IR 05000277/1989015
| ML20247L657 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 05/18/1989 |
| From: | Linville J, Williams J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20247L653 | List: |
| References | |
| 50-277-89-15, 50-278-89-15, IEIN-88-061, IEIN-88-072, IEIN-88-61, IEIN-88-72, NUDOCS 8906020230 | |
| Download: ML20247L657 (41) | |
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U. S. NUCLEAR REGULATORY COMMISSION
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Docket / Report No. 50-277/89-15 License No. DPR-44 50-278/89-15 DPR-56-Licensee: -Philadelphia Electric Company -
-Correspondence Control Desk P. 0.: Box 7520 ;
Philadelphia, Pennsylvania 19101 '
Facility Name: Peach Bottom Atomic Power Statio'n Units 2 and 3 m .
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l Inspection At: Delta,' Pennsylvania
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Dates: April 2 - May 6,1989:
' Inspectors: .T. P. Johnson, Senior Resident Inspector / Restart Manager R. J. Urban, Resident Inspector
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L. E. Myers, . Resident Inspector J. Gadzala, Reactor Engineer J. H. Williams, Project Engineer D. LaBarge, Licensing Project Manager M. Dev, Reactor Engineer D. Draper, Licensing Examiner Reviewed By: k_
T4(y!11ams , ject. Engineer
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Approved By: i ~
.I/ / ./LW17Te; ~ f, ' 'date R ptor Project tion 2A, ifision of Re t r Projects
- Summary Areas Inspected: Routine, on site regular, backshift and deep backshift resident and special restart team inspection (627 hours0.00726 days <br />0.174 hours <br />0.00104 weeks <br />2.385735e-4 months <br /> Unit 2; 197 hours0.00228 days <br />0.0547 hours <br />3.257275e-4 weeks <br />7.49585e-5 months <br /> Unit 3) of accessible portions of Unit 2 and 3, operational safety, Unit 2 prestartup activities, Unit 2 power ascension and testing, radiation protection, physical security, control room activities, licensee events, survei_11ance testing, Unit 3 refueling and outage activities, maintenance, and outstanding item f,g60gg$$83 7 Q
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. i Summary (Continued) 2 I Results: The licensee completed actions to resolve NRC open items prior to restart (section 3.0). The inspectors assessed readiness for startup and determined that the licensee was adequately prepared for the startup of Unit 2 (section 4.3). Several events were reviewed (section 4.2), including a contain-ment isolation caused by a personnel error due to lack of training and an inad-vertent explosive valve firing due to a procedural inadequacy. Fire protection program deficiencies were noted and are unresolved (section 4.3.17). Initial criticality and training startups were observed (section 4.5). One instance of poor LC0 log keeping was noted (section 4.6). The emergency cooling tower sys-tem was retested satisfactorily (section 5.3). Surveillance testing activities
. were noted to be well planned and executed (section 7.0). One allegation was reviewed (section 13.0). The process for clearing nonconformance report tags and equipment trouble tags is weak (sections 4.3.2 and 4.3.16). Other than the general guidance in GP2, Plant Startup, there is no specific drywell closecut procedural guidance (section 4.3.13).
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l TABLE OF' CONTENTS ^
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Pag <1.0 Person's Contacted............................................. -1 2.0 Facility and Unit. Status..................................... ;3.0 Previous Inspection Item Update.............................. 2 r
. 4.0 Plant Operation's Review....................................... 7 4.1 Operational Safety Verification and Station Tours....... 7; 4.2 Follow-up on-Events......... ...........................
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4.3 Unit 2 Pre-Startartup Veri fications. . . . . . . . . . . . . . . . . . . . . 12 4.4 Engineered Safeguards Features System Walkdown..........
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4.5. Initial. Criticality.and Training.Startups.......... .... 25 4.6' Technical; Specification'LCO Log...................... .. 261 4.7 Power Ascension Oversight and Assessment................ '27 5.0 Engineering 'and . Technical Support Activities. . . . . . . . . . . . . . . . . 28-5.1 LTorus Water Level During.'L0CA........................... ~28
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5.2 Control Room Habitability............................... 29 5.3 Emergency Cooling Tower..................................- 30 6.0 Review of Licen see Event Reports. . . . . .; . . . . . . . . . . . . . . . . . . . . . .
. 31 7.0 Surve111ance Testing......................................... .
