IR 05000312/1987040
| ML20151W005 | |
| Person / Time | |
|---|---|
| Site: | Rancho Seco |
| Issue date: | 04/19/1988 |
| From: | Athavale S, Castleman P, Dyer J, Haughney C, Norrholm L, Qualls P, Schneider G, Sharkey J, Smith NRC OFFICE FOR ANALYSIS & EVALUATION OF OPERATIONAL DATA (AEOD), NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V), Office of Nuclear Reactor Regulation |
| To: | |
| Shared Package | |
| ML20151V973 | List: |
| References | |
| 50-312-87-40, NUDOCS 8805030267 | |
| Download: ML20151W005 (46) | |
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ENCLOSURE 2 U.S. NUCLEAR REGULAT M Y COMMISSION OFFICE OF NUCLEAR REACTOR REGULATION Division of Reactor Inspection and Safeguards Report No.: 87-40 Licensse: Sacramento Municipal Utility District P.O. Box 15830 Sacramento, California 95852
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Dorket No.: 50-312 Facility Name: Rancho Seco Nuclear Generating Station Inspection Conducted: December 7-18, 1987 and February 8-17, 1988 Inspectors: ht/69
- d. E. Dyer, Team Leader, NRR
, Yf/7!80 '
Date hlf M , +(l'1l9i-5. V1 Athavale Electrical Engineer, NRR Date W/6 P. I. Castleman, Reactor Operations Engineer, NP,R Date Jew &
P. M. Qualls, Project Engineer, RV 4h/as Date 3%w&
C5cFInsider. TTC Instructor, AEOD hke Date
. S' %Y AL WTY
- A M. Sharkey }eactorOperationsEngineer,NRI Dd te'
,~ 4/g8 5'/ D. Smith, Reactor Operations Engineer, NRR Mte/
Coneultants: *D. Beckman, Prisuta - Beckran Assodates Acccmpanying Personnel:
L. Millen} RV; *R. Zimeman, RY; D. Kirsch, RV;
- J.l Crews,RV;*C,Myers,RV;G.Perez,RV;
- A. D' Angelo, RV; D Baxter, EG&G; *G. Holahan, NRR;
[\ . Kalman, NRR;
,, .j Williams, AEOD Reviewed By: # fi# < . i '
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L.-J. M rrholm, Chi Team In~spection Appraisal Date Signed and Dev pment 5 t n #1, DRIS, NRR I
Approved By:
C. aughne k TllT8 Date Sijned'
Chief, Sp3cial Inspection Branch,
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DRIS NRR
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Scope:
An NRC Headquarters team performed a special, announced ' inspection to review the licensee's readiness to operate the Rai.cho Seco Nuclear Generating Statio This review covered the functional areas of operations, maintenance, .
surveillance testing, design change control, quality assurance and corrective '
actions. The inspection was scheduled to allow the observation of plant heatup and mode change in preparation for reactor startup. Additionally, the team examined open and unresolved items from previous NRC headquarters team inspections 50-312/86-41 and 50-312/87-2 Results:
During the first onsite inspection, the NRC team identified significant deficiencies with the quality of activities in the functional areas of maintenance, operations, surveillance testing and corrective actions. Delays in the licensee's restart testing program prevented the team from observing plant heatup and mode chang In February 1988, the NRC team returned to review the specific corrective actions for issues identified during the first onsite inspection period and to observe plant heatup and mode chang Because of plant events and self-identified problems, the licensee stopped plant testing, further delaying plant heatup and mode change. The NRC team reviewed the specific corrective actions taken in response to previous concerns and found them generally adequate, with the exception of the operations issues.
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The licensee had developed an Operations Management Action Plan that was to be implemented before testiag could be continued. The NRC team closed out the remaining open and unresolved items frcm inspections 50-312/86-41 and 50-312/87-29. Another inspection will be conducted to further assess licensee readiness for restar f f
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Table of Contents PAGE INSPECTION OBJECTIVES ......................................... 1 STATUS OF PREVIOUS INSPECTION ITEMS ........................... 2 Items Closed From ASRTP Inspection 50-312/86-41 ............... 2 Items Closed From ASRTP Inspection 50-312/87-29 ............... 5 Items Closed From Other Inspection Reports .................... 7 DETAILED INSPECTION FINDINGS .................................. 8 Surveillance Testing .......................................... 8 3. Surveillance Test Program and Organization .................... 8 3. Surveillance Test Procedures .................................. 9 3. Surveillance Test Implementation .............................. 11 3. Instrument Loop Calibrations .................................. 14 Maintenance ................................................... 14 3. High Pressure Injection (HPI) Pump "B" Seal Replacement ....... 15 3. Letdown Cooler Isolation Block Valve (FV 22011) Air O p e ra t o r R e p a i r . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 3. Component Cooling Water Flow Element (FE-21267D)
Inspection .................................................... 17 3. Annunciator Panel Fire Repairs ................................ 17 3. Maintenance Backlog ........................................... 18 3. Preventive Maintenance Program ................................ 18 3. Measuring and Test Equipment Program .......................... 19 Operations .................................................... 20 3. Control Room Operations ....................................... 20 3. Field Operations .............................................. 22 3. Plant Testing Program ......................................... 23 3. Loss of Offsite Power Test Events ............................. 24 3. Operator Training Program ..................................... 26 Design Change Control ......................................... 27 3. Design Change Package Reviews ................................. 27 1 3. Modified System Walkdown ...................................... 28 3. Drawing Control ............................................... 28 Corrective Action Programs .................................... 28 3. Nonconforming Reports (NCRs) .................................. 28 3. Occurrence Description Reports (0DRs) ......................... 29 3. Corrective Action Requests (CARS) ............................. 30 3. QA Trending Program ........................................... 30 3. Potential Deficier9y in Quality (PDQ) Program ................. 32 , Quality Assurance QA) Programs ............................... 33
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3. A Surveillance Pro; ram ....................................... 33 1 QA Audit Program ... .......................................... 33 3. Quality Control (QC) Inspection Program ....................... 33 3. Management Observation Program ................................ 34 l
4 PANAGEMENT MEi ING .................................................
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) INSPECTION OBJECTIVES The objectives of this inspection were to review the licensee's implementation i of programs in the functional areas of operations, maintenance, design change l control, surveillance testing, quality assurance and corrective actions. This l inspection was originally scheduled to allow the inspection team to coserve l plant heatup and mode change in preparation for reactor startup, but delays in the licensee's schedule prevented the team from observing these activitie I The NRC team did observe licensee performance of its restart test program and preparation for plant heatup. Additionally, the inspection team reviewed open and unresolved items from previous NRC headquarters team inspections 50-312/86-41 and 50-312/87-2 l
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2 STATUS OF PREVIOUS INSPECTION ITEMS The inspection team reviewed the status of open anc' unresolved items identified during the Augmented System Review and Test Program (ASRTP) Inspection (50-312/86-41) and ASRTP Followup Inspection (50-312/87-29). All items from these inspections were closed. Additionally, the team closed an inspection item remaining open from an NRC Region V inspection (50-312/87-37).
2.1 Items Closed From ASRTP inspection 50-312/86-41 Open Item 50-312/86-41-01: Auxiliary Feedwater (AFW) Turbine Driven Pump Overspeed Issues A concern remai.ed open that the time required for depressurization of AFW pump P-318 turbine governor control oil system after an overspeed trip was unknown and this information was required for operating procedure guidance to prevent a subsequent overspeed trip upon restar The inspection team reviewed the proposed AFW turbine driven pump overspeed ,
test to be performed as part of Special Test Procedure (STP) 1070, "AFW Hot Functional Test," and found it to be adequate. The licensee committed to incorporate the results of this test into the applicable operating procedures and training progra This item is close Open Item 50-312/86-41-07: Main Feedwater (MFW) System Problems The inspection team initially identified eight MFW system status report (SSR)
problems that should be resolved before restart. The status of the two problems remaining open follow *
Problem 18: Correct Casualty Procedure C.26 for MFW Pumo_ Operation With Low Condenser Vacuu The inspection team reviewed Procedure C.26,
"Main Feedwater Pump Operation With Low Condenser Vacuum," Revision 8, and determined that the deficiencies identified in the SSR were correcte *
Problem 31: MFW Pum) Control During Shift From Lovejoy to Bailey Hand /
Auto Station Is Not Performing As Designed. The licensee issued Procedure A.50 "Main Feedwater System," Revision 20, which directed that controller inputs be matched before shifting control. During the performance of 4 STP 1020, "Main Feedwater Pump Protection Test," the licensee verified that this practice resulted in proper controller operation.
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This item is close Open item 5)-312/86-41-11: 125 Vdc System Problems The inspeccion team identified four SSR problems that should be resolved before restart. The status of the one problem remaining open follow "
Problem 8: Operating Procedure A.61 Deficiencies. The inspection team Feviewed Procedure A.61, "125 Volt DC System," Revision 8, and verified that all deficiencies identified in the SSR were correcte I
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_0 pen item 50-312/86-41-12: 120 Vac System Problems ;
The inspection team identified five SSR problems that should be resolved before restart. The status of the three problems remaining open follow *
Problem 5: 120 Vac System Casualty Procedure The inspection team reviewed rr:ently issued Procedure OP-C.157, "Loss of 120 Volt AC Vital Bus S1A." ievision 0, and found no deficiencie *
Problem 7: Response to IE Bulletin 79-2 The inspection team previously reviewed the licensee's response to IE Bulletin 79-27 and determined that a spare 120 Vac cable should be dedicated to provide alternate power to the electrically actuated pressurizer relief valve (PSV-21511). The licensee fabricated a cart and cables under work request 137321 and issued Procedure OP-C.154, "Loss of 125 VOC Non Vital Bus SOE," Revision 0, to provide the alternate power from a spare breaker on bus SOF. The inspec-tion team walked-through the procedure with licensee maintenance personnel and found it adequat *
Problem 12: Local Indication of Circuit Breakers Position. The licensee l physically marked the circuit breakers on Westinghouse power panels SIA3, i SIA4, SIB 3 and 5184 to aid in the detection of a tripped circuit breake The team inspected thre marked circuit breakers and found them adequat ;
This item is close Open item 50-312/86-41-13: 480 Vac System Problems I The inspection team identified nine SSR problems which required further resolution before restart. The status of the three problems remaining open ;
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- Problems 25, 33, and 34: Procedure A.59, "480 Vac System Operating Precedure" Deficiencie The inspection team reviewed Procedure A.59, l Revision 22, and verified that the deficiencies identified in the SSR l were corrected, j
l This item is close Open item 50-312/86-41-14: 4160 Vac System Problems The inspection team identified fcur SSR Problems that required further resolution before restart. The status of the one problem remaining open l follow l
Problem 25: Indication of loss of Control Power for 4160 Vac Switchgea !
The inspection team previously determined that the indicating lights for I the control circuits associated with AFW pump P-319 and the undervoltage trip circuit logic associated with four safety-related 4160 Yac circuit breakers should be modified to provide direct ir.dication in accordance with IE Bulletin 79-27. The inspection team reviewed Engineering Change
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Notice (ECN) R-1045, which removed fuses for the two-out-of-three under-
, voltage protection logic so that the buses were protected by existing control power breakers that alarm when tripped. The team also reviewed 3-
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ECN A-5415, FPR #20, which rewired the indicating lights for AFW pump P-319. The team found these modifications adequat This item is close Unresolved Item 50-312/86-41-28: AFW Pump Operability This item remained open pending completion of the condensate storage tank (CST)
levelinstrument(LI35803)calibrationanddocumentationthattheAFWpumps were operabl The licensee conducted the necessary analyses to support a reduction in the required flow for the AFW pumps to 475 gpm as specified in Technical Specification 4.8.1. Procedures SP 20, "Monthly Turbine / Motor Driven AFW Pump P-318 Inservice Test," Revision 1, performed on February 2,1988, and SP 21,
"Monthly Motor Driven AFW Pump P-319 Inservice Test," Revision 1, performed on January 31, 1988, demonstrated that the pumps would provide the required flow, d
The team verified that the CST level instrument (LI 35803) was properly calibrated and placed in service. This item is close I Unresolved Item 50-312/86-41-30: AFW System Surveillance Procedure Deficiencies The inspection team identified several problems with surveillance procedures used for implementing Inservice Test (IST) Program requirement The licensee updated its IST Program for the second 10-year submittal and issued new procedures to implement the IST Program requirements. The team reviewed Procedures SP 20, "Monthly Turbine / Motor Driven AFW Pumps P-318 Inservice Test," Revision 1, and SP 21. "Monthly Motor Driven AFW Pumps P-319 Inservice Test," Revision 1. The valve lineups for testing, the permanent location for pump bearing temperature measurements, and clearly specified alert and action ranges were found in the procedures. This item is closed.
