ML20033E997
| ML20033E997 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 03/06/1990 |
| From: | Guthrie S, Lanning W, Vandenburgh C Office of Nuclear Reactor Regulation |
| To: | |
| Shared Package | |
| ML20033E990 | List: |
| References | |
| 50-445-89-200, 50-446-89-200, NUDOCS 9003150238 | |
| Download: ML20033E997 (80) | |
See also: IR 05000445/1989200
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ENCLOSURE 3
U.S. NUCLEAR REGULATORY COMMISSION
OFFICE OF NUCLEAR REACTOR REGULATION
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NRC Inspection Report:
50-445/89-200
Permits: .CPPR-D.
50-446/89-200
CPPR-127
Dockets: 50-445
Construction Permit
50-446
Expiration Date:
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Unit 1: August 1, 1991
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Unit 2: August 1, 1992
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Applicant: TV Electric
Skyway Tower
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400 North Olive Street
Lock Box 81
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Dallas, TX
75201
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facility Name: Comanche Peak Steam Electric Station (CPSES),
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Units 1 and 2
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Inspectico e.t:
Comanche Peak tite, Glen Rose, TX
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Inspection Conducted: October 16 theoug'n 27, 1989 and
January 22 through February 2,1990
Inspection Team: Chris A. VanDenburgh, Team Leader, NRR
Jay R. Dall, Operations Engineer, NRR
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William D. Johnson, Senior Resident Inspector, NRR
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David L. Solorio, Operations Engineer, N%
Paul F. Harmon, Senior Resident Inspector, NRR
Jack E. Bess, Senior Operations Inspector, RIV
Donald C. Kosloff, Resident Inspector, RIII
Thomas 0. McKernon, Reactor Inspector, RIV
'NRC Consultants: . Donald A. Beckman, Parameter, Inc.
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Gary G. Rhoads Parameter, Inc.
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Larry R. Veeder, Parameter, Inc.
Robert L. Lewis, Parameter, Inc.
Bruce W. Deist, Parameter, Inc..
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Accompanying
Personnel:
Staffan 0. Forsberg, Swedish Nuclear Power Inspectorate
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Approved by: -Chris A. VanDenburgh. Team trader
Date Signed
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Team Inspection Section C
Special Inspection Branch
Division of Reactor Inspection and Safeguards
Office of Nuclear Reactor Regulation
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Approved by:
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5tephetyc. Guthrte, Chief
Date signed
Team lhspection Section C
Special Inspection Branch
Division of Reactor Inspection and Safeguards
Office of Nuclear Reactor Regulation
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Approved by:
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U hning, Chied \\
Uote Signed
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Specif1 Inspe* tion Bra hT
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Division of Reactor Inst
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Office of Nuclear Reactor Regulation
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INSPECTION SUMMARY
Inspection Conducted: October 16 through 27, 1989 and January 22 through
February 2,1990 (Report 50-445/89-200;50-446/89-200)
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Are_as Inspected:
Special announced safety inspection to assess Unit.1 opera-
t1cnal readiness. The areas assessed were facility managennt, plant opera-
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tions, maintenance, surveillance and testing, power ascension test program,
engineering and technical support, and quality verification. There were no
inspection activities performed on Unit 2.
Results: Within the areas inspected, the inspection determined that the
applicant was capable and prepared to proceed with fuel load and low-power
operations for Unit 1.
Operational programs, procedures, and controls were
generally complete and well implementee. The applicant's staff had success-
mully maoe the transitten from a construction to an operations based organiza-
tion. The staff demonstrated the proper concrrn for safe reactor operations
and had clearly taken responsibility for systems and areas under operaticnal
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centrol. Constructicn and testing had been completed for all of the systems
.ar.d components rtquired for operation up to and including five percent powen
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These systems wre cperetional in accordance with Technical Specifications.
The appliri.. had implemented adequate programs to maintain the plant equipment .
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and the b m identified few material condition problems.
Durkg the ilu pection, two violations, one deviation, and 13 open items were
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identified. The violations involved a failure to take corrective action for a
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concition adverse to quality-(i.e., the failure to take corrective action when
netified that safety-related instrument v61ve lireupe were not independently
verifiedanddocumented)andtwoexamplesoffailuretop(erformactivitiesi.e., the failure to
affecttng quality in accordance with written procedures
perform or document independent verifications of safety-related instrument
valve lineups, and the failure to obtain an equivalent level of review and
approval for a revision to a work order, and to identify to the operating shift
an adverse condition to quality). The deviation involved the failure to
implement an FSAR commitment to comply with Regulatory Guide 1.33 which identi-
fied procedures for energizing, startup, and changing modes of operation of
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electrical equipment (i.e., failure to provide system alignment instructions
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for low-voltage circuit breakers and for verification of size and type of
control fuses on safety-related equipment).
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TABLE OF CONTENTS
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PAGE
1.0 EXECUTIVE SUMMARY............................................-
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2.0
OVERV1EW..................................................... [9
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2.1
Background.............................................
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2.2
Inspection Objectives and Scope........................
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2.3
Corrective Actions for Interim Inspection Findings.....
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3.0 FACILITY MANAGEMENT .........................................
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3.1
Review Scope...........................................
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3.2
Crganization, Training, and Staffing...................
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3.3
Applicant Readiness Assessments........................
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3.4
Manageent Goal $, Comunications, and thersight
Activities...........
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3.5
Onsite Sofety Review Committee...,,.....................
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3.6
Operating Exparienee feedback..........................
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3.7
Conclusions............................................
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4.0 PLANT OPERATIONS.............................................
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4.1
F ev i w S c o p e . . . . . . . . . . . . . . . . . . . . . . . . . . .- . . . . . . . . . . . . . . .
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4.2
Staffing and fxperience................................
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a.3
Staff Stability and
Morale.............................
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4.4
Cperating Shift Routine and 1urnovers..................
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4.5
Operating and Abnormal Operating Procedures............
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4.6
System Status Control and Logs.........................
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4.7
Verif ication of System Lineups. . . . . . . . . . . . . . . . . . . . . . . . .
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4.8
Independent Verification Practices.....................
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4.9
Equipment Out-of-Service Controls......................
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4.10 Nuisance Alarm and Indication Program..................
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4.11 Event Reporting........................................
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4.12 Operations Training Observation........................
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4.13 Simulator Training.....................................
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4.14 Operability Determinations and Operability Drills......
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4.15 fuel Handling Training.................................
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4.16
Conclusions............................................
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5.0
MAINTENANCE..................................................
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5.1
Review Scope...........................................
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5.2
Backlog of Maintenance and Construction Work...........
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5.3
Work Planning and Prioritization. ....... . . . ...... . .. .. .
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5.4
Wor k Completion and C1oseout. . . . . . . . . . .. . . . . . . . . . . . . . . .
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5.5
Post-Maintenance Testing...............................
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5.6
Maintenance Procedure Review and Work Observations.....
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5.7
System Walkdowns and Material Conditions...............
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5.8
System and Component Labe11ng..........................
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5.9
Vendor Manual Control and Incorporation................
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5.10 Preventive Maintenance Program.........................
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5.11
Conclusions............................................
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6.0 SURVEILLANCE AND TES11NG.....................................
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6.1
Review Scope...........................................
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6.2-
Surveillance Procedure Review...........................
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6.3
Surveillance Procedure Observation.....................
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6.4
Interface Between Operations and Startup Testing
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Organizations......................................
6.5
Completion of Pre-start Testing........................
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6.6
Calibration of Peasuring and Test Equipment............
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6.7
Conclusions............................................
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7.0 ENGINEERlhG AND TECHNICAL SUPP0RT............................
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7.1
Review Scope...........................................
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Modification Controls..................................
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7.3
Configuration Controls.................................
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7.4
Temporary Modifications................................
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7.5
Performance of Safety Evaluations......................
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7.6
Sy s t em E ng i ne e r i n g . . . . . . . . . . . . . . . . . . o . . . . . . . . . . . . . . . . . .
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7.7
Ocac1usions............................................
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8.0 POWER ASCENSION TEST PR0 GRAM.......................-.........
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Review Scope...........................................
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Organization a..o Steffing..............................
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8.3
Test Status and Scheduling.............................
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8.4
Hanagement Review and Approval for Plateau Changes.....
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8.5
Quality Assurance and Controls.........................
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Staffing' Prerequisites for Testing.....................
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8.7
Program Change Controls................................
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8.8
Simulator Training on Startup Test Procedures..........
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8.9
Conclusions............................................
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9.0 QUALITY VERIFICAT10N.........................................
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9.1
Review Scope...........................................
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9.2
Quality involvement in Work and Testing... . . , . ... .. . ...
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9.3
Pcot Cause and Corrective Action Programs..............
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9.4
fost-Trip Review Process...............................
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9.5
Incident Review Process................................
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9.6
Conclusions............................................
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10.0 OPEN ITEMS..................................................
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11.0 EXIT MEETING................................................
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Attachment 1: NRC ORAT Interim Exit Letter dated November 16, 1989
Attachnent 2: Summary of Corrective Actions Taken in Response to Interim
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Inspection Results
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Attachnent 3: Operating, Alarm Response, and Abnornel Procedures Rekiewed
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Attachment 4: P.cintenance and I&C Procedures Reviewed
Attachment 5: Completed Work Documents Reviewed
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Attachment 6:
Surveillance Procedures Reviewed and Witnessed
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Attachnent 7: OperationsNotificationandEvaluation(ONE)FormsReviewed
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Attachnent 8:
Exit Meeting Applicant Attendees
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DETAILS
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1.0 EXECUTIVE SUMMARY
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This NRC Operational Readiness Assessment Team (ORAT) inspection yas-conducted
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during the periods October 16 through 27, 1989 and January 22 through
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February 2,1990 by a 14-member inspection team consisting of staff members
fror the NRC Office of Nuclear Reactor Regulation, Region III, and Region IV,
and NRC consultants. The purpose of the ORAT was to ind2 pendently assess
whether TU Electric (the applicant) was able to safely operate the Comanche
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Peak Steam Electric Station (CPSES) Unit 1.
This assessment was one of many
inputs used by the Director of the Office of Nuclear Reactor Regulation in
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making his decision regarding licensing. The team evaluated the functional
areas of facility management, plant operations, maintenance, surveillance and
testing, engineering and technical support, power ascension test program, and
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quality verification.
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During the October 1989 portion of the inspection, the inspection tearo
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conclude 0 that the construction and testing of the facility was not suf fi-
ciently complete to mate en operational readiness determination. Accordingly,
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the team reviewed the technical co7 tent of the CPSES operitional programs, but
was unable to evaluate implerentation in many areas.
The second portion of the
00,AT inspection focused on implerentation of the op u tional reograms and CPSFS
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staf f capability. The team found that construction and teating had been
substantially completed and program improvments had been implemented for
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previously identified problems. As discussed at the exit meeting on
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february 2,1990, the inspection team identified five concerns which required
resolution before operation of the facility.
Resolution of these concerns
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involved the following required actions:
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Identify and implement corrective actions for deficiencies related to the
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violations and deviation forwarded by this inspection report concerning:
a.
Failure to take prompt corrective actions until prompted by the NRC
for an identified condition adverse to quality concerning
safety-relatedinstrumentvalvelineups(Section3.3).
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Failure to provide controls for electrical fuses and circuit breakers
for instrument and control power to safety-related equipment (Section
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4.7).
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Failure to accomplish activities in accordance with written instruc-
tions which required:
(1) maintaining control of instrument valve
lineupsforsafety-relatedequipment(Section4.8);(2)obtainingthe
same level of review and approval for a revision of a troubleshooting
work order (Section 5.6), and (3) not promptly identifying adverse
conditionstotheoperatingshift(Section5.6.d).
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Evaluate the material deficiencies identified during the inspection team's
. system walkdowns and correct those that affected operations (Section 5.7).
3.
Evaluate and install valve labels for those components of the instrument
air system which were required to support five-percent power operation
(Section5.8).
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Take action to ensare that procedure deficiencies are identified and
corrected during their performance (Section 6.3).
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Improve the root-cause evaluation and corrective-action identification
process (i.e., the operations notification and evaluation form grocess)
and ensure that:
(1) a formal root-cause analysis is initiatedgwhen
required by the Operations Notification and Evaluation (ONE) form proce-
dure;(2)thecorrectiveactionsaddressthegenericconcernsandarenot
limited to the first-level symptoms or specifics (e.g., personnel errors);
(3) the corrective actions eddress the inadequacies in the programmatic
p(e.g.sses involved in the specific example identified by the ONE form
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control programs) protection, design control, and operational configuration
the freeze ; and (4) the ONE forms have sufficient detail to demon-
strate that adequate corrective actions have been identified
(Section9.3).
Additionclly, the inspection team identified several items which were satisfac-
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tori $y rasolved during the inspection but which required continued maragement
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attertica to ensure their satisfactory completion. The applicant acknowledged
tre neeo for tl.we actions during periodic meetings with the ORM inspection
tetn e embers and at the exit meeting on February 2,1990. These open items are
idatified in Section 10.0 of the inspection report.
In addition, the inspection team identified several examples .J program and
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management strengths. The applicant had taken aggressive action to improve the
quality of operational procedures and to correct discrepancies. Although the
operation)1 procedares were generally complete, technically accurate and
properly implemented, continued vigilance will be necessary to continue improv-
ing the procedures and to ensure successful implementation. Similarly, the
applicant had developed an operability drill program to improve the operating
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staff's ability to identify and respond to operability and integrated plant
problems. Also, the applicant had taken aggressive action to supplement the
operating experience levels of key managers and the operating staff by the use
of the staff advisors, shif t advisors and duty managers. These actions were
considered especially advantageous considering the plant staff's limited
operational experience. Also, the applicant's system engineering program and
the as-built drawing configuration control program were' considered to be
strengths.
The applicant had established a good working atmosphere beneticial to plant
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operations, in spite of the pressures involved in the completion of construc-
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tion activities. All levels of the applicant's staff demonstrated a positive
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morale and a constructive attitude. The applicant's staff had clearly devel-
oped an operations-oriented attitude and had taken responsibility for systems
and areas under their control. Construction and testing had been completed for
all of the systems and components required for operation up to and including
five-percent power. These systems were being maintained operational by the
performance of all the Technical Specifications surveillance requirements which
could physically be performed. The applicant had implemented adequate programs
to maintain the plant equipment and the inspection team identified few material
condition problems.
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Following resolution of the five concerns identified above and with continued
management attention to the open items identified in Section 10, the inspection
team concluded that the applicant was adequately prepared and fully capable of
safely operating the CpSES up to five-percent power.
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2.0 OVERVIEW
2.1
Background
The Comanche Peak Steam Electric Station (CPSES) is principally owned by Texas
Utilities Electric Company (TV Electric)3
The f acility has two-units each
with a standard 1160-MW Westinghouse four-loop pressurized-water reaktor and a
steel-lined, reinforced-concrete containment. The units are located in
Glen Rose, Texas, approximately 40 miles southwest of Fort Worth, Texas.
The applicant received a construction permit in December 1974 and had essen-
tially completed construction and preoperational testing and turned the Unit I
systems over te operational control in 1984. The original architect-engineer
was Gibbs and Hill; however, Stone and Webster Engineering Corporation has
provided reviews after 1985. Ebasco and Impe11 have also provided engineering
support since 1985.
In 1982, numerous allegations were received, most of which
concerned construction and quality assurance inade
These issues have
been subsequently referred to as-the "Walsh-Doy4"quacles.
issues.
In 1983, an NRC
Construction Appraisal Team (CAT) cwfirmed these allegations and the Atomic
Safety and Licensing Board (ASLB) determined that 10 ElectHe was not in
compliance with Appendix B of 10 CFR Part 50,
The Office of Nuclear Reactor RegJ1ation (NRR) assembled a Technical Review
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Team (TRT),onsitein1984
The TRT ine'xded 50 technical experts from the
hRC, nationti laboratories and consulting organizations. The TRT spent four
monthsinvestigatingtheallegationsanddocumenteditsfindingsinfive
Supplemental Safety Evaluation Reports (SSER).
In addition, numerous concerns
about the design and construction of the plant evolved through contentions
before the NRC's ASLB and the Comanche Peak Independent Assessment Program
review conducted by CYGNA Energy Services.
In response to the concerns, the applicant implemented the Comanche Peak
Response Team (CPRT) in 1984 to address all relevant issues, existing and
future. This program involved a reverification of the design and reinspection
of the construction of selected engineering disciplines.
In 1985 the design
review was initiated. On the basis of the extent of deficiencies identified,
TV Electric developed the Corrective Action Program (CAP) in 1987 to require a
complete design reverification; hardware validation, including hardware rein-
spection and modifications; and design and "as-built" reconciliation in a broad
number of areas.
In 1987, the NRC Office of Special Projects (OSP) was formed to ensure compre-
hensive and timely resolution of complex regulatory concerns with a strength-
ened and integrated staff organization, direct lines of management responsia
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Texas Municipal Power Agency (TMPA) owns a minority interest in CPSES but
has an agreement with TV Electric to transfer its interest in install-
ments. After complete transfer, TMPA will no longer retain ownership
interest.
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bility and authority and appropriate high-level direction. The OSP was
incorperated into NRR in January 1989 as the Associate Directorate of Special
Projects with responsibility for all licensing and inspection activities f or
The applictnt implemented an extensive program effort to correct-thLnumerous
design and construction deficiencies identified over the past severall years,
This program resulted in a significant number of modifications to bring the
plants into conformance with NRC requirements.
In March 1988, the applicant
temporarily suspended work on Unit 2 to concentrate its resources on completing
Unit 1.
The applicant completed these corrective actions and performed more
than 90 percent of the preoperational tests again within the framework of the
Prestert Test Program. The first hot functional test (HFT) sequence on Unit I
was performed in 1985, and a tecond series of HFT sequence and integrated leak
rate testing on Unit I was completed in July 1989.
The applicant's project completion schcdule indicated completion of construc-
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tion and testing for Unit 1 in early October 1989.
In support of this goal, an
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Operational Readiness Assessment Team (ORAT) inspection was scheduled for
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mid-October. The purpose of this inspection was to provide the Cirecter of NRR
with an independent assessment of the construction and operational status of
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Unit 1.
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The first portion of the inspection A s perfcrmee. from October 16 shrough 27,
1989. The inspection team concluded that the construction and testing Of the
facility were not sufficiently complete to make a determination with respert to
operational readiness of Unit 1 for primarily three reasons. . First, thcre were
an insufficient number of systems in the direct operational control of the
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operators in order to support a valid assessment of operational readiness. The
second reason was that the plant staff had not adequately assumed responsi-
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bility for the systems and areas under operational control and had not fully
implemented operational programs and procedures as a direct result of the large
amount of construction and maintenance work remaining. The third reason was
that the operations and operations support programatic readiness was not
adequate because several important operational programs were not implemented or
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contained significant weaknesses which precluded their effective
implementation.
During the remainder of the first inspection, the inspection team completed a
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review of the programs that controlled construction completion, power ascen-
sion, operations, and operations programatic and staffing readinest for
operations. There were several concerns and deficiencies identified during
this review. The applicant was informed of the inspection team's conclusions
and interim inspection findings in a letter dated November 16, 1989
(Attachment 1). This letter also identified several actions that the applicant
was required to complete before the remainder of the ORAT inspection could be
performed.
The applicant completed these actions and entered an operational preparation
period on December 27, 1989. The applicant notified the NRC on January 5,
1990, that Unit I was substantially complete and that following completion of
this operational period, Unit I would be operationally ready on January 22,
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1990. Accordingly, the applicant requested completion of the ORAT inspection
and issuance of an operating license authorizing fuel loading and operation up
to five-percent of rated power subsequent to NRC's confirmation of the
facilities' operational readiness.
2.2 Inspection Objectivos and Scope
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This inspection was performed in accordance with NRC Inspection Procedure (IP) 93806, " Operational Readiness Assessment Team Inspections." Operational
readiness assessments are required before issuance of the low-power license,
and before issuance of the full-power license or during power escalation. The
objective of the inspection was to provide a major input and basis for an NRC
determination of the applicant's readiness to load fuel and conduct power
operations to five-percent of rated power. The major focus of the inspection
was the verification that the applicant was programmatically and operationally
ready to safely operate the facility and that the applicant had established a
conservative operating philosophy before fuel loading. The inspection indepen-
dently assessed the effectiveness of management oversight, corrective action
programs, root-cause analysis, and the readiness to support operations.
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The inspection had tnree major areas of focus:
(1) monitor daily activities in
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the artas of operation $
testing, maintenance, engineering and technical
suprort, and quality vtrification ir. order to assess whether the applicant was
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ready to operate the facility safely; (2) evaluate the status of the prestart
test program to determine whether tosting was essentially completed and verify
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that outstanding maintenance deficiencies would not adversely affect the safe
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operationoftheplant;and(3)independentlyassessthepowerascension,
operations, and operations support progrannatic and staffing readiness for
operations.
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2.3 Corrective Actions for Interim Inspection Findinos
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As previously discussed, CPSES was not operationally ready during the first
portion of the ORAT inspection and several concerns were identified for further
evaluation and resolution. These concerns were identified in a letter dated
November 16, 1989, which is included as Attachment 1.
The inspection team
reviewed the adequacy of the applicant's corrective actions for these concerns
during the second portion of the inspection. The interim inspection findings
and the corrective actions taken by the applicant are summarized in
Attachment 2 to this report.
In addition, Attachment 2 serves as a cross-
reference to the section of the inspection report in which each concern is
discussed.
3.0 FACILITY MANAGEMENT
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3.1 Review Scope
The assessment of facility management was predicated on organizational struc-
ture, staff qualifications, experience, and attitude toward safety. Particular
attention was given to management actions in regard to NRC concerns identified
during the inspection period of October 16 through 27, 1990.
Evaluations were
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made through structured interviews with staff personnel including operations,
technical support, and administrative management personnel. The scope of the
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assessment also included the observation of management involvement with daily
plant and control room activities.
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During the facility managenent inspection, the team interviewed about 30
managers and senior supervisory staff, observed 4 operability drills, and
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interviewed 23 licensed personnel.
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3.2 Organization. Training. and Staffino
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The organization structure was reviewed and determined to be satisfaktory with
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an appropriate span of management control for operations and technic 61 support.
The inspectors also determined that the administration of the organization was
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capable of supporting an operating facility and that various department person-
nel complements were satisfactory.
During the first portion of the inspection, the inspection team was concerned
that although the requirements of American Nuclear Society (ANS) Standard 3.1,
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" Selection,- Qualifications, and Training of Personnel for Nuclear Power
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Plants,".for minimum experience levels had been met, the overall lack of depth
in comercial nuclear operating experience for management and operators would
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make the initial startup more difficult. During the second portion of the
inspection, the inspection team verified that the applicent had satisfactorily
addressed this concern.