- Loss of Off Site Power' Test............................. 32 7.2 RCIC System Testing..................................... 32-7.3 HPCI System Testing..................................... 33 7.4 Routine Surveillance Observations....................... 33 8.0 Maintenance Activities....................................... 34 8.1 Equipment Problems Ouring Unit 2 Startup................ 34 8.2 Routine Maintenance Observations........................ 35 9.0 Radiological Controls... .................................... 36 10.0 Physical Security............................................ 36 11~.0 Assurance of Quality......................................... 37 12.0 Review'of Periodic and Special Reports....................... 37 13.0' Allegation Fo11ow-up......................................... 37
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14.0 Unresolved Items............................................. 38
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15.0 Management Meetings.......................................... 38
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DETAILS 1.0 Persons Contacted
- *C. D. Bruce, Fire System Engineer P. L. Bushek, Supervisor, Independent Safety Engineering Group
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R.- N. Charles, Manager, Performance Assessment Division J. B.' Cotton, Superintendent, Operations
- T. - E. Cribbe, Regulatory Engineer G. F. Daebeler, Superintendent, Technical'
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J. Davis, Peach Bottom Quality Division, Quality Assurance J. Devlin, Nuclear Security Specialist A. Donnell, Superintendent Peach Bottom Quality Division, Quality Services-
- J. F. Franz, Plant Manager
- M. Hammond, Maintenance /I&C Engineer
- G. J. Hanson,- Regulatory R. C. Hirzel, Superintendent Peach Bottom Quality Division, Technical Monitoring R.'Kankus,-Staff Engineer, Peach Bottom Atomic Power Station D. P. LeQuia, Superintendent Services C.-A. McNeill, Executive Vice President,. Nuclear D. R. Meyers, Support Manager
- J. Mitman, Plant Services J. Paquette, Chairman-and CE0 F. W. Polaski, Assistant Superintendent, Operations K. P. Powers, Peach Bottom Project Manager
- J.'M. Pratt, Manager, Peach Bottom QA G. R..Rainey, Superintendent, Maintenance D. M. Smith, Vice President, Peach Bottom Atomic Power' Station Other licensee and contractor employees were also contacte *Present at_ exit interview on site and for summation of preliminary finding .0 Facility and Unit Status 2.1 Unit 2 Unit 2 began the inspection period in cold shutdown. System maintenance and testing were performed during the period. On L April 14, 1989, the Commission voted 3-0 to authorize restart.
p On April 26, 1989, the licensee received authorization from the Region I Administrator allowing the utility to make the reactor crit-ical and to proceed with an approved restart power testing program up to 35% rated power. The modification to the Shutdown Order also marked the beginning of around-the-clock coverage by NRC inspectors.
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At 10:31 p.m., on April 26, 1989, the reactor mode switch was placed {
in startup and at 2:07 a.m., on April 27, 1989, rod withdrawal bega The reactor was critical at 5:44 a.m. The licensee then entered a special procedure to allow their reactor operators to manipulate con-trol rods to take the reactor between subcritical and critical condi- l tions. However, when the reactor was taken critical for the second time at a slightly higher power level, intermediate range monitors (IRMs) C, B and F were not responding. When the problems were pin-pointed to the IRM detectors, the reactor mode switch was placed in shutdown at 8:08 a.m., on April 28, 1989 (see section 4.5).
After successfully repairing two of the three IRMs, the mode switch was placed in startup at 1:57 p.m., on April 29, 1989. During con-trol rod withdrawal, several problems were encountered with control rods and with the A recirculation pump that were subsequently repaired (see section 8.1). The reactor was critical at 8:04 p.m., on April 30, 1989, and licensed operator manipulations recommence Licensed operator training was completed on May 2, 198 On May 3,1989, control rod withdrawal continued to pressurize the reactor to 150 psig to conduct various system tests including the reactor core isolation cooling (RCIC) and high pressure coolant in-jection (HPCI) systems. After the RCIC procedure was corrected and the RCIC barometric condenser condensate pump was repaired, the RCIC test was satisfactorily completed on May 4,1989 (see section 7.2).
HPCI was declared inoperable on May 5, 1989, during testing when the flow controller would not adequately control the HPCI system. A wiring error was corrected, and HPCI was tested satisfactorily and declared operable on May 6, 1989 (see section 7.3).
