IR 05000244/1989016
| ML17261A927 | |
| Person / Time | |
|---|---|
| Site: | Ginna  |
| Issue date: | 01/22/1990 |
| From: | Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17261A925 | List: |
| References | |
| 50-244-89-16, NUDOCS 9002050019 | |
| Download: ML17261A927 (80) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION I
Report No.
50-244/89-16 Licensee No.
DPR-18 Licensee:
Rochester Gas and Electric Corporation 49 East Avenue Rochester, New York Faci 1 ity:
Location:
R.
E. Ginna Nuclear Power Plant Ontario, New York Inspection Conducted:
November 7 through December ll, 1989 Inspectors:
C.
S. Marschall, Senior Resident Inspector, Ginna N.
. Perry Reside t I s ector, Ginna Approved by:
.
C.
McCa e, Chief, Rea or Projects Section 3B Date
~Summar:
f tion activities including plant operations, radiological controls, maintenance, surveillance, engineering/technical support, security, periodic and special reports, written reports of nonroutine events, and follow-up on previously identified items.
Inspection activities consisted of 73.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> of inspection, including 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> of backshift inspection and 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> of deep backshift inspec-tion on November 24, 1989 and 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> of deep backshift December 10, 1989.
This report also documents a management meeting with the licensee on December 4,
1989.
Results:
Overall, the plant operated safely and plant events were dealt with effectively.
Examples of failure to follow procedures for system alignments are considered a violation (Detail 3.c).
An unresolved item was opened (Detail 3.c) pending licensee investigation of procedure steps signed as completed but not performed.
A weakness was identified in the licensee's program for control of scaffolding construction; (Detail 3.e).
Four previously identified viola-tions were closed (Detail 5).
5'0020 0019 9C>01"4 PDR
,ADOCK 0"000244
TABLE OF CONTENTS PAGE
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Persons Contacted.
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Summary of Plant Operations...........:..........
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Functional or Program Areas Inspected.
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5.
Follow-up on Previously Identified Items (92702).
a.
Plant Operations (71707).
b.
Radiological Controls (71707)
c.
Maintenance (62703).
d.
Surveillance (61726)
e.
Engineering/Technical Support (71707).
f.
Security (71707)..
g.
Periodic and Special Reports (90713).......
h.
Written Reports of Nonroutine Events (90712)..
4.
NRC-RGEE Management Meeting
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8 6.
Exit Interview (30703)
DETAILS Persons Contacted During this inspection period, =inspectors interviewed operators, techni-cians, engineers and supervisory level personnel.
The following people were among 'those contacted:
S.
Adams, Technical Manager E. Edgar, Acting Maintenance Manager
- D. Filkins, Manager of HP & Chemistry
"A. Jones, Corrective Action Coor'dinator M. Lilley, Nuclear Assurance Manager'.
Marchionda, Director of Outage Planning
'T. Marlow, Superintendent, Support Services R. Mecredy, General Manager',
Nuclear Production J. St. Martin, Corrective Action Coordinator
- T. Schuler, Operations Manager L. Smith, Operations Supervisor
"S. Spector, Superintendent, Ginna Station
- J. Widay, Suerintendent, Ginna Production RE Mood, Supervisor, Nuclear Security
" Present at exit meeting on December 18, 1989.
Summar of Plant 0 erations At the beginning of the inspection period, the plant was at full power.
On November 13, 1989, plant power was reduced to less than 450 MWe net, approximately 91%, for planned bushing replacement on all three phases of the 9X output breaker in the substation located across from the plant.
Power was further reduced on November 14, 1989 to less than 410 MWe net, approximately 83%, for bushing replacement on the 1G output breaker.
The plant was returned to full power on November 15, 1989.
A turbine runback occurred on November 19, 1989 due to a signal generated in one of the four reactor coolant system average temperature channels.
Operators stabilized the plant at approximately 95% power and called in maintenance personnel.
After the channel was defeated, operators brought the plant back to full power.
On November 22, 1989, after the defeated channel had been restored, a similar turbine runback occurred.
Operators stabilized the plant at approximately 95% powe'r.
Again, plant power was increased to full power after the channel was defeate Plant power was reduced to approximately 47 percent on December 3,
1989 to enable personnel to attempt to identify and plug a condenser tube leak.
Workers were unable to identify any leaking tubes, so later the same day, power was increased to full power.
The plant remained at full power through the end of the inspection period.
3.