,
Theapplicantestablishedaspecialoperationalreadinesstear.(ORT)madeupof
experienced nuclear professionals to concuct a comp chensive self-evaluation.
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As a result of that self-evaluation, the applicant augmented the facility
management positions of Vice President-Nuclear Operations, plant manager,
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maintenance manager, instrumentation and control maintenance manager, technical
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support manager, and radiation protection and chemistry managers with staff
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advisors who had previous commercial operating experience.
In addition, as
discussed further in Section 4.2, the applicant also augmented the experience
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levels of the operating shifts with previously experienced advisors for the
shift supervisors and implemented a duty manager program providing for on-shift
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support of the operating shifts by having a direct representative of the plant
manager either on call or on shift. The applicant committed to maintain these
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support programs until the completion of the power ascension test program. The
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team concluded that these actions were aggressive and of sufficient scope.
This comitment will be followed as an open item (445/89200-0-01).
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3.3 Applicant Readiness Assessments
The inspection team reviewed the process and methodology of the applicant's
self-assessments to determine readiness for fuel loading and operations to
tienel Readiness Program" (plicant's process was controlled by STA-811. " Ope
five-percent power. The ap
revision 0), and included individual management
assessments and an operational readiness plan. The operational readiness
program was implemented to provide a planned and systematic method of assuring
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that nuclear operations had implemented the necessary programs and procedures
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for governing safe operations at the facility.
In addition, as a result of the
operationel readiness program for nuclear operations, the applicant elected to
extend the self-assessment process to include operational support activities
through the support organization managers' self-assessment report.
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The inspection team reviewed the applicant's program for addressing tssues
identified in NUREG-1275, " Operating Experience Feedback Report, New Plants."
Theapplicantdevelopedanactionplan(consistingof108actionitems) Lased
on the applicable items identified in NUREG-1275. The Vice President-Nuclear
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Operations and the plant manager also visited two other NTOL plants to discuss
early operating experiences. Licensee event reports (LERs) for those plants
and five other plants were also reviewed and additional action items were
identified.
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Theinspectorsreviewedtheactionitamsanddiscussedseveralof.tp appli-
cant's improvenent items created as a result of its response to NUREs-1275.
The applicant's action plan included programs to provide simulated radiological
work experience for technicians, to review Technical Specifications, and to
reduce vulnerability to plant transients caused by balence-of-plant systems.
The inspection team identified no concerns during this review.
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The applicant also developed two major teams, en operationel readiness team
(ORY), and an operational quality assessment team (0QAT) and used them to
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review and assess programs and procedures to provide assurance that thuse
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programs and procedures were adeqcato to support operational readinest.
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The ORT was composed of experienced nuclear professionals assembled under the
direction of the Executive Vice President-Nuclear Engineering and Operations.
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The ORT evalu tions consisted of procedure reviews, completed documentation
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reviews, and implementation of plant programs. The ORT completed its evalua-
,
tions on January 5,1990 and concluded that, with minor exceptions Unit 1 was
ready to load fuel.
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The 0QAT consisted of 40 members and included individuals from various depart-
ments within the applicant's organization (TV Electric), as well as representa-
tives from other nuclear utilities. The 0QAT conducted an assessment of the
operations program from November 6 through November 24, 1989.
It reviewed
procedures and procedure implementation, interviewed personnel and observed
activities in 10 areas (i.e., calibration, chemistry control, Inservice inspec-
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tion and testing, licensing, maintenance, management controls, design modifica-
tions, refueling, plant operations, and procurenent).
,
The OQAT ccncluded that programs and procedures required to support fuel load
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were in place, but that certain improvenents were required. The OQAT made 186
observations and recomendations. Many of these observations and recomenda-
tions were categorized as enhancements not required to support fuel load or
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subsequent plant operations.
The ORAT inspection team reviewed the 0QAT report and selected 56 items for
further study by document review, interviews, and observation of plant opera-
tions. Closecut documentation for certain 0QAT items was discussed with the
applicant. The inspection team concluded that the 00AT assessment had been
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developed and conducted in a satisfactory manner with the exception of one
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deficiency.
The inspection team identified one example in which prompt and adequate correc-
tive actions were not taken for a deficiency identified by the 0QAT readiness
review. Observation 170 noted that although the system operating procedures
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(SOPS) contained a prerequisite to verify that a system's valves were aligned
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fornormaloperation,craftspeopleintheinstrumentationandcontrol(180)
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department indicated that documentation was not completed to confirm 1 hat
instrumentation valves were aligned or independently verified. The 0QAT found
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that all comunications between the operations and 180 departments regarding
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the. lineup of safety-related instruments were informal and that records of
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safety-related instrunient lineups were not completed.
In response to this concern, the 180 department stated that a series of I&C
procedures (INC-2100) provided data sheets to be used in conjunction with the
SOPS to perform lineups and independent verification of the positiorpoi the
1
instrument valves for safety-related systems. On the basis of this response,
and as a result of a followup evaluation, the 0QAT concluded that its observa-
tion had been in error.
.
During the review of the 0QAT items, the inspection team determined that the
'
original 0QAT observation was accurate and that the 180 department response was
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incorrect. The 150 procedures were not used to perform or document the initial
valve alignments and the position of safety-related instrument valves was not
independently verified as required. The f ailure to adoquately contro'i end
document the position of thete instrument valves was due to a failure to follow
arocedures within the I&C koartment and a failure to accurately comunicate
>etween departments.
This coanunication failure was $1 nificant because these
2
instruments were sensors for safety-related systems and could potentially be in
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the wrong position (i.e., isolated and nonfunctior.61), thereby makirig the
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safety-W ated equipment inoperable. The applicant promptly identified and
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implemented corrective actions, including verification of the a:: curacy of the
tesponses to the operational quality assessment teu (0QAT), end evaluation in
all departments of implementation of all operational procedures and controls.
The failure to accomplish activities in accordance with the I&C department
procedures is considered to be a violation and is discussed in Section 4.8 of
this inspection report. The failure to take prompt corrective action for an
identified condition adverse to quality is a separate violation of Criterion
XVI of Appendix B, 10 CFR Part 50(445/89200-V-02).
3.4 Management Goals. Communications, and Oversight Activities
As a result of management and staff interviews and observations, the inspection
team concluded that management goals were generally well developed and clearly
communicated. The team determined that the scope and content of such opera-
tional programs as operator training, procedures and system status controls,
e
operational readiness programs, maintenance work control, and surveillance
i
testing programs were broad and comprehensive. The inspection team's inter-
!
views and observations indicated that the applicant's staff had a high morale
and consistently demonstrated a conservative attitude about plant operations
and safety. Management oversight activities such as the duty manager program,
the extensive use of systems engineers, and the proposed station procedure
STA-511. " Plant Performance Overview Program" (draft), reflected an adequate
and responsive approach to the control and improvement of plant programs and
operations. However, the inspectinn team did identify several areas in which
there was evidence of a lack of comunication between organizations. For
example:
1.
As previously discussed in Section 3.3, the I&C department incorrectly
comunicated the status of instrument alignment control activities in
response to a deficiency identified by an internal operational readiness
self-assessment performed by the quality assurance department. As a
result of these incorrect communications between the maintenance and
operations departnents, the positions of safety-related instrument valves
,
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lineups were not docunented and independent verifications were not
performed.
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2.
As discussed in Section 5.6, a potentially adverse condition to quslity
was identified concerning loose linkages in the residual heat removal
(RHR) and containment spray (CS) system electrical breakers,;b( not
correctly comunicated to the operating shif t.
This incorrect tommunica-
tion between the maintenance and operations organizations resulted in the
initiation of a limiting condition for operation action requirement
(LC0AR) on incorrect equipment. The failure to accurately comunicate the
adverse condition to quality was the result of not following procedure
requirements concerning obtaining an equivalent level of review and
approval as the original work order following changes to the work order's
intentandnotissuinganoperationsnotificationandevaluation(ONE)
ferm upon identification of a potentially adverse condition to quality.
3.
As discussed in Section 6.2, testing personnel did not accurately identify
the status of testing on the safety injection system to the operating
shift. During performance of a flow balance test on the safety injection
system, the test personnel indicated that testing had been suspended on
flow indicator 1-FI-922. Subsequent testing produced fluctuations en the
indicator which the operator did not expect.
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IL addition, the inspection team identified two examples in which the
performance expectations of senior management were not clearly
comunicated,
e.
As discussed in Section 6.3, the operations department management's
intent to ensure aggressive pursuit and correction of procedural
d(ficiencies during performance of procedures was not clearly
identified at all levels of the operations department.
b.
As discussed in Section 4.14, the objectives for the operability
drill program were not clearly identified and comunicated to
personnel responsible for drill development, implementation, and
participation.
As a result of discussions and direct observations, the inspection team con-
cluded that the above examples were not representative of tie generally high
quality of communication observed throughout the inspection. However, the team
concluded that continued management attention is necessary to ensure that
comunication with and between organizational elements does not become a
problem. The need for continued management attention in this area will be
followedas.anopenitem(445/89200-0-03).
4
3.5 Onsite Safety Review Comittee
!
The inspection team reviewed procedure STA-401, " Station Operations Review
Comittee (SORC)" (revision 16); procedure STA-707, "10 CFR 50.59 Reviews,"
(revision 6);andthestaffingandqualificationsoftheSORC;andobservedthe
operation of the SORC during two meetings. The team determined that the
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organizational structure, staffing assignments, and operation of the 'comittee
were satisfactory.
It was noted that all comittee members met the require-
ments of ANS 3.1, " Selection, Qualification, and Training of Personnel for
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Huclear power Plants " and that those members with minimal experience levels
had previously experienced staff advisors assigned to help them.
Although STA-707 required personnel responsible for preparing and reviewing 10 CFR 50.59 reviews to attend and pass a 10 CFR 50.59 review training class,
members of the 50RC had not received such training. Discussionsvitpthe
applicant indicated that providing such training to the 50RC members had not
been the intent of STA-707 and that comittee qualification requirenents woul.
ensure reviews would h conducted by qualified individuals. The applicant
agreed, however, to define, develop, and implement specific training on safety
evaluations for 50RC members. These actions will be followed as an open item
(445/89200-0-04).
3.6 geratingExperienceFeedback
The applicant's formel program for reviewing industry operating pretience was
governed by p(rocedure STA-507, " Review and Assessment of Industry Operatingrevis
Experience"
Network"(revision 3). The plant evaluation manager, who reported directly to
the Vice President-Nuclear Operations, was responsible for administering the
program. . STA-507 specified requirements for assessrent and distribution of
reports received from 00 NRC, the Institute of Nuclear Power Operations
(thPO),andvendors. V)S-102 controlled distribution of information received
on the INPO nucir., aetwork telecomunications system. The inspection team
c
deterrrined that the procedures and the expertise of the responsible managers
were acequate. During discussions with plant operators and other plant staff,
the team noted satistectory knowledge of industry operating experience.
Procedure ODA-106, " Review of Documents and Operations Feedback" (revision 4),
implemented lessons learned and required reading. Required reading was identi-
fied by the operations manager, the operations support manager, or the shift
operations manager. The required reading material was distributed to each
shift with a cover sheet for each member of the shift to sign, if documentation
was required. Some material was distributed for discussion in shift meetings
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only. Required documentation was maintained by the shift operations manager.
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Anyone in the operations department could place innediately needed information
in a " lessons learned" book located in the main control room. The lessons
learned book was established June 26, 1989, as a result of incidents involvina
improper valve alignments and subsequent check valve backflow. At the-time of
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the' inspection, there were approximately 50 items in the lessons learned book.
Each item pieced in this book was entered in the index and a sign off sheet was
provided for each shift. The latest information in this book was required
reading at each shift turnover. This was not always signed off at shift
turnover; however, the shift supervisor was responsible for ensuring his
shift's signoffs were completed within 30 days. Missing signoffs were, for the
non-shift, duties. The team
most part, f rom shif t nembers assigned to other
foundthatthelessonslearnedbookwasausefulsourceofinformationfor
operating shift crews.
3.7 Conclusion
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The team concluded that facilities' management was responsive, sound, and
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reliable. Although continued management attention is necessary to conitor
comunications and ensure that effective comunication exists within and
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betweenthevariousdepartments,thespecificstrengths(suchastheactions
regarding staff experience, the status and scope of operational programs, and
the overall depth of applicant response to identified discrepancies) indicated
that the applicant's management had the ability and expertise to safely proceed
with reactor fuel loading and operations to five-percent of rated power.
1 [
4.0 PLAT 4T OPERA 110HS
,
4.1 Review Ccope
The inspection team reviewed the plant operations organization, staffing, and
experience levels. The team assessed the plant operational aspects by observ6-
tien of shift and other operating ectivities; discussions with operators, shift
te:br,1 cal advisors, shift advisors, and the opration's management staff;
inspectich of operating and abnormt.1 operating procedurer, review of system
status contrels and logs;'the:ks of valve lineups and of the control of systen
configurations; and obsersatitas of licensud operator training and op+rability
crills.
The inspection team observed control room activities for 98 continuous nours
and 32 additional day shift hours. During this coverage, the team interviewed
28 licensed and non-licensed operators and review d 21 operating and abnormal
operating procedures. The team also accompanied operetnrs on 12 plant tours
and logleeping rounds, mor' ared the performaace of 4 partial valve lineups,
and walked down 5 system alignments. The team also observed 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br /> of
simulator training and 4 operability drills.
In addition, the team observed
the operability verification of th) fuel handling equipment and transportation
of a dummy fuel assembly f rom the fuel building to the reactor vessel.
4.2 Staffing and Experience
The operations department organization and staffing was determined to be
adequate for fuel loading and subsequent startup. The overall CPSES operations
organization was managed by an operations manager and was comprised of two
sections, shift operations and operations support.
The responsibilities of the shift operations section included fuel loading and
fuel handling. The section was fully staffed with an adequate number of
licensedreactoroperators(R0s)andseniorreactoroperator(SR0s). The
number of outlified non-licensed auxiliary operators (A0s) exceeded the
Technical Specification requirement for plant operations.
The applicant had previously concluded that the operating experience level of
personnel assigned to shift activities was weak. As a consequence, a special
-hot participation experience program was used to augment experience levels of
SR0s in nuclear power plant operations. This program consisted of temporarily
assignibg shift supervisors and unit supervisors to operating power plants to
obtain additional experience. The SR0s interviewed about the program indicated
that most assignments involved working closely with operators and senior
operators and that the assignments were considered valuable learning
experience. The inspection team concluded that the experience requirements of
the hot participation experience program had been met. However, supervisory
involvement in the program had been weak because the applicant failed to verify
individual involvement and program effectiveness was not evaluated.
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As a result of the inspection team's previous concerns regarding commercial
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operating experience, the applicant planned to supplement the shift's
- comercial operating experience levels by adding four SRO-experienced shift
advisors and had reduced the administrative burden of the shift supervisors by
assigning duty managers who were either on call or on shift. The inspection
team reviewed procedure STA-104, " Duty Manager and Shift Advisor".(rtvision 1),
)
which controlled the assignment of the duty managers and shift advisbrs. The
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duty managers were appointed by the plant manager and work with and rovide
aovice to the shift supervisors on an as-needed or as-directed basis.
Functionally, the duty manager assisted the shift supervisor by coordinating
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and directing departments and organizations to support plant activities.
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Adequate controls existed to ensure that the duty managers should not exceed
their advisory role. All shift advisors had recent onshift experience as shift
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supervisors. They were charged with the responsibility to advise and assist
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the shift supervisor during onshift operations and were instr 9cted to emphasize
the safety and regulatory aspects of plant operation.
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The team concluded through procedures review, interviews, and observations of
shift operations and operability crills that the duty manager and shift advisor
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programs provided beneficial support to the operating shift.
4.3 Staff Stability and Morale
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The stability of the operations staff .ias evident due to minimal turnover of
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personnel. For example, the junior shift supervisor had been on shift at CPSES
for more than eight years and the average unit supervisor had been on shift for
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more than five years. Of the 18 reactor operators and auxiliary operators sent
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in 1987 to the Braidwood Station to gain operating experiente, 15 remained on
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shift at the CPSES and another individual was on temporary assignment to the
training department as part of the applicant's " personnel exchange" program.
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The inspection team noted a high level of enthusiasm among members of the
operating staff. Personnel had the technical knowledge and the operational
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support to start up and operate the f acility. They displayed a high level of
confidence and were anxious to demonstrate their competence. The attitude of
the operators and senior operators was considered to be a positive factor.
,
The operations staff stated that the management changes made over the past two
years resulted in several benefits and improved conditions. The staff reported
an increased spirit of cooperation between operations staff and operations
management and a new awareness of training needs on the part of senior
management. Personnel cited the exchanging of operations and training
-department personnel and the pre-approval of retraining classes by operations
management as an example of the increased spirit of cooperation.
4.4 Operating Shift Routine and Turnovers
During routine observations of shift and other operating activities, the
operating crews demonstrated a high level of professionalism. Shift business
and control room written material were controlled by shift personnel and
limited to operatin
In accordance with station administrative
procedureSTA-616,gactivities. Control Room Access and Conduct" (revision 4), access
the control room operating area was strictly controlled by shift personnel to
exclude workers from that area when they were not directly involved in activi-
ties at hand.
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During the first portion of the inspection, the team identified concerns with
'the applicant's operational responsibility and operator ownership of the plant.
In addition, the team noted a few examples of poor shift communications.
In
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response to these concerns, the applicant evaluated the operations department
practices end procedures to 1;nprove comunications, feedback, and evaluations
of personnel performance. Operations department administrative procpdures
ODA-301, " Operating Logs" (revision 8); ODA-302, " Relief of Personnel" (revi-
.
sion 9); ODA-102, "Shif t Conduct, Complenent, Responsib111 ties and Aothorities"
(revision 11); and Operations Work Instruction OWI-203, " Operations Department
Management Periodic Reviews" (revision 4), were revised to address the
concerns.
In general, these procedure revisions were inten6ed to improve:
interpersonal, shif t, and interdepartmental comunications; documentation cf
.
conditions and problems in logs and turnover sheets; and management assessment
of individual operator and supervisor comunications effectiveness during
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periodic performance reviews.
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During the second period of the int,pection, the team observed good comunica-
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ttert and coordinatinn oatween the operators. A prompt response was seen to be
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initiated for all annunciators and offnormal conditions. Operator knowledge of
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syste;n status was generally very good. Centrol room logs were legible and
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current. Shift turnovers were comprehensive. A preshift briefing by the
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off-going shift supervisor of the entire on-coming shift crew on the status of
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plant activities was seen to be beneficial, Panel nikdowns were observed to
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take place between the on-coming end off-gting d ifL. Formal turnover sheets
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were prepared by the eff-going shift nenbers for use by the on-coraing crew.
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Although the inspection team did identify one example discussed in Section 6.3
l
of this inspection report, in which operations comunIcations was deficient,
overall, the operators demonstrated proper comunications and conducted control
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room activities in a professional manner,
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4.5 Operating and Abnormal Operating Procedures
The inspection team randomly selected a cross-section of operating, abnormal,
!
and alarm procedures for review. The review included walkthroughs with opera-
tions personnel, observations of procedure use by operation personnel, and
verification that procedures could be used as written in the control room and
!
in the plant. For each procedure reviewed, the inspection team verified that
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plant drawings and equipnent nomenclature described in the procedure reflected
the as-built condition of the facility. The procedures reviewed and observed
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by the inspection team are listed in Attachment 3 to this report.
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The team noted that the operating, abnormal, and alarm procedures were
l
generally written well. During the performance of the procedures, it was
evident that the operators were trained to execute the procedures. Procedures
H
were followed as written or exceptions and changes were processed in accordance
with administrative requirements. There were, however, some discrepancies
identified as a result of abnormal and elarm procedure reviews and walkthrough
observations. The following discrepancies were given to the applicant for
review and procedure upgrading:
1..
In abnormal procedure ABN-301A, " Instrument Air System Malfunction"
(revision 3), the procedure gave the incorrect location for valves 101-650
and 101-651. Also panel EAB8 was incorrectly identified in the procedure
and panel CP1-EPPREC-02 did not have an identification label.
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In abnormal procedure ABN-703A, " Power Range Instrumentation Malfuhetion"
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(revision 3)..an incorrect Technical Specification reference was given.
3.
In abnormal procedure ABN-710A, "SG Water Level Instrument Malfunction
Check" (revision 2), the operators incorrectly identified the steam
generator protection bistables due to confusing references. Seption 5.8
of this inspection report provides more details on this concernt
.
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In abnormal procedure ABN-905A, " Loss of Control Room Habitability"
(revision 2), the nomenclature in the procedure for valve LCV-112B did not
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match the nomenclature on the valve.
5.
In station operating procedure 50P 607A, "118 VAC Distribution System and
Inverters" (revision 5), the electrical supply breaker for static inverter
IVIpC3 was not labeled in accordance with the procedure.
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With the exception of item nuirier .'; which is discusud further in Section 5.8,
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the prccecure discrepancies identified did not affect safety. The intent of
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the precedures was met and the proceduret could be performed in spite of the
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deficiencies.
4.6 System Status Control and Logs
1
The inspectors reviewed the applicant's me&od for tracking system configura-
tion and operational status on e day-to-day basis. Procedure ODA-410. " System
Status Control" (revision 1), required the meintenance of system status files
and status drawings. The applicant wat using the system status drawings to
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reflect component status as controlled by the system operating procedure
l
lineups and any active clearances or temporary modifications. During the first
portion of the inspection, the team found that the status drawings were not
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being kept current for all the systems under operational control. During the
second inspection visit, the team again found that although all the systems
were being controlled by the status drawings, the drawings did not, in all
,
cases, accurately reflect the current system status. Although updating the
system status drawings was a time-consuming and labor-intensive activity, the
applicant intended to continue to try to fully implement this program by
upgrading controls in this area. Successful implementation of this program
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will be followed as an open item (445/89200-0-05).
During the first portion of the inspection, the team reviewed several active
limiting condition for operation action requirement (LC0AR) tracking forms, and
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found them to be incomplete.
Entries and exits of LC0AR conditions were not
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logged as required and the justification or rationale for terminating LC0AR
requirements was not documented. Reviews, audits, and notifications to manage-
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ment required by ODA-308, "LCO Tracking Log" (revision 0), were not documented
(e.g., shift technical advisor reviews of recent LCO actions). No provision
was included in ODA-308 regarding when and how to obtain management authoriza-
tion for voluntary entry into LC0AR conditions.
LC0AR-related documents were
not required to be retained as quality records.
The applicant revised ODA-308 to strengthen provisions for reviews of the LC0AR
logs and documentation. Section 6.2.1 was added to the procedure to provide
instructions for controlled entry into an action statement, including author-
ization requirements. Section 6.5 was revised to require explicit action for
justifying and documenting termination of an LC0AR. Section 6.5.4 designated
LC0AR forms and appropriate documents as quality assurance records.