2.2 Unit 3 The unit remained defueled during the inspection period. Plant modifications, corrective and preventive maintenance, and system testing were performe .0 Previous Inspection Item Update (92701, 92702)
3.1 (Closed) Unresolved Item (277/87-22-01). Improvements needed in the licensee's permits and blocking system. The licensee responded to this concern and delineated their plans for overall system upgrades in a letter dated April 6, 198 Items currently
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accomplished include: revised procedure A-41, " Control of Safety L Related Equipment," to include independent review of blocking permits; implemented controls for preapproved blocking sequences; developed a set of standards or " protocol" to improve overall implementation; restricted temporary clearances to one per permit; and established a task force to study further potential
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upgrades. The inspector reviewed the response, confirmed corrective actions, and discussed i.nprovements with operators and management personne The inspector noted that a final report ;
from the task force is due in October 1989. The inspector has noted fewer errors, reportable events and overall blocking problems in the past six months. The unresolved item is close The inspector will continue to evaluate this are .2 (Closed) Unresolved Item (277/89-81-03; 278/89-81-03). Motor operated valve (MOV) torque switch (TS) setting adequacy. The ,
. licensee responded to this concern in a letter dated April 6, i
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1989. The licensee stated that differences between static and dynamic testing (differential pressure conditions) were recognized during the response to NRC Bulletin 85-03. Further information was promulgated by MOVATS, Inc., Technical Notice j 89-02, " Spring Pack Response Under Differential Pressure". The licensee's nuclear engineering group reviewed the MOV static test results and identified 31 valves that required a TS setting adjustmen Special procedure (SP) 1253, " Unit 2 MOV Diagnostic Testing" documented this adjustment for 31 MOVs for Unit Similar evaluations for Unit 3 valves is complete and adjustments are-planne The. inspector reviewed the response, SP-1253, other related documentation and discussed this item with licensee engineer Emergency cooling water valve M0-498 experienced a closure problem on April 8, 1989. The inspector questioned whether M0-498 was consistent with the MOV TS program (see section 5.3).
Based on the licensee's response, the inspector concluded that l the TS setting of MO-498 was consistent. Based on the above, the unresolved item is closed. Dynamic MOV testing will be reviewed during future restart inspection .3 (Closed) Unresolved item (277/89-81-01; 278/89-81-01). Prior to restart provide the results of a review of instrument air tubing and support installations and show that the root cause analysis of modif-ications adequately encompasses this installation deficienc The licensee responded to this issue in a letter dated April 6, 198 The licensee stated that they reviewed the instrument air tubing and support installation deficiency as part of an overall modification program evaluatio The results of this evaluation were summarized in this response letter. The licensee concluded that since December 1988, several deficiencies in modifications have been identifie I The results of a root cause analysis and additional audits identified a number of short and long term corrective actions. An engineering evaluation determined that two hardware discrepancies were safety significant: one licensee identified item regarding installation of flex hoses, and one NRC identified item regarding pneumatic tubin _ _ _ _ _ _ _
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The licensee's root cause analysis determined that there was a I lack of installation and inspection procedural guidance; and, '
that there was failure to follow procedures and a lack of attention to detail on the part of craft, engineering and QC personnel. The licensee has completed actions to address these deficiencies. Reinspection and additional audits were performe NRC inspectors reviewed this item including: the response letter; a March 27, 1989 memorandum; hardware reinspection criteria; modification program evaluation and effectiveness !
logic; root cause analysis and corrective actions; and a letter !
to all personnel involved in the modification activity that stresses compliance with procedure The inspector had several questions regarding the licensee's review and corrective action ,
The licensee adequately responded to these questions and specific i answers are summarized below:
(1) An electrical audit (PA 89-05) found some problems with >
electrical separatio Corrective actions were addressed and complete (2) Some missing QC inspection records could not be located and 100% reinspection of pneumatic tubing was performe (3) QC inspection guidance has been detailed in construction department procedures (CD). In addition, 20 QC inspection guideline (QCIG) procedures have been developed for parallel use in the CD procedures. These QCIGs address all disciplines including: electrical, mechanical, civil, piping, welding and testin The inspector had no further question Based on the above, this item is close .4 (Closed) Unresolved Item (50-277/89-01-01). Safety grade air !