Functional or Pro ram Areas Ins ected Plant 0 erations (71707)
b.
The inspectors assessed whether the R.
E. Ginna Nuclear Power Plant operated safely and in conformance with license and regulatory re-quirements.
Control room staffing was adequately maintained and access to the control room was properly controlled.
Control room log books were reviewed to obtain information concerning trends and acti-vities, and recorder traces were observed for abnormalities.
Shift turnovers were adequate to ensure necessary information was addressed.
The'nspector determined whether selected engineered safety feature valves and breakers were correctly aligned, and por-tions of the containment isolation lineup were correct.. All access-ible areas of the plant were toured and plant conditions and activi-ties in progress were observed by the inspector with no inadequacies identified.
The inspector verified that plant technical specifica-tions were complied with and that selected safety-related tagouts were proper.
Shortly after the turbine runback on November 22, 1989, the inspector observed activities in the control room.
Operators were maintaining the plant at approximately 95% power, by procedure, while instrumen-tation and controls personnel were assessing the situation.
The inspectors observed that the affected channel was defeated within one hour of the runback as required by Technical Specifications.
Addi-tionally, the event was properly reported as required.
Monitoring of the instrumentation, as well. as root cause evaluation activities, failed to identify the cause for the turbine runbacks.
The inspectors concluded that operator actions in response to the runback were appropriate and in compliance with Technical Specifications and approved procedures.
Radiolo ical Controls (71707)
The resident inspector periodically verified that Radiation Work Per-mits were implemented properly, dosimetry was correctly worn in con-trolled areas and dosimeter readings were accurately recorded, access control at entrances to high radiation areas.was adequate, personnel used contamination monitors as required when exiting controlled areas, and postings and labeling were in compliance with regulations and procedures.
No inadequacies were identifie t
e Maintenance (62703)
The inspectors observed portions of various safety-related mainten-ance to determine that redundant components were operable, activities did not violate limiting conditions for operation, required adminis-trative approvals and tagouts were obtained prior to initiating work, approved procedures were used or the activity was within the "skills of the trade," appropriate radiological controls were implemented, ignition/fire prevention controls were properly implemented, and equipment was properly tested prior to returning it to service.
Portions of'the following maintenance activities were observed:
Maintenance (M)-37. 130, Disassembly 5 Reassembly of Pipe Flange Connections,
"A" CCW Pump Suction Flange, Revision 3, effec-
,tive July 5, 1989, observed November 17, 1989.
M-71.4, Removal and/or Installation of Foxboro Control Modules with Exposed AC Line Feeds, Module Tag ¹TT401, Revision 2, effective August 5, 1989, observed November 20, 1989.
Calibration Procedure (CP)-401, Calibration and/or Maintenance of T Avg Channel 401, Revision 2, effective October 17, 1989, observed November 22, 1989.
No inadequacies were identified during the first two maintenance ac-tivities; the inspector noted active involvement of quality control personnel in assuring proper replacement part qualification while per forming M-71.4.
On November 17, 1989, during performance of the daily control room checkoff, operators noted that the 1B subcooling monitor indication was off scale high.
The 1B subcooling monitor had been taken out of service earlier that day for periodic maintenance and had been re-turned to service approximately one hour prior to discovery of the high indication.
The 1B subcooling monitor was declared inoperable and Instrumentation and Controls ( I&C) technicians were called in for troubleshooting.
The technicians discovered that the test switch was not in the position required by Calibration Procedure (CP)-410A.
The test switch was repositioned, the monitor's restoration and indication was verified, and the monitor was returned to service.
No technical specification limit was exceeded.
A licensee Human Performance Evaluation System (HPES) investigation revealed that several problems and errors contributed to the inci-dent.
In June 1989, based on a concern raised by the resident in-spectors, management described the procedure for performing indepen-dent verifications in a
memo addressed to all maintenance personnel.
However, the HPES investigation concluded that at least some mainten-ance planners and workers were unaware of the memo.
The investiga-tion also concluded that (1) the preplanning for the 1B subcooling
monitor'maintenance was weak, (2) the maintenance procedure was weak since more than one action was required by one sign-off step, (3) the June 1989 memo was not effectively communicated to working. personnel, (4) the switch in question was not labeled, and (5) the practice of walking down the instrumentation after performing maintenance was not followed.
Licensee corrective actions include labeling the two test switches, and administrative procedure training for I&C personnel to emphasize independent verification requirements.