Unresolved Item 50-312/86-41-31: 125 Vdc System Surveillance Testing This item remained open pending the issuance of revised surveillance procedures for the battery chargers to correct problems with acceptance values for current i limits, overvoltage relay setpoints, equalizer voltage and float voltage ,
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The licensee revised drawing 101, sheet 93 (Revision 7), sheet 130 l (Revision 2), sheet 190 (Revision 0) and sheet 191 (Revision 0) by ECh R 2181 l to the correct values. Additionally, the team reviewed Procedure EM.161, l
"Station Battery Charger Routine," Revision 2, to verify that the correct '
values were incorporated into the surveillance program. This item is close Open Item 50-312/86-41-34: AFW Pump Runout Recognition and Control This item remained open pending issuance of a procedure for recognition of AFW pump runout conditions. With the installation of the flow cavitating venturis to prevent overfeeding the once-through steam generator (OTSG) during casualty ;
conditions, the probability of pump runout was significantly reduced. AFW Pump !
runout could only occur when the OTSG was depressurized or when a discharge line upstrean of the flew venturis rupture l-4- '
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The licensee issued the "IDADS Annunciator Response Procedure," Revision 4 to include confirmation of a runout condition when the alann was received. A lesson plan was developed for this subject and all shifts were trained beginning the week of December 14, 198 This item is close Unresolved Item 50-312/86-41-36: Valve Maintenance Procedure This item remained open pending issuance of maintenance procedures for safety-related air-operated valves (A0Vs).
The licensee issued six new maintenance procedures (listed in Appendix B) for the disassembly, repair and reassembly of safety-related A0Vs. Each procedure was for a specific design of the A0V, and collectively all safety-related A0Vs were covered by a particular maintenance procedure. This item is close Open Item 50-312/86-41-39: QA Surveillance Program This item was being held open pending implementation of recently issued QA Surveillance Program procedure The team reviewed the QA Surveillance Program as implemented from October through December 1987. Based on a review of the number and quality of QA surveillance reports, it appeared that the level of effort in this area had decreased. When the team returned to the site the second time and reviewed QA surveillances conducted from December 1987 through February 1988, a significant improvement was observed as discussed in Section 3.6.1 of this report. This item is close .2 Items Closed From Inspection 50-312/87-29 Open Item 50-312/87-29-01: Nuclear Service Cooling Water (NSCW) Pump Safety Signal Defeated by Non Safety-Related Level Switch I
The inspection team previously determined that safety feature actuation system (SFAS) signals to the NSCW pumps would be defeated by the NSCW surge tank i low-low-level contacts which were actuated by non-safety-related level instru-i ment The licensee accomplished ECN R2348 to disconnect the level switches from the protective circuit. This change disabled the automatic trip on low-low surge tank level, but retained the alarm functio The licensee revised Procedure A.24,
"huclear Service Cooling Water System," Revision 14, the alarm response sheets for H25FA (Revision 8) and H2SFB (Pevision 9), and the system description and functional requirement document for the NSCW system to reflect this chang ,
Once this alann is received, operators are directed to investigate the need to !
trip the NSCW pump. This item is close l 03en Item 50-312/87-29-02: Inadequate Fire Door for Emergency Diesel Generator I GEB Room The inspection team identified a concern that the fire door between the i Emergency Diesel Generator GEB room and east-west hallway did not appear to be adequately designe '
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The licensee war committed to comply with National Fire Protection Association (NFPA) 80, "Standard for Fire Doors and Windows," 1983 Edition. Section 2- of NFPA-80 requires that the clearance between the bottom of the door and the sill not be greater than 3/8 inch. During the inspection, the team verified that the distance between the door and sill was 3/16 inch. This item is close Open Item 50-312/07-?9-03: Emergency Diesel Generator GEA and GEB Rooms Drain System The inspection team was concerned that the 2-inch lines from each room that merged into a comon 3-inch drain line were inadequate to remove the sprinkler system water. The licensee had no anlyses to demonstrate that the size was adequat The licensee performed Calculation Z-CDS-M2329 to address the potential for backflooding into both emergency diesel generator rooms. This calculation analyzed the various possible situations and concluded thdt it was not possible for the sprinkler system to cause backflooding. The team reviewed the calcu-lation and found it acceptable. This item is close Open Item 50-312/87-29-04: Emergency Diesel Generator Starting Air System Capacity The inspection team was concerned that Emergency Diesel Generator GEA2 and GEB2 starting air accumulators had not been adequately sized to meet their design requirements. The licensee committed to demonstrate the adequacy of these '
accumulators by testin The licensee decided to install a dedicated backup control air system for starting the emergency generators. This modification was implemented by ECN A-3748 and tested by STP 1146, "Operational Test Backup Control Air."
The team reviewed ECN A-3748 and the test outline for STP 1146 and found them acceptable. This item is close Open Item 50-312/87-29-05: Emergency Diesel Generator Air Compressor Over-pressure Protection l l
The inspection team was concerned that the air compressor outlet safety valves appeared to be set above the nameplate rating of the compressors (290 psig vs 250 psig)
The licensee contacted the compressor manufacturer and obtained written approval !
for the compressor application. The vendor stated that the pressure rating on l the nameplate was for continuous duty and the compressor would run intemittently 1 (approximately two 15 minute runs every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />). On this basis, the manufac-turer concurred with the existing design of the system. The team found this analysis acceptable. This item is close ,
0 pen Item 50-312/87-29-06: Procurement and Material Control
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The inspection team identified potential problems with licentee practices for procuring and controlling safety-related materials and equipment. This item was held open pending further review and inspection by the NR l-6- ,
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The NRC conducted an announced team inspection of the procurement area during the period January 4-14, 1988. The results of this inspection are documented ;
- in Inspection Report 50-312/88-02. This item is closed.
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2.3 Items Closed From Other Inspection Reports ]
Inspector Followup Item 50-312/87-37-03: Adequacy of Location For Control Room HVAC Radiation Monitor Detectors R15701 and R15702 i The detectors, which actuate isolation of the normal control room heating, ventilation and air condition (HVAC) system and initiation of the emergency control room HVAC system, are located on a wall approximately 10 to 18 feet from the HVAC intakes. During this inspection, the team reviewed SP 655
"HVAC Beta Monitor Calibrations - R15701/R15702," Revision 0; and SP 618
"Refueling Interval CR/TSC Essential Filtering System," Revision 0; and report GVC-87-1023. "Engineering Evaluation of the Location of the CR/TSC HVAC Radiation Detectors," dated October 23, 1987. The calculations and report reevaluated the present detector locations and considered detector beta and gamma response, nonuniform radioactive gas distribution in the air, j and the effective sensitivity ranges for the actual detector location The report found that the upper detector was able to adequately monitor post-accident gases entering the intake. The team selectively performed ,
independent bounding calculations and reviewed the licensee's analysis, '
finding it acceptable. On December 14, 1987, the team witnessed performance of SP 486, "Monthly CR/TSC Ventilation Gas Monitor Test," Revision 0, and .
- confirmed that the procedure corresponded to the requirements of the above I calculation and setpoint study. The team found these actions acceptabl This item is close .
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3 DETAILED INSPECTION FINDINGS
! 3.1 Surveillance Testing .
The inspection team reviewed the licensee's program for implementing the testing requirements imposed by the Technical Specifications and the ASME Boiler and Pressure Vessel Code,Section XI, Inservice Test (IST) Program. The review included assessments of the responsible organization, written procedures, test perfomance and resolution of problems found during testing. At the time of the inspection, the IST Program and Technical Specifications were not finalized and testing requirements were changing. The licensee was developing procedures based on what they believed their testing requirements would be for startu On the basis of its review of the activities observed during the initial inspection period. December 7-17, 1987, the team concluded that the !
Surveillance Testing Program was not ready to support operational mode-change decisions. The licensee made substantial progress through the second inspec-tion period, February 8-17, 1988. At that tirle, the licensee's program controls, administration, and procedure development hid progressed to a point where they appeared ready to support restart; however, test procedure implementation continued to be wea .1.1 Surveillance Test Program and Organization The Surveillance Testing Program was administered by the Plant Performance Group; test procedures were being written by personnel from the Operations and Maintenance Departments who also conducted the testing. Additionally, credit for some periodic surveillance tests was being taken based on completion of ,
the System Review and Test Program (SRTP) special test procedures (STPs). !
During the first inspection period, it appeared that the Surveillance Test !
Program was just recently receiving the attention necessary to prepare the plant for operation. The Plant Performance Department's Surveillance Group was staffed in September 1987 and a Surveillance Program Action Plan was
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developed to implement new program requirements. This action plan provided detailed milestones to ensure that the correct procedures were implemented to support the plant heatup and startup schedules. The plan also included a matrix that cross-referenced Technical Specification requirements to sur-veillance procedures, required that the SRTP testing be reviewed to ensure that credit was taken for applicable surveillance tests and established a 1 i computerized tracking schedule to ensure that the required test periodi&ities l were accomplished. Although the inspection team was favorably impressed with the action plan, it appeared that its implementation was not progressing suf-ficiently to support plant startu During the second inspection period, the licensee had made substantial progress with the development of the Surveillance Test Program. The inspection team
, fcund the program administration ready to support restart activities. As a result of a revision to the action plan, the test matrix and schedule had been refined, restart procedure requirements had been better identified, the test results review and problem identification processes had been improved and i
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actions had been taken to correct prior surveillance test failures and prece-dure inadequacies. Training programs had also been irplemented for staff engineers, surveillance test performers, and test data reviewers; the training program appeared to be responsive to the identified need .- .-. -
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3.1.2 Surveillance Test Procedures '
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The inspection team reviewed the adequacy of the surveillance procedures listed I in Appendix B to this inspection report. The program administration procedures
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were reviewed for compliance with the licensee's Technical Specification and i quality program comitments. The detailed implementing procedures were !
compared, on a sampling basis, with system design and operating inforwation, j
- plant drawings and installed hardware. During the first inspection, the team )
i found that, in many cases, the surveillance procedures did not provide adequate
! guidance for the implementation of Technical Specification and IST Program i
- requirements. Specific examples of these deficiencies follo (1) Several procedures were missing specific guidance for the installation
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and removal of test equipment, restoration from test lineup and indepen-dent verification of valve position, lifted leads, switch lineups and j i jumper installation:
(a) Procedure SP 18," Quarterly Cold Shutdown Check Valve Full Stro '
- Test," Revision 1 did not provide guidance for restoration of ;
j system lineups or removing of blank flange '
(b) Procedure SP 322A, "Refueling Interval Nuclear Service Bus 4A2 l
- Voltage Protection Calibration," Revision 1 did not require i verification of either the installation or removal of test gear and
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only required verification of electrical jumper removal upon system
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restoration. Further, the procedure did not provide a detailed sequencing of test steps or specific terminal points for test l
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equipment installatio i
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(c) Procedure SP 60, "Quarterly EHOV Block Valve Test," Revision 0, did not require independent verification during test lineup or 4 restoratio (d) Procedure SP 41A, "Refueling Interval SFAS Digital Channel Test 1A."
Revision 0, did not provide independent verification for system '
restoratio As a result of the team's concerns about procedural adequacy, the licen- i see initiated its own review of the surveillance procedures for similar i concerns. At the end of the first inspection period, the licensee had !
additionally identified 4 procedures that required further guidance for '
system restoration, 22 procedures that required further guidance for test equipment installation and removal, and 7 procedures that required steps for independent verification. The licensee continued these reviews through the second onsite inspection period, improving procedures when problems were identified. These reviews appeared effective because the i team found no technical deficiencies with procedures during the second '
onsite inspection period. The team also verified during the second onsite inspection period that all the deficiencies identified above were !
