators (Enova calc. 0104-031-C01)
- 2A Calculation # 52.15.142, "SGRP Load Path Evaluation - Seismic Stability Analysis of the Steam Generator/Transporter at Elev. 140' Auxiliary
- Building Area GE and K (Enova calc. 0104-032-C01)
- 1A
- Calculation # 52.15.143, "SGRP Load Path Evaluation - Evaluation of Floor at Elev. 140' Auxiliary Building Area GE and K due to Movement of
- New/Old Steam Generators (Enova calc. 0104-032-C03)
- R0309046 02 Diesel generator 2-3 installation of recorder to monitor
- DEG start, December 21, 2007
Section 2OS1:
- Access Controls to Radiologically Significant Areas (71121.01)
- Action RequestsA0695011A0695199A0695353A0695683A0695740A0695961A0696887A0696907A0697100A0697727A0698424A0700022
- A0700672A0703336A0703338A0703339
- Audits and Self-Assessments Diablo Canyon Power Plant Quality Performance Assessment Report, 1
st Period 2007
- Diablo Canyon Power Plant Quality Performance Assessment Report, 2
nd
- Period 2007
- 2007 Radiation Protection Program Audit dated August 9, 2007
Procedures
- Number Title RevisionRP1Radiation Protection4ARCP D-240Radiological Posting17
- RCP D-370Evaluation of Internal Deposition of Radioactive Material7
- RCP D-500Routine and Job Coverage Surveys23
Section 2OS2:
- Action RequestsA0695351A0695591A0695595A0695730A0695936A0695974A0696277A0696286A0696352A0696741A0697472A0697722
- A0698373A0698378A0698387A0698396A0698548A0698582
- A0699099A0701401A0703330A0703352
- Radiation Work PermitsSWP 10021R14 Scaffolding in ContainmentSWP 10331R14 RHR Recirc & Containment Sump
- SWP 10441R14 Eddy Current Inspection & Tube Work
- AttachmentSWP 10741R14 Fire Stops and Insulation ReplacementSWP 10771R14 Insulation Double Banding
Procedures
- Number Title RevisionRP1 D-200Writing Radiation Work Permits37RCP D-205Performing ALARA Reviews15
- RCP D-211Control of Work in Radiologically Significant Areas3
- RCP D-220Control of Access to High, Locked High, and Very High Radiation Areas
- 2RCP D-222Radiation Protection Lock and Key Control5
Section 4OA2:
- Identification and Resolution of Problems (71152)
- Action RequestsA0695011A0695199A0695353A0695683A0695740A0695961A0487341A0487674A0616447A0619113A0638538A0650060
- A0711967A0777733A0710082A0677367A0675465A0710868
- A0710817A0715625A0657428A0686900A0706229A0708847
- A0710652 Audits and Self-Assessments Diablo Canyon Power Plant Quality Performance Assessment Report, 1
st Period 2007
- Diablo Canyon Power Plant Quality Performance Assessment Report, 2
nd
- Period 2007
- 2007 Radiation Protection Program Audit dated August 9, 2007
Procedures
- Number Title RevisionTS3.ID2Licensing Basis Impact Evaluations8PEP M-98AComparison of Final Feedwater Flow Nozzles to "AMAG" Ultrasonic Flow Instrumentation
Miscellaneous
- Title Date/Revision
- CENPD-397-P, "Improved Flow Measurement Accuracy Using Crossflow Ultrasonic Flow Measurement Technology"
- 01-P A-DP1-PS-0001, "Feedwater Flow Measurement Using the Crossflow Ultrasonic Flowmeter at PG&E Diablo Canyon Unit 1" 000 Semiannual Trend Review Assessment Reports Diablo Canyon Power Plant, Quality Performance Assessment Report, 4
th Period 2006
- Diablo Canyon Power Plant, Quality Performance Assessment Report, 1
st Period 2007
- Diablo Canyon Power Plant, Quality Performance Assessment Report, 2
nd Period 2007
- Diablo Canyon Power Plant, Plant Perfor mance Improvement Report, September 2007
- Diablo Canyon Power Plant, Plant Perf ormance Improvement Report, August 2007
- Quality Verification Department Bi-Weekly Observation Report, December 27, 2007
Miscellaneous
- PCPP Observation Card (ID# 21788) Operation Decision Meeting following failed reactor coolant pump breaker undervoltage relay, November 2, 2007
Section 4OA5: Other
Miscellaneous
- Holtec Project Procedure
- HPP-1073-6, "VCT Factory Test Procedure," Revision 2
- Holtec Project Procedure
- HPP-1073-6, "VCT Factory Test Procedure," Revision 3
- Holtec Standard Procedure
- HSP-187, "Interface Procedure For Manufacturing of ITS B
- Transporters at Lift Systems," Revision 3
- Diablo Canyon Transporter Manual, Revision 0
LIST OF ACRONYMS
ADAMSagency document and management systemAFWauxiliary feedwater
ALARAas low as is reasonably achievable
ARaction request
AASHTOAmerican Association of State Highway and Transportation Officials
CFRCode of Federal Regulations
DEGdiesel engine generator
FSARFinal Safety Analysis Report
HPPHoltec project procedure
HSPHoltec standard procedure
ISFSIindependent spent fuel storage installation
ITSImportant to Safety
LERlicensee event report
MPCmulti-purpose canister
NDEnondestructive examination
NRCNuclear Regulatory Commission
PARSPublicly Available Records System
PDTPacific daylight time
PG&EPacific Gas and Electric Company
RWSTrefueling water storage tank
SSCstructure, system and component
SLURSsecond-level undervoltage relays
TSTechnical Specifications