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During the second inspection visit, the team reviewed 2 active LC0ARs, 21
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tracking LC0ARs, and nunerous entries in the LC0AR tracking work sheet.
)
Although in.plenentation of the program was adequate to accon:plish its intent,
!
several minor administrative errors or inconsistencies still existed, indicat-
t
ing that more aggressive operations management oversight was needed.
1
4.7 ' Verification of System Lineups
During the second portion of the inspection, the team performed partial
welkdowns of five systems using the current system operating procedure lineups
,
and vital station drawings in order to verify the systems were aligned as
needed to support plant conditions. The five systems were the safety injection
system, auxiliary feedwater system,125-V de distribution system, emergency
,
diesel generator system, and service water system. These walkdowns consisted
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of verifying valve position and locked or unlocked status of valves, and
pertorming sampling checks of metal-clad switchgear, motor control centers, and
wiectrical distribution brcakers.
Durir4 the wanderns, the inspection team found that the applicant had r.o
,
program it place to ensure cuatrol of certain portions of the plant systems.
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Specifically, there was no routine or periodic walkoown of fuses in the motive
or control power circuitry and no verification of breaker or switch positions
of 125-Y dc or 118-Y ac control power circuits. The applicant considtred these
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areas to be adequately controlled by the normal control of work proceNt.
For
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instance, work plans required any fuse pulled during wotk to be r7 1 aced by the
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same fuse. i.iiewisc, work pr6ctices inside the clearance baurAaries were
!
considered adequate to reposit%r breders and switches when the clearance w&s
released.
The inspection team concluded that the control of fuses and control
>ower
'
circuitry solely by reversal of work clearance steps was inadequate aecause
errors introduced by several mechanisms could go undetected.
If an error
existed in fuse type or size or in control voltage configuration at the time
work was initiated, the error would be replicated when the clearance was lifted
.or the work completed. This is significant because these breakers and fuses
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supply control power to operate the solenoids, relays, and contactors needed to
operate the equipment. With these breakers in the incorrect position,
safety-related equipment might be inoperable. With incorrect fuses installed,
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safety-related equipnent might not be protected during fault conditions.
,
The Final Safety Analysis Report (FSAR) discusses the CPSES commitments on
[
regulatory guides for the nuclear steam supply system and balance of plant
Appendix 1A(B) for compliance with Regulatory Guide (ppendix 1A(N) refers toAp
design, construction, startup, and operation.
FSAR A
RG)1.33.
states that the quality assurance requirements of RG 1.33 will be implemented
rovisions of ANSI N18.7-1976, and that CPSES is in compliance with
per the p(revision 2).
In addition, FSAR Table 17.2-2, " Regulatory Guides and
Industry Standards," states that the CPSES quality assurance program is consis-
ly with the
tent with the guidance of RG 1.33, and that CPSES connits to comp (B).
respective regulatory positions as discussed in FSAR Appendix 1A
(revision 2), Appendix A, section 3.5.2, indicates that the onsite ac and de
systems should be controlled by written procedures and states that procedures
are required for energizing, startup, shutdown and changing modes of these
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systems.
The applicant's failure to provide controls for fuses and low-voltage-
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breakers is a oeviation from FSAR commitments to implement the guidance of.
[
Regulatory Guide 1.33(445/09200-D-06),
The applicant agreed t'o walk down, prior to fuel loading, all fuses at the
single-line diagram level to ensure that the proper fuses were instqlled, and
to control work practices by requiring the fuse type and size to be specified
in both cle.arance and work package preparation. Control voltage configuration
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would be improved by developing checklists of breaker and switch positions and
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Lintegrating the checklists into the system operating procedures.
'
Although this was considered to have been a significant oversight in the
applicant's program for control of system configuration and a deviation from
FSAR commitments, no other discrepancies were found. The team concluded
therefore, that the applicant's program for control of system alignments in
,
support of plant operations was satisfactory.
4.8 Independent Verification Practices
l
The applicant had included provisions for documented, independent verification
of valve, breaker, or control switch positions in operations administrative
procedure ODA-404, " Guideline on Component Positioning and Independent Verifi-
cation" (revision 3).
In general, independent verification was performed for
all system operating procedure (S0P) lineups for safety-related systems specif-
' l
.ically listed in ODA-404
Further, ODA-404 required S0P operating steps to be
I
revised to designate which components required independent verification during
)
routine operations. The applicant was incorporating the individual procedure
R
changes as the procedures were changed for other reasons. ODA-404 also
included protocols for actual performance of independent verification,
personnel qualifications, and instructions for determining the position or
condition of specialized components. The applicant's provisions for indepen-
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E
dent verification' provisions were observed in conjunction with the valve
lineups and system walkthroughs discussed in Section 4.7 of this report.
Asipreviously discussed in Section 3.3 of this report, the inspection team
found-that the applicant had not implemented an organized or well-documented
method of performing instrumentation alignments or instrumentation operability
. verifications in conjunction with system alignments. The SOPS included
instrument lists as attachments and had prerequisites performed during system
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alignmentrequiringthattheinstrumentationandcontrols(I&C)departmentbe
notified to perform an instrument alignment in accordance with the attachment.
l
The instrument lists typically han My check marks adjacent to most of the
' instrument numbers, did not include the individual instrument valves, and did
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not provide for I&C technician documentation of either instrumentation valve
-alignment or independent verification of the alignment.
In addition, the lists
F'
contained no criteria for performing the instrument alignment. The instrument
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lists were attached to operations procedure performance sheets (form
~ODA-407-2), but these forms were also not signed by the I&C technicians who
l
performed the instrument alignments. Temperature elements were included on the
lists, but-typically were not checked off, so it was unclear whether their
operability had been checked during the system alignment.
The inspection team considered that the proper alignment of instruments
associated with safety-related systems was an important aspect of the
operability of the systems. With isolation valves or squalization valves in
,
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the wrong position, the instrument could not perform its intended function,
in
someccases inoperebility of the instruments could not be detected from the
control room during normal plant conditions. Section 6.1.10 of Instrument and
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Control Administrative Manual Procedure ICA-115, " Instrument and Control
Section Verification Activities," stated that quality-related work activities
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required independent verification. Section6.1.3ofprocedureICA-175 required
i
the use of form STA-606-12 or equivalent to document verification activities
'
for which procedures or work orders do not provide for signoffs.
Independent
verification of the proper alignment of instrumentation associated with
safety-related systems was neither performed nor documented during the system
. alignments performed between December 1989 and January 22, 1990. During this
period, system alignments were perforned in order to declare systems operable
in preparation for fuel load. The failure to act in accordance with 18C
department procedures is considered to be a violation of Criterion V of
Appendixbof10CTR50(445/89200-V-07).
The applicant's short-term corrective actions in response to this violation
included issuing ONE form FX-90-799 and changing station procedures ICA-101
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"I&CWorkControl"(revision 0)andICA-115"InstrumentationandControl
Section Verification Activities" (revision 1), to ensure that independent
verifications were performed and documented for instrument valve lineups.
In
addition, instrument valve lineups were performed and independently verified
for the 27 systems listed in attachment 8A of procedure ODA-404
These lineups
were performed under work orders using guidance provided in the work orders and
the attached instrument list from the associated SOP.
Docunentation was
performed on Form STA-606-12, " Verification Record."
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As.a result of these corrective actions, the applicant found ten instruments
out of service because the instrument valves were equalized or isolated. These
instruments involved eight pressure and flow transmitters on non-safety-related
systems (steamgeneratorfeedwater,steamgeneratorblowdcwn,heaterdrain,
boron recycle and extraction steam systems) and two pressure instruments on
safety-related sy(CVCS)][. component cooling water (CCW) and chemical and vol
stems
control systems
Although the non-safety-related system instruments
.were out of service, these systems had not been aligned and placed in service.
The safety-related system instruments had been aligned, but these instruments
'
provided local or redundant remote indications and did not provide a control
. function. The applicant determined that the isolated pressure indicators on
the safety-related systems (i.e., CCW and CVCS) did not affect the operability
.
of the systems.
In all cases, the inspection team concluded that the mis-
alignments would have been identified and corrected as the systems were aligned
-and placed in operation. The applicant properly repositioned the instrument
valves and. initialed ONE forms to document the as-found discrepancies. Other
>
discrepancies,suchasprocedure(i.e.,instrumentlist)errorsandcomponent
c
tagging problems were also identified during the lineups. The applicant also
identified ONE forms to control corrective action for these items.
The applicant also committed to revising the SOPS to provide coordination of
instrument alignments and to revise the instrument lists to provide the neces-
<
sary guidance for performance of instrument alignments and to provide for
documentation of both the initial-alignment and its independent verification.
The INC-2100 series of' procedures had been prepared to provide guidance for
instrument alignment and documentation, but these procedures had fallen into
disuse and had become outdated. The applicant initiated action to retire this
series of procedures.
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4.9 Ecuipment Out-of-Service Controls
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The inspection team reviewed and discussed STA-605 " Clearance and Safety
Taggina"(revision'6)with.theapplicant. The operations department's work
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contrcl center was manned by licensed operators on relief shift. This group
developed clearances and reviewed work packages. All of the information needed
-to develop a clearance and research a work package was located in'a trailer at
'the work control center,l dayshift but not on the backshifts.approximately 500 yards from
,
area was manned on norma
Therefore, the
)
operators were required to leave the power block, on occasion, in order to
prepare a clearance; however, the minimum shift staffing was maintained in the
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control-room. The developed clearances were forwarded to the clearance pro-
cessing center and entered into the clearance computer program. The program
tracked clearances from this point through the process of hanging and clearing
the tags. The process was manpower intensive because each clearance was
required to be entered into the computer and removed from memory when the
clearance was cancelled. The applicant planned to add storage capability and
. to have the computer system flag Technical Specifications LCOs.
1
During the first portion of the inspection, the team was concerned that,
procedurally, the shift supervisor could verbally order clearance tags tempo-
rarily removed and operate the cleared component without informing the clear-
]
ance holder or verifying the status of the system. The applicant revised the
clearance procedure to require that all work parties be informed before per-
forming a temporary lift of a clearance tag.
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4,10 Nuisance Alarm and Indication Program
The applicant used procedure ODA-401, " Control of Annunciators, Instruments and
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Protective Relays" (revision 2), to control response to annunciators, identifi-
cation of problem and nuisance annunciators, and corrective action for problem
and. nuisance annunciators. The applicant's Performance Indicator Descriptions
Manual (draft) included an indicator for out-of-service control room Instru-
ments which would count out-of-service annunciators along with other
out-of-service control room instrument and control-devices. The program
appeared acequate; however,.this program required further review as plant
conditions changed to ensure that management attention remained appropriate for
the number and importance of out-of-service control ~ room annunciators,
controls, and instruments.
4.11 Event Reporting
'The inspection team reviewed the applicant's administrative procedure for
assuring accurate and timely reporting of operating incidents to the NRC as
Procedure STA-501, "Nonroutine Reporting"
. required by)10 CFR 50.72.(revision'3 , outlined the reporting requirements for various ty
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and supplied forms for use by shift personnel in documenting pertinent facts
'
related to an event.
In addition, the team observed the reporting of a
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safeguards event for which 10 CFR 73.71 required NRC notification within
one-hour. . The notification was completed in the allotted time. No concerns
were identified.
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4,12 Operations Trainin' g
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The inspection team reviewed-the CPSES operator training organizetion and
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operator and auxiliary operator training programs. The operators reported that
recent changes in the management and structure of the training organization
helped operations staff morale and performance. Recent improveme'nts in the
training programs included closer attention to detail, rapid respons[e to
required simulator updetes, and more job-related training. The insp6ction team
P
noted that an extra retraining cycle on the simulator was used to prepare for
the requalification examination administered in July 1989. This exam had a
100 percent passing rate and operations personnel credited this success to the
training organization.
<
Improvements in the auxiliary operator program included the assignment of
18 people to operational facilities for approximately a year. Both R0s and A0s
were assigned to the Braidwood Station to gain in-plant experience.
In
. addition, a detailed task analysis was developed to define specific training
requirements. The program used the task analysis as the basis for a training
program for A0s which ranged from general employee training through general
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plant information and systems training to on-shift, on-the-job training using
job perform 6nce measures.
4.13 -Simulator Trainino Observation
The inspection team observed 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br /> of licensed operator simulator
requalification training. The following simulator evolutions were reviewed and
observed:
(1) a 50 percent-load rejection resulting in a turbiae trip and
station blackout, (2) a shift to the h a shutdown panel followed by cooldown
A room, (3) a 10 percent design load
from the panel and shift back to th-
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swing, and (4) a 100 percent load P W 6
resulting in a reactor trip.
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The inspection team verified that the m . a ors demonstrated a conservative
operating philosophy during the performance of these simulator evolutions. The
operators used the correct procedures, demonstrated proper connunications, and
. conducted control room activities in a professional manner. During this
training, the inspection team watched the interchange between the operations
department personnel and the shift test director. .The shift test director
reinforced the direction that the licensed operators were in charge of the
plant and could terminate the ISU test if required by the plant response. The
shift test director also explained the purpose of each test and the portions of
the plant that would be. monitored during the test. During the simulator
requalification exercises, the shift supervisor always remained in charge and
used the' shift test ~ director as an advisor.
The inspection team verified that the applicant had used the simulator to train
the operators on the power ascension testing program. The applicant's simula-
tor requalification training included a classroom review of selected initial
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startup(ISU) tests.
Forty-six of the sixty-nine ISU tests had been reviewed
during the classroom portion of licensed operator requalification training.
Eight of these tests were also performed as part of simulator requalification.
All of the ISU tests that involved plant transients or close coordination
between operations and the ISU test group were scheduled to be performed as
part of requalification training.
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4.14 0perability Determinations and Operability Drills
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The applicant had developed and implemented an operability drill program
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consisting of a series of drill scenarios designed to exercise the interactions
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between the operations department and support organizations. The objectives of
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information and services to the operations department, (ganizations 4.0 supply
the program were to:
(1) test the ability of support or
2) test the L
,
comunications links between the control room personnel, other plant-
1
departments, and among these other plant departments, and (3) test the ability
of support organizations to respond quickly to operating shift's requests. The
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drills were unannounced and occasionally run on the backshift. The drills were
implemented by a drill coordinator and controllers from the plant performance
department. A critique followed each drill and included all the drill
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participants and the drill controllers.
The inspection team considered the applicant's development and use of the
o>erability drills to be an innovative method to improve comunications between
tie operating shift and support organizations.
However, the inspection team
identified several implementation deficiencies which weakened the effectiveness
of the drills.
For example, during a drill concerning water in the oil of
safety injection (SI) pump A, the drill team expected entry into TS 3.0.3 in
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order to sample SI pump B.
This was not necessary, so the drill coordinator
!
improvised by declaring the SI pump inoperable through a clearance requirement
.
that was unreelistic and unnecessary. A majority of the drill focused on
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simulated communications with NRC regional personnel over a trivial issue. The
drill team expected the shift personnel to complete a root-cause analysis,
including actions that would be unlikely to be required on backshift, such as
contacting all of the A0s to determine how often oil was added to the SI pump.
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The inspection team concluded.that the drills were inadequately planned, did
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not fully meet the stated objectives, and were implemented in an unsatisfactory
manner.
In addition,'the drill critiques did not adequately address either the
.1
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drill' objectives or scope and the drill coordinator's comments during the drill
1
and subsequent critique constituted negative training. The applicant comitted
to include management participation in the performance of the drill and drill
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critiques in order to ensure that the critiques were used as a fact-finding
)
-interview and that any training of the operating crew was endorsed by the
operations department management. This comitment will be followed as .an open
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item (445/89200-0-08).
4.15 Fuel Handling Training
During the'first inspection, the team noted that no provisions-had been devel-
oped to recover the fuel element transfer trolley following a mechanical
binding event. This had occurred at other Westinghouse plants, but the
experience gained from this event had not been incorporated into the
1
applicant's refueling procedures. Before completion of the first inspection,
.
the applicant had initiated actions to revise the procedures to incorporate the ,,
applicable sections from the vendor technical manual.
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LTheLinspection team reviewed the records of training received by four fuel
loading crews and observed one crew transport a dummy fuel assembly from the
fuel building to the reactor vessel. The team observed the performance of the
required 100-hour operability checks of-the fuel handling equipment before its
use. The following procedures were used to accomplish these tasks: .RF0-402,
" Operating Instructions for the Fuel Tran:;fer Equipment (revision.3)$on 3); and -
- RFO-403,
RF0-501, " Refueling Machine Checkout Instructions," (g Tools" (revis
" Operating and Checkout Instructions for Fuel Handlinrevision 2). The inspec-
tion team verified that these tasks were all performed satisfactorily.
-The fuel load procedures used a video camera located on the fuel transfer crane
'
.to verify the orientation of each fuel assembly during fuel loading. This
camera was also used to provide a final verification record of the loaded core.
The 100-hour operability checks verified the crane travel and weight
interlocks.
In addition, the inspection team verified that the fuel loed
l
procedures provided an adequate method for inventory control in the control
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room and refueling building.
Inventory control was required to be maintained
with~ status boards in both locations by the station nuclear engineers.
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Although use of_these status boards was not demonstrated, interviews with the
engineers indicated that they were familiar with their use.
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The inspection team verified that the design of the fuel handling tools pre-
. vented 'if ting of the fuel assemblies further than 3-feet above the loaded fuel
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as m blies.
In addition, the team ver;fied that the applicant had changed the
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design of the reactor vessel seal to use a mechanical seal (vice an inflatable
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seal, between the reactor vessel and refueling cavity.
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The fuel handling crew was very knowledgeable of the fuel handling equipment
operation. .The senior reactor operator in charge of the crew possessed a clear
understanding of his responsibilities and authority during the fuel handling
,
-activity. The team also observed personnel and material accountability con-
1
trols while in the' fuel building and containment., No concerns'were identified.
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4.16 Conclusions
Operating procsdures and controls were generally complete and well implemented.
~
Although problems with maintaining system status drawings up to date.were -
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noted, the applicant had committed to improve this situation. The inspection.
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team found_that procedures did not exist for the control of electrical circuit
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breakers for control power to safety-related equipment or for verification of
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correct fuse sizing and typ7
In addition, the I&C department procedures for
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the performance and verification of instrument valve lineups were not per-
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formed. Although these were considered to be significant oversights in the
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applicant's controls for_ ensuring proper system alignment during operations,
1
lthe applicant had taken aggressive corrective actions for these deficiencies.
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The applicant had a satisfactory training program for licensed and unlicensed
operators. Significant improvements in the operator training programs were
noted.
In addition, the A0's offsite training program was considered to be a
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strength
The team noted that the operators had a positive attitude toward
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-training. The operational readiness drills were potentially an effective tool
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to prepare the plant staff for facility operation, but effective implementation
required additional management attention. The inspection team concluded that
'the operations training organization and management were capable of supporting
operations activities.-
Because'the operators posses' sed a minimal amount of comercial op'eraiing
experience, the applicant had taken significant actions to supplement the.
experience levels of the operating shift by the use of shift advisors and the
- duty manager program. The applicant committed to monitor these programs to
ensure that the shift advi: ors and duty managers did not exceed their advisory
roles.
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On the basis-of its direct observations of the shift crew's performance, the
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inspection team concluded that the operations staff was prepared to operate the
facility safely and displayed a high level of professionalism and competence.
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5.0 MAINTENANCE
5.1 Peview Scope
The inspection team reviewed maintenance-related programs and procedures,
conducted structured interviews, and held informal discussions with the mainte-
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nance staff. The team assessed the effectiveness of the programs, activities,
- and personnel through plant and system walkdowns, observation of maintenance -
activities, and reviews of completed maintenance documentation.
5.2 Backlog of Maintenance and Construction Work
During the first phase of this inspection, the applicant was resolving
construction deficiencies and completing turnover of systems, rooms, and areas
from construction to operational control. The applicant projected beginning an
operations: preparation period on October 25, 1989. Although extensive work-
items remained as discussed below, nearly all systems had been turned over to
'
the operations department. The rooms and areas of the plant had been divided
into priority 1 and priority 2 categories based on their importance to fuel
load. On October 16,123 of 145 priority. I rooms and 144 of 274 priority 2
rooms had been turned over to the operations department.' The applicant had
-identified about 21,700 open construction items and estimated about 8700 of the
~
items actually required work, while the remainder required engineering or other
documentation actions. The principal emphasis of work control activities was
directed at completing construction and turning the plant over to the opera-
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tions department. The inspection team concluded that too many systems and
areas had a large amount of maintenance and construction work in progress and
that too few systems were adequately controlled by the operations department.
i
On the basis of this concern, the applicant revised its planning, based on
-workload and completion rates, to include an operations maintenance phase
during which all-work required to support operational Modes 6 through I would
be completed, required post-work test reports would be completed, and systems
1
would be groomed until they were ready for operation (i.e., ready for perfor-
mance of Technical Specifications surveillance requirements and decla, red
operable). This period was expected to last at least two to four weeks until
late November or early December 1989 and lead to a minimum two-week period for
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operations preparation. lDuring this latter operations preparation period, the
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t applicant expected all maintenance and testing to be under the control of the
shift supervisor, system lineups to be completed, all pcssible mode-required
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surveillance tests to be performed, and the limiting condition for operations
(LCO)-tracking program to be fully implemented. A specific schedule for
,
performingtheseactivitieshadnotbeendeterminedbytheinterimegitmeeting
1
of October 27,'1989.
During the second inspection visit, the team confirmed that the actions taken
inresponsetoinspectionteam'sinteriminspectionresults(Attachment 1)had
i
been completed, that the applicant's programs for completion of engineering
construction, maintenance, and testing actions had been adequately applied, anc
that the construction and maintenance status of the facility was adequate to
,
support initial operations. All systems and areas had been turned over to
i
operational centrol and remaining work had been prioritized es further
discussed in Section 5.4.
.
5.3 ~ Work Planning and Prioritization
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During the first portion of the inspection, the team reviewed the turnover
processofSTA-802,"AcceptanceofStationSystemsandEquipment(revision 8),
and STA-810, " Acceptance of Rooms, Areas, and Structures (revision 1), and
their implementation for the auxiliary feedwater (AFW) system, the safety
+
' injection-(SI) system, the residual heat removal (RHR) system, the emergency
i
diesel generators (EDGs), and the 125-Y vital de power system, as well as the
areas in which these systems are located. The applicant's general acceptance
,
_ process involved:
(1) review of outstanding ~ engineering and construction work
items containea in the management information tracking system (MITS),
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(2) walkdown of the systems for operability, maintainability, and identifica-
ttion of damage; and (3) review of testing status.
Open items were identified for construction completion or for resolution by)the
operating staff as listed on the managed maintenance computer program (MMCP .
The' inspection team's walkdown inspections of the systems and areas noted a
number of cases in which the applicant's programs had either been ineffective
-
in identifying discrepancies or permitted redevelopment of discrepancies after
the turnover process through inadequate equipment protection, maintenance, or
work control. In some cases, it was evident that the applicant was not giving
enough attention to the plant systems and areas to support system operability.