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(2) Implementation of interim and temporary changes for some procedures appeared weak and had resulted in performance problems. The licensee was issuing new procedures and substantially revising existing proce-dures to reflect modified systems or new IST and Technical Specification ,
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requirements. The team found the following instances durin onsite inspection where temporary (PTCN) and interim (PICN)g changethe initial notices were not properly implemented:
(a) Change PTCN O to Procedure SP 43A "Refueling Interval Reactor Building Spray System, Loop A SFAS Surveillance," allowed deviation
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~ from the described restoration lineup if approved by the Shift Supervisor. There were no speelfic alternative lineups described in ;
the PTCN. The team considered this general approval to deviate from '
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an approved procedure to be inappropriate. Such deviations should be 1
handled on a case-by-case basis by the procedure change proces (b) Procedure SP 348, "Quarterly Nuclear Service Cooling Water System, Loop B Surveillance and Inservice Test," Revision 1 had five change
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notices outstanding that affected virtually every page. However. the coverpagesdidnotaccuratelyaccountforthechangedpages. The
licensee s practices for document control were to retain both the l revised and original pages in the working copy of the procedur '
Consequently, Procedure SP 34B was extremely difficult to follow and ,
implement correctly. Additionally, the team found that Procedures SP i 43 and SP 42 both had three outstanding change notices that changed a l large number of pages and could confuse operators performing the surveillance test i l (c) The team observed that during the perfonnance of SP 486, "Menthly I CR/TSC Ventilation Gas Monitor Test," Revision 0, on December 14, 1987, the technician inadvertently repeated procedural steps when he )
failed to recognize that a procedure page was duplicated because of '
a change notice. In this case, the syste:n was not damaged and the
- technician properly corrected his erro (d) The licensee has also identified instances in which temporary changes to surveillance procedures contributed to system performance problems. In one case, described in occurrence description report (0DR)87-173, Procedure SP 43B had a PTCN written to change a PIC This fact apparently was overlooked by the operator and the emergency diesel generator test switch was not properly realigned during the ;
restoration lineu j i
I The inspection team concluded that many of the issued procedures were not i properly validated by a walkthrough after their development and this j resulted in an excessive number of temporary changes being issued for i these procedures during implementation. The licensee agreed with this l observation and noted that its new Surveillance Program Action Plan included the requirement for walkdown of the surveillance procedures before being submitted for approval. During the second onsite inspection, ,
the team found that the licensee had reorganized to consolidate the j procedure development process under a single support group and had stream- l lined the procedure revision process. Surveillance test procedures that i bad an excessive number of changes were being revised to permanently )
incorporate the changes. This approach appeared to eliminate the reliance !
, on the excessive use of temporary changes, but the team remained concerned i i
about the potential for confusing personnel conducting tests using the 1 changed procecure l
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(3) The inspection team identified the following weaknesses with the format of surveillance procedures:
(a) The procedure format required by Procedure AP 2.26 "Surveillance Procedures - Description and Fomat," Revision 0, often resulted in multiple tables for recording test equipment installation and removal or test data for multiple trains or channels. Each table frequently '
included several pages. This format made the procedure very diffi-cult to follo (b) Several procedures did not include acceptance values in the data tables in which the test data were recorded. The team was concerned that this format increased the probability that an out-of-specifica-tion reading would be missed and an inoperable system would not be recognize The licensee agreed with this observation and noted that the Surveillance Program Action Plan had scheduled resolution cf this fematting problem after restar .1.3 Surveillance Test Implementation During the first visit, the inspection team reviewed the results of approxi-mately 40 surveillance tests and witnessed the perfomance of all or part of a test performed by Operations, Instrumentation and Control, and Electrical Maintenance Department personnel. The following observations were made during this review-(1) The licensee improperly completed Procedure SP 203.06, "Quarterly Decay Heat System and Containment Building Spray Valve Test and Inspection at Shutdown," Revision 11, and failed to retest the affected valves. The procedure tests reactor coolant system (RCS) hot-le HV-20001 and HV-20002, and decay he6t systemRCS (DHS) g isolation return line stopvalves check valves DHS-15 and DHS-16, which are required by Technical Specifi-cation 4.2.2 to be operable during cold shutdown. It appeared that these valves had been tagged open when the RCS was drained and vented. Procedure SP 203.06 was completed on September 18, 1987, but data entries for stroke times and visual inspection of the valves were marked "not applicable" i because the valves were tagged open. Testing for these valves was not identified for rescheduling when plant conditions would pemit, and the licensee failed to test them when the RCS was refilled and the tags were ,
removed. Procedure AP 303.03, "Exemption Request for Surveillance '
j Procedures," Revision 0, was not applied to defer this test. The team i was concerned because these valves provided isolation boundaries between !
i the RCS and the low-pressure DHS piping. When the RCS is pressurize l these valves must be able to shut to prevent overpressurization of the l low-pressure piping if a pressure transient should occur. Upon identifi- i cation by the team, the licensee successfully tested the valves on !
3 December 14, 1987 and subsequently issued Licensee Event Report 87-46 l documenting the omission, enrrective actions and preventive actions taken j to preclude recurrenc I (2) The licensee did not have adequate decurrentation to show that service tests perfomed on station batteries BA2 and BB2 demonstrated they would ,
support their design loads. The service tests were perfomed in March l 1987 with initial surge currents of 335 amps and 385 amps, respectivel l l-11- l
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for batteries BA2 and BB2. After the service tests were completed, new load profiles were developed for the batteries which increased the initial design surge current to 602 amps for battery BA2 and 652 amps for battery BB2.
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On further review, the team discovered that the new load profiles were developed for battery sizing during procurement and reflected the maximum loading possible with existing de bus configurations. These load profiles were more conservative than the current as-built load profiles required for battery service discharge tests. In an internal memorandum, NED 88-0126, dated February 12, 1988, the licensee adjusted the battery '
procurement lead profiles to reflect current system loading and concluded that previous service test results were adequate to demonstrate the i ability of batteries BA2 and BB2 to support existing design loads. The team reviewed the analyses in the memorandum and found them adequat The licensee's stated intentions were to use the procurement load profile for future service tests because it was the most conservative option and would ensure proper battery capacity. The team was concerned that, although this practice was conservative from the testing standpoint, it discharged the battery more than was necessary and could degrade battery capacity and reliability over the years. The licensee agreed to review this issue before their next required battery discharge tes (3) During the conduct of Procedure SP 41A, "Refueling Interval SFAS Digital Channel Test 1A," Revision 0, an identified problem did not appear to receive the proper corrective action. Procedure SP 41A verified that the high-pressure injection (HPI) system nozzle line check valve will open by '
passing 120 gpm through each line with one pump operating. On November 17, 1987, the measured flow through 3 of the 4 lines was out of specification
, at approximately 100 gpm each. NonconformingReport(NCR)7422wasissued to irvestigate and evaluate this proble I hCR 7422 was closed because the test was satisfactorily performed during 1 the performance of STP 1092, "High Pressure Injection System Test," one l
- . month before. the performance of Procedure SP 41A. In discussion with the !
Surveillance Group Supervisor, the team concluded that the reason for the l out-of-specification results was that the system was not flow balance ,
The supervisor had rescheduled the test for performance after HPI system i flow balancing. The team was concerned that an NCR wculd be closed based on earlier data indicating its acceptability, when more recent data indicated there may be a problem. The Surveillance Group Supervisor issued NCR 7751 to document the improper handling of NCR 7422 and the l Surveillance Program Action Plan was revised to require that engineers be i trained in proper handling of test result deficiencie l
(4) During performance of Procedure SP 34A, "Quarterly NSCW System Loop A
, Surveillance and IST Test", on November 17, 1987, operators noted on the procedure that the local and remote valve position indications for valve
. SFV 50011 did not agree. The local indicator showed the valve to be l
) partially open, while the remote control room indication showed the valve fully closed. No corrective action was initiated fn- the discrepanc Further problems with local valve position indicators are discussed in
) Section 3.5.4(3) of this report.
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(5) An entire set of data was lined-out on Procedure SP 203.05A "Quarterly DHR Loop A Surveillance," Revision 19, performed on October 20, 1987 and there was no reason given for the initially unsatisfactory dat The Operations Department subsequently determined that the data takers had prematurely recorded the local pump data before establishing the test condition The licensee subsequently issued Special Order 87-47 on December 14, 1987 instructing operators to include the reason for the markups when changing date sheet (6) The coments section of Procedure SP 203.05A also noted that a spurious isolation switch alarm was received for Valve HV-20517 when the isolation switch for Valve SFV-25003 was actuated. Apparently no further action was taken at the time (October 20,1987) to investigate the potential proble On December 14, 1987, the licensee initiated Work Requests 143865 and 139076 to investigate and correct the proble (7) Procedure SP 18. "Quarterly Cold Shutdown RCS Check Valve Full Stroke Test," Revision 0, performed on October 30, 1987, required that the as-found valve positions be recorded in Data Table 9.2. No such data was entered for the "Initial Lineup for RSC-001 Test with P261A." Although these omissions did not appear to affect the test results, they were not identified by the Shift Supervisor or during engineering reviews. The team was concerned that omission of these data could result in a failure to identify a preexisting deviation from the required normal valve lineups.
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During the second inspection period, another 35 surveillance test procedures were reviewed, but surveillance test perfonnance could not be observed because a hold was imposed on testing. The following observations were made during the procedure review which indicated continuing problems with Operations Department implementation and documentation of testing:
(8) Procedure SP 20 "Monthly Turbine Driven / Motor Driven AFW Pump P-318 Inservice Test," Revision 1, performed on February 2, 1988, and Procedure SP 21. "Monthly Motor Driven Auxiliary Feedwater Pump P-319 Inservice Test," Revision 1, performed on January 31, 1988 each had valve and circuit breaker lineup sheets. Deviations to these lineups, apparently resulting from safety tagouts conflicting with the procedure lineup, were not noted in either the comments sections or cover sheets of the proce-dures and the procedures were signed off as satisfactorily completed by shift supervisors and reviewed without comments by the system engineer (9) Procedure SP 2, "Daily Instrument Checks and Systems Verification,"
Revision 0, performed on February 12, 1988, had several items annotated in their respective steps as either "NA" or "out of service," including ,
specific equipment operability steps for meteorological tower channel A, :
the reactor building particulate monitor, the liquid effluent monitor, ;
and a feedwater valve instrument air accumulator. Again, the procedure !
had been signed off as acceptable without coment or justification for the noted conditions, j The Surveillance Group had identified similar problems with the most recent performance of Procedures SP 83, "Peactor Building Isolation Valve Stroke Test," Revision 0, and SP 99 "Refueling Interval Auxiliary Feedwater System Auto Start Test for EFIC Actuation," Revision The inspection team was-13
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concerned that Operations Department personnel did not fully appreciate the !
significance of the discrepant test results with respect to Technical Specifi- '
cations. These discrepancies were discussed at a meeting with Surveillance ;
Group representatives and the Shift Operations Superintendent on February 12, ;
1988. The Operations Department managers appeared sensitive to these concerns l and were incorporating short- and long-term actions into the Operations l Management Action Plan to improve the quality of surveillance testing activi- .
ties. The Performance Department also returned the specific procedures to the l Operations Department for review and correctio . Instrument Loop Calibration During the initial onsite inspection period, the team reviewed instrument loop calibration procedures and noted that setpoints and related margins were not I supported by engineering calculations. The licensee utilized a process standard that had been developed during construction and was maintained over i the years by administrative controls for safety-related procedures. However, '
the documentation to justify changes to the setpoints and margins could not be retrieved. The Expanded ASRTP (EASRTP) Inspection Program had previously identified this concern and the licensee had contracted to have calculations ,
performed to provide state-of-the-art bases for instrument loop calibration l The licensee comitted to have the new bases developed for the safety features i actuation system (SFAS), reactor protection system (RPS) and emergency feedwater !
initiation and control (EFIC) system before restart and the balance of plant systems after restart. The inspection team was concerned that SRTP testing was in progress using the unjustified setpoints and margins that could later be 1 determined to be incorrect. The licensee comitted to perform a full review when the new setpoints and margins were receive During the second onsite inspection period, the team verified that the licensee had confirmed the validity of the setpoints for SRTP testing. The new infonna-tien had been reviewed and no setpoints required changing; however, the instrument I drift values identified by the study for the EFIC pressure transmitters would I require recalibration of the transmitters every 12 months instead of the l 18-month periodicity specified in Technical Specification Table 4.1.1. The l licensee had already taken action to revise its internal schedule to reflect i the 12-month periodicity and initiated a change to the plant Technical 1 Specification l l
3.2 Maintenance l The inspection team evaluated the maintenance area by observing four main- l tenance activities and conducting document reviews. During the first onsite l visit, the team witnessed the replacement of a pump seal, the repair of an air 1 operator, and the inspection of a flow orifice. On the second visit, the teaf ,
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observed the restoration of an annunciator panel after it was damaged by fir The team reviewed selected vintenance procedures, portions of the preventive maintenance program and the measuring and test equipment programs. The inspection team also reviewed the maintenance backlog for systems required for the heatup mode change. At the conclusion of the first inspection period, the team concluded that the licensee's maintenance program was not ready to support an operating plant. During the second onsite inspection period, the team noted several improvements in the maintenance program, but did not have the opportunity to observe any maintenance of safety-related equipmen .