supply. This item was left unresolved pending resolution of the following issues:
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Add containment isolation valves 2502A and B to a surveillance test (ST) to leak test the air supply check valve Determine an acceptable leakage rate and nitrogen bottle pressure to ensure availability of the containment isolation valves for thirty day Leak check the air piping for the containment isolation valves before startup of each unit to determine the adequacy of the backup air suppl The inspector verified that containment isolation valves 2502A and B were added to ST 20.010, "(LLRT) Primary Containment Purge and Vent Valve Air Piping LLRT," Rev. 1, 3/31/89. Engineering Work Request (EWR) P-50840 was submitted by the site concerning leakage rates and nitrogen bottle pressure Engineering reported that the valves
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needed to be operable for 101 days if the instrument air was los The licensee committed to this_ length of time in their Environmental Qualification submittal. Based on the above commitment, the allowable leakage rates would be extremely small and bottle replacement would occur. frequently at a high pressure. The licensee determined that these new criteria were extremely difficult to meet. The site group F submitted EWR P-50992 to Engineering questioning whether or not Peach -
Bottom could operate safely with higher leakage rates than reported in EWR P-50840. Engineering reported that Peach Bottom could operate safely based on the following reasons:
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normal air supply is provided by Class-1E powered compressors,
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safety grade air supply will be complete (MOD 1316) by the end of 1989,
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concurrent LOCA and seismic event need not be postulated,
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frequency of maximum credible earthquake is 2.6E-08, and
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worst case as left bottle leakage rate would provide a twenty day air suppl . Finally, the licensee performed leak rate tests on all eleven butterfly valves. The worst leakage rate was 105 standard cubic centimeters per minute (SCCM). Allowing for some leeway (125
-SCCM) the bottles would need to be replaced at 1300 psig to ensure
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a twenty day air supply. The inspector attended the PORC meeting concerning this item. All PORC identified concerns were correcte The inspector had no further questions. This item is closed for Unit 2, but remains open for Unit .5 (Closed) Unresolved item (50-277/88-42-03). Inadequate sealing of emergency core cooling system (ECCS) pump rooms. This item was left unresolved pending resolution of the following issues that were identified in LER 2-88-29:
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equipment penetrations through ECCS pump room walls were unsealed,
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conduit penetrations through ECCS pump room walls were
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small bore piping welded to funnels in ECCS pump rooms were not analyzed as being welded,
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funnels, drains and cleanouts in ECCS pump rooms were not sealed, and
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spillways connecting ECCS pump rooms to the torus room were blocke Request R-188, " Penetration Flood Seals Internal Flood Protection," was written and performed to seal all suspect equipment and electrical penetrations below elevation 111 foot level. Two seals on the standby gas treatment system duct that
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1 penetrate the RCIC and HPCI rooms were exclude It was calculated that this duct could rupture if subjected to a flood {
level.of 111 feet. A separate modification is being written'(MOD
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5111) to address this issue separately. The licensee wrote a safety evaluation to justify not repairing the duct work prior to restart. The inspector found actions taken for the first two areas to be acceptabl The licensee performed a Small Bore Piping Evaluation to address welded lines to funnels. This was reviewed in NRC Inspection 277, 278/89-08. About two-thirds of the Unit 2 drain lines were evaluated and two nonconforming conditions were repaire Nonconformance Report (NCR) P88123-213 was written to address unplugged floor drains, cleanouts and equipment drainage system Corrective actions prescribed by the NCR were adequate to address these problem areas. In addition, procedural controls were instituted to control removal and installation of plugs in floor
' drains, cleanouts, and equipment drains. A routine test'(RT 13.9) " Floor and Equipment Drains & Cleanouts Closure and Cover Plate Survey," was written to ensure that the integrity of drains and cleanouts is maintained. A prerequisite for plant startup is satisfactory performance of RT 1 An abnormal operating procedure (A0 20A.1) " Removing a Floor Drain Plug, Equipment Drain Plug or Cleanout Cover," was written to provide instructions necessary to remove plugs during shutdown or power operation In addition, labels were placed near all drains and cleanouts stating that shift management approval is necessary prior to openin The final area of concern, blocked spillways, was addressed by NCR P88095-215 and in a safety evaluation for high energy line break (HELB). The safety analysis determined that the spillways were no longer needed for to two reasons. First, the condensate line to the i ECCS pumps was upgraded in 1970 to seismic class 1. Therefore, flood l due to a condensate line break is no longer vali Secondly, steam line breaks in the HPCI or RCIC rooms have adequate relief volumes
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without the spillway The inspector determined that corrective j actions were adequate and this item is closed for Unit 2, but remains j- open for Unit 3.