Maintenance guidelines are planned to be revised to require that planners review procedures prior to use to ensure requirements for independent verification of restoration have been established.
In addition, the licensee commit-ted to have new procedures for maintenance of the subcooling moni-tors, requiring sign-offs for independent verification, approved for use prior to the next maintenance or calibration of the subcooling monitor system.
The inspectors concluded that, in this case, there was only minor safety significance since while the 1B subcooling monitor was out of service, the redundant channel was operable at all times, and the period of inoperability did not exceed that permitted by the tech-nical specification limiting conditions for operation.
However, Technical Specification 6.8. 1 requires that written procedures be established, implemented, and maintained covering activities refer-enced in Appendix A of Regulatory Guide 1.33, November 1972.
Acti-vities referenced in Appendix A include maintenance and equipment control.
Ouring performance of CP-410A,'on November 17, 1989, I&C technicians failed to proper ly return the subcooling monitor to ser-vice,= and failed to independently verify the return-to-service steps as required by procedure A-1408.
Consequently, the test switch for the circuit was not restored to the original position, and the sub-cooling monitor remained out of service.
Additionally, maintenance planners failed to indicate in the procedure that independent veri-fication was required.
As a final operability check, Administrative Procedure (A)-52.4, Con-trol of Limiting Conditions for Operating Equipment, requires an additional independent verification.
Although procedure A-52.4 was performed by I&C and operations personnel, independent verification by visual observation of proper instrument indication was not accomp-lished as required by step 3.9. 1; the instrument remained pegged high as a result of incorrect position of the test switch.
Failure to follow procedures and the lack of independent verification have been previously identified by RG&E and the NRC (see NRC Inspection Reports 50-244/89-15 and 89-18);
and therefore, additional management atten-tion is needed.
Failure to properly position and independently verify equipment as required by procedures CP-410A, A-1408 and A-52.4 is a violation (50-244/89-16-01).
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As discussed above, a final review to ensure control of the "B" loop saturation temperature monitor system prior to equipment return-to-service was performed using procedure A-52.4.
Two IEC personnel, the head control operator, the control room foreman, and the shift super-visor initialled steps 3.9.1, 3.9.2 arid the review signatures indi-cating completion of independent verification, operability of the system, and acceptance of the completed maintenance by operations personnel.
Approximately one hour after procedure A-52.4 was com-pleted, -operator s discovered the instrument pegged high while per-forming daily operability checks.
The inspectors questioned how the steps were completed in procedure A-52.4 without proper control room indication.
At the conclusion of the inspection, plant management was investigating to determine how this happened.
This remains an unresolved item pending the results of the licensee's investigation (50-244/89-16-02).
As corrective action for an NRC violation (see NRC inspection Report 50-244/88-08)
the licensee developed Administrative Procedure (A)-1408, Independent Verification.
This procedure requires indepen-dent verification of systems related to technical specifications whenever items are manipulated for maintenanc'-
or test activities; the 1B subcooling monitor is required to be operable by Technical Specification 3.5.3.
The licensee HPES investigation did not address A-1408 until after the inspector brought it to the licensee's atten-tion.
The inspector concluded that the requirements of A-1408 are not fully understood by all plant personnel, many personnel are not aware of the procedure's existence, and licensee methods of communi-cating station policy were ineffective.
Surveillance (61726)
Inspectors observed portions of surveillance tests to verify that test instrumentation was properly calibrated, approved procedures were used, work was performed by qualified personnel, limiting con-ditions for operation were met, and systems were correctly restored following testing.
Portions of the following surveillances were observed:
Periodic Test (PT)-3, "Containment Spray Pumps and NaOH Additive System,"
Revision 49, effective August 8, 1989, observed Novem-ber 16, 1989.
PT-12. 1, "Emergency Diesel Generator 1A," Revision 50, effective August 15, 1989, observed November 20, 1989.
No inadequacies were identifie ~
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En ineerin /Technical Su ort (71707)
Mhile performing a periodic plant tour through the screenhouse on November 14, 1989, the inspector noted unattended scaffolding with unsecured planking in the vicinity of the service water pumps; the inspector raised the concern to plant management.
The scaffolding was not required by procedure to be seismically constructed, because a partial barrier existed between it and the service water pumps.
However, several long unsecured planks 'were laying on the scaffold-ing.
Because of their location, the inspector was concerned that the unsecured planks could fall and affect the service water pumps:
h The following morning, the inspector noted that the planking was still unsecured.