This is more fully discussed in Section 5.7 of this inspection report.
When the systems and areas were turned over to the operating staff, responsi-
bility for completion of construction open items and maintenance upkeep was
,
also transferred. Procedure STA-815, "Open Item Evaluation and Deferral
-Process" (revision 1), provided for operating staff review of open work items
for plant impact and required identification of the Technical Specifications
-
operational mode or date by which the work must be completed. The program was
' administered by the plant manager's administrative assistant (formerly SR0
licensed on another facility) and assisted by the licensed operations staff.
,
The applicant used two computer-based work-tracking systems which coordinated
with the work-scheduling system to identify the dates by which work items must
be completed.
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During the first portion of the inspection the inspection team performed a
general review of all MMPC and MITS items Ior five safety-releted systems (SI,-
RHR, AFW, EDG 125-V dc) and confirned that the STA-815 process was accurately
characterizing the plant mode by which open construction punchlist and n.ainte-
nance items must be corrected. Specific examples for the SI, EDG, RHR, and EDG
systems were reviewed in depth.
,
{
Although the team found that the punchlist and maintenance items appeared to be
properly prioritized for required completion for the applicable Technical
- Specification operational mode, concerns were identified with the volume of
such items and equipment condition to support license issuance. On the basis
of the team's concerns and applicant interaction with NRC Headquarters'
personnel, the applicant modified its planning on October 21, 1989 to have all
possible identified Mode 5 through 1 items completed before fuel load.
'During the second portion of the inspection, the inspection team again reviewed
the prioritization of the MMPC and MITS open work order items, as well as open
.designchangeauthorizations(DCAs),nonconformancereports(NCRs), design
modifications (DMs),andpost-testingrequirements(PTRs). Following the first
phase of the inspection, the applicant had developed an improved prioritization
plan that had more categories in which to describe open work items. The
applicant tracked the outstanding work items in each of these new categories.
On January 31, 1990, there were 7 open work items that the applicant was-
required to complete before fuel 1" Wing, and 105 items, including 38 open
PTRs, were categorized as required by Mode 1.
The inspection team reviewed a
computerized list of the open items in each of the applicant's priority catego-
ries, and also reviewed the priority classification of specific open work
orders or PTRs, to verify that work had been properly.prioritized. On the
basis of this review, the team determined that the applicant's work order
planning and priority process was adequate.
5.4 Work Completion and closeout
As previously discussed, the applicant was tracking, at the time of the first
-portion _of the inspection, close to-21,700 open construction items and-
estimated that approximately-8700 of the items actually involved physical plant
work. At the end of the second portion of the inspection, the backlog of work
items had been reduced from more than 21,000 to 2369, with the latter number
including some redundant items and a number of documentation and engineering
actions which involved no physical work. All items involving physical work had
been identified as work orders (W0s) or as post-test requirements (PTRs) and
hdd been prioritized for Completion before appropriate startup milestones. At
the end of' the second portion of the inspection,1337 W0s and PTRs had been
issued, with 7 requiring completion before entering Mode 6, 4 requiring
completion before entering Mode 5, and 36 W0s and 21 PTRs requiring completion-
-
before beginning post-fuel-load plant heatup.
The applicant had significantly reduced the maintenance and construction
'
backlog. Based upon the large and relatively rapid decrease in the backlog,
the inspection- team was concerned that the quality of the work closure process
may have been adversely affected.
In order to assess the quality of the work
completion and closeout, the team reviewed a sample of recently completed work
documents to determine the work scope, closure mechanism, and comprehensiveness
of the completion documentation. The documents reviewed are listed in
Attachment 5.
Based on this review, the team concluded that the work completed
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-was appropriate for the condition described and that actual field work was not
being bypassed or sigrid off as complete without the work actually being
completed or without an acceptable evaluation that the work was.not required.
The inspection team did not identify any concerns in this area.
5.5 Post-Mainten6nce Testing
.
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'The inspection team reviewed the post-maintenance test program described by
STA-623, " Post-Work Test Program" (revision 4). The process had undergone
major revision effective October 23, 1989, and was acceptable. As of
October 19, 1989, approximately 1055 PTRs remained open as pre-fuel load items.-
The open PTRs were coordinated by the site work control center (SWCC) staff.
During the second phase of the inspection, the team reviewed the status of the
open PTRs with members of the SWCC. Before December 1989, the work orders were
routinely closed out with PTRs remaining to be performed, and a lack of conti-
nuity resulted.
In December 1989, the applicant revised the process to require
the work order to remain open until the PTR was closed. The team reviewed the
list of open PTRs and selected a sample of 12 open PTRs for review to determine
if the testing appeared adequate for the work performed, and if the testing was
properly categorized. The PTRs reviewed were:
[TR
System
Component
C890006550
1-8818-D
C890007487
ME
CPI-MEMHCH-30
C890009919
C890009921
C890009923
IAF-0106
C890009955
C890012097
GA
ISS150005
C890014336
C890015697
C890016152
RH
1-8702B-M0
0890016204
SI-
1-8809A-M0
C890016206
1-8809B-M0
The inspection team concluded that the program was adequate and pro >erly
implemented. The determinations made by the applicant concerning w1en the PTRs
were required to be completed (i.e., mode dependency) were also acceptable. As
previously' discussed in Section 5.4, the inspection team also reviewed recently
closed PTRs and determined that the closure process was adequate.
By January 31, 1990, the number of open PTRs had been reduced to 123. Of
these, the applicant had determined that none were required to be com leted for
fuel load, and only 38 were considered to be mode dependent. This si nified a
large reduction in the number of outstanding tests required to be per ormed.
The team concluded that the PTR program was properly implemented and it
properly documented both open and completed testing.
5.6 Maintenance Procedure Review and Work Observations
.
The maintenance department programs and procedures were reviewed to establish
that maintenance activities of safety-related systems and components were being
. conducted in accordance with approved procedures by trained personnel. The
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inspection team conducted interviews with maintenanca departnent and instrument
and control (160) department managers and supervisors to obtain a general
overview of the maintenance processes at CPSES. The team reviewed the mainte-
nance and I&C procedures listeo in Attachment 4 of this inspection report, the
departmental staffing and workloads, the individual training records, and the
departments' training programs.
In addition, the inspection team.ob erved
following work activities:
a.
On October 18, 1989, the inspection team witnessed partial performance of
work ordar WO C89-13159 for calibration of the air activator and limit
switches for 1-PV-2325, steam generator #1 power-operated relief valve
(PORV). The work was performed by trained I&C technicians in accordance
with the work order and instrument procedure instructions. No discrepan-
cies were identified,
b.
On October 19, 1989, the inspection team found the containment spray valve
isclation tanks open. The tanks (located in room 65 of the safeguards
building) had been opened for maintenance on the valves located inside.
The work package (WO C89-12477) for the valve maintenance stipulated the
need for a confined space entry permit in accordance with STA-628, " Con-
fined Space Entry" (revision 1). Confined space entry permits had been
issued; however, after completion of the work inside the tank, the con-
fined space work permit was removed from the work location even though the
tank remained open and no warning was posted that .idry into the tank
could be hazardous. The applicant issued plant incident report
(PIR)89-301 to document this condition and concluoed that STA-628 did not
contain sufficient direction to cover such situations. The procedure was
revised on November 29, 1989 to include additional guidance. The team
concluded that these corrective actions were acceptable. No similar
problems were identified during the team's system walkdowns,
c.
On October 19, 1989, during review of maintenance administration and
temporary modification procedures, the inspection team noted that existing
work procedures did not include provisions for evaluating prospective work
orders for alarms, indications, and inter-system actuations expected to
result from the work and did not provide for notifying shift supervisors
of such effects.
In STA-606, " Work Requests and Work Orders,"
(revision 11) the applicant added a requirement that the worker or planner
specifically brief the shift supervisor or reactor operator of expected
alarms or erroneous indications that may result from the work to be
performed.
d.
On January 23, 1990, during observation of control room activities, the
inspectionteamnotedthatanoperationsnotificationandevaluation(ONE)
form and a limiting condition for operation action requirement (LC0AR) was
initiated for train A of the residual heat removal (RHR) system. The ONE
form and subsequent LC0AR were initiated because the maintenance depart-
ment had noted that a' nut was missing on the relay linkages of the RHR
system pump breaker during troubleshooting activities. The applicant
later identified that the ONE form and subsequent LC0AR were incorrectly
initiated on the RHR system when the maintenance department determined
that the missing nut was actually on the containment spray (CS) system
pump breaker.
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The electrical maintenance department was performing troubleshooting
activities as part of an investigation into the failure on January 17,
1990, of. vital bus IEA1 to transfer from its preferred to alternate power
source when offsite power was lost to one of two startup transformers.
Work order C90-0705 was written to troubleshoot the IEA1 auto transfer
circuitperMSE-G0-1210."TroubleshootingGuidelines."MSE-G0-1$10 limited
troubleshooting activities to problem identification. Except as specifi-
cally approved by the procedure, all corrective actions or adjustments
.
required a revision of the work order. Corrective actions allowed by the
procedure were limited to fuse replacements, fuse holder realignment,
annunciator printed circuit board replacement, indicator replacements, and
cleaning of components.
g
During troubleshooting activities on January 18, 1990, the maintenance
department discovered that the the linkage to the "B" contact switches,
device AE, in both the RHR and CS pump breaker cubicles were loose. On
January 19, 1990 a revision to troubleshooting work order (W0) C90-0705
was initiated to increase the scope of work to allow for the tightening of
i
the hex nuts on the cell switch linkages. This revision was not forwarded
,
E
to the shift supervisor for review prior to its implementation. On
January 20, 1990, electrical maintenance personnel further noted that not
k
only was the linkage loose on the CS breaker but that a nut was missing.
This condition was not identified-to the operating shift until January 23,
1990, when a request for a permanent equipment transfer was initiated to
,
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obtain a replacement nut from the Unit 2 CS breaker.
Immediately follow--
ing identification of the deficiency to the operating shift, the duty -
,
manager initiated a ONE form to identify the potentially adverse condition
to quality. The shift supervisor later declared the CS system inoperable
y
and entered the TS LC0AR for the CS system.
In a subsequent investigation, the applicant determined that the mainte-
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nance department had incorrectly identified the electrical breaker with
1
-the missing nut. Although the CS breaker had a loose nut and relay
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linkage, the nut was missing from the RHR breaker and not the CS breaker.
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Based on this' incorrect information, the operating department had initiat-
ed TS action requirements on the incorrect system. The operating depart-
ment had attempted to independently verify the missing nut on the CS
breaker, but the physical location of the linkage prevented a positive
verification of the missing nut. The inspection team verified that an
independent serification was not possible without disasserbly of the relay
linkage. The team concluded that the incorrect TS LC0AR was entered due
to the poor comunication between the maintenance and operating depart-
ments and the failure of the maintenance department to follow procedural
requirements.
ProcedureSTA-606"WorkRequestsandWorkOrders"(revision 12),
Section 6.6.2.1.0, required that a revised work order receive,.as a
<
minimum, the equivalent level of review as the original work order. The
work supervisor was required to notify the shift supervisor if the scope
of work was revised.
In addition, STA-606, Section 6.6.2.14, required the
initiation of an operations notification and evaluation (ONE) form per
STA-421 for potential or actual adverse conditions to quality identified
during the performance of work, including equipment malfunction, damage,
or degradation other than anticipated wear or situations remedied by
routine maintenance. The failure to follow the procedural requirements to
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obtain approval of shift operations for s revision to a troubleshooting
work order and to write a ONE form when a potentially adverse condition to
quality was first identified during the performance of the maintenance
work is an additional example of a violation of Criterion V of Appendix B
of 10 CFR Part 50. The first example of this violation (445/89200-V-07)
is identified in Section 4.8 of this inspection report.
. {'
e.
On January 27, 1990, the inspection team witnessed work performed on WO
C90-0951, concerning retorquing of mounting hardware in 480-V ac motor
control cubicles (MCCs). The work was acceptably performed and mainte-
nance administrative controls were appropriately applied,
f.
On January 29, 1990, the team observed I&C work orders 590-0080 and
590-0197 being performed in the control room. Under these work orders,
plant staff performed partial analog channel operational tests (ACOTs),
removed various circuit cards from the cabinets, removed labels f rom the
cards, wrote the card identification information on the card in indelible
ink, reinserted the cards, and reperformed the ACOT. Under the first work
order, the plant staff performed this task on steam generator level, loop
1, protection set 11, channel 0519; under the second work order, the plant
staff performed the work on refueling water storage-tank level, protection
set III, channel 0932. Two I&C technicians were assigned to each task,
and an I&C lead technician was in the Winity monitoring work for most of
the tasks. The team observed that t' . technicians were performing the
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work in accordance with the instructions given in the work orders, that
properly calibrated measuring and test equipment (MTE) equipment was being
used, and that the readings being taken were accurate.
g.
On January 29, 1990, the team observed work order C90-0758. This WO
performed non-safety-related troubleshooting and repair work for RM-21
computer train "A" cable NK008805. The personnel appeared knowledgeable
about the' controls over troubleshooting work orders for both
safety-related and non-safety-related work.
h.
On January 31, 1990, the team witnessed work order S90-0454, under which
the plant staff performed a weekly surveillance test on three of the
safety-related batteries. The fourth battery was undergoing an equalizing
charge at the time of the surveillance; therefore, the weekly surveillance
was not performed on this battery. The surveillance was performed in
accordance with mechanical surveil' lance electrical instruction
MSE-S0-S701},"SurveillanceofSafety-RelatedStationBatteries"
(revision 1
for batteries CPI-EPBTED-01, CPI-EPBTED-02, and
CP1-EPBTED-03. The measurements taken included battery pilot cell specif-
ic gravity, level, temperature, and cell voltage,.along with battery
voltage; all readings were within the acceptance criteria of the surveil-
lance procedure. During the surveillance, the team noted that the battery
undergoing the equalizing charge had individual battery cell levels above
the indicated high-level mark. The team requested that several of the
ce11' levels be checked. All of the requested cell levels were found to be
within the Technical Specifications acceptance level of 1/4-inch above the
high fill mark.
.
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~With'the exception of the maintenance troubleshooting activities described in
Section 5.6.d concerning loose relay linkages, the inspection team concluded
that the applicant was performing maintenance activities in an acceptable
manner.
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5.7 Systems Walkdowns and Mater'ial Condition
. {
,
During the first inspection visit, the team conducted on-shift tours and
the safety injection (SI) system, the residual heat removal (generators (EDGs),
'
system-specific welkdown inspections of the emergency diesel
i
RHR) system,the
- auxiliary feedwater (AFW) system, and the vital 125-V de electrical system.
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Major construction activities were evident throughout the plant. Although the
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applicant was attempting to maintain the housekeeping and material condition,
the extensive construction activities prevented progress in overall plant
cleanup. However, in those areas in which construction was substantially
complete, the inspection team found a number of places in which the applicant's
programs were ineffective.
In some places, it was evident that the existing
level of attention to the plant systems and areas was inadequate to support
system operability. The examples found by the team were similar to those
identified in Inspection Report 50-445/89-65 and represented additional weak-
nesses in the applicant's program. The team concluded that these discrepancies
were extensive and were the result of the continuing high levels of
p
construction.
'.
The NRC staff notified the applicant about the deficiencies in a letter dated
November 16,1989(Attachment 1). During the second portion of the inspection,
.the team verified that-the applicant had taken specific corrective actions for
1
each item. = Unless specifically noted, the team verified acceptable completion
,
of~all of the-corrective actions during the second portion of the inspection.
'
These actions are discussed below. The generic considerations and corrective
actions are discussed later within this section of the inspection report.
'1.
The leakage of 1A diesel generator jacket water and service water mechani-
cal piping joints were repaired per work order C89-14155.
2.
Standing water, removed relay label plates, and-broken terminal board wire
- retainers in diesel generator control cabinets were corrected per work
order C89-13743.
-I
f
3.
Quality control nonconformance report (NCR) waiver tags on the AFW system
and the CVCS were verified to be invalid and removed.
4.
The applicant had prepared and implemented revision 8 to ODA-301, "Operat-
-l
ing Logs," which required the auxiliary operators on tour to identify and
correct such conditions as open electrical cabinet doors.
.
5.
The applicant removed the electrical tape from vital power static inverter-
relay poter,tiometers. The tape had been used during transportation and
-
installation of the circuit cards as a precaution against vibration.
l/
6.
' Although the system engineer was originally unfamiliar with the require-
ments, step 5.4.2.3 of procedure 1-RWS-101A, " Reactor Coolant Drain Tank
,
System" (revision 5), provided the trigger mechanism for installing and
removing the safety injection accumulator drain line spool pieces. The
pieces were originally removed in accordance with work orders (C89-17753,
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CS9-17754,C89-17755,C89-17756) which authorized installation and removal
of all the affected spool pieces to support plant operations between
December 19 and 25, 1989, and provided formal documentation of proper
installation and removal.
7. .
On the basis of the team's observations that vent and crain'taippiece pipe
caps were not consistently installed and, where they were insta91ed, did
not agree with the piping and instrumentation drawings, the applicant
erformed technical evaluation (TE) SE-89-635, issued design change notice
p(DCN)89-541 (revision 0), and installed the missing pipe caps.
These
documents allowed installation of threaded pipe caps and permitted their
use to temporarily stop valve leakage for housekeeping purposes.
It was
noted in the TE that this method was not acceptable to permanently stop
leakage from pressure boundaries as defined in the Boiler and Pressure
Vessel Code of the American Society of Mechanical Engineers (ASME).
8.
On the basis of the. team's observation that several rising stem
motor-operated valves had debris in the top of the actuator which could
impair the operation and reliability of the valves, the applicant surveyed
the potentially affected rising stem valves and issued design change
authorization (DCA)73482andworkorderC89-15191 to install
,
vendor-supplied stem covers on the actuators. The covers were being
installed during the second inspection visit and appeared acccatable.
Further, housekeeping conditions had substantially improv;d; tie sources
,
of debris had been removed in most valve locations.
9.
The applicant had removed all construction phase scaffolding and had fully
implementedCMP-CV-1014."ScaffoldErectionandControl"(revision 0),on
January 22,-1990 to control operations phase scaffolding. The inspection
team found no new instances of uncontrolled installation of scaffolding
over safety-related equipment.
10. The applicant verified that the seat leakage from service water system
relief valve 1-SW-0444 was within allowable limits. Action had also been
taken to collect the leakage.
11. The leaking drain valve on the line to containment spray flow transmitter
IFT-4772-1 was replaced in accordance with WO C89-15072.
12. The applicant reconnected the flexible conduit and replaced missing limit
switch box screws on the RHR limit switch (1-HVC-0606) per WO C89-14112.
13. Per work order C89-17724, plant staff repaired the local valve position
MOV-1-8100 (seal water return isolation valve)ystem (CVCS) valve
indicator on the chemical and volume control s
.
14. On the basis of an accessibility review for emergency operations the
applicant installed new grating in the turbine-driven auxiliary Ieedwater
,
'
-(TDAFW) pump room under design modification (DM)89-400. The grating was
installed to permit operators to reset the turbine trip and throttle valve
L
without impediment from the steam drains, piping, and supports and to
l
provide 360-degree access around the room. One horizontal, rigtd support
still impeded access in a minor way and its removal was being evaluated.
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With respect to the manual AFW valve operations, the applicant had com-
pleted a valve operations study and had issued cperations department work
instruction 0Wl-206, " Guidelines for Operation of Manual and Power
Operated Valves" (revision 1), Attachment 6. " Difficult to Operate Valves
With Remote Operators." 0Wl-206 provided the number of turns and time in
minutes to stroke the valves in one direction so that operators.could
anticipcte the time and personnel needed for valve operation'. the gear
ratio on one velve (1AF-0041) had been changed, reducing its operating
turns, and other changes were under consideration. None of the valves
,
were required to be operated in any abnormal or emergency procedures.
The applicant also performed an adequacy review (Memoranda, Rosette to
Brcu, January 11, 1990, and Terrel to Flores, January 5,1990) of the room
ventilation, and concluded that-it was adequate for both normal and
post-accident conditions. The evaluation considered heat stress stay
times, adequacy of heat stress control procedures and required operator
actions in the room. The team found the applicant's reviews and actions
adequate.
15. As discussed in Section 5.3 of this inspection report, the applicant had
.made substantial progress in completing maintenance and construction work
between the first and second. team visits. The clearances in place during
the secord visit were considered to be minimal and of minor effect on
plant conditions and system operability.
The applicant's respcnse to Attachment 1 also addressed the generic and
programatic implications of the above observations and initiated several
actions intended to improve their ability to identify and correct such prob-
lems; the team review (d these actions during the second inspection visit:
1.
The maintenance manager initiated seven plant-wide initiatives during
November and December 1989 (docunented in Memorandum CPSES-8901822) which
included scheduled cleanup and housekeeping activities, quality control,
,
plant walkdowns, electrical and 18C panel cleaning, and similar
activities.
2.
ProcedureODA-301,"OperatingLogs"(revision 8),wasissuedtoinclude
'
watchstander guidelines and specific equipment conditions and housekeeping
attributes for operator inspection rounds; the revised procedure was
__
responsive to the team's general findings.
3.
Structured system engineer walkdowns were initially chartered during the
first inspection visit by Memorandum TIM-893267 (D. J. Reimer to System
Engineers, dated October 23,1989). On December 18, 1989, these instruc-
tions were expanded and defined by engineering instruction REI-206,
" System and Area Walkdowns" (revision 0). On the basis of its review of
completed system engineer walkdown logs and walkdowns of the several
systems with the system engineers, the inspection team concluded that the
applicant's actions were acceptable and seemed effective.
Additional system walkdown inspections were conducted during the second portion
of the inspection and included observations of system and area material condi-
tions, verification of system operating procedures, and switch and valve
lineups for the safety injection (SI) system, auxiliary feedwater (AFW) system,
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service water (SW) system, emergency diesel generator (EDG) system and auxilia-
3
ries, and . vital 125-V de power systems. Overall, the material condition of the
'
plant had substantially improved during the second inspection visit. Construc-
tion activities were complete and essentially all extraneous construction
material, scaffolding, and tooling had been removed from the plant. The areas,
systems, and equipment had been cleaned and repainted, and insulit1@ activi-
ties were completed. Electrical cabinets had also been inspected anti cleaned.
Surveillance tests had been performed and system operating discrep *
ancies corrected.. As discussed in Section 5.3, the remaining maintenance items
had been evaluated for plant impact and assigned a date by which they must be
completed.
The team's specific findings and applicant actions included:
-1.
Spring hangers for service water lines in both safety injection pump rooms
were pinned (hydrotest stops were installed), defeating the support
function. The applicant determined that the hangers should not have been
pinned and identified an action plan in Memorandum CPSES 9002637 on
!