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I 3.2.1 High Pressure Injection (HPI) Pump "B" Seal Replacement :
Work Request 1398520-0 was issued to replace the inboard and outboard mechanical seals in pump P-238B because of excessive leakage from the existing seals. As a training exercise, the licensee was performing this task under the constraints of an assumed 72-hour limiting condition for operations (LCO). The
"B" HPI pump was located within the radiologically controlled area (RCA) and was within a posted radiation area. The NRC inspector arrived at the job site as the outer seal was being reassembled and followed the job through completion ,
over five shifts. The observations of this maintenance activity concerned the l team in the areas of health physics (HP), maintenance planning, and technical l adequacy of maintenance procedure (1) The following HP concerns were identified:
(a) The work area and tool laydown area area were setup directly in front of a posted 1.5 rem / hour hot spot. The maintenance foreman chose to supervise the job from the area imediately adjacent to the posted hot spot, periodically resting his am on the handwheel for the valve (SIM-042) containing the hot spot. The HP technician observing portions of the maintenance also viewed the job from the aree imediately adjacent to valve SIM-042. After prompting by the NRC inspector, licensee personnel relocated the staging and viewing areas to a lower radiation level are (b) During the maintenance, plastic tubing, routed from a potentially contaminated drip bag under valve NSW-067 outside the posted area to a flocr drain inside the posted area, was pulled out of the drai This action resulted in a spill of approximately one pint of water on the yellow herculite floor covering. The NRC inspector had to prompt the HP technician to clean up the potentially contaminated spill tsefore maintenance personnel stepped in the wate (c) The team noted that a metal chair in use at the grade level HP control desk had three "Radioactive Material" stickers attached to it. The HP control desk was located inside the RCA near the anti-contamination clothing dressing room. When asked, the attending HP technician stated that he did not know if the chair was actually contaminated. The technician then "frisked" the chair and stated that the chair contained fixed, surface contamination reading approximately 1600 eps. The chair apparently was routinely used by HP technicians at the centrol desk, but it could not be determined how long it had been there. The chair was later decontaminated, disassembled, and discarded, j l
(?) The following deficiencies were noted concerning the technical adeouacy
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of maintenance procecures:
(a) During reassembly of the outer seal, the naintenance technicians encountered difficulties determining the proper position of a lock pin that aligned the collector flange and the disaster j bushing. The drawing used at the job site, SMUD drawing N/.02-10, I
"Pump Detail Assembly," Sheet 1. Revision 2, did not show the !
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location of the lock pin. Because the pin location could not be .
determined from the drawing, the technicians attempted to fit it '
in virtually all possible recesses, including a drain port in the l collector flange. The NRC inspector determined that the pin 4 location had been omitted when the vendor drawing (Borg-Warner s Drawing 18-7156-06) was converted to SMUD Drawing N7.02-1 (b) Procedure M.20 "Makeup and High Pressure Injection Pumps," Revision 5 Section 6.2.1, "Shaft Journal and Thrust Bearing Removal - Inboard Journal Bearing," did not specify that the pump coupling hub had to
, be heated in order to remove it. Consequently, the job was delayed until the appropriate equipment and permits were obtaine '
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l (c) The technicians were not aware that the rotating backing ring had l to be remachined to obtain a proper fit until they attempted to install the replacement ring. Although the drawing in use at the job site (SMUD N7.02-10) contained a note stating that the rotating backing ring had to be remachined before installation, Procedure .
M.20 did not address this requiremen !
(3) The following concerns about the planning and supervision of this job were noted:
(a) The seal reassembly was delayed because two flange gaskets had
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not been obtained from the warehouse. This oversight was not
- discovered until it was time to install the replacement gaskets.
! (b) The fact that the pump coupling grease was contaminated was not ,
addressed during the maintenance shift turnover. The shift turn-over did discuss concerns about the amount of smoke that would result from heating the coupling, but not the potential for airborne contamination. The NRC inspector discussed this concern '
with the oncoming maintenance foreman before the coupling was heate ;
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' (c) The "B" HPI pump room was a posted noise hazard area. Consequently, ;
because the job foreman chose to supervise the seal reassembly from '
outside the posted RCA, he did not realize the technicians were
confused about location of the lock pin discussed in section 3.2.1(2)(a).
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(d) QC involvement in hold-point verification appeared to be inadequate.
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The QC inspector signed off a large number of hold-points at one time, as opposed to signing off each hold-point as it was complete Additionally, the QC inspector was less than aggressive in perfor-ming his quality checks in that the maintenance journeyman would
- point out to the QC inspector where they were in the procedure and which hold-points had been completed.
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(e) Neithermaintenancecrew(dayshiftornightshift)wasawarethat
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this job was being perfonned as a test to see if the work could be completed within the time limits of the LCO that would have
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applied had the plant been operating.
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As a result of the concerns raised by the inspection team, the licensee !
reviewed this maintenance activity and trained Maintenance Department personnel as the results of this review indicated were necessary. The team noted an inprovement in the quality of maintenance activities on this job after this review was conducte .2.2 Letdown Cooler Isolation Block Valve (FV-22011) Air Operator Repair .
The inspection team developed additional concerns about the control of
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maintenance while cbserving this activity. The scope of this task involved the
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disassembly, inspection and repair of the air operator for FV-22011, Lt.tdewn i Cooler Isolation Block Valve. An internal leak was suspected in the air .
eperator shaf t seal, preventing the valve from fully opening when stroke Work Request 1405620-0 was issued to repair the leak using SMUD Drawing N7.08-55, Sheet 1, Revision 0, and the vendor manual overhaul instructions for this series of air operator (Leslie size 135R). The licensee ennsidered the 1 overhaul of the air operator to be within the skill of the craft personnel.
. After the initial steps in the disassembly were completed, the maintenance technicians noted that the installed assembly differed significantly from the SMUD drawing configuration and that the vendor overhaul instructions did not apply to the installed valve. The maintenance foreman was consulted and the disassembly continued without obtaining either the correct drawirg or the correct vendor overhaul procedur '
Although no technical deficiencies were identified with this maintenance item, the inspection team was concerned that without accurate drawings, component disassembly was Oncontrollec, regardless of whether the job was or was not !
within the skill of the craft. Additionally, without the correct drawing, obtaining the correct replacement parts could be difficult, if not impossibl The team felt that the decision to continue disassembly of the air operator without the correct drawing or procedure was imprudent. With the plant in an operating mode, this practice could render a safety system inoperable for unwarranted reasons for an ettended period of time, j 3.2.3 Component Cooling Water Flow Element (FE-212670) Inspection Flow element FE-212670 was suspected of being obstructed by an internal blockage. The orifice plate was designed to measure component cooling water flow to reactor coolant pump "0" seal cooler (P-2100). Work Request 1385CE0-0 !
was issued to remove the orifice plate and determine the cause of the suspected blockage. The team observed that this maintenanca activity was well controlled, i maintenance technicians exhibited the proper ALARA awareness, HP coverage '
and briefings for maintenacce technicians were comprehensive, and proper ;
documentation was provided in the work package. The team also noted that
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the system engineer examined the condition of the orifice and properly diagnosed the cause of the flow obstruction. No discrepancies were noted in the performance of this maintenance tas .2.4 Annunciator Panel Fire Repairs During the second onsite inspection period, the team observed the maintenance and troubleshooting effort in recovering from a fire in annunciator panel H4AR The team noted that appropriate administrative centrols were in use at the job i
" site, including the lif ted lead and electrical jumper log. The team also noted i that the room had been declared as a quality control quarantine area with strict acc?ss controls. No deficiencies were noted while observing this activit <
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l During the first part of this inspection the team reviewed the maintenance ;
j backlog to detemine the level of effort required to complete heatup and (
j restart maintenance work. The maintenance backlog consisted of approximately ;
i 1400 work requests. The licensee's administrative goal was to reduce this to . !
l 1000 work requests at the time of plant restart. In reviewing the backlog, the ;
J inspection team noted that the defined backlog consisted of only outstanding i work requests for corrective maintenanc The licensee considered a work ;
request to be outstanding until the work package was turned in for review. At ;
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the time of this inspection, 811 outstanding plant preventive maintenance (PM) ,
j work requests also existed. The team recognized that approximately 20 percent
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of the outstanding PM work requests were for preventive maintenance tasks that l i
had recently been added. According to the guidelines for developing new l FW for existing equipment, a PM was due the day it became a fonnal require-ment. The total nun'ber of outstanding plant work recuests at the time of this ;
inspection was 2.644. TP 3 v ber represented all outstanding work requests for corrective and preve; 't <.aintenance, modifications,supportitems(such i as removing lagging for , - ~ iive maintenance), and surveillance testin During the first part of m . inspection, the daily ratio of closed work
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l requests to new work requnts was approximately 8: The licensee's effort to reduce the maintenance backlog included 24-hour shif t ;
coverage by Maintenance, Engineering, Materials Manaaement and Quality )
Assuranc During this inspection, the licensee it v sed the management presence on the backshift in an attempt to incressJ uco thift productivit :
Considering the review in this area, the team concle chat the maintenance l backlog was manageable, but would require 4 significant effort to be ready for plant restart in March 198 .2.6 Preventive Maintenance Program The inspection team reviewed the implementation of the preventive maintenance (PM) program as described in Procedure MAP-0009, ' Preventive Maintenance Program "
Pevision 1. The following three instances were noted during which the require-ments of Procedure MAP-0009 were not being observed:
(1) The licensee had undertaken a significant effort over the past two years to improve the PM program. This effort included a comprehensive review of the bases for periodic maintenance, such as vendor recomendations, industry experience, and tquipment history. To verify the adequacy of the revised PM program, the team randomly selected some safety-related equip-ment ar.d reviewed the vender-recommended maintenance. By reviewing safety-related pump vendor manuals, the team noted that the PM program incorporated all vendor-recomended maintenance, with the exception of the high pressure injection and makeup pump couplings. The vendor recomended that the lubrication of the coupling be checked semi annuallyt however, this lubrication had not been done. The licensee subsequently datermined that only the "B" HPI pump and the makeup pump coupling had been lubricated within the past 6 months. During the inspection, Work Requett 1439690 was issued to lubricate the "A" HP'. pump coupling, and a new PM was developed to ensure the pump couplings were lubricated at the vendor-recommended frequency. After further review of the PM program, the team detemined that this was an isolated instance in which the vendor recomended maintenance had been over1 coke l
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(2) Section 5.9 of Procedure MAP-0009 required that the results of predictive maintenance activities (such as oil analysis, vibration analysis, and thermography) be reviewed on a quarterly basis,. The purpose of this revi? was to examine the various maintenance data collectively, thus ident Ung equipment that was failing, but whose failure was not detect. le on the basis of any one predictive maintenance test. At the time of this inspection, the Trend Analysis Group had never met and group membership was inconsistent with the Maintenance Department organizatio In response to the team's finding, the licensee scheduled the initial meeting of the Trend Analysis Group for the week of February 21, 198 (3) Preventive maintenance tasks that could not be or were not performed within the required time interval were classified as incomplete or delinquent, respectively. The PM supervisors were required to submit a monthly report to the Maintenance Manager describing all delinquent and incomplete PM tasks, the reason for the delay, and the potential impact on plant safety. At the time of this inspection, these reports only provided the number of delinquent and incomplete PM tasks by disciplin The reports did not include the reason for the delay or the potential impact on plant safety. The licensee stated that this information was informally (orally) provided to the Maintenance Manager. The licensee comitted to formalize this reporting process as required by MAP-000 By comidering this review of the PM program and the outlined corrective actions for the deficiencies identified above, the team determined that the licensee had adequately implemented the program requirement .2.7 Measuring and Test Equipment (M&TE) Program The inspection team reviewed imr,lementation of Procedure MAP-0008, "Calibration and Control of Measurement and Test Equipment," Revision 0, and identified the following concerns:
(1) Section 5.8.8 of Procedure KAP-0008 required that when a piece of M&TE was found to be out of tolerance, an evaluation be made of the acceptability of items previously inspected or tested with the M&TE. The team was concerned that there were no administrative controls to ensure that these out-of-tolerance reports were tracked, completed, and reviewed. It appeared that this practice could lead to improper evaluation of the consequences resulting from the out-of-tolerance M&T (2) Section 5.8.10 of Procedure PAP-0008 required that out-of-tolerance M&TE not be repaired or adjusted until the Metrology Supervisor's review of the out-of-tolerance report (0TR) was completed. This provision was to allow the opportunity for data testing and verification that may be required of the M&TE before adjustments. However, an interview with the Metrology Supervisor revealed that out-of-tolerance equipment was repaired or adjusted as soon as possible because of usage demand (3) Section 5.5.3.5 of Procedure MAP-0008 required that instruments with restricted usage be identified to deter their improper or unauthorized use and Section 5.5.3.2 stated that equipment containing mercury was prohibited for use on nuclear-related systems and was restricted for use on other systems. During an examination of the M&TE calibration facility, the team noted that thermometers containing mercury were not labelled for restricted us __
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(4) Section 5.3.1.4 of Procedure MAP-0008 required the use of a "Limited Cal" l sticker for M&TE calibrated to partial or to less-that-stated specifica- '
tions. An audit of the instruments in this category and an interview with the Metrology Supervisor revealed that "Limited Cal" stickers were never printed. Rather, "Cal Not Required" stickers were used with amplifying )
information about the partial or less-than-specified calibration status of the affected M&TE. Additionally, Section 5,3.1.7 required the use of
"SMUD Calibrate Prior to Use" labels for M&TE identified as infrequently required and that such instruments be placed in segregated storag !