The concern was again raised with plant management and the planking was removed.
The planks in question were apparently
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used as an aid during construction of the scaffolding and, due to inadequate licensee inspection of the scaffolding, were left in place for at least one night.
The remaining scaffolding was inspected by the licensee and found acceptable.
Licensee personnel had checks" the scaffolding after the inspector initially raised the concern, but found it to be installed as re-quired.
The loose planks identified by the inspector were not recog-nized by licensee personnel.
The effectiveness of corrective action was not adequate in this instance.
No actual safety significance was associated with the existence of the loose planking, because the licensee's engineering
"evaluation concluded the planking did not have the potential for affecting safety-related equipment.
After further investigation, the inspector determined that the origi-nal scaffolding, located well away from the service water pumps, had been added onto twice.
The original temporary structural feature authorization form had been appended twice, rather than submitting two additional separate forms.
The controlling procedure, A-1406. 1, Installation and Removal of Temporary Structural Features, does not prohibit updating the authorization form; however, the updated authorization form did not receive the same level of review and in-spection required for the original installation.
The licensee con-cluded that although the planking was not required to be secured, it should have been removed, and that a
new authorization form should be initiated for review and approval when additions are made to existing scaffolding near safety-related equipment.
To prevent further potential problems, the licensee committed to change the practice of updating authorization forms for scaffolding near safety-related equipment.
The inspectors concluded that, al-though no violation of requirements occurred in this case, more man-agement attention is needed in this area to prevent a future safety pr obl e f.
~Securit (71707)
During this inspection period, the inspectors verified that certain detection equipment was operational, protected area and vital area barriers were, well maintained, access control during security turn-over was adequate, personnel were properly badged for unescorted or escorted access and compensatory measures were implemented when necessary.
No inadequacies were identified.
9.
Periodic and S eci al Re orts (90713)
Upon receipt, periodic and special reports submitted by the licensee pursuant to Technical Specification 6.9. 1 were reviewed.
This review included the following considerations:
reports contained information required by the NRC; test results and/or supporting information were consistent with design predictions and performance specifications; and reported information was valid.
The following report was reviewed:
Monthly Operating Report for October 1989.
The report met regulatory requirements.
h.
Written Re orts of Nonroutine Events (90712)
Written reports submitted to the NRC were reviewed to determine whether details were clearly reported, causes were properly identi-fied and corrective actions were appropriate.
The inspectors also determined whether assessment of potential safety consequences had been properly evaluated, generic implications were indicated, events warranted onsite follow-up, reporting requi rements of 10 CFR 50.72 were applicable, and requirements of 10 CFR 73 had been properly met.
The following LERs were reviewed (Note: date indicated is event date):
89-012, October 7, 1989, NIS Dropped Rod Signal Causes Turbine Runback.89-013, October 20,"
1989, Containment Gas Radiation Monitor Spikes, Due to Flow Imbalance, Causes Containment Ventilation Isolation.89-014, October 23, 1989, Containment Gas Radiation Monitor Spikes, Due to Flow Imbalance, Causes Containment Ventilation Isolation.
No inadequacies were identified.
The corrective actions to prevent a
recurrence of the event in LERs89-013 and 89-014 were reviewed in Inspection Report 89-15 and found satisfactor.
NRC-RG5E Mana ement Meetin 5.
On December 4,
1989 a meeting was held between NRC and RGKE management in the NRC Region I offices.
RGEE provided an update to the Regional Admini-strator on the status of licensee programs addressing RG&E Nuclear Con-cerns which were presented to th'e NRC in January 1989.
A copy of the handouts from the meeting is attached.
Follow-u on Previousl Identi-fied Items (92702)
(Closed) Violation 88-24-03: fire brigade does not attend preplanned drills.
All shift brigades attended a preplanned drill during the last quarter of 1988.
Additionally, Administrative Procedure A-103.9, "Fire Brigade Training," was changed to require all fire drills to be preplanned.
The inspectors reviewed training documentation and A-103.9, and had no further questions.
6.
(Closed) Violation 88-26-03:
Inadequate corrective action to prevent recur-rence of sensing line freezing.
Temperature sensing devices have been installed in temperature sensitive areas throughout the plant., The two lines which were frozen have been relocated to less temperature sensitive areas.
Administrative Procedure (A)-54.4. 1, "Cold Weather Walkdown," has been revised to require earlier and more in-depth reviews.
Additionally,-
temporary closure plates are installed earlier and cold weather concerns are rai sed at daily meetings and on the closed circuit television system.