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l 3.6 (Closed) Unresolved Item (277/87-30-03; 278/87-30-03). To meet l the separation criteria of 10 CFR 50, Appendix R, simultaneous high E impedance faults should be considered for all associated circuits located in the fire area of concern. The licensee developed, estab-11shed, and implemented procedures to restore power sources required for safe shutdown of the reactor caused by multiple high impedance faults in each fire area. To restore a power source to a load center with safe shutdown loads, first all loads are removed, then the power source breaker closed. Only safe shutdown loads in unaffected areas are reconnected to the power source. The safe shutdown loads for
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'" Safe and Alternative Shutdown System" analysis data base. A series of emergency procedures (T-300) for each fire area was develope These procedures incorporate listings of safe shutdown components, breakers, load centers and power sources. -In addition, cn March 15, 1989, a meeting was held between the NRC and licensee to discuss'this
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The inspector reviewed these procedures, the lesson plan to
. implement the procedures, and walked down several of these procedures. Licensed and non-licensed operators were trained in
. the procedures. The inspector attended the classroom.and in plant walk through training. The inspector verified training'
attendance record Due to scheduling problems five operators could not attend the training sessions. These operators will be required to read the lesson plans and sign off the required reading list. The lesson plan will be incorporated into the regular training cycles. .The inspector concluded that the T-300
. procedures can be adequately implemente The inspector had no further questions at this tim This item is close .7 (Closed) Unresolved Item (277/87-30-04; 278/87-30-04). . Protection of the low pressure primary coolant boundary. piping during or after a postulated 10 CFR 50, Appendix R fire. Specifically, the residual heat removal (RHR) shutdown cooling suction line isolation valves (M0-10-17 and 18) could open spuriously resulting in a high pressure to low pressure leak. To resolve the issue, the licensee removes motive power by opening the breaker to the outside containment RHR shutdown cooling isolation valve (MO-10-17). This is done by admin-istrative control when the reactor is at powe The licensee commit-ted to this in letters to the NRC dated March 31 and April 11, 198 The inspector reviewed procedure GP-2, revision 49, " Normal Plant Startup", which implements this control. In addition, the inspector verified implementation of this requirement during the April 26, 1989, Unit 2 reactor startu The inspector had no further questions. This item is close .8 (Closed) Unresolved Item (277/89-81-04; 278/89-81-04) Emergency Cooling Tower (see section 5.3).
4.0 Plant Operations Review 4.1 Operational Safety Verification and Station Tours (71707, 71715)
The inspector completed the requirements of NRC Inspection Procedure 71707, " Operational Safety Verification," by direct observation of activities and equipment, tours of the facility, interviews and discussions with licensee personnel, independent
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.a verification of safety system status and limiting conditions for operation, corrective actions, and review of facility records and '
i log The inspectors performed 381 total hours of on site backshift time, inciuding 182 hours0.00211 days <br />0.0506 hours <br />3.009259e-4 weeks <br />6.9251e-5 months <br /> of deep backshift.and weekend tours of the facilit Deep backshift inspections included around-the-clock coverage from April 26 to May 6,198 .2 . Follow-up On Events Occurring During the Inspection (93702)
4 High Pressure Coolant Iniection (HPCI) System Inoperability Due to Design Deficiency During the conduct of a HPCI system evaluation in response to INp0 SER 25-88 and NRC Information Notice '
88-72, PECo engineers found that the worst case DC power distribution system voltage, coupled with elevated temperatures from a design basis accident, could adversely affect two DC motor operated valves which contain starting current limiting resistor Failure of these valves (M0-23-14 and 19) would cause HPCI to become inoperabl Consequently, the licensee made a four hour ENS report at 12:25 p.m. on April 5, 198 The licensee performed a review of the HPCI system design and determined that the starting resistors in these MOVs are unnecessary. Corrective actions were.to remove the starting resistors under modification (MOD)
5125, which allows the valve operator motors to draw sufficient starting current to generate the necessary torque for timely valve actuatio This was completed for Unit 2 on March 30, 1989, and will be performed for Unit The inspector reviewed operator logs, the Event Notification Worksheet, Engineering Work Request P-50721, INP0 SER 25-88, NRC Information Notice 88-72 and MOD 5125 documentatio No unacceptable conditions were note .