However, these stickers had never been printed nor was segregated storage l provided for such instrument I (5) Section 5.3.1.6 of Procedure MAP-0008 required that M&TE suspect, damaged, malfunctioning, or exceeding its calibration due date have a "SMUD M&TE Reject Label" applied. However, an audit of 11 instruments in this category revealed that none had a "SMUD M&TE Reject Label" applied to the (6) Section 5.4.2 of Procedure MAP-0008 provided for storage of large M&TE in plant locations where it was normally utilized and Section 5.4.4 stated J that unattended storage areas must be locked. However, an intarview with '
the Metrology Supervisor revealed that th!s category of equipment was not ,
kept in a locked area and that access was passible by any person using a '
site security badg ;
The licensee informed the team that these issues aad others were also identi-fied by the Institute of Nuclear Power Operations (INPO) during their recent visit and that a corrective action program for M&TE was being developed to i resolve these issues. The team reviewed the proposed actions and concluded I that they adequately addressed the identified concern l 3.3 Operations )
The inspection team reviewed the conduct of operations both in the control room and in the plant, observed a system valve lineup, verified licensee compliance with operator overtime policies and evaluated operations involvement with the plant testing effort. Additionally, the team reviewed the licenste's operator j training program. During the initial onsite inspection, the licer.see was i preparing for plant heatup, completed hydrostatic testing of both once-through steam generators (OTSGs) and started the lost-of-offsite-power testing. After observing these activities, the team became concerned that operators were not adequately controlling plant activitie During the second onsite inspection period, the licensee had stopped testing due to problems identified by events and the management observation progra The team reviewed the investigations into the events which appeared to confirm the initial concerns about adequate control of testing activities. The team also reviewed the proposed Operations Management Action ?lan which appeared to address the pertinent areas of concern. The team was unable to evaluate the improvements made by the plan, since the plan had not yet been implemente . Control Room Operations The inspection team maintained extensive coverage of the control room during the-20-
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day shift throughout the inspection. The following observations were made during this coverage: l l
(1) Overtime for all shift operations personnel during the period from August 30 to November 22, 1987 showed an average of about 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> of overtime work per week. During the recent SRTP testing effort, the 72-hour weekly limit was exceeded on several occasions. In each case, however, senior i management approval of the additional overtime was obtained before it !
was authorized. The team did not observe any degradation of operator j performance because of fatigue during the inspectio (2) Control room access was strictly controlled by the on-shift operator Non-shift personnel were not al10wed into the control room area without operator permission. The control room was arranged to allow the proces- !
sing of administrative actions without interfering with the operators nenitoring plant parameters. Non-operations personnel were well-informed of this policy and appeared to understand the importance of maintaining i strict control of access to the control roo (3) Control room operators conducted themselves in a very professional manner l and connunications between personnel in the control room appeared to be good. As explained in Section 3.3.3(3) of this report, there appeared to i be some communications problems between control room operators and testing l personnel in the plant during the loss-of-offsite-power testing event that I occurred on December 16, 198 (4) Shift turnovers among operators appeared to be thorough and included l a detailed discussion of plant activities, walkdown of control boards and review of logs. Access to the control room was secured during the shift turnover to prevent any distractions from the process. After the oncoming shift personnel received the turnover information from their counterparts, they met with the oncoming Shift Supervisor to discuss the planned shift evolution (5) Control room logs generally appeared to be brief, but adequate for reconstruction of operational evolutions. One notable exception occurred during the loss-of-offsite-power testing event discussed in Section J.3.3(3) of this report; during that event, details of the emergency diesel generator oil leak, overload, reverse power and local tripping were not adequately entered in the control room logs. However, this informa-tion was available in the test director's record (6) The control room system status files were not properly maintained. These files contained information on the curr$nt status of the system, such as valve lineups, open work requests, temporary modifications and outstanding nonconforming reports. The team found documents in the wrong folders and there was outdated and duplicate information in the files. Additionally, valve lineups in the file indicated that more than one month had elapsed between initial positioning and independent verification of valve positio The licensee stated that this happened because the heatup schedule slippe The te3m was concerned that valve repositioning during the lineups for surveillance testing would invalidate the lineups. The licensee agreed to review this practice as part of its Operations Management Action Pla . _ . .- - . .
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(7) The team reviewed the compensatory actions taken after the loss of all centrol room annunciators on February 8,1988. The operations staff thoroughly reviewed equipment monitoring requirements for the shutdown mod For required equipment not covered by computer alarms, log sheets were developed for inside and outside of the control room. The team con-cluded that the licensee's response to this problem was thorough and effectiv .3.2 Field Operations In order to evaluate the quality of operations outside the control room, the inspection team observed a portion of the independent verification of the auxiliary feedwater system valve lineup, followed auxiliary operators on plant tours and walked through the procedure for shutting down the plant from outside the control room. The inspection team found that the operators were generally very knowledgeable and performed their duties in a responsible manner, with one exception. The following observations pertain to this evaluation:
(1) Auxiliary operators appeared to be very knowledgeable about the status of the plant and equipment modifications. The log entries cade during the rounds were very detailed in describing equipment in an abnomal status and this information was readily communicated to the control roo (2) An operator verified the position of motor operated valves (MOVs) without reliable local valve position indication by taking manual control of the operator and checking it shut. No further operation of the valve was conducted to ensure that the electric motor had realigned properly with the operator or that the valve had not been jammed during the manual operatio Procedure AP 23.10 "Equipment Maintenance and Operating Standards," Revision 0, required that manually stroked MOVs be electrically stroked and timed afterwards to ensure proper alignment. This requirement was established after problems were discovered with MOVs not realigning after manual operatio The inspection team was also concerned about the contributing causes to this problem. First, Procedure A.51, "Auxiliary Feedwater System," l Revision 34, Enclosure B.1, provided guidance for the valve lineup but did not contain a note promulgating the requirements for MOV operation described in Procedure AP 23.!0. Apparently, operators were not adequately trained in all aspacts of this procedure. Second, the operator used the manual checking of the valve instead of observing the local valve position indication because the local indication was either not aligned or not functioning. This problem was not noted on the procedure, and a deficiency was not identified stating that the procedure could not be l performed correctly. It appeared that the operators were making up for hardware deficiencies by violating their procedures. The problem with defective local valve position indicators is discussed further in Section '
3.5.4(3) of this repor The licensee outlined the following program of corrective actions and ccmitments to correct the local valve position indication and operation problems:
All MOVs and A0Vs important for safe shutdown outside of the-22-
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j control room were identified and will have acceptable local valve l position indication installed before plant restar >
All category 1 M0Vs and A0Vs will be prioritized for local valve position indication installations to be continued until all are installe Operating procedures will be revised to give direction on both methods of first and second verifications and operators will be trained on these tequirement The inspection team concluded that these actions would adequately address the identified concerns with local valve operation and indicatio (3) During a walkdown of the remote shutdown panels, the operators demonstrated a detailed knowledge of the systems and procedures used to shut down the plant from outside the control room. The operators had reviewed the systems and had walked through Procedure OP-C.13A, "Remote Shutdown," during their training periods. The team was concerned that the licensee had apparently never tested the remote shutdown panel capability as described in Regulatory Guide 1.68.2, "Initial Startup Test Progre.m to Demonstrate Remote Shutdown Capability for Water Cooled Nuclear Power Plants." Previously, only component tests were performed to demonstrate the operability of the system. The l licensee had not demonstrated the ability to integrate the operations for I all systems used for maintaining control of the plan j During the inspection, the licensee committed to test portions of the remote shutdown system during the power ascension test program after the i trip from 25% power. An STP will be developed utilizing portions of pro- l cedure OP-C.13A to demonstrate the; (a) operability of the EFIC system controls and indications under closed loop conditions, l
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(b) relationship between EFIC and non nuclear instrumentation (NNI)
steam generator level and pressure control, (c) response time from EFIC initiation to the required AFW flow of 475 l gpm to the OTSG is achieve l Additionally, the test will otablish inventory control and primary-to- !