February 1,1989 to correct this deficiency. The plan included: (a)
t
walkdown and correction of discrepancies in systems required for Mode 6;
(b) walkdown and correction of discrepancies before plant heatup for the
remaining spring cans; and (c) issuance of a new procedure f9r control of
work associated with pipe supports to prevent recurrence.
-,
2.
The bolts and washers on the A motor-driven AFW pump motor lead terminal
box cover had been removed to support thermographic analysis of motor
leads per work order P89-4483. They were found stored inside an adjacent-
structural steel tube and had not been tagged or controlled as required by
the material control program. Recognizing this loss of material control,
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the applicant replaced the bolts.
L
3.
Several minor housekeeping and miscellaneous equipment conditions were
L
also noted during the inspection team's walkdowns. These included:
l'
.a.
An excess steel plate (6" x 22" x 1") was found loosely hung (i.e.,
without nuts) on 1-inch anchor bolts in the turbine-driven AFW pump
H
room. The applicant believed that the plate was a mislocated
,
baseplate which was left from installation of the access grating.
Work request WR-66516 was issued to remove it,
b.
Protective wire cages were missing'around the glass bulbs of the A
motor-driven auxiliary feedwater (MDAFW) pump bearing oiler. The
L
system engineer found that not'only were the protective cages missing
l.
but that the oilers appeared to differ from the vendor's original
L
design. ONE form FX-90-881 was issued to document the apparent
l
discrepancy and work request WR-66515 was issued to install the wire
cages.
c.
Lighting junction box covers, light bulbs, and seismic lighting
lanyards were missing in the condensate storage tank (CST) room. W0s
were issued to correct the conditions.
.
d.
A small oil spill was found in the condensate transfer pump in the
CST room.
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Minor oil leaks on diesel generator head covers had already been
identified by W0s C89-15711 and C89-15712.
f.
Oil-campened gauges on the 1A diesel generator fuel and" start air
.'
system dryer had low dampening oil levels. WO C89-89401, C89-20339,
C89-20343, and C89-20344 were issued to add oil.
.
{
g.
Rigging slings and cables were found loose in the containment spray
,
valve room and safety injection pump rooms. Work requests 81244 and
81246 were issued to remove them,
h.
Gauge cocks for the engine-mounted diesel generator fuel oil pressure
gauges had vendor valve number tags but no permanent tags. The label
for circuit breaker IEA12 was held in place by temporary tape. The
,
items were referred to the plant labeling project for correction.
Althouch the team concluded that the minor discrepancies identified above did
not represent an impediment to operation of the facility, continued aggressive
l
action was necessary to maintain and improve the material condition of the
plant. The applicant comitted to review the specific deficiencies and correct
'
'
will be followed as an open item (y of safety-related systems.
those that affected the operabilit
This commitment
445/89200-0-09).
l.
5.8 System and Component Labeling
During the first portion of the inspection, the team was concerned that valves
l
and components were labeled with small metal tags which were very hard to
locate and use. Room and comodity labeling was essentially absent with
u
extensive unofficial, hand-written numbering present. The applicant had
previously recognized the need for better labeling, had initiated a major
labeling program during 1987-88, but had delayed implementation until the first
!
refueling outage. Because of the team's concerns, the applicant reevaluated
and re-prioritized the-upgrade program. The program schedule and new priori-
I
ties were reviewed by the team and considered adequate. Completion of this
j
programwillbefollowedasanopenitem(445/89200-0-10).
During the first portion of the inspection, the team walked through abnormal
l
procedure ABN-710A, "SG-Water Level Instrument Malfunction Check" (as discussed
in Section 4.7 of this report). This procedure had referencing inadequacies
!
which, in combination with incorrect temporary bistable card labeling in
reactor protection system-(RPS) instrument racks, resulted in a number of
operators incorrectly identifying the components to be operated. The appli-
cant's corrective actions included issuance of.an Operations Policy Memorandum
,
on October 23, 1989, identifying the correct and incorrect bistable labelino
,
and directing its proper use. Concurrently, the instrument and control depart-
E
ment was removing the incorrect temporary labels during routine reactor protec-
tion system surveillances. This involved performing a calibration check on the
4
affected' card, pulling the card from its slot and removing the label, rein-
stalling the card, and reperforming the calibration check. The applicant also
walked through eight other abnormal procedures identified as being similar to
ABN-710A, and verified that no similar ambiguities existed. As an additional
measure, the applicant determined that I&C technicians were more fami-liar with
the RPS rack internal equipment than the operators and revised ABN-710A to use
I&C technicians for performance of certain procedure steps. The team found
these actions to be acceptable.
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As previously discussed in Section 5.7 of this report, the inspection team
.
identified several minor labeling discrepancies during the system walkdowns.
B
Most of these discrepancies were not operationally. significant; however, the
= inspection team also observed that a large number of instrument air branch
>
header-valves and root valves had no identification labels. Discussions with
r
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the applicant's labeling project personnel determined that about-130) missing
i
labels had.been previously identified for the system and that aboint 550 metal
!
tags had been installed to date as a temporary measure. The remaining 650
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h
items were still being worked. The inspection team was concerned that without
labels on the valves, an accurate lineup of the instrument air system could not
be performed. This is significant because the instrument air system provides
g'
. the motive force for many safety-related valves. The applicant comitted to
. evaluate the labeling of the instrument air system and to-install labels
necessary to support power operations. This commitment will be followed as an
L
openitem(445/89200-0-11).
g
5.9 Vendor Manual Control and Incorporation
g
?
The inspection team confirmed that the applicant had a program in place to
addresstherequirementsofGenericLetter(GL)83-28,"RequiredActionsBased
on Generic Implications of Salem ATWS Events," concerning vendor manual con-
'
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fication and Vendur Interface (Reactor Trip System Components)quipment Classi-
trol. The applicant's response to Section 2.1 of GL 83-28, "E
" was reviewed
,
and approved by the staff in Supplement 22 to NUREG-0797 " Safety Evaluation
. Report Related to the Operation of the Comanche Peak Steam Electric Station,
Units 1 and 2."
The applicant's response to Section 2.2 of GL 83-28 " Equipment
p
Classification and Vendor Interface (Programs for all Safety-Related Compo-
nents)," was being included in Supplement 23 to NUREG-0797. The team noted
t-
l
that the applicant was taking steps to respond to corrective action request
'
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(CAR)89-015. This CAR, dated September 12, 1989, dealt with vendor technical
manuals (VTMs) and updates that had not received the required technical review.
"
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-The backlog of quality-related VTMs and updates was scheduled to be reviewed by
January 31,'1990.
The inspection team verified that the VTMs were used as reference material
during the development of maintenance and operational procedures and that the
l
VTMs were listed as a reference in the procedures. Procedure STA-206, " Control
,
,
'
ofVendorTechnicalManuals"(revision 13),requiredthedocumentcontrol
"
center-to notify the affected organizations when a VTM revision was received.
-The inspection team identified no concerns in this area.
,
5.10 Preventive Maintenance-Program
The preventive maintenance (PM) program was implemented by STA-677, " Preventive
MaintenanceProgram"(revision 1). The technicel support manager was responsi-
ble for overall program development, evaluation, and management. Various
managers were given responsibility for executing and documenting completion of
the activities specified in the program. The administrative procedure directed
the PM to be implemented as systems were placed in service. Before startup,
limited FM programs were implemented for preoperational and layup conditions.
The most recent revision to the program required staff at the site work control
center to schedule the PM on the project schedule and to identify overdue PM to
the responsible manger.
It also required the PM deferral process to take place
in the plan of the day meeting. A delinquent PM report was given to the plant
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manager on a monthly basis.
In October 1989 69 mechanical maintenance and 178'
electrical me.intenance Fils were overdue.
Fifty-sixoftheseweredelinquent
(i.e., past due by greater than 25 percent of their frequency). Most of the
PMs were on hold due to the large amount of actual work in progress.
During the second portion cf the inspection, with all systems having.been
ceclared ready for fuel-load, only 13 PM items were overdue. Seven bf these
o-.
were delincuent.- A technical evaluation had been prepared for delinquent PMs
and for those anticipated to become delinquent. The small number of overdue Pf1
'
activities indicated that CPSES personnel had the ability to plan, schedule,
a
and perform PM tesks as required by the PM program. The applicant stated that
a PM improvement project was scheduled to be initiated by March 1990. This
project was planned to include consideration of PM needs for all equipment in
the master equipment list, provisions for documenting the technical basis for
the program, and any deviations from vendor recomendations.
The inspection team reviewed seven vendor manuals for safety-related equipment
.to sample whether the applicant was incorporating Pli recommendations. The
safety-related components were the se.fety injection pump and motor, the aux 11-
iary feedwater pump and motor, the station battery and battery charger, and the
.'
- energency diesel generator fuel oil transfer pump. The team determined that
for these components the applicant's Pit program included the vendor recomenda-
l
tions. The inspection team had no concerns in this area.
'
5.11 Conclusions
The maintenance arograms and workload management controls were generally
acceptable. Altiough additional system walkdown discrepancies were noted
during the second phase of the inspection, the material condition of the plant
,
l
had improved significantly and was considered ready for low-power oserations.
There were work control problems in electrical maintenance troubles1ooting,
continued discrepancies in the areas of system and component labeling, and
.
- system walkdown discrepancies. Although these areas' required continued atten--
L
' tion. the overall maintenance program was acceptable and capable of supporting
safe plant operations.
E
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6.0 SURVEILLANCE AND TESTING
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.6.1
Review Scope
iThe Technical Specifications (TS) operational surveillance program was defined
by procedure STA-702, " Surveillance Test Program," (revision 7) and the master
' surveillance test list (MSTL).
Inspection of this area included a tabletop
technical review of 6 surveillance procedures and observation of 18 surveil-
lance: procedures, .9 of which were specifically performed fot the inspection
/
team'sobservations(seeAttachment6).
In addition, the inspection team
reviewed the completion of prestart testing, calibration of measuring and test
equipment, the work relationships between the operations and startup testing-
departments, and the involvement of the quality assurance department in the
surveillance testing process,
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6.2 Surveillance Procedure Review
The objectives of this review were to determine the technical adequacy,
!
accuracy, and quality of surveillance procedures to ensure that the applicant
was implementing these procedures to fulfill the surveillance requirgments of
plant Technical Specifications. The inspection team reviewed statiop procedure
STA-702, "Surve111ance' Test Program," (revision 7), which implemented the
surveillance program. The team found that the surveillance program was suffi-
ciently defined and the delineation of responsibilities was clearly stated.
The team raised two concerns during the first portion of the inspection con-
cerning procedure OPT-102A, " Operations Shif tly Routine Tests (revision 3).
This procedure was used to perform the Technical Specification (TS) surveil-
lance requirements of shif tly frequency. This procedure was used as the
trigger procedure for the surveillance requirement of TS 3/4.7.2. This sur-
veillance required that any time steam generator (SG) temperature or reactor
coolant (RC) temperature was less than 70 degrees Fahrenheit, SG pressure must
be read hourly. The' team expressed concern that since OPT-102A was only
required to be done once per shift, an hourly reading may be missed. The
applicant reviewed other possible procedures that could be used as a trigger
procedure and determined that there appeared to be no better place to insert a
-trigger mechanism.- During control room observations, the team verified that
-ine one-hour-readings were being properly recorded. The team had no further
questions in this area.
The second concern involved satisfying the surveillance requirements of TS
5/4.7.10. This specification required that temperature readings be taken in
selected plant locations. The readings were not being taken by the operators
during performance-of OPT-102A. The team noted that readings were not being
taken at two of the areas listed on TS Table 3.7-3, "CRDM Platform Barrier" and
"RC Pipe Penetration." Theapplicantpresentedthreecalculations[1-EB-300-1
_ revision'5),1-EB-300-2 (revision 2), and 1-EB-300-7 (revision 7)] which
(demonstrated that the missed temprature readings were bounded'by other temper-
~
ature readings.taken during operator rounds. Since the readings were bounded
by other TS surveillance readings under all conditions, the two areas required
by the TS table ap p ed to be redundant. The applicant stated that a TS
change request would be submitted to remove these redundant areas from the
table. The applicant also stated that OPT-102A would be changed to indicate
that the two-area temperature readings were not being directly taken, but were
-
bounded by other area temperatures. The team had no further questions in this
area.
The tabletop review of six surveillance procedures listed in Attachment 6
included a step-by-step verification to determine workability, a review of
referenced drawings, and a comparison to actual plant configuration. The
following discrepancies were noted:
1.
In OPT-201A, " Centrifugal Charging System Operability Test" (revision 1),
step 9.2.11 of the data sheet did not correspond to step 9.2.11 of the
procedure.
2.
OPT-204A, " Safety Injection System Operability Verification" (revision 2),
listed TS 4.5.3.1.1.1 as a requirement which this procedure satisfied;
however, the referenced TS requirement did not exist.
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3.
InOPT-403,"AxialFluxDifference"(revision 2), step 9.6.1,ofthe
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- procedure-was missing the wording or symbol for delta flux.
- The; team noted that these were minor errors and that the procedures were well
written and-contained sufficient detail so that the test objectives could be
-
achieved. None of the procedure discrepancies noted above affected plant
- safety.
In 611 cases, the applicant initiated procedure changes to torrect the
discrepancies. Overall, the quality of the surveillance procedures reviewed by
the tear was satisfactory.
- 6.3 Surveillance Procedure Observation
The inspection team observed the performance of 18- surveillance tests (Attach-
ment 6). The inspection team specifically requested that 9 of the 18 surveil-
lances be performed so they could be observed.
During observation of'the surveillances, the inspection team verified that the
prerequisites of each test were met before the start of the test. The inspec-
,
l-
tion team also verified that the required data were collected, the test instru-
L
ments were in calibration, the acceptance criteria were met or appropriate
i
action was taken, the TS requirements were satisfied, and the system was
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restored in accordance with the appropriate procedures. The team noted that
'
before the start of each surveillance test, all of the personnel involved in
.
- the tes+ are briefed. The control room operators and auxiliary operators
comunicated well with each other. The inspection team noted that the surveil-
lance procedures were structured and easy to use. The procedures contained
L
sufficient detail to allow them to be used as written. Test personnel appeared
to have been adequately trained to execute the surveillance tests.
'
Although all of the surveillance tests had been performed at least one time
i
before_the inspection, several discrepancies were identified during the inspec-
- tion team's observance of the surveillance performance. The deficiencies are
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listed below.
1
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1.
The inspection team observed performance of OPT-203A, " Residual Heat
b
Removal System Operability" (revision 1), on two occasions. On both
occasions,-the pump failed-the surveillance and the operators declared the
RHR pump inoperable. This failure was due to the procedure's reliance on
L
the automatic mini-flow recirculation valve to establish proper initial-
_
conditions for the test. The initial condiition required the mini-flow
recirculation valve to be fully open, therefore, any subsequent flow
l
degradation would prevent achieving the initial conditions and result in a
failure of the test. After the second attempt, the operators informed the-
'
system engineer that the test could not be successfully completed as
written.
L
2.
Step 9.32 of OPT-470A, " Train A Safeguards Slave Relay K616 Actuation
l
Test"-(revision 0),requiredthatthehandswitchforcontainmentspray
_
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pump 3 (1-HS-4765) be verified in the " auto after stop" position after
completion of the test. However, when the plant was not in Modes 1
through 4, the position of the hand switch was required to be left in the
" pulled out" position. Because the surveillance procedure did not provide
for a different switch position required by a plant mode other than
Modes 1 through 4, the operator had to place the switch in the " pulled
1
=out" position following completion of the procedure.
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3.
During the performance of OPT-205A " Containment Spray System Operability
Test," (revision 1) the fan cooler unit (FCU-13) associated with contain-
ment spray (CS) pump 3 ~did not start automatically. However, the fan
cooler unit (FCU-11) associated with CS pump 1 did start automatically.
OPT-205A, Step 9.3.38, required verification of FCU-13 start argi did not
mention automatic operation of FCU-11. Although FCU-13 was under clear-
ance and would not automatically start, the surveillance procedure did not
indicate, and the operators did not know, if FCV-11 should start automati-
cally when CS pump 3 started. The applicant later determined that both
FCV-11 and FCV-13 receive a start signal when either CS pump is automati-
cally started. During two performances of the surveillance procedure, the
failure of FCU-13 to automatically start was not verified or documented by
the procedure. This surveillance procedure also required the CS pump hand
switches to be placed in the " auto after stop" positions after test
completion with no provision for the different positions required by
different plant modes.
During(performance of OPT-209A, " Safety Chilled Water System Operability
4.
Test" revision 1), the team noted several discrepancies. For example.
-step 9.3.10a opened the local gauge glass isolation valves, but no step
included instructions to close them. Step 9.3.8 required the operator to
loop a temporary drain hose above the drain valve to prevent draining a
section of piping. However, the operator was required to interpret the
intent of the procedure and loop the drain hose above the pipe, which was
located five feet higher than the drain valve. Stcp 9.2.5 required the
operator to establish an initial condition for the test by throttling the
chilled water pump discharge valve to obtain a differential pressure of
78.5 psid anr1 returning the throttle valve to the full-open position at
the completion of the test. However, the pump obtained a 78.5 psid
differential pressure with the throttle valve fully open. This was
significant because eventual flow degradation will prevent the pump from
obtaining this-differential pressure and the initial conditions will not
be able to be met in subsequent tests. Finally, OPT-209f, did not address
unusual changes in system flow. This system is flow balanced and the
procedure should address changes in system flow as a potential change in
the flow balance.
5.
During the performance of test procedure EGT-713A, "S.I. Injection Throt-
tie Valve Adjustment," the inspector observed a technician inform the
reactor operator that the test was going to be stopped temporarily because
of an apparent problem with test equipment. The inspector and the reactor
operator concluded from the technician's statement that the control room
safety injection (SI) flow indicator (1-FI-922) would not be responding to
test signals until further notice. Shortly thereafter, the inspector
observed indicated flow on 1-FI-922 slowly increase from zero to offscale
high. The inspector brought this to the attention of the reactor operator
who unsuccessfully attempted to contact the technicians performing the
test.
The inspector discussed this comunication deficiency with the unit
supervisor and with operations management. Both agreed that immediate
feedback was appropriate in such situations to help ensure that all
personnel were aware that the operations department should always be kept
correctly informed of plant conditions. Although this comunication
44
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problem did not have safety significance it indicated a need for contin-
. ued management attention to the issues of shif t comunications and opere-
tions responsibility..
As previously discussed these discrepancie.s should have been identified during
the previous performances of the surveillance procedures. Theinspeptionteam
concluded that-the previous performances had focused on determining bpera-
bility, and that personnel were not aggressively attempting to upgrade the
. quality of the procedures. The applicant committed to reinforce its intent to
aggressively. identify and correct procedural deficiencies and to continue to
upgrade the quality of all operational procedures. This contr.itment will be
followedasanopenitem(445/89200-0-12).
6.4 interface Between Operations and Startup Testing Organizations
The inspection team reviewed station procedure STA-818. " Conduct of Initial
Startup Testing" (revision 0). This procedure adequacy described the shared
-activities between the operations department and other organizations involved
in initial startup (ISU) testing and required that a shift test director be-
E
assigned to provide the link between the operations and testing departments.
The procedure clearly stated that the licensed operating personnel were in
control of the plant at all times. The licensed personnel approved the start
of each test and could stop the test at any time. The inspection team inter-
viewed two shift test directers.' The test directors were familiar with the
procedure that described their duties and responsibilities and were aware of
the limits of their authority.
6.5 Completion of Pre-start Testing
At the time of the second portion of the inspection, the applicant had complet-
ed all but one prestart test. The remaining test, PT-24-03, " Primary Plant
Filtration System Filter Test," was scheduled for the week of February 5,1990.
The test had been delayed to allow. completion of painting-prior to loading
charcoal-into the filtration beds. Two completed prestart tests were reviewed.
PT-04-01 " Station Service Water" (revision 0), on the service water (SW)
system and MSE-SO45710 " Battery Performance Discharge Test" (revision 1). Both
tests appeared conplete and all test deficiencies were resolved before the
closure of the test packages.
'6.6
Calibration of Measuring and Test Equipment
The calibration of measuring and test equip (ment (MTE) was specified in STA-608,
" Control of Measuring and Test Equipment" revision 14). The program was well
documented and provided traceability of the MTE. Each piece of test equipment
checked by the inspection team had documentation of each use of the MTE since
the last calibration. This information was stored for historical purposes each
time that the MTE was recalibrated. The inspection team verified that the
maintenance and operations departments' surveillance procedures required
listing the test equipment identification number and calibration due dates in
the surveillance procedure and verification of the current calibration.
In
addition, the MTE history card filled out during the surveillance test identi-
fied the procedure used and the location of the MTE during the test.- If an MTE
component f ailed calibration, each component on which the MTE was used since
the last successful calibration was evaluated and retested as necessary. Prior
45
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to MTE issuance, the calibration was routinely verified in the range needed for
the _ test equipirent.
Theinstrumentand' control (l&C)departmenthaddevelopedaprogramtocali-
brate P-2500 computer points that were used by the operations department to
satisfy TS surveillance requirements. The I&C surveillance test Woutid fail-if
the computer point was out of calibration. The operations department had
provided a list of P-2500 computer points that it had identified as being used
to satisfy TS surveillance requirements.
'
6.7 Conclusions
In sumary, the performance of surveillance procedures was demonstrated to be
acceptable. All of the surveillances that could be performed for Modes 1
through 6 had been performed at least once. One area of concern was the
failure of operations department personnel to identify deficiencies during
previous performances of the surveillance procedures. Although the surveil-
lance program adequately tested the equipment as required by the facility
- '
Technical Specifications, continued management attention was necessary to
ensure that procedure deficiencies were identified and corrected. The training
of shift test directors along with the licensed operators on the simulator was
expected to improve the quality of the power ascension tests and aid in build-
ing the team concept between the groupe
The system for control of measuring
and test equipment (MTE) was comprehensive and provided assurance that test
.
equipment used to satisfy TS surveillance requirements was in calibration.
'
7.0 ENGINEERING AND TECHNICAL SUPPORT
-
7.1 Review Scope-
The team reviewed the engineering procedures and programs which support opera-
l.
tions. -- The team interviewed managers and system engineers and performed system
j
walkdowns with system engineers. Engineering support of operations was
observed during daily activities, and engineering reviews and technical evalua-
i
p
tions were assessed during operability drills.
'
7.2 ' Modification Controls
q
licant had established measures in STA-716. " Design Modification Pro-
I
The app (revision 4) to ensure that design modifications were in conformance with
cess" _
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the requirements of the Technical Specifications (TS), 10 CFR 50.59, the Final
~
Saf ety Analysis Report (FSAR)', and the facility's quality assurance program.