4. Missing Motor Control Center (MCC) Switchboard Terminal l Block Holddown Screws The licensee made a four hour ENS report on April 6 1989, concerning missing holddown screws on safety related MCC terminal blocks. An engineering evaluation of this condition determined that the terminal blocks do not meet seismic qualification criteria without some fastening device like the holddown screws installe The
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?" screws did not appear in the original equipment drawings L
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nor did maintenance procedures specifically require their reinstallation after removal. Additionally, since the; L-terminal blocks'have~a snug fit the licensee believes j that maintenance workers may have neglected to replace' i
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all, removed screws over the course of various routine >
maintenance actions on the terminal block The' licensee inspected ~all safety related MCCs on Unit 2 to determine the extent of-the problem. For all-equipment which was' feasible to be de-energized the instal-lation of any missing screws-was' completed under Engineering'
M' Work Engineering Work Requests-(EWR) P-50869 and P-5098 Equipment which was not feasible to de-energize had the terminal blocks secured as necessary with tie. wraps as documented by the engineering disposition of-Nonconformance Report (NCR)-P89-163-312. Unit 3 deficiencies are: planned for later correctio The inspect'or reviewed operator logs, the' Event Notification
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Worksheet, EWRs P-50869 and P-50982,-NCR P89-163-312, and chapter-8 of the FSAR. A select number of Unit 2 MCCs were inspected in the field. Personnel involved in the planning and performance of the corrective procedures were interviewe No unacceptable conditions were note . 4. Containment Atmosphere Systems Pneumatic Tubing Improperly Installed During the conduct of.a containment atmosphere control /
dilution (CAC/ CAD) system evaluation in response to a pre-vious NRC finding (see section~3.3),.PECo engineers found'
that safety related pneumatic seismic spans were found to be excessive and thermal displacement'under accident condi-tions was not analyzed. Consequently, the licensee made a four hour ENS report at 4:55 p.m. on April 10,-1989. The licensee has initiated work permit R-245 to restore the system to code requirements. The work is complete on Unit 2 and scheduled to be performed for Unit The inspector reviewed operator logs, the Event Notification Worksheet, the work permit and verified corrective action _ _ - - _ _ . - _ - _ - _ - _ _
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4 . 2 . 4' Excessive Grease on Emergency.4KV Switchgear Fuse Clip
. Contacts On_ April 11, 1989, the licensee was returning. emergency buses back to service. A non-licensed operator noticed corrosion.on the control power fuse. clips for_ the 4 KV lro kers. The corrosion identified was similar to corrosion found on several failed area space heaters. A license . investigation showed that the corrosion'would cause a voltage drop beyond that allowed in the DC load analysis. Therefore, several breakers may not-have closed when.' required. The
. grease (GE Type D50H47) us'ed to . lubricate the fuse clips caused corrosion of the. copper. To. correct the problem, the licensee cleaned the grease'and any corrosion from all emergency bus fuse clips and relubricated them with a.new approved greas The inspector reviewed operator logs and the incident
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report,'and discussed the event with electrical-and maintenance personnel ~The. inspector-determined that adequate corrective action was taken. An LER'will be-submitted and it will be reviewed in a future' repor 'The inspector had no further questions.or concern . Unit 2 Containment Isolation on April 15,'1989 A Unit 2 inside containment group II primary containment isolation. signal occurred'during fuse cleaning on the E-12 4KV bus at 5:35 p.m. on-April 15, 1989; The isolation was due to a personnel error by an operator'during fuse' instal-lation. A bus load shed on the 480V E-124 load-center occurred and de-energized a portion of the primary contain-ment isolation logic resulting in the' containment. isolatio Power was restored and the isolation signals were rese An ENS call was made at 9:30 Fuse cleaning was being performed due to incorrect grease (see section 4.2.4 above).
The fuses are inside a holder and the operator reinstalled the fuse holder 180 degrees from its proper orientatio The licensee conducted an investigation into this even The licensee held a critique and issued operations incident report number 2-89-40. The licensee's root cause analysis determined that inadequate training resulted in the operator erro Licensee corrective actions included training operators in the different types of fuse holders, providing a training mock up to show these fuse holder blocks, and implementing a better fuse holder identification program.