secondary plant beat transfer from the remote shutdown panels. This proposed testing was submitted to NRC for review by SMUD letters GCA 88-029 dated January 25, 1988 and GCA 88-061 dated February 8,1988. The NRC is currently reviewing these submittal ,
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3.3.3 Plant Testing Program
' 4 The inspection team reviewed the System Review and Test Program (SRTP) testing evolutions in progress to determine whether adequate operator involvement and control were being implemented outside the control room. The licensee completed hydrostatic testing of both OTSGs and performed portions of STP 961,
"Loss of Offsite Power Test." The following observations, made during the-23-
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first onsite inspection, indicate that the licensee was not maintaining adequate control over plant testing activities:
(1) Test clearance tags were only used for tests at the discretion of the Shift Supervisor. During STP 961, racked out distribution breakers were not tagged and a complete copy of the test procedure was not in the control room. This practice left the operators without documenta-tion in the control room of abnormal equipment status. The team was concerned that this practice increased the potential for damaged equipment and personnel injuries. Delays and changes in test sche-duling would increase the risk that later shifts were unaware of system status, and could result in operating error (2) During the OTSG secondary hydro' static test, drawings defining system test boundaries were not in control room. The team was concerned that the control room operators may not have been adequately prepared to expeditiously respond to a test problem because they were not aware of system boundaries. The control room operators did have a copy of the procedure that described the boundaries and the test director did have a drawing identifying the system boundaries in the test control cente (3) An event occurred on December 16, 1987 during STP 961 that revealed apparent comunication and cocrdination problems between operators and the testing group. During the test, a minor oil leak developed on Emergency Diesel Generator GEB? requiring the test to be stopped. There appeared to be confusion between the control room operators and test director in the diesel room on how the test should be aborted. As a result, Emergency Oiesel Generator GEB2 was paralleled with offsite power when still in the sochronus (SFAS) mode which resulted in the generator assuming its maximum load (3300 KW) from offsite power. Subsequent operator action to reduce the load resulted in the generator reversing power to approximately 150 KW. Finally, the emergency diesel generator was tripped by a test engineer without direction from the control roo After the emergency diesel generator overpower and reverse-power event, the licensee issued a stop work order for all testing. A thorough investigation of the problem was initiated and changes to policies for operator involvement in the testing programs were implemented. The results of this investigation and corrective actions are discussed further in Section 3.3.4 of this report. The inspection team was unable to observe any further tests during either onsite inspection period because the licensee stopped work until corrective actions could be fully implemente .3.4 Loss-of-Offsite-Power Test (STP 961) Events During the second onsite inspection period, the inspection team reviewed the licensee's investigation and corrective actions in response to the recent events that occurred during STP 961. The following investigations of events were reviewed:
(1) On December 16, 1987, the team observed Emergency Diesel Generator GEB2 first exceed its load rating and then reverse power before being-24-
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tripped as described in Section 3.3.3(3) of this report. The investiga-tion identified the following problems:
(a) insufficient guidance by operations and SRTP management for test <
program performance (b) inadequate knowledge by operators of emergency diesel generator control logic (c) deficiencies with applicable operating and test procedures for loss-of-offsite-power testing (d) inadequate test briefing which did not discuss potential problems and possible courses of action '
(e) poor communications between test engineers in diesel room and control room operators (f) incorrect processing of revisions to the test procedure The team found that this investigation was thorough ac comprehensiv The System Review and Test Group (SRTG) Action Plan was developed to improve the quality of testing being conducted onsite. Licensee manage-ment stopped all testing from the time of the event until January 4, 1988 to develop and implement the SRTG Action Plan. Because of problems with the emergency diesel generators, STP 961 was not resumee until January 28, 198 (2) On February 3, 1988 at 11:10 p.m., operators inadvertently omitted a step in the test procedure to block the start feature for Emergency Diesel Generator GEA upon loss of the 4A bus. When the 4A bus was later deenergized for the test, Emergency Diesel Generator GEA started because '
of low bus voltage. The output breaker did not shut because it was racked out #3 the test and the diesel operated for a few minutes without auxiliary support systems. The licensee determined that the cause of the event was operator error and resumed testing at 11:20 p.m., on February 3, 198 Training and procedures were to be reviewed with each shift when they arrived for dut (3) On February 4, 1988 at 2:00 a.m., the Emergency Diesel Generator GEA2 output breaker failed to close as expected during testing because a mispositioned test disconnect switch was found open from a test performed in November 1987. The licensee determined that this problem was caused by incorrect control of test switch position. The switch was repositioned '
and other test switches applicable to the test in progress were checked for proper position. Testing was resumed at 3:00 a.m., with parallel corrective actions initiated to check all test switch positions and tag STP 961 test lead (4) On February 4, 1988 at 3:37 a.m., Emergency Diesel Generator GEA2 failed to shut down when a stop signal was initiated. The diesel began the stop sequence but restarted and was finally shut down using the emergency stop function. This problem was caused by the manual operation of a circuit test switch by an operator, which blocked the stop signal. Operator training had incorrectly indicated that test switch operation should not-25-
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affect the shutdown cycle, when such operation actually blocked the shutdown signa (5) On February 7,1988, when opening all SFAS MOVs, approximately 1100 gallons of potentially contaminated water was drained from the borated water storage tank (BWST) through the lower reactor building spray ring into the reactor building. This problem was caused by an incorrectly positioned manual valve in the spray line which should have been shut to prevent gravity drain from the BWST when all the SFAS MOVs were opene l The valve had not been properly repositioned after a recent surveillance l test and operators had not verified system lineups properly before starting the loss-of-offsite-power test After the event on February 7, 1988, the licensee stopped all testing until an effective corrective action program could be implemented. Licensee management was concerned that previous programs were not correcting the root cause of the', ;
problems and that the working level operators were not convinced that they were '
part of the proble ~
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As a result of these concerns, the Operations Management Action Plan was developed by the Shift Supervisors and Assistant Shift Supervisors to improve the quality of operations and testing. This plant addressed a goal of zero personnel errors and identified the following areas for improvement- 1 i
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comunications between operations management and shift management
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on-shift organization, schedule and responsibilities
professionalism in the control room
attention to detail
personnel accountability
supervision in the field and coordination with control room
procedure quality and compliance
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operations surveillance procedure conduct and work planning equipment status control l
operations department morale and attitude i The inspection team reviewed tne action plan and found it to address the problems that were apparent from the events and previous inspections. However, the team was not convinced that this plan would be successful at correcting all the root causes for problems at Rancho Seco. In particular, the team was concerned that j these types of problems also existed in organizations outside the Operations '
Department. Licensee management acknowledged this concern and noted that similar programs were being initiated by all departments but not with the priority sche-duling of the Operations Departmen .3.5 Operator Training Program The inspection team reviewed the licensee's operator training program to determine its effectiveness for conducting modifications training end the adequacy of system training manuals. The following observations were made of these activities:
(1) The EFIC system training lesson plans were well organized and had clear objectives and good graphics. The training on the EFIC system was extensive, including classroom instruction and simulator drill '
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(2) A requalification training class was attended by the inspector. The class covered modifications and alanns to indicate auxiliary feedwater pump runout, and procedures covering HVAC and instrument air system The instructors were well prepared and training was conducted in an organized and professional manner. Excellent interaction between the instructors and operators was also observe (3) The team reviewed the licensee's process for getting industry experience into operator training programs. All l.ERs, NRC information notices, NRC bulletins, INPO reports and occurrence description reports (00Rs) were sent to the Training Department. The Training Department followed the guidance in its procedures for assistance in determining how an issue should be addressed in training. Information was provided by reading assignments, briefings or formal classroom training, and all methods '
were formally documente I
(4) The system training manuals were being revised and tighter controls to
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prevent misuse of outdated training manuals were already implemente Procedures required system manuals to be reviewed after each refueling !
outage and revisions to be issued within 90 days after restar (5) The team reviewed the nuclear service raw water (NSRW) system training manual and walked down part of the system. The team found that the training manual accurately described system configuration. Additionally, the training manual properly described the new method for ensuring that the NSRW was flow balanced. This new method utilized a portable flow meter to adjust throttle positions and then locked the valves. The old 1 method balanced flow by repositioning valves to a predetermined position l identified by a number of turns on the handwheel. The NSRW system could not be accurately flow-balanced using the old method. The team also verified that the system alignment procedure contained a precaution to leave NSRW system flow balancing valves undisturbed while valve position was being verifie .4 Design Change and Modifications_
The inspection team conducted an in-depth review of the licensee's program for closing out Engineering Change Notices (ECNs) to detennine whether the design was properly implemented 'in the plant. The ECN development process was previously evaluated during inspections 50-312/86-41 and 50-312/87-29. The team reviewed design change packages, conducted a walkdown of a modified system and audited
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proper distribution of controlled drawings to make an evaluation of the design change process. The team found no problems with the administration of the closecut process; however, deficiencies were identified with the followup resolution of nonconforming reports (NCRs).
3. Design Change Package Reviews The inspection team reviewed the governing procedures and selected ECN packages listed in Appendix B to this report. The following observations were made concerning this review:
(1) The procedures reviewed appeared to adequately address the design closecut proces . _ _ _ _ _
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l (2) All packages reviewed appeared to have been properly assembled and to contain supporting documentation to demonstrate proper implementation of )
the modification j (3) Five implementing maintenance work requests were reviewed for proper administrative reviews and proper technical guidance. No discrepancies were identifie (4) Pertinent procedures were updated and operator training was conducted before the system became operational for testin (5) The required changes to the Technical Specifications and Updated Safety Analysis Report (USAR) were initiated for all modifications reviewe (6) A total of 22 NCRs, issued to resolve final walkdown deficiencies, were reviewed and 3 had been closed out prematurely. This issue is discussed further in Section 3.5.1 of this repor .4.2 Modified System Walkdown The inspection team walked down portions of the AFW system to determine whether the emergency feedwater initiation and control (EFIC) system had been properly modified. The system configuration appeared to be in agreement with the "as-built" drawings identified in the respective packages. During the walkdown, the team found several local valve position indicators that were not properly aligned with the remote position indication. This issue is discussed further in Section 3.5.4(3) of this repor . Drawing Control The team selected drawing changes issued as a result of the ECNs and verified that the latest revisions were posted in the control room and the drawing control librar Additionally, the team verified that the current drawing revision was listed on the computerized printout of effective drawings. No deficiencies were identified during this revie .5 Corrective Action Programs ,
The inspection team reviewed the licensee's corrective action programs to ;
detennine whether adequate measures existed for identifying, tracking and '
correcting conditions adverse to quality. This review encompassed the programs for nonconforming reports (NCRs), occurrence description reports (00Rs) and corrective action requests (CARS). Additional programs were in place to manage j the resolution of specific problems identified during the various special !
reviews conducted during the outage. The team did not review these special i programs, concentrating instead on the programs needed to support an operating l plant. Initially, it appeared that these corrective action programs were not ready to support an operating plant; however, increased attention by the licensee before the end of the inspection appeared to make them viable, i Additionally, the licensee developed a more effective overall corrective action l program that will be implemented before restar . Nonconfonning Reports (NCRs)
The NCR program was reviewed to determine whether identified deficiencies were-28-
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adequately tracked and corrected. NCRs were issued to identify material or equipment deficiencies. Procedure QAP-17. "Nonconforming Material Control,"
Revision 7, provided the latest guidance for processing NCRs and had been revised 4 times during 1987. The procedures were revised to recognize new responsibilities of the CAR Program for significant conditions adverse to quality and the Quality Trending Program for identifying the root cause of problems. The shifts in responsibility for closecut of NCRs apparently caused some confusion among systems and quality engineers, so that NCRs were being closed before the corrective action was completed. The tcam identified the following examples where NCRs were closed out before complete implementation of the corrective action:
(1) NCR 56053, dated June 8,1987, cor.cerned drawing deficiencies associated with 14 MOVs and identified the resolution as revising the subject drawings. It appeared that the NCR was closed out on July 2, 1987 although one drawing identified in the NCR still had not been revised at the time of this inspectio (2) NCR S7023, dated October 13, 1987, identified deficiencies with an emergency diesel generator fuel oil piping line and specified perfor-ming a hydrostatic test of the fuel oil line as part of the resolutio A nitrogen gas pressure test was substituted for the hydrostatic test, but the NCR was not revised to reflect this change. The NCR was subse-quently closed on December 11, 1987 even though the proposed resolution differed from the test actually performe (3) NCR 57295, dated October 23, 1987, identified deficient ECN drawings that required 4160 Vac cables to be routed with control and low-voltage power circuits. The NCR was closed on December 8, 1987 although the ECN package was not closed out at the time of the inspectio The inspection team concluded that these findings were examples of implementa- l tion problems with licensee procedures. Paragraph 5.2.9 of Procedure QAP-17 required that all dis wsition actions be completed before final closecut by the Quality Engineering 5roup. It appeared that this was not occurring in all instances. This issue was subsequently followed up by NRC Region V and Violation 50-312/87-44-01 was issue .5.2 Occurrence Description Reports (ODRs)
The inspection team reviewed approximately 75 ODRs issued during the period June - December 1987. The licensee used ODRs to document procedure and imple-mentation problems that occur in the plant and as the principal mechanism for identifying potentially reportable events. As such, this program was main-tained by the Licensing Department. The team identified a trend of repetitive problems with ODRs in the areas of valve misalignments, failure to follow procedures and inadequate system clearances. These repetitive problems appeared similar to deficiencies identified by the team during the inspection and to causes of the events discussed in Section 3.3.4 of this report. The team was concerned that adequate corrective actions were not being taken for the ODRs and that this program was being used primarily for reporting purpose _ -____-_-________ ___.
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3.5.3 Corrective Action Requests (CARS)
During the first onsite inspection period, the team reviewed the CAR Program as implemented during 1987 to determine its effectiveness at correcting signifi-cant conditions adverse to quality and preventing their recurrence. As described in Proceoure QAP-27, "Corrective Actions," Revision 3, the purpose of issuing a CAR was to obtain corrective action for a significant programmatic deficiency that required direct involvement of senior management. Procedure QAP-27 required, among other things, a determination of reportability and that applicable SMUD management respond to QA by an assigned date. In the seven CARS reviewed by the team, three either had late or no responses without explanation and four were not evaluated for potential reportability. The team concluded that the CAR Program, as implemented in 1987, was not adequate to ensure that future significant conditions adverse to quality would receive proper attentio During the second onsite visit, the team reviewed the CAR Program as imple-mented during the first two months of 1988 and noted a significant improvement in the quality of issues, responses, and corrective actions taken for the 10 identified CARS. The licensee had revised Procedure QAP-27 (Revision 4) to better categorize thresholds for the issuance of CARS and the team found issues identified by CARS that were similar to concerns being identified by the NRC and plant events. These issues included the questionable quality of safety-related materials installed in the plant (CAR 88-04), maintenance and modifica-tion activities not being conducted in accordance with approved drawings (CAR 88-05) and problems with plant drawings (CAR 88-06). The team was encouraged by the improvements made in the CAR Program, but remained concerned whether this program would continue to receive adequate attention after restar The team disagreed with the scheduled resolution of CAR 88-07 concerning the qualification status of several safety-related MOVs. Apparently, maintenance personnel had been removing unused limit switch cartridges from four-barrel limit switch assemblies in installed MOVs and were using them in other MOVs when defective cartridges were found. This practice left the drive gear for the removed cartridge exposed atd could allow limit switch grease to leak from the assembly. The licensee had correspondence from the M0V vendo Limitorque Inc., indicating that this configuration of the limit switch ,
assembly had not been environmentally qualified at its laboratory. The '
licensee had performed some preliminary tests to convince themselves that the configuration was sufficiently qualified to last until the next outag :
The inspection team did not agree that the limited testing performed by the licensee was adequate and concluded that the missing cartridges should be replaced before restart. The licensee agreed to resolve this issue before restart by either replacing the switches or completing the qualifi-cation of the modified assemblies. Further investigation by the licensee revealed that some of these switch cartridoes had been removed in 1983 and that the plant had previously operated in this configuration. On the basis of this finding, NRC Region V took the lead to followup the issue to deter-mine whether the licensee had previously violated 10 CFR 50.49, "Environmental )
Qualification of f.lectric Equipment important to Safety for Nuclear Power Plants."