The inspectors reviewed the procedure, the relocation of the sensing lines, the local thermometers in the plant, and had no further concerns.
(Closed) Violation 89-06-02:
the inspectors noted the additional training given to security personnel and had no additional questions.
(Closed) Violation 89-18-02:
inadequate corrective action for failing to perform weekly rodding of boric acid tank level bubbler tubes.
The acti-vity was added to the Outage Computer Systems for outage'ctivity schedul-ing.
Operations Procedure 06. 11 was revised to provide a check-off in the weekly surveillance checks.
The inspectors reviewed the procedure change and had no additional questions.
Exit Interview (30703)
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The inspectors met with senior plant management periodically and at the end of the inspection period to discuss inspection scope and findings.
Based on NRC Region I review of this report and discussions held, with lic-ensee representatives, it was determined this report does not contain in-formation subject to 10 CFR 2.790 restriction NRC MANAGEMENT MEETING AGENDA DECEMBER 4 1989 I.
Introduction Staffing and Overview Mr. Robert Smith Senior Vice President Engineering and Production II.
Review of 1989 Accom lishments
CFR 50.59 Reviews Maintenance Work Control Mr. Stanley Spector Plant Manager Ginna Station Post Maintenance Testing Housekeeping Procedure Adherence Procedure Upgrade Programs Configuration Management Q List IST Valve Program QA/QC Effectiveness Mr. Bruce Snow Chief Engineer Mr. Charles Anderson Manager, Quality Assurance III. Review of 1990 Priorit Tar ets IV.
Process Plannin Priorit Assi nments P
V.
Conclusions Mr. Robert Mecredy Director, Nuclear Production Mr. Robert Mecredy Mr. Robert Smith
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l0 CFR 50.59
~Trainin Completed March l989 Technical Personnel Management Personnel PORC Members Procedure Im rovements Procedures (Procedure Changes and New Procedures)
Minor Modifications (TSR)
NCR (Use-as-is or Repair Disposition)
Procurement (Documented through NCR or Minor Mods)
Future Plans Incorporated into on-going (continuing training) for all appropriate groups Continuing reviews of procedures to incorporate improving methodology
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Maintenance Work Control Pre lannin of Maintenance Work Procedure review for adequacy Special instructions specified Scope reviewed for configuration changes (and authorized)
Review of prior history (trending and industry information review for recurring problem identification)
Verification of concurrent activities impact Post maintenance testing determined Work Authorization Complete package given to worker
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Operating shi ft approval/notif ication on work start and completion Feedback on Work Supervisory review of work prior to determining work complete Results of maintenance documented with necessary details included Planners/analyst review of feedback Updating of equipment history and reliability centered maintenance program
Post Maintenance Testing Criteria established to determine post maintenance testing required Post maintenance testing required is established as work is authorized (short-term)
l990 Maintenance objective to systematically determine post maintenance testing requirements on routine jobs
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Housekeeping Major Upgrade Program high priority actions complete Intermediate Building Auxiliary Building Screenhouse Housekeeping standards approved Employee familiarization/reinforcement completed 12/07/89 Management=assignments of responsibility areas