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The inspector reviewed operator logs and the incident i
report, discussed the event with operators and engineers, and examined fuse holder blocks.in switchgear. The inspector concluded that the licensee had performed an adequate root cause analysis and
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proposed effective corrective actions. The inspector had no further questions nor. concerns at this tim '4.2.6 Unexpected Firing of the ' Standby Liquid ~ Control (SLC)
Squib-Valves on April 16, 1989
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On April 16, 1989 at 1:30 p.m., during performance of ST-1.3B-2, PCIS Group II/III Logic System Functional Test, the SLC Squib valves unexpectedly. fired. During the test, the SLC pump breaker for the system being tested was opened, but once-the pump control switch was placed in start,'the. opposite Squib valve fired. The test did not account for the fact'that when the control switch is placed in either the "A" or."B" pump start position,.both SLC Squib valves fir The licensee determined that'this event was not reportable because an engineered safeguards feature actuation did not occu The licensee conducted an investigation into'this event. .A critique was held and operations incident report numbe was issued. The licensee determined that a test procedure deficiency was the event root cause. Corrective actions include:
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Revise ST-1.38-2 to preclude the firing of a Squib valve during performance of the tes Direct the preparers of " logic type" procedures and tests to include a review of both test mode and operating mode impact Significant changes to these types of procedures shall be reviewed by the System Engineers and discipline experts whose systems or disciplines are affecte Perform an additional review of the HPCI and RCIC logic system functional tests before they are performed during Unit 2 power ascensio Issue a copy of the incident report to all PORC members and alternates as a reminder that independent reviews shall be performed on major logic system functional tests, and similar, revision _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ - _ - _ _
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Issue a copy of the incident report to all licensed operators and shift technical advisors to ensure that they heighten their awareness during test Repl&ce the Squib valves and retest the SLC syste The inspector _ reviewed operator logs and the incident report, attended the critique, discussed the event with the operators and engineers performing the test, discussed the event with
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operations and plant management, and performed a walkdown of the SLC system after repairs. The inspector concluded that the licensee performed an adequate root cause analysis and implemented effective corrective actions. The inspector also noted that this event was addressed in an Operations News Letter dated April 21, 1989. The inspector had no further questions nor concerns at this tim .3 Unit 2 Pre-Startup Verifications 4. System Operability (71707, 71710)
The inspectors reviewed Technical Specification (TS)
systems and other "important to safety" systems-operability prior to Unit 2 restart. Selected system walkdowns were performed (see section 4.5) and system status was reviewed during control room and plant tours, and during record and document review During an early morning tour on April 25, 1989, the inspec-tor noted a Unit 3 information tag (3-56-C87-5537) on the Unit 2 feeder breaker on motor control center (MCC)
E-124-T- This MCC breaker provides alternate power to the Unit 3 30 battery charger. However, this 3C battery charger and its respective 125 VDC battery provide control power for the E-3 diesel generator (DG) and the E-32 (Unit 2) and E-33 (Unit 3) 4KV buses. Thus, the Unit 3 3C battery and charger are required for Unit 2 startu The inspector determined that maintenance on the Unit 3 normal feeder breaker to the charger power supply (E334-R-B) required that the alternate feed (E124-T-8) from Unit 2 be energize This as found condition powered two of the four independent 125 VDC batteries needed for the DGs from the same power suppl _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - _ _ _ _ - _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ -
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- The inspector informed the licensee of.this coridition '
at the 8:00 a.m. morning meeting on April- 25, 198 The inspector held further discussions with licensee engineering and management personnel. .After review, the licensee concurred with the inspector's concer .The: licensee completed preventive maintenance on the
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. Unit 3 breaker and performed inspections of all 'othe .
batteries, battery chargers and related power supplie No other abnormal lineups were noted. 'The inspector
, verified these corrective action During a control room tour on April 26,'1989,- the inspector noted that the Unit 2 high pressure coolant injection (HPCI)
steam bypass valve A0-4807 was inoperable and blocked. in the closed: position. The inspector questioned HPCI opera--
bility. .The_ inspector reviewed TS, the FSAR, HPCI operating procedures and the Peach Bottom safety evaluation repor The license'e reviewed this condition. Unit 3 does not have this similar valve. The licensee concluded that the. valve performs no function which is important to the operability of the.HPCI system. A PORC meeting also came to this~ con-clusion. Since it is a containment isolation valve, it w closed and deactivated in that position as. required by 1T echnical: Specification 3.7.D.2. The licen'see subsequentl .;
L completed: repairs to the solenoid 'for A0-4807 valve prior '
to restar .;
The inspector concluded that equipment required by the~
Technical' Specifications for plant criticality was operable without reliance or. Limiting Condition for Operation action statements. However, there were two other primary contain-ment isolation valves which were closed and made' inoperable in' accordance with Technical. Specification- paragraph 3.7. (see section 4.3.7). Also, nonsafety-related equipment required for criticality was in a condition to support safe plant operatio . Quality Assurance (QA) Reviews (40500, 35502)