3.5.4 QA Trending Program During the initial onsite inspection, the team reviewed the implementation of Procedure QAIP-16, "Trend Analysis Program," Revision 1, to determine the-30-
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licensee's effectiveness at identifying the underlying causes for station problem Since the program was implemented, only one trend report had been issued (October 28,1987). This report identified the following four trends:
- cable and termination problems
- operator and valve deficiencies
' snubber testing procedure inadequacies
- procedure, specification and drawing noncompliances The team had the following concerns about this report and the overall QA trending program:
(1) Not all forms of deficiency reporting were considered in the statistical analysis conducted to determine the abnormal trends. Data for non-QA deficiencies such as ODRs were not considered. Apparently, these defi-ciencies were trended by the Licensing Department, but the results were not compared or incorporated with the QA trending result (2) Trends identified by the report were not investigated thoroughly to determine whether a root cause existed. In fact, the report appeared to make excuses for the following trends:
(a) The trend with valve operators was dismissed because "MOV problems are an industry-wide problem area that is not unique to any particu-lar plant." The team did not consider this disposition to be an acceptable reason for not pursuing the issue further. However, the trend report did note that there was a refurbishment program in progress to correct MOV problem (b) The trend with the snubber testing procedures was identified as indicating "the possibility of a situation adverse to quality " but was dismissed because the procedure deficiencies had no detrimental effect on the hardware. The team was concerned about this attitude because the purpose of the trending program was to discover problems before they damaged hardwar (c) The procedural noncompliance trend was dismissed because most of the problems identified were the result of work performed in the past and didn't reflect the current situatio The trend report did state that such problems would be monitored closely in the future, but this monitoring did not appear to be occurring. The inspection team identified similar problems in the maintenance, operations and surveillance testing area (d) The trend with the cables and terminations was dismissed from further action because it was the result of numerous plant walkdowns. The team egreed that a program was established to correct these problems but concluded the licensee should have determined the root cause and evaluated the need for additional corrective actio (3) The trending program did not detect the problems with MOV local valve position indication that the team found throughout the plant. During the l
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walkdown of the auxiliary feedwater system and general tours of the plant, the inspection team found several MOVs that appeared to have damaged or misaligned local valve position indicators. The licensee had previously identified these deficiencies on NCRs, surveillance test procedures, deficiency tags and as contributing causes for events on ODRs, yet no action had been taken to correct the problems. In fact, as described in Section 3.3.2(2) of this report, it appeared that operators were violating their procedures to accommodate the lack of reliable local valve position indication. When this issue was raised with operations management, they confirmed that reliable local valve position indication was required for several of the deficient MOVs and a program was started to resolve this ,
issue before restart, as discussed in Section 3.3.2.(2) of this repor '
The inspection team concluded that the trending program was not being implemen- !
ted in a manner capable of identifying underlying trends for plant problems, i Additionally, the separation of management for the ODR and NCR programs between the Licensing and Quality Departments appeared to limit the data base for ;
identifying trends and prevented realizing potentially significant deficiencies, l When the team returned for the second onsite inspection, there was a noticeable improvement in the quality of the trend programs and CARS were being initiated based on repetitive problems. There still seemed to be a lack of coordination between ODRs and NCRs but the licensee appeared to be implementing a new program as described in Section 3.5.5 of this report which would improve the trending program in this are .5.5 Potential Deficiency in Quality (PDQ) Program During the inspection, the licensee determined that its existing scheme of corrective action programs was frag aented and did not facilitate good com-munications of issues requiring resolution. In response to this determination, the licensee developed the PDQ Program to improve the effectiveness of its corrective action programs. This program had the following characteristics:
(1) utilized a single source document for problem identification which super-seded both NCRs and ODRs (2) designated the Operations Department to screen deficiencies, detennine initial corrective actions and assign followup action to other departments (3) designated the Quality Department to track, trend and verify closure of identified deficiencies (4) designated the Licensing Department to evaluate deficiencies for repor-tability and to investigate the root cause for events, and significant deficiencies (5) provided feedback to the PDQ originator to ensure that initially identified concerns were resolved adequately The inspection team reviewed the proposed program and determined that the PD0 Program could offer considerable improvements over existing corrective action programs if it were properly implemented. The licensee comitted to imple-ment this program before restar . . - _ - _-. . -. --
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3.6 Quality Assurance (QA) Programs The inspection team reviewed the QA Surveillance, QA Audit and QC Inspection l Programs to detemine whether the licensee was aggressively looking for problem During the first inspection, the team found that these programs were not always aggressively managed and, as a result, management was not aware of weaknesses in the station. On the second site visit the team found that the ;
QA Surveillance and QC Inspection Programs had been significantly improved and l the licensee had established a Management Observation Program to ensure that managers directly viewed their organization's performance. Because of these new and enhanced programs, the team concluded that the licensee was aggres-sively searching for problems and related solution .6.1 QA Surveillance Program During the first onsite period, the inspection team reviewed the licensee's QA Surveillance Prrgram and concluded that it was not oriented towards ensuring that the plant was ready to operate. Apparently, three of the four personnel assigned to the QA surveillance Group were temporarily transferred to line departments to assist with closing out problems. A review of the surveillance reports issued during the fourth quarter of 1987 revealed that most were status reports of previous problems or document reviews. There were very few perfor-mance observations in key areas such as maintenance, testing and operation In view of the problems identified by the inspection team in these areas during this inspection, the scaling back of the surveillance effort just before plant mode change appeared to be contrary to the best interests of plant safet During the second onsite inspection period, the team found an improved QA Surveillance Program. Staffing levels were increased to include five full time inspectors and one supervisor and the licensee had completed approxi-mately 90 QA surveillances during calendar year 1988. The team found the quality and scope of the surveillances to be responsive to identifying concerns for plant heatup and startup. Corrective actions identified and taken for the identified deficiencies also appeared to be adequate. The team concluded that the QA Surveillance Program implemented by the licensee during 1988 was capable of supporting an operating plan .6.2 QA Audit Program The QA Audit Program was reviewed to verify audit compliance with Technical Specifications, effectiveness of corrective actions, and followup of those actions by the Quality Department. This area had been previously inspected during inspections 50-312/86-41 and 50-312/87-29. The implementation of the Quality Assurance Audit Program appeared to remain satisfactor .6.3 Quality Control (QC) Inspection Program The inspection team reviewed the QC Inspection Program to determine its effec-tiveness at ensuring quality in maintenance, modification and testing activi-ties within the plan During the first i spection period, the team identified a significant concern with the manner in wnich a QC inspector was observing hold-points during naintenance on "B" HPI pump [see Section 3.2.1(3)]. Further observations of QC coverage during testing and maintenance activities convinced the team that overall QC coverage was adequate within the plant and that the
"B" HPI pump maintenance coverage was an isolated cas ___ - _ _ _ _ _ _ _ _ _
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During the second onsite inspection period, the team found an improved QC Inspection Program that included both the normal QC verification activities and a new field inspection program. The QC Field Inspection Program required inspectors assigned to a particular job to evaluate other aspects of the jo These aspects included planning, radiological control practices, procedural adequacy and compliance, and general job performance characteristics. These findings were recorded on a single page with amplifying information, forwarded to the responsible organization for action and recorded in the Quality Department computer for trending. Monthly, the Quality Engineering Group trended the field inspection findings and when degrading trends were identi-fied, a QA surveillance was scheduled to further investigate potential problem Since the program was established in Decenber 1987, the licensee had perforced more than 1400 field inspections and had identified two trends that required followup. These trends were in the areas of maintenance procedure adequacy and job planning. The team concluded that the QC Field Inspection Program constituted an innovative approach to identifying plant problems and contributed to overall plant safet . Management Observation Program On January 21, 1988, the licensee implemented a Management Observation Program that required managers to assess the performance of their organizations at least monthly by observing ongoing activities in the field. The observations made during these activities were to be provided directly to subordinates and were also recorded on observation forms for trending and further evaluation The team reviewed the completed observation forms and found them to be thorough and honest appraisals of plant activities. Interviews with licensee managers revealed that observations made during this program alerted them to the types of problems being encountered in the field and provided input for the Operations Management Action Plan. The team concluded that this program contributed significantly to plant safety by increasing management's awareness of the quality of ongoing activities, i
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. . - MANAGEMENT EXIT MEETING An interim exit meeting was conducted at the conclusion of the first onsite inspection period on December 18, 1987. The licensee representatives at the exit meeting are identified in Appendix A. Mr. J. B. Martin, Regional Administrator, Region V, represented NRC management at this meeting. The scope of the inspection was discussed and team members presented their findings and answered the licensee's questions. The licensee was informed that a second !
onsite inspection period would be scheduled to review station activities during >
hot functional testin On February 17, 1988 a final exit meeting was conducted at the concinion of l the second onsite inspection period. The licensee representatives at this I exit meeting are indicated in Appendix A. Mr. G. M. Holahan, Assistant Director of Projects for Regions Ill/V, NRR, and Mr. R. Zimerman, Chief, Reactor Projects Branch, Region V, represented NRC management at this meetin The s: ope of the inspection was discussed and the licensee was informed that the inspection would continue with further in-office data review and analysis by team members. Team members pretented their observations from the second !
onsite inspection period; the presentation included the status of previous j findings and new 13 sue The team members also responded to questions from licensee representatives. The licensee was informed that some of the observa-tions could become potential enforcement findirigs.
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APPENDIX A Personnel Contacts *
Y. Able Operations M. Aikens EASRTP P. Anderson Maintenance
- C. Andognini CEO, Nuclear S. Baker Quality Assurance J. Baldauf Design Engineering J. Baldwin EASRTP M. Basu Design Engineering R. Betes Maintenance J. Behen Systems Engineering
- E. Blackwood Licensing L Bliss Maintenance
!*D. Brock Mcnager, Maintenance Department A. Brown Maintenance C. Buchanon Document Control G. Clefton Maintenance J. Cole Maintenance Q. Coleman Quality Assurance
- D. Compton Licensing D. Comstock Operations M. Cooper Operations J. Cork Operations
- G. Cranston Manager, Nuclear Engineering Department
- R. Croley, Assistant General Manager, Nuclear
- S. Crunk Manager, Licensing Department X. Davis Systems Engineering ,
R. Deay SRTG '
- J. Delezinski Licensing R. Dobson Maintenance D. Elliot Quality Assurance D. Falconer Licensing
- S. Farkas Licensing'
X. Farris Maintenance J. Field Systems Engineering
- J. Firlit Assistant General Manager, Nuclear
- J. Flynn Manager, Plant Performance Department
- L. Fossum Manager, Scheduling and Outage Management
- A. Gehr Nuclear Advisory Conmittee Department J. Gibson EASRTP P. Grod Operations M. Hardin Maintenance S. Harris Design Engineering J. Hayes Design Engineering H. Heckert Plant Performance T. Himber Operations J. Irwin Systems Engineering L. J6u EASRTP C. Jindal Design Engineering
- Attended Final Exit, February 17, 1988
- Attended Interim Exit, December 18, 1987 A-1
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APPENDIX A - (Continued)
Personnel Contacte :
P. Johnson Maintenance J. Kearns Document Control J. Kelly Design Engineering
- W. Kemper Manager, Operations Department
- D. K, uter Director, Nuclear Operations and Maintenance J. Koontz EASRTP
- G.Legner Licensing B. Lennox Operations
- S. Levy Nuclear Advisory Comittee J. Lucas Maintenance P. Martin Operations D. McIntire Training M. Meridith Operations D. Moreana EASRTP D. Morgan Maintenance E. Murphy Licensing K. Myers Maintenance R. Nagel Training J. Naleway Design Engineering B. Nash Operations R. Nossardi Design Engineering M. Parenteau Quality Assurance T. Parker Quality Assurance
.