Procedure, Adherence Procedure adherence training provided by April 1989 Management reinforcement at plant meetings Supervisory reinforcement frequent at small group meetings Emphasize procedure adherence is in all initial training and continuing training Significant improvements have been noted in mo'st areas On-going management reinforcement needed, especially in areas still needing improvement On-going criteria for supervisory inspections and quality inspections of work in progress
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Procedure Upgrade Programs Notable EOP upgrades completed July 1989 Calibration Procedure Upgrade Program on schedule (84 approved, 131 in approval process of 360 total)
Administrative Procedure Upgrade Program on schedule for 1990, completion Operating procedures upgraded July 1989 Independent verification resolution in all procedure sets Procurement procedures upgraded (due to be completed December 1989)
1990 Goals Completion of calibration procedure upgrades Completion of administrative procedure upgrades Reconciliation of operating procedures with drawing upgrades Initiation of mechanical maintenance procedure upgrade
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CONFIGURATION MANAGEMENT PROGRAM
~ SCOPE
~ STATUS
~ SCHEDULE
~ RESULTS
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CONFIGURATION MANAGEMENT PROGRAM SCOPE
~ RE-ESTABLISH GINNA BASELINE CONFIGURATION P8ID AND ELECTRICAL DRAWING UPGRADES
~ PERFORM DESIGN BASIS DOCUMENT RECONSTITUTION
~ STRENGTHEN THE CHANGE CONTROL PROCESSES TO ENSURE APPROPRIATE CONFIGURATION CONTROL
~ REVIEW ORGANIZATIONALINTERFACES NECESSARY TO MAINTAINCONFIGURATION INFORMATION
~ UPGRADE ADMINISTRATIVE,TECHNICAL AND MAINTENANCEPROCEDURES
~ DEVELOP AN INTEGRATED INFORMATION SYSTEM
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CONFIGURATION MANAGEMENTPROGRAM STATUS
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+ CONFIGURATION MANAGEMENTOVERSIGHT TASK FORCE FORMED (4/89) AND FUNCTIONING AS A STRATEGIC AREA
~ PLANT WALKDOWNS ARE IN PROGRESS FLUID SYSTEMS COMPLETE
~ DRAWING UPGRADES IN PROGRESS P8IDs COMPLETE (11/30/89)
ELECTRICAL IN PROGRESS SEISMIC DRAWINGS 90% COMPLETE
~ VENDOR TECHNICAL MANUALREVIEWS IN PROGRESS VTM INVENTORY COMPLETE $2/89 DETAILED REVIEWS INITIATED11/89 Q-LIST IN PROGRESS REVIEW OF UFSAR AND GINNA DOCKET COMPLETE (6/89)
SYSTEM CLASSIFICATION BASIS ESTABLISHED (7/89)
PLANT SYSTEM AND STRUCTURES LIST COMPLETE (11/89)
~ ADMINISTRATIONAND MAINTENANCE,PROCEDU RES UPGRADE IN PROGRESS
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CONFIGURATION MANAGEMENT PROGRAM SCHEDULE
~ FUNDING ESTABLISHED TO SUPPORT INTEGRATED SCHEDULE
~ INTEGRATED SCHEDULE UTILIZES THE ON-GOING RGRE EFFORTS ( Q-LIST DRIVES SCHEDULE )
COMPLETE Q-LIST 1990 COMPLETE PBclD UPGRADE 1989
- COMPLETE CONFIGURATION MANAGEMENT INFORMATION SYSTEM 1992
~ PROGRESS AND COST TRACKING SYSTEM IN PLACE
CONFIGURATION MANAGEMENT PROGRAM RESULTS
~ FORMATION OF RGRE CM OVERSIGHT TASK FORCE
~ FORMATION OF RGBE CM PROJECT TEAM
~ ESTABLISHED CM STRATEGY
~ ESTABLlSHED CM POLlCY
~ DEVELOPED CM PROGRAM MANUALAND ACTION PLANS
~ DEVELOPED AN INTEGRATED CM SCHEDULE AND BUDGET
~ DRAFTED PROCEDURES FOR ENHANCED CONFIGURATION CONTROL
~ FLUID SYSTEM WALKDOWNS COMPLETE P8ID COMPLETE
~ ESTABLISHED SENIOR MANAGEMENTCOMMITMENTTO PROGRAM
CONFIGURATION MANAGEMENT PROGRAM RESULTS(CONTINUED)
~ INITIATED THE FOLLOWING EFFORTS:
ELECTRICAL WALKDOWNS AND DRAWING UPGRADES DOCUMENT CONTROL UPGRADES STATION PROCEDURE UPGRADES COMMITMENT TRACKING PROGRAM VENDOR TECHNICAL MANUALREVIEWS
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GINNA EQUIPMENT SAFETY CLASSIFICATION PROJECT Q-LIST
SCOPE.