The program delineated who could initiate a design modification; the author-
l
ization process; the design review and approval circuit; the design moditica-
tion review, installation, and testing; and the closure process. Twelve
operational quality assessment team (0QAT) observations and corresponding
recommendations were initiated following the 00AT review of the modification
control ~ process. These were addressed in Revision 5 of STA-716, " Design
Modification Process." The inspection team reviewed these changes with respon-
sible applicant personnel. The modification controls were adequate to support
modifications performed during operations.
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7.3'. Configuration Controls
The applicant had established treasures for controlling. configuration changes.
that resulted from a design change. Methods, procedures, and responsibilities
' for. performing design verification,10 CFR 50.59 reviews, and interdisciplinary
-review had been established and. appeared adequate.
Furthermore 'adn nistrative
.controlsfordesigndocument(i.e.,designbasisdocuments, specific {6tions,and
calculations) control were established and sufficiently implemented.' The
facility had established controls for recalling such obsolete design documents
as revised drawings, marking the as-built documents for design changes on an
,
interim' basis, and incorporating DCAs in a timely manner.
{
<
The applicant had established measures for controlling activities that tempo-
rarily altered the design function of a system or component in the plant. The
controls provided guidance for the initiation of temporary modifications,
evaluation of the temporary modifications to include 10 CFR 50.59 safety
-evaluations, evaluation of ALARA (as low as is reasonably achievable) reviews,
and approval of temporary modifications.
In addition, guidance was provided
for installation, restoration, and revision of temporary modifications.
Controls had been established to ensure that the operations department partici-
pated in the temporary modification installation and restoration process along . - 3
with independent verification of the restoration.
Furthermore, guidance was
given for processing and resolving closed temporary modifications. As previ-
.ously discussed, the team noted during the first portion of this inspection
that the applicant had not provided sufficient guidance in STA-606, " Work
Request and Work Orders" (revision 12), to ensure operators had been informed
.about potential alarms and actuations during temporary modification work.
- During the inspection, the applicant acknowledged the discrepancy and revised
STA-606 to provide the additional guidance.
-During the first portion of the inspection, the inspection team reviewed
procedure STA-716 " Design Modification Process" (revision 3), to determine if
the plant modification procedure required 10 CFR 50.59 safety reviews to be
performed. -The procedure required that safety evaluations be performed in
accordance with STA-707, "10 CFR 50.59 Reviews' (revision 6), which clearly.
' stated that the procedure was not applicable until the plant was licensed.
.This allowed temporary modifications and. procedure changes to be completed
'without a safety review. During the second portion of the inspection, the team
-verified that the applicant placed additional controls on the DCAs and tempo :
rary modification system to ensure that any modification still open at the time
of licensing will be evaluated for unreviewed safety concerns before being
included in the plant design, and that any temporary modification installed in
the plant at the. time of licensing was evaluated.
L
7.5 Performance of Safety Evaluations
!
The inspection team reviewed STA-707, "10 CFR 50.59 Reviews" (revision 5),
!
which described the arecess for performing 10 CFR 50.59 safety reviews. The
procedure followed tie guidelines of NSAC/125, " Guidelines for Performance of
10 CFR 50.59 Safety Evaluations" prepared by the Nuclear Safety Analysis Center
L-.
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~ (NSAC) of the Nuclear Management and Resources Council. The inspection team
-reviewed six completed 10 CFR 50.59 safety evaluations and found them adequate
- end in compliance with the STA-707 procedure requirements.
ProcedureSTA-205,"ChangestoProcedures"(revision 12),wasrevkewedto
ensure that it properly addressed the need to perform 50.59 safety eyaluations
for procedure changes. STA-205 required a safety evaluation in accetdance with
STA-707 unless the procedure was being changed to correct a ty>ographical error
or was an innediate change that did not change the intent of tie procedure.
.During~the first portion of the inspection, the team was concerned that the-
definitions for typographical errors and changes of intent were so broad that
changes could be implemented without preparing a safety evaluation. On the
basis of these concerns, the applicant revised STA-205, " Changes to Procedures"
- (revision 12). This revision defined typographical errors better and ensured
that safety evaluation screenings were required for any change to a procedure's
intent.
7.6 System Engineering
The system engineering department was staffed with 32 TU Electric employees and
3 contractors. Typically, each system engineer was responsible for two or
three plant systems. Backup system engineers were not designated.. The system
engineering manager indicated that backups, if needed,- could be provided from
the existing experience base in the specific groups. The system engineering
department was divided into six subordinate groups:
station nuclear engineer-
ing,) nuclear steam supply system (NSSS) mechanical systems, balance-of-plant
.
(B0P mechanical systems, electrical systems, plant support systems, and
I
instrument-and control systems. Each group's supervisor typically had more
than six years of nuclear plant experience, but little previous commercial
. experience.
-A review of the system engineer's training indicated that the engineers had not
received dedicated systems training. The applicant had previously identified
the need for. additional training and had committed to implenent a professional
staff training program by August 1990. This program would encompass personal
'
development training, reactor theory review, plant systems and operations,
i
continuing training, and detailed discipline-specific training. The implemen-
tation of this training will be followed as an open item (445/89200-0-13).
)
-During the first portion of the inspection, the team was concerned that al-
'
though the system engineers had several data bases to assist in equipment
performance _ data trending, the integration of these programs was dependent upon
.
manual data reduction by the responsible engineer.
In response to this con-
l
cern, the applicant presented a-long-term plan for data trending under STA-736,
" Equipment Performance Monitoring" (revision 0). The procedure provided
administrative controls, identification of equipment and equipment parameters
[
to be monitored, performance testing, and performance data trending and evalua-
tion.
Initial program inputs were being obtained from the respective system
engineers and programs were being developed. Long-range plans included inte-
grated computer reduction and analysis of data. STA-736 was designed to
complement the activities of STA-680, " Equipment History Program" (revision 1),
and reactor engineering instruction REI-502, " Equipment History Trending"
(revision 0), these were not yet fully implemented, but initial training was
either complete or in progress, and implementation was planned. STA-514,
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" Nuclear Plant' Reliability Deta System (NPRDS) Program (revision 0), was in
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place and scheduled to comence with commercial operations. To improve how
NRPDS data and plant data related, the applicant had added a field to the
1
master equipment list (MEL) to identify NPROS applicability; this action was
i
fully impleunted. The full implementation of the NPRDS will be followed as an
1
1
open item (445/89200-0 14).
, p-
7.7 Conclusions
3
-
The systen engineers appeared to have sufficient staffing, programs, qualifi-
cations, and tools available to support the facility during initial startup and
J
subsequent operating cycles. The applicant had established sufficient measures
for controlling design modifications, configuration changes, and temporary
modifications. The applicant had committed to upgrade and implement system
functional training for the system engineers. The inspection team concluded
that the engineering and technical support organizations had the staff, train-
ing, and programmatic controls to support safe plant operation.
8.0 POWER ASCENSION TEST PROGRAM
}
- 8.1 Review Scope
The inspection team reviewed the applicant's power ascension testing program
(PATP) and the testing requirements of Regulatory Guide (RG) 1.68, including
r
low-power _ physics tests. The inspection team also verified that the test
requirements of RG 1.68 excluded from the PATP had received authorized excep-
'
tion through amendments 41, 66, and 76 to the FSAR and NRC approval dated
June 1, 1988.
'
8.2 Organization and Staffing
t
The power ascension testing program (PATP) organization was chartered under the
performance and testing (P&T) department as the initial startup group reporting
.
to the P&T manager. The station nuclear engineering group -a subset of the
- system engineering department, was designated to interface with the P&T depart-
>
ment during-the test program. The station nuclear engineering group was
staffedwithagroupsupervisorand4~stationnuclearengineers(SNEs),andwas
. supported by 12 engineers from the P&T department. -The planned size of the
shift complement during initial startup (ISU) tests appeared sufficient to
_
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ensure adequate coverage.and independent verification of recorded data.
The applicant had incorporated lessons learned from other near-term operating
license (NTOL) plants. The SNEs, P&T personnel, and operations personnel had
received both.onsite classroom training and simulator training. The SNEs
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training consisted of required reading of information related to NTOL
I
experiences at the Vogtle power plant and NRC information notices and bulletins
and Institute of Nuclear Power Operations (INPO) significant operating events
reports (50ERs) related to industry experiences during startup and testing
l
programs. .In addition, a number of the SNEs had participated in the initial
L
startup and power ascension program of the South Texas Project nuclear power
p
- plant, as well as the startup of the Diablo Canyon nuclear power plant.
A review of SNE qualifications and training indicated that the requirements of
- American Nuclear Society (ANS) Standard 3.1 were satisfied, but the SNEs did
not have: previous experience at other nuclear plants during hot operations and
49
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PATP periods. The inspection team also roted that although the staff of the
P&T departrent generally had more experience than the SNE group, they also had
little previous commercial operating experience.
In order to support the SNE
group, the applicant had employed 38 contract personnel in the P&T group who
had extensive previous consercial operating experience. These contract person-
nel had direct power ascension testing responsibilities.
1 [
B.3 Test Status and Scheduling
The PATP test status was maintained by a test director in the control room. The
shift suptrvisor was inforined of the test conpletion as a requirenent of the
procedure. Additional test status was maintained by the applicant's management
information tracking system (MITS) and the maintenance management computer
program (MMCP). The P&T group scheduled the PATP tests through the work
control center. The work control center used a PREMISE software data base to
generate a performance evaluation reference tracking (PERT) diagram. The
scheouling diagram sufficiently categorized the tests at the required power
level.
8.4 Managenent Review and Approval for Plateau Changes
The applicant had established measures for the review, evaluation, and approval
of test results by multiple levels of management. The initial review and
approval of PATP tests results was performed by the SNE or test engineer as
appropriate. The secondary review was perforned at the test review group (TRG)
level. The TRG was composed of six members: the TRG chairman, a technical
member
support group nember, an operations department member, a P&T group (optional)an
engineering department member, and a Westinghouse representative
.
The results of the TRG review were required to be reported to the Station
Operations Review Committee (50RC) with any comments or recommendations
attached. The 50RC was responsible for reviewing the test results and recom-
nendations and for reconmending power ascension to the next power plateau level
to the Vice President-Nuclear Operations, who was responsible for the final
approval to proceed to the next power plateau.
8.5 Ouality Assurance and Controls for PATP
-
Quality assurance controls for PATP were provided by incorporating hold and
verification points into the ISU test procedures. Additional controls in the
test procedures were achieved by independent verification of test data and
subsequent evaluations of results by the SNE or appropriate test engineer.
In
addition, the applicant had contracted for vendor core physics personnel to be
present during initial core loading and low-power physics tests.
8.6 Staffing Prerequisites for Testing
the test complement, excluding normal
Duringinitialstartup(ISU) testing,fttestdirector,ashiftstationnuclear
operations staffing, included: a shi
engineer, a shift P&T group engineer, a shift test manager, and a vendor core
physicist and technician. These individuals would be located in the control
room. Additionally, a test engineer would be positioned in the plant for the
specified test performance. Additional support would be provided through the
ISU manager.
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8.7 Program Change Controls
The applicant had establi. bed adequate actinistrative controls for the initia-
tion, review, approval, and integration of changes to the ISU program. The
cor.trols provided for retesting by performing specified steps again and docu-
menting new data on incorporated sheets.
,
{
S.8 Simulator Traininc on Startup Test Procedures
-
The' ISU test were performed on the simulator as part of the review and approval
of the tests. After approval of the ISUs, 46 of the 69 tests were covered as
part of the licensed operator requalification classroom training.
In addition,
the eight ISUs that involved plant transients or required close coordination
,
between the operations department and the PATP department were performed on the
i
simulator as part of licensed operator requalification training.
'
The P&T department had comitted to provide a shift test director to perform
i.
the pre-test briefing for each ISU test used in the simulator requalification
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program. This training on ISU tests resulted in several benefits.
For exam-
l
ple, the licensed operators suggested several ISU procedural enhancements for
y
. incorporation in the next revision of the procedure. The involvement of the
' shift test director helped to build team spirit in operations department
personnel and the PATP group. As part of the pre-shift briefing for each test,
l
the shift test director emphasized that the licensed operating staff was in
L
charge of the plant and could terminate a test anytime it judged it was neces-
sary in order to control plant conditions. And finally the ISUs were per-
formed on the simulator at least seven times before theIr actual use. The team
considered this to be a strength in the applicant's PATP training,
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8.9 Conclusions
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.The applicant had established sufficient measures for conducting, performing,
!
and evaluating the results of 150 tests. Acequate measures were provided for
the independent review of the PATP sequence tests and changes in the power
l
plateaus. Staffing levels were adequate to support the testing program.
Although the qualifications of the test personnel met the minimum ANS 3.1
j
requirements, the engineers did not have a high percentage of staffing with
,
previous testing experience, The 4pplicant had taken sufficient action to
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supplement experience levels by adding contract personnel. The applicant had
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established adequate controls to ensure independent verification of recorded
I-
data; provide quality assurance ccerols; identify, evaluate, and disposition
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test deticiencies; make necessary changes to the test program; and ensure
i
proper sequencing of tests. The applicant had taken aggressive actions to
l
provide simulator training of PATP tests. The inspection team concluded that
PATP-activities were adequate te support safe startup and low power operation
of the facility.
.
.9.0
QUAllTY VERIFICATION
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9.1 Review Scope
In order to assess the scope and adequacy of the applicant's quality-verifica-
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tion programs, the inspection team evaluated the involvement of the quality
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organization in work and testing and reviewed the root cause and corr.stive
'
action, post-trip review, and incident review programs. The inspection teata
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interviewed cuality assurance (QA) management and staff and reviewed the QA
audit schedule for the final quarter of 1989 and the proposed schedule for the
first quarter of 1990.
In addition, the team reviewed the audit on the assess-
ment of the Technical Specifications surveillance test proceduress and reviewed
^
the routine operations requirements program and the initial startup (ISU) tes;
program. The team reviewed 17 approved operations notification and pvaluation
(ONE)formsthatinvolvedeventsorincidentswhichrequiredcorrectiveac-
tions. The inspection team also reviewed the station procedures governing
'
processing of ONE forms, root-cause analyses, post-trip reviews, and team
incident evaluations,
i
9.2 Qualit_y involvement in Work and Testino
During the first portion of the inspection, the inspection team identified
numerous discrepancies in the computerized scheduling of Technical Specifica-
tions surveillance requirements. Of 10 iter:s reviewed, 4 surveillance items
were incorrectly listed on the schedule so that the surveillance may not have
been completed before the time the applicable system was required to be opera-
ble per the Technical Specifications. On the basis of this concern, the
applicantissuedplantincidentreport(PIR)89-295toevaluatethesurveil-
j
lance scheduling program.
During the second portion of the inspection, the team reviewed the status of
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the corrective actions taken in response to this PIR. The applicant had
completed a reverification of the Technical Specifications surveillance
computer scheduling data base in MMCP. Each department responsible for a
Technical Specification surveillance was required to reverify their portion of
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the data base. After completing this reverification, a separate memorandum was
issued documenting the reverification and any additional findings:
,
The inspection team determined that these reverifications were comprehensive as
far as ensuring the computer base had accurate scheduling information for
t
Technical Specifications surveillances. The applicant also limited the number
of people having access to this computer data base to prevent unauthorized
changes to the data base.
In addition, procedure revisions were made to
integrated 31 ant operating procedures IPO-002A " Plant Startup From Hot Standby
toMinimum.oad,"andIP0-00!A,*PlantHeatupfromCold.ShutdowntoHotStand-
by," to add requirements for the operations department to verify that all
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required surveillances were completed before entering a new mode. Finally, the
applicant instituted a program of performing a periodic check to determine if
any unauthorized changes had been made to the data base. This was being
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performed on a weekly basis.
At the time of the first portion of the inspection, no audits or surveillances
had been performed on the Technical Specification surveillance scheduling
program. The QA department indicated that an audit was planned for this
j
program to take place around the time of initial plant licensing. The team was
concerned that this schedule would not identify errors in the scheduling
program before licensing and could potentially result in a Technical Specifi-
cations violation.
In response to this concern, the QA department audited the
operations dcpartment Technical Specifications surveillances. At the time of
the second portion of the inspection, the audit results had not been approved,
but a draf t copy of the audit appeared to be comprehensive. During this
inspection, the team found no additional problems with the Technical Specifi-
cations surveillance test scheduling in the MMCP.
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Durirg the second portion of the inspection, the inspection team verified that
routine QA invohement in plant activities was thorough and adequate. Routine
surveillances perforned by the QA surveillance group were acceptable.
In
addition to typical, routine QA efforts, the QA department had instituted two
additional cycrsight iunctions that were considered positive and constructive.
rovide QA
The first effort, routine operations requirements, was initiated to gThe
involvement on a 24-hour-per-day basis in routine plant activities.
purpose of this group was to evaluate the plant operation of systems', perfor-
mance end conduct of shif t personnel, plant cleanliness and housekeeping, shift
and conduct of
turnover, adequacy of administrative processes and procedures
routine surveillancts. TheteamreviewedtheworkstatementIorthisgroupand
considered it complete and aggressive. The team reviewed the routine opera-
tions requirements reports for the week of January 15, 1990, and found the
repcrts acceptable in content and in coverage of the group's charter
requirerrtnts.
A second special effort to provide additional QA oversight was scheduled to
begincoincidentwiththebeginningoftheinitialstartup(ISU) testing
program end was to continue through 100-percent power testing. The ISU testing
oversight was directed primarily at observing and evaluating the series of
special tests beginning with fuel load. Twenty-four-hour-per-day coverage by
QA was planned during this period. The scope of work for the ISU group was
reviewed and was considered acceptable by the inspection team.
The QA department was responsive to negative trends and made frequent changes
based on results from the trend analysis group.
Information from this group
was analyzed by the QA overview comittee comprised of senior plant and QA
managers. Redirection of QA effort or focus was provided by that comi' tee.
This process was well established and offective. The inspection team was
concerned, however, that developing issues were not promptly identified. For
example, the QA departnant was not familiar with several of the operational
issues which developed during the second portion of the inspection. On tht.
basis of this observation and discussions with the QA personnel, the inspection
team concluded that additional emphasis is necessary to ensure that operations
oversight is performed on a "real-time" basis. The ability of the QA depart-
ment to respond to current operational issues will be followed as an open
item (445/89200-0-15).
9.3 Root Cause and Corrective Action programs
The inspection team reviewed the problem identification and ccrrective action
rogram as defined and controlled by the operations notification and evaluation
p(OKE)formprogram. The controlling procedures for this program included
station procedures STA-422, " Processing of Operations Notification and Evalua-
tion (ONE) Forms"(revision 1),STA-421."OperationsNotificationandEvalua-
tion (ONE) Form"(revision 0)andSTA-515,"RootCauseAnalysis"(revision 0).
These precedures provided direction for:
initiation of the ONE form by the
originator who identifies a problem, review by the shift supervisor for imedi-
ate operability determination, processing by management at the work control
center for assignment of responsibility, and resolution via corrective action.
The program provided timely evaluation of an identified problem for both
o>erability determinations and reportability. The inspection team verified
t1at the shift supervisor had conducted an initial review within minutes of
initiation of previously completed ONE forms. The ONE forms were then
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asaluated by the work control center to determine the appropriate method for
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handling the problem. -Routine, easily correctable items, in which root cause
or programmatic deficiencies were not indicated, were corrected via STA-606,
" Work Requests and Work Orders," (revision 12). Problems requiring investiga-
tion, analysis, or root-cause determinations were resolved by STA-422
(revision 1), Attachment B; * Resolution of Plant Incidents," Attachnknt C,
" Resolution of Nonconformances," or Attachment D. " Disposition by Engineering
Evaluation."
If the problem identified in the ONE form appeared to meet the
criteria for special evaluation ej a task group, an evaluation team was initi-
attd as required by STA-423, " Evaluation Team," (revision 0).
The inspection team's review of dispositioned ONE forms indicated that the
l
proper threshold has been estabitshed for designation of the proper corrective
action process. The controlling programs, timeliness, and usability of the
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problem identification and resolution process appeared adequate.
Of the approximately 300 ONE forms initiated since December 1,1989, only 16
required an evaluation of the root cause and had completed corrective actions
(
assigned. A list of these ONE forms is provided as Attachment 7.
After
,
reviewing thece 16 ONE forms, the inspection team concluded that 13 were
deficient in either root cause determination, corrective action identification,
'
documentation, er combinations of all three. The inspection team discussed the
concens with the ONE forms with the appitcant. The applicant had also re-
l
viewed the ONE forms and had reached similar conclusions concerning the specif-
1
ic inadequacies. The inspection team concluded that the root cause was not
being consistently or accurately determined and corrected. This was evidenced
by corrective actions which addressed only the specific deficiency and rarely
mentioned the program failures. Examples included four separate events involv-
ing failures in the applicant's freeze protection program, five failures
involving operational configuration or system status control, and three events
involving inadequate control of design output from the engincering department.
None of these evaluations addressed the progrannatic failures that allowed the
incidents to occur. Rather, the corrective actions only addressed the specific
deficiency for which the ONE form was initiated. Since the root-cause assess-
ments did not adequately determine how the failure was allowed to occur,
similar events would not be precluded.
In addition, STA-422 required develop-
ment of the root causes for the event, but did not require a formal root-cause
evaluationinaccordancewithSTA-515,"RootCauseAnalysis"(revision 0),for
1
plant incidents. The applicant agreed that a procedural requirement was
implied for assessing the root-causes of incidents, but was not mandated by a
procedure step.
.
The inspection team concluded that additional action was required to imp (rove
the root-cause evaluation and corrective action identification process
i.e.,
theONEformprocess).
Prompt action was considered necessary to ensure that:
a formal root-cause analysis is initiated when required by the ONE form proce-
dure; the corrective actions address the generic concerns and are not limited
-to the first-level symptoms or specifics (e.g., personnel errors); the correc-
l
tive action evaluations address the inadequacies in the
arogrammatic process
control involved in the specific example identified by tie ONE form (e.g., the
freeze protection, design control, and operational configuration control
,
programs);andthattheONEformshaveadequatedetailtodemonstratethat
adequate corrective actions have been identified. The completion of these
actions will be followed as an open item (445/89200-0-16).
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9.4 Fost-Trip Review Process
During the previous inspection visit, the inspection tenni identified deficien-
cies in the applicant's post-trip review program, including technical and
administrative wtaknesses. The applicant addressed these items in Revision 2
to ODA-108, *Fost-Trip Review Evaluation." The inspection team reviewed this
revision and concluded that the procedure was adequate and that all becessary
changes had been implemented. Changes to ODA-108 included:
(1)proceduralized
use of STA-515,)" Root Cause Analysis" (revision 0), to determine the root cause
of the trip, (2 requirement for Station Operations Review Comittee (SORC)
review and approval of the post-trip report when clear definitive causes and
contributors to the trip could not be detemined. (3) the inclusion of
feedwater flow and temperature recordings in the review package, and (4)
preservetion of applicable physical evidence for evaluation. The inspection
teani had no further concerns in this area.