E. Pfister Systems Engineering M. Price Maintenance A. Ray Quality Assurance :
- S. Redeker Operations S. Reed Operations J. Reynolds Operations D. Rice Systems Engineering B. Sanders Operations R. Savoie Design Engineering J. Scheffler Operations
- D. Schuman Licensing P. Schwartz Training F. Sheehan Design Engineering i
- J. Shetler Manager, SRTG l
- T. Shewski Quality Assurance i W. Stahl SRTG
- F. Stock Licensing D. Stockton Operations B. Supremo Design Engineering T. Telford Design Engineering '
- B. Thomas Public Affairs
- D. Tipton Operations R. Tomchuk Materials Management
- Attended Final Exit, February 17, 1988
- Attended Interim Exit, December 18, 1987
A-2
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i APPENDIX A .(Continued)
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Personnel Contactai T. Tucker Operations P. Turner Manager, Training Department
- J. Vinquist Director, Quality Assurance ,
R..VonEschen EASRTP J. Wheeler Maintenance D. Wiles Maintenance L. Wittrup Systens Engineering
- G. Yelliot, Manager Procedure Development 1 P. Zelmer EASRTP
- Attended Final Exit, February 17, 1988
- Attended Interim Exit, December 18, 1987 '
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l APPENDIX B Procedures Reviewed AP-2,30, Revision 0, "Routine Test Procedures, Description and Fonnat" AP-3A, Revision 1, "Daily Work Schedule" AP-48, Revision 4 "Test Authorization Procedure" AP-18, Revision 2, "Plant Housekeeping and Inspection" j AP-19, Revision 4 , "Plant Performance Monitoring, Testing and Inspection" l AP-22, Revision 12. "Occurrence Description Reports" AP-23.17, Revision 0, "Independent Verification" AP-35, Revision 2, "Tools and Equipment Control" AP-44, Revision 12. "Plant Modifications - ECN Implementations"
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l AP-44, Revision 13 (draft), "Plant Modifications - ECN Implementations" i AP-46, Revision 4, "Control of Vendor Technical Manuals" !
AP-65, Revision 0, "Routine Test Procedures, Description and Format" AP-80, Revision 0, "Training of Technical Support Test Personnel" i AP-90, Revision 1, "Work and Test Authorization Program" AP-98, Revision 1, "ECN Punchlist" AP-303, Revision 12, "Surveillance Program" i AP-303.03, Revision 0, "Exemption Request for Surveillance Procedures" l AP-303.04, Revision 0, "Cress Index of TS and SPs" !
EM.161, Revision 2, "Station Battery Charger Routine" EM.187, Revision 2 "Control of Electrical Plant Modifications" GEG.500, Revision 0, "Guidelines for Updating Controlled Manuals" I-011, Revision 3, "General Calibration Procedure" I-014, Revision 2, "General I&C, Maintenance and Surveillance Guidelines" I-032, Revision 4, "Monthly Auxiliary Feed Pump P-318 and P-319, and AFW Flow Indicator Operational Verification Test" I-038C, Calibration Procedure for Loop Calibration Auxiliary Feedwater Flow, FT-31850" I-655A & B. Revision 0, "HVAC Beta Monitor Calibration" MAP-0002, Revision 0, "Control of Maintenance Activities" MAP-0006, Revision 1, "Work Request Planning" MAP-0007, Revision 0, "Maintenance Material Control" l MAP-0008, Revision 0, "Calibration and Control of Measurement and Test Equipment" MAP-0009, Revision 1, "Preventive Maintenance Program" M 103, Revision 2, "Valve Inspection and Maintenance" M.181, Revision 0, "Fisher Series EC and ES Control Valve Disassembly, Repair and Reassembly" M.182, Revision 0, "Fisher Series DBQ Control Valve Disassembly, Repair and Reassembly" M.183, Revision 0, "Fisher Type 667 Diaphram Actuator Disassembly, Repair and Reassembly" M.184, Revision 0, "Air Operated Flow Control Valve Maintenance FV-20525, FV-20526" l
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Procedures (cont)
M.185, Revision 0, "Maintenance Procedure for Air Operated 12" Butterfly Valves SFV-46014, SFV-46204, and SFV-53610" M.188, Revision 0, "Air Operated Flow Control Valve Maintenance SFV-24013" MP/IS 102, Revision 0, "Establishment and Control of Modification and Inspection Standards" MP/IS 105, Revision 0, "Removal and Storage, Shipment, or Disposal of Permanent Plant Equipment, Components, or Devices" MP/IS 107, Revision 0, "Training" '
MP/IS 114, Revision 0, "Non-Conforming Reports" MP/IS 115, Revision 0, "Work Requests" NEAP-4126, Revision 0, "Master Equipment List Validation" NEAP-4304, Revisiion 0, "Identification of Safety-Related Items" NEAP-4801, Revision 0, "MOV Design Process" NEP-4109, "Rancho Seco Configuration Control" QAP-2, Revision 3 "Design Control" QAP-17. Revision 4, "Non-Conforming Material Control" QAP-17. Revision 5, "Non-Conforming Material Control" QAP-17, Revision 6 "Non-Conforming Material Control" QAP-17, Revision 7, "Non-Conforming Material Control" QAP-26, Revision 3, "Test Control" QAP-27, Revision 3, "Corrective Action" 0AIP :6, Revision 1, "Trend Anaylsis Program" ( " 27, Revision 0, "Maintenance / Modification Planning" Q, .,1801, Revision 1, "Quality Assurance Internal Audit" QAIP-1804, Revision 0, dated December 4,1987 "Ouality Assurance Surveillance Program" QAIP-1805, Revision 0, "Qualification Requirements for Auditors and Sur-veillance Personnel" RP.305.7, Revision 0, Radiation Control Manual, "Area Definitions, Posting, and Requirements" RSAP-0803, Revision 3, "Work Request" RSAP-0807, Revision 0 "Maintenance Test Program" RSAP-1301, Revision 0, "Corrective Action Program" RSAP-1306, Revision 0, "Audits and Surveillance" SP-18, Revision 0, "Quarterly at Cold Shutdown Cneck Valves Full Stroke Test" SP-20, Revision 0, "Monthly Turbine / Motor Driven Auxiliary Feedwater Pump SP-318 Inservice Test" ;
SP-21, Revision 0, "Monthly Motor Driven Auxiliary Feedwater Pump P-319 l Inservice Teat" SP-26, Revision 0, "Refueling Interval Main Feedwater System Test for EFIC Actuation" SP-27A, Revision 0, "Monthly and Prior to Any ECCS Flow Tests, HPI Pump SP-238A Venting Surveillance" SP-29A, Revision 0, "Monthly Decay Heat Removal Pump A Venting i Surveillance" B-2
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0A Surveillance Reports 88-S-03 88-S-20 88-S-41 88-S-80 88-S-186 88-S-15 88-S-31 88-S-71 88-S-92 Vendor Technical Manuals M5.06.IM01 M16.01-41 M17.02-IM02 M27.04-45 M5.06-IM'^ M17.02-103 M17.02-IM05 M29.03-lM01,75 N29.03-Di10 M30.01-27 N7.02-22 M29.03-1M21 M30.01-27,13 N7.02-23 Work Requests 1398520 1400740 1358820 1328310 1356160 1253890 1368230 1389390 140392A 1394420 139610A 1398890 1378340 1377500 1400970 139440A 139611A 138957A 1385670 1404550 1359140 1356180 1398880 1413510 1391570 1396350 1397110 1397100 1181120 1372460 1435460 1403890 1255650 1255660 1218310 1217300 1292190
SMU0 Drawings E-208 E-105 E-107 E-108 E-203 E-206 E-208 i E-209 E-228 E-1011 M-503 M-504 M-510 M-522
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M-524 M-525 M-527 M-543 M-551 M-552 M-561 M-563 M-570 i
Quality Assurance Surveillance Documents l l
Quality Assuance Surveillances for October 1987 - February 1988 i QA Surveillance Checklist-Operations QA Surveillance Checklist-Maintenance / Modification ;
Quality Assurance Surveillance Plan 1988, JVV 87-151, dated December 2,1987 !
Quality Surveillance Schedule December 1987, QLC 87-048, dated December 2,1987 l
Non-Conforming Reports S-7008 S-7009 S-6872 S-6555 S-6385 S-6570 S-6644 S-7281 S-7384 S-6053 S-7272 S-7295 S-7422 S-6762 i S-7181 S-7219 S-7225 S-7263 5-7285 S-7287 S-7311 S-7295 S-6348 S-5770 S-6405 S-6053 S-6712 S-6867 l S-6085 S-6389 S-6360 S-5795 S-5990 5-6106 S-6152 Corrective Action Reauests i 87-002 87-004 87-005 87-006 87-007 87-008 87-009 and 38-001 through 88-010 B-4 l
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Procedures (cont)
SP-318, Revision 0, "Quarterly DHS Valve Test and Inspection at Shutdown" SP-33A, Revision 0, "Quarterly Nuclear Service Cooling Water System Loop A Surveillance" SP-348, Revision 1, "Quarterly Nuclear Service Cooling Water System Loop B Surveillance and Inservice Test" SP-39, Revision 0, "Cold Shutdown Core Flood System Surveillance" SP-41A, Revision 0, "Refueling Interval SFAS Digital Channel 1A Test" SP-41B, Revision 0, "Refueling Interval SFAS Digital Channel IB Test" SP-43A, Revision 0, "Refueling Interval Reactor Building Spray System Loop A SFAS Surveillance Test" SP-43B, Revision 0, "Refueling Interval Reactor Building Spray System Loop B SFAS Surveillance Test" SP-60, Revision 0, "Quarterly EMOV Block Valve Test" SP-65, Revision 0, "Monthly Reactor Building Purge Valves Status Verification" SP-66, Revision 0, "Quarterly Makeup and Purification System SFAS Valve Inspection and Test" SP-71, Revision 0, "Quarterly OTSG Sample Isolation Valves Surveillance Test" SP-74, Revision 0, "Quarterly AFW System Valve Inspection and Surveillance" SP-79, Revision 0, "Refueling Outage Concentrated Boric Acid System Valve Surveillance" SP-80, Revision 0, "Quarterly Reactor Building Isolation Valve Stroke Test and Inspection" SP-81, Revision 0, "Quarterly Reactor Building Isolation Valve Stroke Test and Inspection" SP-203.06A, Revision 0, "Quarterly Decay Heat Removal "A" Loop Valve Inspection and Surveillance" SP-203.06C/0, Revision 11 "Quarterly DHS and CBS Valve Test and Inspection at Shutdown" SP-203.05A, Revision 19. "Quarterly Decay Heat Removal Loop "A" Surveillance" SP-213.01, Revision 12,"Inservice Tests and Inspections of Pumps" SP-214.01, Revision 7, "Inservice Testing and Inspection of Valves" SP-214.02, Revision 2 "Inservice Testing of Relief / Safety Valves" SP-322A, Revision 1, "Refueling Interval Nuclear Service Bus 4A2 Voltage Protection Calibration" SP-324B, Revision 0, "Battery BB Service Test" SP-325A, Revision 0, "Battery BA2 5 Years Performance Test" SP-315A, Revision 0, "Refueling Interval Nuclear Service Bus 4A Voltage Protection Calibration" SP-324A, Revision 0, "Batttery BA Service Test" SP-486, Revision 0, "Monthly CR/TSC Ventilation Gas Monitor Test" SP-655, Revision 0, "HVAC Beta Monitor Calibrations - R15701/R15702" SP-618, Revision 0, "Refueling Interval CR/TSC Essential Filtering System" Engineering Change Notices R-2348 A-3748 A-5415 R-0357 A-5233 R-0828 R-0361 R-0717 R-0953 R-0825 R-0164 R-0699 R-0914 R-0824 R-1003 R-1036 R-1300 R-1672 R-0717 B-3
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Miscellaneous Rancho Seco Technical Specifications Quality Assurance Audit 87-20 and associated responses Corrective Action Request Log Quality Trend Report, JVV 87-103, dated October 28, 1987 Inservice Testing Program Update, Second 10 Year Cycle, Revision 3, l dated July 23, 1987 !
NRC Telecopy to SMUD, Pump and Valve Inservice Testing Questions, Second 10 Year Cycle i Computer Listing, IST Requirements of the Updated IST Program, dated '
December 7, 1987 Surveillance Procedure Master Log /Index, undated Surveillance Procedure Status Log, dated December 7, 1987
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i Technical Specifications Surveillance Procedure Program Description, dated i December 7,1987
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