ENSURE THAT ALL EQUIPMENT NECESSARY TO SAFELY OPERATE, SHUTDOWN OR MITIGATETHE CONSEQUENCES OF AN ACCIDENT IS UNIQUELY IDENTIFIED
~ STATUS:
PROJECT UNDERWAY
- QUADREX AWARDED CONTRACT
- RG&,E MANAGER APPOINTED
- PROCEDURES DEVELOPED SYSTEM CLASSIFICATION UNDERWAY SYSTEM PRIMARY FUNCTIONS IDENTIFIED DATABASE UNDER DEVELOPMENT PARTS LEVEL CLASSIFICATION IMPLEMENTED AS A PARALLEL EFFORT ON AN AS NEEDED BASIS AT THE PLANT
GINNA EQUIPMENT SAFETY CLASSIFICATION PROJECT Q-LIST{CONTINUED)
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SCHEDULE:
- SYSTEM/COMPONENT Q-LIST {THIRD QUARTER 1990}
- PARTS LEVEL ON AN ONGOING BASIS
~ RESULTS:
- OVERALL CM SCHEDULE BEING DRIVEN TO SUPPORT Q-LIST
- PARTS LEVEL ACTIVITIES LINKED TO ON -GOING PROCUREMENT
- PROCEDURES AND PROJECT CONTROLS IDENTIFIED
CONFIGURATION MANAGEMENTPROGRAM PROJECTED MILESTONES FOR JAN-JULY 1990
~ COMPLETE COMPONENT LEVEL Q-LIST
~ COMPLETE THE GINNA STANDARD NOMENCLATURE LIST INCORPORATE INTO CONTROLLED DOCUMENT
~ COMPLETE DBD PILOT PROGRAM INITIATEDBD UPGRADE PROJECT
~ CMIS - COMPLETE CMIS SCOPE DEFINITION
- COMPLETE HIGH LEVEL FUNCTIONAL SPECIFICATION
-. COMPLETE THE FORMATION OF A PROJECT PLAN FOR IMPLEMENTATION
~ COMPLETE ENHANCED CHANGE CONTROL PROCESS
~ FINALIZE REMAINING CM PROGRAM ACTION PLANS
~ MAINTAINCM ISSUES PUNCHLIST
~ COMPLETE CM INTEREFACE REQUIREMENTS
'ESIGN P ROCESS PROCUREMENT DOCUMENT CONTROL MAINTENANCE
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INSERVICE PUMP AND VALVE TESTING PROGRAM REVIEW AND UPGRADE PROJECT MAY 1988 NRC INSPECTION FOUND IST PROGRAM DEFICIENCIES MANAGEMENT DIRECTS FULL SCOPE PROGRAM REVIEW IST REVIEW PROJECT TEAM ESTABLISHED PROJECT REVIEW CRITERIA ESTABLISHED
PROGRAM REVIEW
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PERFORMED SYSTEMATIC REVIEW TO SELECTION CRITERIA
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COMPLETE RESPONSES TO EGKG QUESTIONS
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DEVELOP NEW PUMP/VALVE TEST TABLES PERFORMED OPERATIONAL READINESS REVIEW
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COMPARE NEW PUMP/VALVE TABLES TO TEST PROCEDURES
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CLASSIFY NEWLY IDENTIFIED TESTS AS PROGRAM UPGRADES, DEFICIENCIES, OR OMISSIONS
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EVALUATE IMPACT ON PLANT OPERATIONS AND DEVELOP JCO'S
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INTERIM PROGRAM APPROVAL RECEIVED BY NRC BASED ON EGLG RESPONSE REVIEW ISSUE INTERIM CMANGES AND UPGRADE TEST PROCEDURES CHANGES RESULTING FROM REVIEW
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VALVES CLASSIFIED AS OMISSIONS
VALVES CLASSIFIED AS DEFICIENCIES
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VALVES CLASSIFIED AS PROGRAM UPGRADES
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VALVES DELETED FROM PROGRAM
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PUMPS ADDED TO PROGRAM
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TEST PROCEDURE CHANGES
PROCEDURE REVISIONS
NEW PROCEDURES
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PROJECT RESULTS INITIATED 5 MODIFICATIONS TO SUPPORT CODE TESTING
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TRAINING FOR NEW TESTING REQUIREMENTS COHPLETED ALL REQUIRED TESTING DURING 1989 OUTAGE UPGRADED IST PROGRAM FOR THIRD INTERVAL INCREASED UNDERSTANDING OF INSERVICE TESTING
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COMPUTER BASED PROGRAM FOR HAINTAINING PROGRAM COMMITMENTS AND TRACKING IMPLEMENTING PROCEDURES
~