9.5 Incident Review Process
During the first inspection visit, the team reviewed the applicant's program
for identification, evaluation, and followup of operational incidents in
accordance with STA-503, " Plant Incident Reports (PIRs)" (revision 3). The
team found several instances in which PIR actions were either not implemented
or were ineffective, such as:
(1) inmediate corrective actions were not
documented by)on-duty shift supervisors for actions taken before the PIRs were
initiated; (2 a PIR was not initiated for a turbine lift oil valve lineup
discrepancy which spanned several shifts; (3) operations department management
believed that PIRs could be closed out when corrective actions were identified
but not yet implemented, resulting in an overstatement of the status of PIR
completion;and(4)asofOctober 20, 1989, 23 outstanding PIRs were overdue by
as much as from 1 to 4 months and 4 PIRs involving inadequate clearances dating
from April 1989 had not been evaluated.
The applicant initiated several actions in response to this concern. With
respect to the specific incident-related problems, PIR 89-291 was initiated and
dispositioned for the turbine lift oil valve lineup problem. As discussed in
Section 4.4 of the inspection report, procedures ODA-102, ODA-301, and ODA-302
were revised to improve docunentation, comunications, and management evalua-
tion of personnel performance. With respect to the PIR program problems, the
applicant had replaced the PIR system with the ONE fom system. The applicant
_
had reviewed all previously open PIRs and had assigned and scheduled corrective
actions, although not all PIRs were completely closed. The inspection team
found the actions acceptable.
Procedure STA-423. " Evaluation Team" (revision 0) was used to investigate
events of a significant nature. Initiation of event investigations were above
and beyond the more routine incident investigations described in STA-422
" Processing of Operation Notification and Evaluation (ONE) Foms,"
Attachment B, " Resolution of Plant Incidents." Event evaluation teams coulo be
necessary at several stages during processing of ONE foms. The procedure was
adequate to initiate and direct an evaluation team in perfoming an investiga-
tion, documenting the results, and making corrective action reconsendations.
'
To assess the incident review process, the inspection team reviewed the appli-
cable procedures and one event evaluation team report--at the time of the
inspection, only one event had been evaluated using station procedure STA-423.
55
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The team reviewed a plant incident report (PIR 89-597) concerning metallic
particles 1ound in comon reactor makeup water pump discharge. The event
report followed the guidelines of STA-423, provided adequate documentation, and
arrived at a reasonable root cause with appropriate recomendations. Thus,
the inspection team concluded that the incident review process was adequate.
,
9.6 Conclusions
The QA department had provided oversight in sufficient scope and depth for the
inspection team to conclude that the requisite functions of that organization
were performed in en adequate manner. The team also noted the initiation of
innovative programs designed to provide more coverage of routine and special
operating shift activities. Although additional measures were necessary to
reduce the time required by the QA department to recognize programatic prob-
lems areas, the inspection team concluded that the QA department's involvement
in work and testing was acceptable.
The team also concluded that root-cause determination was not effective and at
tines not even applied in corrective action applications.
Before the end of
the inspection, the applicant had comitted to correct the root cause identifi-
cation process. Sub,iect to the resolution of this concern, the inspection team
concluded that the quality verification activities adequately supported the
safe operation of the facility.
10.0 OPEN ITEMS
Open items are matters that have been discussed with the applicant, that will
be reviewed further by the NRC, and that involve some action on the part of the
NRC, the applicant, or both. The16(445/89200-01 through 445/89200-16)open
items disclosed during the inspection are:
Open item Nurber
Sumary
445/89200-0-01
Open item concerning comitment to maintain shift
advisor, duty manager and staff advisor support
programs until end of power ascension test program
(Section3.2).
445/89200-V-02
Violation of Criterion XVI of 10 CFR Part 50,
Appendix B for an identified condition adverse to
qualify (Section 3.3).
445/89200-0-03
Open item concerning continued management
attention to ensure accurate comunication within and
betweenorganizations(Section3.4).
445/89200-0-04
Open item concerning definition, development and
implementation of safety evaluation training for 50RC
members (Section3.5).
445/89200-0-05
Open item concerning maintaining control room
systemstatusdrawingsuptodate(Section4.6).
56
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445/89200-0-06
Deviation of FSAR comitwent to Regulatory
Guide 1.33 concerning procedures for control of low
power breakers and fuses (Section 4.7).
445/89100-V-07
Two examples of a violation of Criterion V
"
of 10 LFR part 50, Appendix B concerning failure to
accomplish quality activities in accordancelwith ISC
rocedures (Section 4.8) and maintenance procedures
p(Section 5.6.d).
445/09200-0-08
Open iterr. concerning comitment to provide
management participation in operability drills and
critiques (Section4.14).
445/89200-0-09
Open item concerning comitment to review NRC
walk through discrepancies and correct those with an
irpact on operability (Section 5.7).
Open Item Number
Summary
445/89200-0-10
Open item concerning implementation of labeling
upgrades by the completion of the first refueling
outege (Section 5.8).
445/89200-0-11
Open item concerning comitment to evaluate and
install component labeling in the instrument air
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system (Section 5.8).
445/89200-0-12
Open item concerning comitment to reinforce
intent to perform procedures es written and aggres-
sively identify and correct errors (Section 6.3).
445/89200-0-13
Open item concerning implementation of dedicated
,
systems training for system engineers (Section 7.6).
!
445/89200-0-14
Open item concerning full implementation of the
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NPRDS(Section7.6).
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445/89200-0-15
Open item concerning the ability of the QA
department to respond on a "real-time" basis to
operationalissues(Section9.2).
445/89200-0-16
Open item concerning actions to improve the
root-cause evaluation and corrective action identifi-
cationprocess(Section9.3).
11.0 EXIT HEETING
Exit meetings were conducted on October 27, 1989 and February 2,1990, with the
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applicant's representatives who are identified in Attachment 8 to this report.
The team gave the applicant no written material during this inspection. The
applicant did not identify as proprietary any of the materials provided to the
-inspection team or reviewed by the team during this inspection. During these
meetings, the NRC inspectors sumarized the scope and findings of the
.:
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inspection.
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ATTACHMENT 1-
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NRC Letter November 16, 1969
documenting fincings of the
inspection team
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UNITED STATE 8
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mamwovow. o. c. nones
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NUCLEAR REGULATORY COMMISSION
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November 16, 1989
Docket No. 50-445
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9
Mr. W. J. Cahill, Jr.
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Executive Vice President
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--Texas Utilities Electric
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400 North Olive Street, Lock Box 81
l
Dallas, Texas 75201
Dear Mr. Cahill:
g
SUBJECT: NRC INSPECTION REPORT 50-445/89-200 - COMANCHE PEAK OPERATIONAL
READINESS ASSESSMENT TEAM INSPECTION
An announced special team inspection of the Comanche Peak Steam Electric
Station was conducted by the NRC Headquarters staff during the period of
October 16-27, 1989. The purpose of this inspection was to provide the
Director of the Office of Nuclear Reactor Regulation with an independent
assessment of the construction and operational status of your facility.
TheOperationalReadinessAssessmentTeam(0 RAT)inspectionconcludedthat
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the construction and testing of the plant was not sufficiently complete to make
a determination with respect to operational readiness. Consequently, the team
held an interim exit with you and members of your staff on October 27, 1989,
and will schedule a follow-up inspection visit in the future. This letter
documehts the team's conclusions, and the concerns identified during the interim
exit that require your attention before the follow-up inspection. This letter
does not detail.any of the strengths identified by the inspection team. A
discussion of the inspection findings will be provided in Inspection Report
50-445/89-200, which will be issued following the completion of the remainder
of the inspection.
The inspection team concluded that an insufficient number of systems were in
the direct operational control of the operators to support a valid assessment
i
of operational readiness.
In addition, the team concluded that the plant
L
staff had not adequately assumed responsibility for the systems and areas under
I
operational control, and had not fully implemented operational programs and
i
procedures as a direct result of the large amount of remaining construction and
maintenance work. Finally, the team concluded that the operations and
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operations support programmatic readiness were not adequate because several
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operational programs had not been implemented or had weaknesses which precluded
their effective implementation.
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Mr. W. J. Cahill, Jr.
-2-
November 16, 1989
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As we discussed with you and your staff, our inspection activities resulted in
a clearer definition of the expectations regarding the level of construction
completion required for issuance of the operating license and1a spre detailed
assessment of the progress of your reuaining work activities.
Itaddition,
the meaning and purpose of the operational readiness period was clarified.
As discussed during the interim exit, several actions must be taken before the
remainder of the inspection can be completed.
1.
Evaluate and resolve the specific concerns identified by the inspection
team and listed in Enclosure 1.
In addition, perform a broad-based
assessment of the adequacy and implementation of all of your programs
to identify and resolve any similar deficiencies.
2.
Based on the minimal previous comercial experience levels of your
mid-level managers and licensed operating staff, take steps to:
a.
Reduce the maintenance backlog and ensure that all systems are
functional for power operations.
b.
Evaluate augmentation of the management staff with experienced
personnel,
c.
Focus attention on plant-labeling adequacy by examining the status of
the present plant labeling and evaluating the need for imediate
corrective actions, and by committing to implementing labeling
upgrades before the completion of the first refueling outage.
3.
The remainder of the ORAT inspection will be perfomed after you have:
a.
Demonstrated that all systems can function by the successful
performance of all technical specification surveillance tests that
are required for 5 percent power operations--to the extent they
can be performed before fuel load.
.
b.
Decided that the facility is operationally ready for low power
operation, including completion of the items above, and advised the
NRC that the facility is ready for the team to return and confirm
your operational readiness assessment.
Sincerely,
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.6 ?M.
Dennis M. Crutchfield, Ass e ate Director
for Special Projects
Office of Nuclear Reactor Regulation
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Enclosure:
Identified Concerns
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Mr. W. J. Cahill
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November 16, 1989
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cc w/ enclosure:
Mr. Robert F. Warnick
Jack R. Newman, Esq.
Assistant Director
Newman & Holtzinger {
for Inspection Programs
1615 L Street, NW
Comanche Peak Project Division
Suite 1000
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U. S. Nuclear Regulatory Commission
Washington, D.C.
20036
P. O. Box 1029
Granbury. Texas 76048
Chief Texas Bureau of Radiation Control
Texas Department of Health
Regional Administrator, Region IV
1100 West 49th Street
U. S. Nuclear Regulatory Comission
611 Ryan Plaza Drive, Suite 1000
Arlington, Texas 76011
Honorable George Crump
County Judge
Ms. Billie Pirner Garde Esq.
Glen Rose. Texas 76043
Robinson, Robinson, et al.
103 East College Avenue
Appleton, Wisconsin 54911
Mrs. Juanita Ellis, President
Citizens Association for Sound Energy
1426 South Polk
Dallas, Texas 75224
E. F. Ottney
P. O. Box 1777
Glen Rose, Texas 76043
Mr. Roger D. Walker
Manager, Nuclear Licensing
Texas Utilities Electric Company
400 North Olive Street, L. B. 81
Dallas, Texas 75201
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Texas Utilities Electric Company
c/o Bethesda Licensing
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3 Metro Center Suite 610
Bethesda, Maryland 20814
William A. Burchette Esq.
CounselforTex-LaElectric
Cooperative of Texas
Heron, Burchette, Ruckert & Rothwell
1025 Thomas Jefferson Street, NW
Washington, D.C. 20007
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GDS Associates, Inc.
Suite 720
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1850 Parkway Place
Marietta, Georgia 30067-8237
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ENCLOSURE 1
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CONCERNS IDENTIFIED DURING INTERIM INSPECTION EXIT OF OCTOBER 27, 1989
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1.
Unidentified hardware deficiencies - Numerous hardware deficiencies were
fdentifted in systems and rooms which had been turned over to operational
control. These deficiencies had not been identified during the room and
system turnovers, and had not been identified by the operators or system
engineers during routine tours and surveillances.
For example, the inspection team identified (1) leakage of the IB Diesel
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Generator (DG) jacket water and service water piping joints, and
(2) standing water, loose relay label plates, and broken terminal board
wire retainers in DG control cabinets. The IE battery cells had
electrolyte levels above high level marks and showed evidence of
overfilling. There were invalid Quality Control Nonconformance report
,
waiver tags posted on equipment which had not been removed nor identified
during room and area turnovers. The team found a leaking Containment
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Spray (CS) service water relief valve, tape blockage of the CS flow
transmitter drain line, a disconnected limit switch on valve HCV-0606,
and removed safety injection accumulator spool pieces without proced:a al
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guidance.
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Throughouttheplant,theteamnotedthat(1)theelectricaldistribution
and process instrumentation doors under operational control were not
not installed, and (3)perations, (2) the vent and drain valve caps were
routinely secured by o
several rising stem valves had water and debris in
the top of the actuator which could adversely affect the operation and
reliability of the valves.
2.
Operational Responsibility - The actions of a licensed operator inoicated
a lack of " ownership" for the operational consequences of conflicting
testing requirements, in that the operator was persuaded by maintenance
technicians to simultaneously perform two surveil' lances whic~n he believed
conflicted.
3.
Shift Communications - The team observed a lack of effective communication
between operating shifts concerning the corrective and troubleshooting
actions following problems encountered turning the main generator.
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4.
System Status Control - ODA-410. " System Status Contrc1," provided a
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method for recordin7the current system valve alignments and maintaining
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configuration control of all operational systems. A review of the DG
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system identified that the valve status file was not being updated as
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required, in that the position of DG starting air isolation valves was not
correctly updated on the drawing. Although the use of marked-up drawings
is a difficult method to implement, the valve alignments of only four
systems were being controlled by the procedure.
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5.
LCO Tracking and Control - ODA-308, "LCO Tracking Log," provided a method
for tracking and control of LCO action requirements. The procedural
requireaants were not correctly implemented in that the entry and exit of
LCOs were not logged, and the shift technical advisor reviews of recent
LCO action requirements were not performed.
6.
PlantInvestigationReports-STA-503,'PlantInvestigationRdsort"
provided for identification and tracking of PIRs in order to o>tain timely
and effective implementation of corrective actions for plant events. This
programwasnotproperlyimp(lementedandthecorrectiveactionswerenot
timely or effective because 1) immediate corrective actions were not
being recorded (2) PIRs were not initiated for problems concernin
main generator turning problems as indicated by the shift log, (3)g the
the
cperations department believed that PIR closure could occur when correc-
tive actions were identified vice implemented, and most importantly (4) 23
outstanding PIRs were overdue on October 20, 1989, by as much as
1-4 months and 4 PIRs on inadequate clearances as early as April 1989 had
not been evaluated.
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7.
Corrective Actions for NRC inspections - There were several corrective
actions which remained to be completed for previous NRC inspection find-
ings.
For example, the team noted that 159 of the original 238 discrep-
,
ancies between the emergency response guidelines and the facility's design
basis remain to be resolved prior to fuel load.
In addition, the team
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noted that the corrective actions to resolve the accessibility and opera-
bility of equipment in the AFW turbine feedwater pump room had not identi-
fiedorresolvedconcernsinvolving(1)inadequategratinginstalledto
access equipment (2) excessive turns required to operate valves, and (3)
inadequate room ventilation.
B.
Confined S pace Entries - STA-606, " Work Requests and Work Orders "
requireo t1at a confined space work permit be issued prior to beginning
work in any confined space. The team noted that work was secured on tne
outboard containment isolation valve for the containment spray system;
however,theconfinedspacewasnotsecured(i.e.,closedorposted)
following the completion of this work.
9.
Design Modifications - STA-205, " Changes to Procedures," and STA-717,
" Design Modification Review Group," procedurally allowed modifications to
be performed without a safety evaluation if the modification was performed
prior to fuel load. The applicant had performed safety evaluations for
all modifications and intended to incorporate all modifications as a final
safety analysis change prior to fuel load; however, the potential existed
to miss evaluating a change'to the facility.
In addition, STA-205 did not
require a safety evaluation or screening for typographical errors or for
non-significant changes of intent. This ambiguous requirement had the
potential to miss safety evaluation for omitted symbols such as +/- signs
and required individual interpretation as to the intent of the procedure.
10. Limiting Conditions for Operation Tracking - ODA-308, "LCO Tracking Log,"
did not require documentation of management authorization for voluntary
LCO entries, verification of the required periodic management reviews, and
docunentation and retention of the rationale for LCO exits.
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11. Root Cause Analysis and Trendino - The system engineers manually performed
data reduction and trencing of component root cause failure. This method
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was time consuming and difficult to perform because the nuclear plant
reliability data system (NPRDS) was not fully implemented and had numerous
component identification differences with the master equipment list.
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12.
Inter-system Actuations - STA-606, " Work Control Procedure,' kid not
require notes or precautions to specifically identify to the operators
anticipated inter-system actuations such as alarms or trips which may
occur during planned work activities.
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13. Timely Incident Invest 1 cations - STA-422. " Processing of One Forms," did
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not support an expeditious initiation of incident investigations because
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the one form must be processed through the work control center and plan of
the day meetings before the incident team is formed.
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Post-Trip Reviews - ODA-108, " Post-Trip Review,' assumed that all trips
nac a cerinttive cause and did not provide for additional evaluations of
those trips which cannot be definitively identified prior to restart of
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the f acility.
In addition the procedure did not require timely written
statementsoftheprincipalsinvolvedinatripinordertodocumentthe
circumstances before memories fade.
15.
Plant labeling - An upgrade program to improve the useability of the plant
labeling throughout the plant had not been in
The valves and
componentswerecurrentlylabeledwithmetalglemented.
dog tags" which were very
difficult to locate and use.
Inaddition,roomsandcommodities(i.e.,
,
trays, conduits, and piping) were not currently labeled throughout the
plant. The implementation of this upgrade program had been delayed until
completion of the first refueling outage (and may not be finished by
then). Because of the difficulty in finding and reading the present
labels, a potential exists for operator errors.
16. One Forms - STA-421 "One Form Evaluation," provided a new method for
identification and resolution of plant deficiencies and had not been
implementea. This program was intended to consolidate and simplify the
several problem identification methods.
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17. Safety Evaluations - STA-602, " Temporary Modifications," did not require a
safety- evaluation of temporary modifications which were performed before
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fuel load. The applicant was performing temporary modifications without
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safety evaluations and intended to reduce the number of outstanding
temporary modifications, and perform safety evaluations of the remainder
at the time of fuel load. Although acceptable, this method had the
potential to miss performing the required safety evaluations.
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18. Preventive Maintenance Proqrams - All of the periodic preventive mainte-
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nance requirements were no; being performed due to the large construction
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and maintenance work load. As a result, the PM backlog was increasing.
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19. Scaffolding - CMP-CV-1014, " Scaffold Erection and Control," which con-
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trolled scaffolding erection over safety-related and seismic e'quipment
during the operations phase, had not been implemented.
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2D. Previous Comunercial Experience - Although the licensed operators met the
minisus expertence requirements of the applicant's program for hot partic-
1pation experience, the operators had minimal previous comunercial operat-
ing experience.
In addition, the mid-level managers in th' . areas of
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operations, technical support, plant evaluations, radiation protection,
and fire protection, also had minimal previous comunercial operpting
experience. Although the ANSI 3.1 requirements for minimal e gerience
levels had been met, the lack of depth of cosmercial operating. experience
in managers and operators will make a smooth initial startup more
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difficult.
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21. Procedural Inadequacies - ABN-710A, "SG Water Level Instrument Malfunction
Check," had referencing inadequacies which had the potential to confuse
the operators and result in a trip of the reactor. All of the operators
questioned incorrectly identified the steam generator protection bistables
due to confusing references ici the procedure.
In addition, there were
unauthorized and unreviewed temporary markings on the instrument cards
which incorrectly identified the level switch numbers. Although correc-
tive actions for previously-identified procedure problems had been imple-
mented for this procedure, this potential error was not identified.
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22. Cuality Assurance Involvement in 0>erations - Discussions with the
Operations Manager indicate that tte Quality Assurance Department had not
been used for the identification and resolution of operations problems.
In addition, the Quality Assurance Department had not performed an audit
of the technical specification (TS) surveillance scheduling program, but
did intend to review this master schedule of the TS required testing prior
to fuel load. During a limited review, the inspection team identified
four errors in the master schedule where required TS surveillances were
not scheduled. The lack of Quality Assurance Department involvement in
the support of management overview of the operations department and
operational programs was not indicative of a pro-active approach to
quality. involvement in the support of operational readiness.
23. Technical Specification Surveillance Procedures - The trigger procedures
(i.e., shift logs) for conditional T5 surveillance requirements allowed
missing hourly primary and secondary temperature and pressure readings due
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to the longer frequency of the trigger procedures.
In addition, the TS
surveillance requirements for localized containment temperatures were not
specifically obtained by the surveillance procedure.
24
Clearance Procedures - STA-605, " Clearance and Safety Tagging," allowed the
shift supervisor to remove a danger tag and reposition or operate equip-
ment on a temporary basis in nonemergency conditions without sufficient
controls to ensure the adequacy of the remaining clearance. This is
particularly safety significant at this facility due to the extensive use
of master clearances and tiered clearances.
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ATTACHMENT 2
Summary of Corrective Actions Taken in
Response to Interim inspection findings
s included
Theburposeofthisattachmentistolisteachoftheindividualitin E closurt I of Attachment 1 to this in
tion of the original concern, a brief description of the applicant's action
taken in response to the concern, and the section of the inspection report in
which the details of the item can be located.
1.
Team-loentified System Walkdown Hardware Deficiencies
Original concern: The nuinber and type of deficiencies found by the
inspection team while perforn.ing system walkdowns indicated that the
operators and system engineers lacked a feeling of personal responsibility
for the material condition of the plant and also indicated a plant not yet
ready for plant operations.
Actions: All the individual deficiencies were corrected. New items found
during the second portion of the inspection were minor in nature, and were
typical of those found at an operating facility.
Plant material condition
was greatly improved.
Report details: Section 5.7
2.
Licensed Operator Exhibited a lack of Ownership
Original concern: An operator was observed to permit two surveillance
activities to be performed at the same time even though the operator felt
the two activities would have conflicting interactions. This indicated a
lack of ownership for plant activities on the part of plant operators.
Actions: The applicant revised procedures and practices for shift commu-
nications, operator responsibilities, and management evaluation of opera-
tor personnel to improve performance in this area..
Report details: Section 4.4
3.
Shift Comunications Between Operating Shifts Needed Improvement
Original concern: The lick of adequate shif t communications allowed a
problem noted with turning the main generator to continue without taking
timely corrective actions. This indicated a lack of understanding about
proper and necessary shif t comunications.
Actions: See item 2 above.
Report details: Section 4.4
4
Control Room System Status Control Program Not Fully Implemented
Original concern: The control room system status control program had only
been implenented on four plant systems, and discrepancies were found on
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the systems that were beir.g maintained. This indicated a lack of system
control by the operators.