COMPUTER BASED TREND AND ANALYSIS PROGRAM I'TAFFING INCREASE FOR PROGRAM MAINTENANCE ENGINEERING - IST ENGINEER PLANT IST COORDINATOR
~
ADDITIONAL TEST TECHNICIANS
I
QA/QC Era'ECTIVENESS 1989 ACCOMPLISHMENTS MAJOR REORGANIZATION
~
AUDIT PROGRAM QA SURVEILLANCE PROGRAM SPECIAL ASSESSMENT CAPABILITY 1990 OPERATING PLAN era~215
AUDIT PROGRAM TRANSITION TO PERFORMANCE BASED IN'MAJORITY OF MORE THAN 30 INTERNAL AUDITS YEAR TO DATE USE OF TECHNICAL SPECIALIST CONTINUES TO INCREASE APPROXIMATELY 50%
OF AUDITS
~
'LANS FOR FEWER MORE COMPREHENSIVE AUDITS IN 1990 ARE FORMULATED t
era/215
QA SURVEILLANCE PROGRAM ESTABLISHED
~
PROCEDURES DEVELOPED
~
PILOT EFFORT CONDUCTED WITH REPORT ISSUED
~
CONDUCTED SEVERAL ORIENTATION SESSIONS AT GINNA &
ENGINEERING
~
MANAGEMENT APPROVAL TO PROCEED
~
RESOURCES BEING RECRUITED AND TRAINED
~
1 SURVEILLANCE PERFORMED IN NOVEMBER
~
SURVEILLANCES SCHEDULED FOR DECEMBER era~215
SPECIAL'ASSESSMENTS FOCUS ON PERCEIVED AREAS OF CONCERN LESS FORMALLY STRUCTURED THAN AUDITS & SURVEILLANCE UTILIZE BEST AVAILABLERESOURCES INCLUDING LINE SUPERVISORS THREE ACCOMPLISHED IN LAST 5 MONTHS NSARB PROCUREMENT CONTROL FORCED OUTAGE MANAGEMENT era~215
I
1990 OPERATING PLAN
~
Features effective resource utilization through enhanced management direction (Table 3)
~
Substantial progress on a large majority of the QA/QC objectives (four are included in this presentation)
a)
Achieving an effective performance based monitoring system-QA Surveillance Introduced 4th QTR Target
Audits - Broader scope performance based b)
Improve the value of quality performance reports c)
.
Assist QA/QC Subcommittee to become a more effective advisor to management and to NSARB on quality issues of safety significance d)
Facilitate self-assessments of management effectiveness (approximately 6)
cra4215
C Ce
TABLE 3.
Technical Leaders for Ma'or A/
C Functions Functional Area Technical Leader Procurement Support Design Reviews 3.
QA Surveillance 4.
QA Audits 6.
7:
"A" Procedures (Interim Responsibility)
QC Inspection/Surveillance QC Planning Ken Easterbrook Mike Lilley Charlie Anderson Charlie Anderson Jef f Germain Mike Lilley Tom Alexander 8.
QA/QC Sections Procedures QA Program/Manual 1 Performance Analysis QA/QC Section Administrative Support (Budgeting, Activity/Training Scheduling, PC-Based Systems Development, etc. )
Jim Bodine Brian Stanfield Jim Bodine Jim Bodine whn~ 014
TABI,E 1.
Qualit Performance De apartment flanaaement Or anization (August
1989)
1'111 HcCov Dent Hanager Quality Perfor ance Charlie Anderson
.Hanaaer
?uality Assurance Hike I,illey Hanaaor uclear Assurance John Smith Hanager material Enara.
&
'nspect.
Services Jim Bodine Senior Quality Performance Analvst
~Ij
1990 PRIORITY TARGETS I
Follow-on to 1989 Activities
0
0 Staffing Procedures Configuration Management Q-List QA/QC Effectiveness
'a cg,
~
1990 PRIORITY TARGETS II Nev Initiatives o
Deficiency reporting system including Root Cause analysis o
Training Adequacy o
Personnel Safety.
o
. Security Systems Upgrade
~
~
l
~ L
PROCESS PLANNING PRIORITY I
Strategic Plan IZ Nuclear Concerns'II Establishment of Priorities ZV Strategy Managers V
Objective Based Management Job Plans VZ Periodic Reviews by Production
&
Management Engineering Division
~
~
V r>
CONCLUSIONS o
GOOD PROGRESS TOWARDS GINNA'S PLANNED OBJECTIVES FOR 1989 o
-
STRATEGIC PLANNING, PROCESS AND PRIORITIZATION IN PLACE FOR NUCLEAR IMPROVEMENT o
MANAGEMENT COMMITMENT FOR FINANCIAL AND MANPOWER RESOURCE REQUIREMENT (89-91)
o GINNA NUCLEAR POWER COST FORECASTED TO INCREASE ABOVE INDUSTRY MEDIAN (89-91)
o QUALITY PERFORMANCE ESSENTIAL TO ASSURE GINNA VALUE
,%a.
~ y Iy v