Actions: The applicant had made interim improvements in its procedures
but implementation problems persisted. The applicant was evaluating
alternative methods.
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Report details: Section 4.6
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5.
LCO Tracking and Control Program Had Numerous Discrepancies
Original concern: Procedural requirements for the tracking of entry and
exit of Technical Specifications action statements were either not being
implemented, or did not provide sufficient documentation to assure proper
actions were being taken. This indicated a lack of attention to detail on
the part of operators and shift technical advisors, and insufficient
controls to ensure proper system control.
Actions: Procedures were revised to address each problem and the inspec-
tion team's observations of implenentation found them adequate.
Report details: Section 4.6
6.
Plant incident Report Program Was Not Being properly implemented
Original concern: Theplantincidentreport(PIR)programwasnotbeing
properly implemented in the areas of PIR initiation, PIR evaluation, and
PIR cicsure. This indicated a lack of aggressiveness in evaluating and
correcting identified plant problems, and a lack of operator knowledge
about the program requirements.
Actions: The applicant evaluated all PIRs and identified corrective
actions. The PIR for the main generator problem was evaluated and corree-
tive actions were completed. The PIR program has been replaced by the ONE
form program for the initiation of identified plant problems.
Report details: Section 9.5
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7.
Previous NRC Inspection Items Remained Open
Original concern: Numerous NRC inspection items from previous NRC inspec-
tions which remained open at the time of the ORAT inspection. This
indicated that the applicant had either not taken an aggressive enough
attitude in closing these outstanding issues, or had not aggressively
pursued their closeout with the NRC.
Actions:
In recent inspections, the NRC regional office had reviewed the
specific examples considered during the first portion of the inspection.
The NRC resident office was coordinating closure of remaining open items
with the applicant.
Peport details: Section 3.4
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6.
Confined Space Not Preperly Controlled
Original concern: After work had been completed in a confined space, the
applicant did not properly control access to the area. This-indicated a
lack of safety concern and a poor attitude regarding the construction
effort.
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Actions: Provisions were added to the confined space permit precedures
adequately addressing the specific problem. 110 further implementation
problems were cbserved.
Report details: Section 5.6
9.
Procedural Deficiencies for Safety Evaluations and Procedure Changes
Origirie.1 concern: Modifications could be made to the plant right before
an operating license was granted that had not been evaluated by the
applicant f or safety concerns, and procedure changes that should be
evaluated for safety concerns might not receive the safety evaluation due
to deficiencies in the existing procedure.
Actions: Th applicant strengthened the existing program to avoid the
placement cf any design modifications at time of licensing without a
safety evaluation and also strengthened the procedure change program.
Report details: Section 7.4
10.
LCO Tracking Log Program Weaknesses
Original concern: The LCO tracking program did not have provisions for
docunenting management authorization for voluntary entry into Technical
Specifications Action Statements, management reviews of the logs, and
documentation and retention of the rationale for LCO exits. The team was
concerned this could result in misuse of the LCO tracking program, and
possibly result in violation of Technical Specifications.
Actions: See item 5 above.
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Report details: Section 4.6
11,
implementation of Trendino Programs were Cumbersome and Not Fully
In.plemented
Original concern: The trending program for the system engineers required
marcal data reduction, and the nuclear plant reliability data system
(NPRDS)wasnotfullyimplemented.
Actions:
New procedures had been issued and implementation plans devel-
oped for the programs.
Report details: Section 7.6
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12. Work Orders Did Not Provide System Interaction Information
Original concern: Work orders had to provisions for alerting operators
that the planned maintenance could be expected to cause alarms, equipment
position or condition changes, or effects in other systems.
Actions: Theworkorderprocedurewasrevisedtoincludethosdprovi-
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sions; no further similar problems were observed by the team.
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Report details: Section 5.6
13.
Potential 1or Delay in ONE Form Incident Investiuation
Original concern:
Incident investigation may be delayed due to the
procedure's sequence requirement to process the ONE form through the work
contrc,1 center before making a decision to form an investigation team.
Action: The procedure was revised to provide for early consideration of
investigation team use and to permit team initiation at nearly any point
of the process.
Report details: Section 9.3
14
Deficiencies Found in the Post-Trip Review Program
Original concern: The program as written did not address actions required
if the cause of the reactor trip could not be identified, and did not
recuire timely written statements from individcals involved in the event.
These deficiencies could lead to important information not being retained.
Action: The applicant revised its procedures to include the additional
guidance.
Report details: Section 9.4
15. Priority for Plant labeling Upgrade Program
Original concern: Plant equipment and components were identified by smL11
metal tags which were difficult to find and read. The labeling upgrade
program did not have a high priority to expeditiously address this
problem.
Action: The applicant changed the priorities of the interim and upgrade
programs and accelerated implementation of the labeling upgrades.
Report details: Section 5.8
16. ONE Form Program Not Fully Implemented
Original concern: With the ONE form 3rogram not implemented, the team
could not determine the adequacy of tie program.
Action: The program was implemented in December 1989 with about 600 ONE
forms issued through January 1990. The applicant and the team identified
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implementation problems which were being addressed by further program
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improvements.
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Report details: Section 9.3
17. Temporary Modification Program Deficiencies
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Original concern: Since safety mluations were not required to be
performed on temporary modifications until after the applicant received an
operating license, the lotential existed that a temporary modification
would be installed in tie plant at the time of licensing which did not
,
have a safety evaluation.
Action:
The applicant revised the procedures to ensure that all temporary
modifications that existed at the time of licensing would have safety
evaluations performed.
Report details: Section 7.4
18. Preventive Maintenance Program Not fully implemented
i
Original concern: The preventive maintenance (PM) program had a ltrge
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amount of backlogged and overdue items because the large amount of con-
struction work in the plant had a higher priority. This indicated that
the plant was not yet completed sufficiently to have the normal operating
maintenance program fully implemented.
,
Action:
The applicant had adequately reduced overdue and backlogged PM
items and was planning major program upgrades.
Report details: Section 5.10
19. Scaffolding Program Not implemented
"
Original concern:
Extensive scaffolding was still evident in the plant
during the first inspection visit, indicative that the plant was not
prepared for plant operation. The scaffold control procedure had been
issued but was not in use.
i
Action:
Nearly all scaffolding was removed and existing scaffolding was
adequately controlled.
Report details: Section 5.7
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20. Minimal Staff Plant Operating Experience
Original concern:
Even though the plant staff met all the regulatory
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requirements for operating experience, the inspection team was concerned
that the operating staff would encounter initial difficulties in plant
operations because it had limited previous comercial nuclear operating
experience.
,
Action: The permanent staff was augmented with ex>erienced advisors in
all key positions.
Protocols and duties were esta)11shed for the
advisors.
Report details: Section 3.2
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21. Procedural Inadequacies - Eouipment identification
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Original concern: An ambiguous abnormal operating procedure and poor
temporary equipment labeling practices resulted in several operators
having difficulty performing critical procedure steps.
Ac lon: Thespecificprocedureandlabelingproblemswerecordected.
An
evaluation was done for potentially generic impacts.
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Report details: Section 5.8
22. Quality Assurance involvement in Operations
Original concern: Deficiencies found in the surveillance scheduling had
rot been previously identified in quality assurance (QA) audits or sur-
veillances. QA personnel had not looted in this area and did not plan to
review it until the operating license was issued. The team was concerned
about the operations implementation of the QA program.
Action: The plant departments reverified the surveillance schedule and
corrected the schedule. The operations QA program was implemented, and
the surveillance schedule was audited.
Report details: Section 9.2
23. Technical Specification Surveillance Procedure Concerns
Original concern: A procedure used as a trigger procedure could cause the
operator to miss a required surveillance; not all area temperature read-
ings were being recorded in the shift logs.
Actions: The applicant reviewed other procedures to identify a better
trigger procedure. The shift log will be revised to indicate the area
temperatures are being taken for the required reading. The applicant
comitted to submit a Technical Specification change request to delete
temperature readings not being taken directly.
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Report details: Section 6.2
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Insufficient Controls on Temporary Removal of Safety Tags
Original concern: The clearance and safety tagging procedure permitted
the shif t supervisor to temporarily remove safety tags and operate equip-
ment without any requirement to notify personnel working on equipment,
thus creating a potential personnel safety hazard.
Actions: The procedure was revised to require the shift supervisor to
notify all work parties before temporarily lifting clearance tags.
Report details: Section 4.9
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ATTACHMENT 3
Operating, Alarm Response and Abnormal Procedures Reviewed
System Operation Procedures (SOPS)
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SOP-102A - Residual Heat Removal System, revision 5
S0P-201A - Safety Injection System revision 5
SOP-202A-SafetyInjectionAccumulators, revision 4
$0P-304A - Auxiliary Feedwater System, revision 6
SOP-501A - Station Service Water System, revision 5
50P-605A - 125 VDC Switchgear and Distribution Systems, Batteries, and
Battery Chargers, revision 6
SOP-607A - 11B VAC Distribution System and Inverters, revision 5
SOP-609A - Diesel Generator System, revision 6
SOP-610A - Diesel Generator Fuel 011 and Transfer System, revision 3
SOP-802 - Control Room Ventilation System, revision 5
Abnormal Procedures (ABNs)
ABN-104A - Residual Heat Removal System Malfunction revision 4
ABH-301A - Instrument Air System Malfunction, revision 3
ABN-602A - Response to a 6900/40SY System Malfunction, revision 1
ABN-701A - Source Range Instrumentation Malfunction, revision 3
ABN-703A - Power Range Instrumentation Malfunction, revision 3
ABN-704A - T /N-16 Instrumentation Malfunction, revision 3
ABN-707A-SfeamFlowInstrumentationMalfunction, revision 3
ABN-708A - Feedwater Flow Instrumentation Malfunction, revision 3
ABN-710A - Steam Generator Water Level Instrumentation Malfunction Check,
revision 2
ABN-905A - Loss of Control Room Habitability, revision 2
ABN-912A - Cold Weather Preparations, revision 3
AlarmProcedures(ALMS)
ALM-0052A - Alarm Procedure 1-ALB-5B PRZR 1/4 Press LO, revision 4
ALM-0053A - Alarm Procedure 1-ALB-5C 1 of 4 OT N16 H1, revision 3
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ATTACHMENT 4
Maintenance and 18C Procedures Reviewed
ICA-101
- l&C Work Control, revision 0
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ICG-010
- 18C Technician Qualification Guide
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ICG-01)
- 1&C Technician 0-J-T Guide
INC-7296A
- Analog Channel Operational Test and inannel Calibration Steam
Generator NR Level, Loop 1, Protection Set II, Channel 0519,
revision 2
INC-76BCA
- Analog Channel Operational Test and Channel Calibration Refuelir.g
Water Storage Tank Level, Protection Set 111, Channel 0932,
revision 2
MDA-101
- liaintenance Departnent Organization and Responsib111 ties,
revision 1
HDA-102
- Conduct of Maintenance, revision 2
NDAA-404
- Materials Control, revision 5
MSE-80-5701 - Surveillance of Safety-Related Batteries, revision 1
NE0 Policy Staten<nt No. 4
- Conduct of Maintenance, revision 0
SOP-201A
- Safety injection System, revision 5
SOP-202A
- Safety injection Accumulators, revision 4
SOP-304A
- Auxiliary feedwater System, revision 6
SOP-501A
- Station Service Water System, revision 5
SOP-605A
- 125V DC Switchgear and Distribution System, Batteries, and
Battery Chargers, revision 6
- Diesel Generator System, revision 6
SOP-610A
- Diesel Generator fuel Oil and Transfer Systern, revision 3
STA-605
- Clearance and Safety Tagging, revision 6
STA-606
- Work Requests and Work Orders, revisions 11 and 12
STA-607
- Housekeeping Control, revision 10
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STA-608
- Control of Measuring and Test Equipment, revision 14
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STA-618
- Station Labeling Control, revision 2
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STA-623
- Post-Work Test Program, revision 4
STA-628
- Confined Space Entry, revision 1
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- Non-Plant Equipment Storage and Use Inside Seismic kathgory 1
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STA-661
Structures, revision 1
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STA-677
- Preventive Maintenance Program, revision 1
STA-679
- Predictive Maintenance Program, revision 0
b
STA-725
- Pressure Testing, revision 2
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STA-680
- Equirwnt History Program, revision 1
STA-802
- Acceptance of Station Systems and Equiprent, revision 8
STA-806
- Construction Work Requests and Work Orders, revision 13
STA-810
- Acceptance of Station Systems and Equipment, Rooms, Areas,
,
and Structures, revision 1
STA-815
- Open item Evaluation and Deferral Process, revision 1
TRA-401
- Maintenance Department Craft Training Program
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TRA-402
- Maintenance Department Staff Training Program
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18C Department Activity Guide
Electrical Maintenance Activity Guide
Mechanical Maintenance Activity Guide
Maintenance Department Comitment to Excellence, August 17,1989
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Post-Work Test Guide, revision 0
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ATTACHMENT 5
Completed Work Documents Reviewed
Post Test Requirements (PTRs)
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C890003604
- Auxiliary feedwater pump CPI-AFAPPD-01, closed
December 16, 1989
,
C900000069
- Auxiliary feedwater pump, CPI-AFAPMD-01, closed
January 13, 1990
C890008653
- Safety injection valve ISI-0053, closed December 20, 1989
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C890015106
- Safety injection pun.p lube oil sump TBX-SIAPSI-01, closed
December 20, 1969
C890011981
- Service water pressure instrunent 1-PIS-4250, closed
December 2, 1989
,
C8900014693
- Service water components CPI-SWSRPL-01, 02, 04, 05, 06,
ar.d 08, closed November 15, 1989
Non-Conformance Reports (NCRs)
,
87-05743
- Valcor solenoid valve equipment qualification, closed
January 3,1990.
87-02658
- Valcor solenoid valve equipment qualification, closed
January 8,1989
M85-102084
- Violation of procurement instructions, closed
January 8,1990
Design Change Authorizations (DCAs)
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82504
- Derating the Circuit Breaker requirements for four circuits,
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closed January 9,1990
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42402
- Changes made to environmentally qualify limit switches,
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closed January 8, 1990
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Work Orders (W0s)
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089-13305
- Valcor 0-ring EQ replacement for valve 1-HV-5546, closed
October 18, 1989
C89-12609
- Replace CPI-ELDPEC-02 Main breaker, closed December 30, 1989
C89-12569
- Replace CP1-ELDPEC-01 main breaker, closed December 13, 1989
C89-12426
- Rep 1cce breaker IEC3-2/1, closed November 1,1989
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WorkOrders(continued)
C89-12420
- Replace breaker IEC4-2/1, closed November 13, 1989
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C69-12636
- Rework NAMCO lin.it switches, closed December 5,1989
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- Repair diesel generator IA jacket water leaks, clodd
C89-13677
November 4, 1989
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P89-0980
- Perform motor filter inspection no. 2 MDAFW pump, closed
July 14, 1989
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F89-6246
- Perform motor filter ir,spection No. 2 HDAFW pump, closed
October 4, 1989
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C90-0087
- Ferform INC-7304A and remove adhesive labels, closed
January 25, 1990
089-14155
- Repair RHR MOV limit switch compartment for valve
>
1-8702B-MO, closed November 18, 1989
C89-14112
- Repair NAMC0 limit switch and reterminate flex conduit for
RHR valve 1-HVC-0606, closed Hovember 15, 1989
C89-15072
- Repair leaking vent valve on Rosemount transmitter
1-FT-4772, closed December 27, 1989
C89-15893
- P,epair leaking service water relief valve 1-SW-0444, closed
December 5, 1989
C89-13743
- Miscellaneous cleaning and repairs diesel generator control
panel 1A, closed November 6, 1989
C89-17753
- Install / remove il S1 accumulator drain spoolpiece to support
draining, closed December 28, 1989-
C89-17754
- Install /renove #3 SI accumulator drain spoolpiece to support
draining, closed December 28, 1989
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C89-17755
- Install / remove #2 SI accumulator drain spoolpiece to support
draining, closed December 28, 1989
C89-17756
- Install /ren.ove f 4 SI accumulator drain spoolpiece to support
draining, closed December 28, 1989
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ATTACHMENT 6
Surve111erce Procedures Reviewed and Witnessed
The following six surveillance procedures received a tabletop reviewy but the
actual performance of the procedures was not witnessed:
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OPT-110A - Neasurerent of Controlled Leakage, revision 2
OPT-201 A. - Centrif ugal Charging System Operability Test, revision 1
OPT-204A - Safety Injection System Operability Verification, revision 2
OPT-206A - Auxiliary Feedwater System Operability Test, revision 3
OPT-214A - Diesel Generator Operability Test, revision 2
OPT-403
- Axial flux Difference, revision 2
The following 18 surveillance procedures were observed by the inspection team
during actual performance:
OPT-102A - 0)erations Shiftly Routine Tests revision 3
- 0PT-201A - Ciarging System Operability Verification, revision 4
- 0PT-203A - Residual Heat Removal System Operability, revision 1
- 0PT-205A - Containment Spray System Operability Test, revision 1
- 0PT-207A - Service Water System Operability Test, revision 2
- 0PT-209A - Safety Chilled Water System Operability Test, revision 1
- 0PT-215A - Class IE Electrical System Operability, revision 4
OPT-221A - Cold Shutdown Class IE Electrical Undervoltage Relay Test,
revision 0
OPT-470A - Train A Safeguerds Slave Relay K616 Actuation Test, revision 0
OPT-517A - Diesel Generator Starting Air Receiver Check Valve Operability,
revision 0
- RFO-402
- Operating Instructions for the Fuel Transfer Equipment, revision 3
- RFO-403
- Operating and Checkout Instructions for Fuel Handling Tools,
revision 3
- RFO-501
- Refueling Machine Checkout Instructions, revision 2
INC-7296A - ACOT and Channel Calibration Steam Generator Harrow Range Level
Channel 519, revision 2
INC 7309A - ACOT and Channel Calibration Steam Pressure. Channel 544, revision 4
INC-7675A - Channel Calibration Turbine Trip, revision 1
INC-7862A - ACOT and Channel Calibration Accumulator Tank Level, revision 2
INC-7880A - ACOT and Channel Calibration Refueling Water Storage Tank Level,
revision 3
- Surveillance test performed at the request of the inspection team.
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ATTACHMENT 7
OperationsNotificationandEvaluation(ONE)FormsReviewed
FX-89-579
- RCP seal injection filter isolated improperly resultire in-lost
seal injection (configuration control, root cause ina & quate).
FX-89-590
- Vacuum pump started with suction valve closed (configuration
control, root cause inadequate).
FX-90-616
- A hand selector switch which was tagged of f" was later found in
the " auto" position (configuration control, human factors review
of panel design inadequate).
FX-90-536
- Fuse reinstalled while work was still in progress (configuration
control, root cause inadequate, tagging procedures).
FX-89-630
- Simuitaneous pump start instead of sequenced start (inadequate
documentation, control of test activities).
FX-89-605
- Slave relays did not trip as designed due to an improper modifi-
cation (work control process, design control, root-cause
inadequate).
FX-89-629
- A relay coil was replaced with the wrong type coil (design
control,rootcauseinadequate).
FX-89-631
- The diesel fuel oil 7-day storage tank requirements were
improperly) changed (design output control, root cause
inadequate .
FX-90-645
- Relay leads found unlanded (design control, root cause
inadequate).
FX-89-588, - Equipment failures due to cold weather conditions (freeze
FX-89-589,
protection program, root cause inadequate).
FX-89-542,
FX-89-002
FX-90-583, - No deficiencies noted.
FX-89-536,
FX-89-597
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ATTACHMENT 8
Exit Meeting Applicant Attendees
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M. Axelrad, Newman and He'itainge:
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f* _ . J. W. Beck, Vice Presider 1, Nclesr Engineering and Licensin~g, ifU Electric
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J. E. Benther, President, The Bentham Group, Inc.
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M. R. Blevins, Manager of Hue N r Operations Support, TU Electric
H. D. Bruner, Senior Vice Presiuent, TU Electric
W.-J. Cahill, Executive Vice President, Nuclear TV Electric
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W. G. Council, Vice Chairman, Nuclear, TV Electric
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D. L. Davis, Technical Support Manager, TV Electric
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D. E. Deviney. Deputy Director Quality Assurance, TV Electric
J. A. Dobbs, Staff Advisor, Operations, TV Electric
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S. L. Ellis, Performance and Test Manager, TV Electric
D. R. Ferguson, ORAT Coordinator, TENERA-
.#*
D. Fiore111,' Public Information Officer, TU Electric
S. P. Frantz Newman and Holtzinger
P. Freeman, TU Services
J. L. French, Independent Advisory Group
B. P. Garde, Attorney, CASE
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W. G. Guldemond, flanager of Site Licensing, TU Electric
J. C. Hicks, Licensing Compliance Manager, TV Electric
C. B. Hogg, Chief Engineer, TU Electric
T. A. Hope, Site Licensing, TU Electric
R. T. Jenkins, Manager Unit 1 Operations Support Engineering, TU Electric
J. J. Kelley, Plant Manager, TU Electric
J. L. LaMarca, Manager of Electrical and I&C Engineering, TV Electric
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G. J. Laughlin, 18C Manager, TV Electric
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W. G. Lee, TU Electric
.F. W. Madden,' Mechanical Engineering Manager, TU Electric
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D. M. McAfee, QA Manager, TU Electric
.S. G. McBee, NRC Interface. TU Electric
'J. F. McMahon, Nuclear Training Manager, TV Electric
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J. W. Muffett, Manager of Project Engineering, TU Electric
W. Nyer, Independent Advisory Group
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E. F. Ottney, Program Manager, CASE
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. S. S. Palmer, Project Manager, TU Electric.
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'H. S. Phillips, Consultant, CASE
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W. O. Porter, TU Electric
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D. Ramsey, TU Electric
C. J .Rawley, Executive Assistant, TU Electric
P. Raysircir, Deputy Manager, Project Engineering, TU Electric
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J. D. Redding, Executive Assistant, TV Electric
D. M. Reynerson,' Director of Construction, TU Electric
H. C. Schmidt, Director of Nuclear Services, General Division, TU Electric
A. B. Scott Vice President, Nuclear Operations, TV Electric
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J. D. Seawright, Licensing Engineer, TV Electric
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J. C. Smith, Plant Operations Staff. TU Electric
M. Spence, President, TV Electric
- R. L. Spence, Unit 2 Quality Control Manager, TU Electric
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~P..B. Stevens,. Manager of Operations Support Engineering, TU Electric
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J. F. Streeter, Director. Quality Assurance, TV Electric
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_N. Terrel, Technical Support, TU Electric
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C. L. Terry,_ Manager of Projects. TU Electric
0.iL. Thero QTC Consultant, CASE
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R. D. Walker,-Manager of Nuclear Licensing, TV Electric
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f Present at exit meeting on October 27, 1989.
- Present at exit meeting on February 2,1990.
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