The inspector reviewed QA involvement in pre-startup activ-ities, including the-status of open nonconformance reports (NCR). The inspector noted that QA was in attendance at all pre-startup PORC, management and other periodic meeting Open NCRs were reviewed at these meetings. QA procedure
'NQA-16 requires a management signoff for QA readiness for startup. This signoff by QA was documented in GP-2, Normal Plant Startup Procedur .___- _ _-- __ _______ - _ _ _ _ _ _ - _ _ - _ __ _ __ _ _ _ ____ _ -
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During pre-startup tours, the inspector noted NCR tags
! hanging on a safety related breaker for a residual heat removal system valve and on a 125 VDC battery charger. The inspector questioned QA personnal about whether or not these NCR tags were active. QA reviewed their records and deter-mined that both NCRs were closed; however, the tags had not been removed. QA performed a walkdown of Unit 2 and common areas. No additional NCR tags were foun . Engineering Work Requests The inspector obtained a computer printout of all outstand-ing engineering work requests (EWRs) for Unit 2 and commo After a review of EWR packages and discussions with the site / nuclear engineering department liaison, the inspector was concerned about one EW EWR-P50953, "2C heat exchanger HPSW flow oscillations," addresses the discharge valve (MO-89C) for high pressure service water from the 2C RHR heat exchange The licensee noted flow oscillations with the 2C heat exchanger and pinpointed the problem to the valve. To further determine the cause of the problem, the valve must be disassembled and inspected. The licensee stated that this was not considered a restart requirement for the following reasons:
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this valve is not used during operatio the flow oscillations occur at very low flow rate there are three other heat exchangers available for shutdown coolin The licensee stated that they will disassemble MD-89C for an inspection during a future outag . Temporary Plant Alterations (TPA) (71707)
The inspector reviewad licensee records to determine the status of temporary alterations and to verify consistency with administrative procedure A-42,
" Control of Temporary Plant Alterations". Revision 15 of this procedure became effective April 1, 1989, and the changeover to the revised TPA log index and control forms remains in progress. The inspector noted some minor administrative deficiencies including that a copy of one TPA control form was missing from the Control Operator system file These were broucht to the attention of the licensee and corrected. In addition, the inspector examined plant panels for TPA tags. All
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notedLtags were authorized'by the TPA procedure. The .
inspector concluded that there weren't any TPAs.that could affect system operabilit .
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-e 4. Blocking Permits, Information Tags and Operator Aids (71707)
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'The inspector reviewed equipment blocking permit'. status-
[ to . verify' operability of Unit 2 and common equipment.
L' The inspector reviewed the control room ~ system i .
equipment files and toured the plant looking for-i blocking permits. No open Unit 2 blocking permits were identified that would affect safety equipment operability. However, one Unit 3 permit regarding.the Unit 3 3C battery charger was noted (see section 4.3.1).
The inspector also reviewed information tags and posted operator aids. No unacceptable conditions were note '4. Surveillance Tracking plan / Surveillance Testing (61726)-
The inspector reviewed outstanding. surveillance tests (STs) and routine tests (RTs) that needed to be performed before placing the mode' switch to startu ..'
Approximately one week prior to startup,'there were five STs and two RTs outstanding. When the mode switch .
was moved to startup on April 26, 1989, all seven outstanding STs and RTs were complete In addition, the inspector requested the latest performance dates of ten randomly selected STs. Eight STs were current and two STs needed reactor steam to perform. These two STs will be performed shortly after startu Finally, the inspector obtained three of the eight STs for further review. They were ST 1.6, and 6.8 (see section 7.0 for further details of these STs). The inspector noted infrequent use of temporary procedure changes (TCs). The STs were complete and legible and no problems were identified. The inspector concluded that the surveillance test program was satisfactory to support startu , < On April 27, 1989, the shift inspector noted that the licensee was performing ST 9.21-2, " Jet pump Operability". Technical Specification (TS) 3.6. states that flow indications from each of the 20 jet pumps shall be verified prior to initiation of reactor startup from a cold' shutdown condition. There was no 1 signoff in GP-2, " Normal Plant Start-Up", to ensure
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that this TS was' met, nor was ST 9.21-2 performed the
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L previous day. After the NRC restart staff questioned the
. licensee concerning this problem, they were able to produce a recirculation system daily-data sheet kept by the site reactor engineering group. All 20 jet-pump readings ~were observed during two loop operation on the morning of April'
25, 1989. To prevent a recurrence of_this situation, the licensee temporarily changed GP-2 (TC #89-816) to now per-O form ST 9.21-2 after both recirculation pumps are runnin A permanent revision will be made to GP-2. The inspector had no further question B 4. Technical Specification (TS) Limiting-Condition'for Operation (LCO) Log and Locked Valve Log-(71707)
The inspector reviewed the licensee's LCO log for equipment listed as inoperable and for TS compliance. One' item that was being carried as inoperable for Unit 2 and common was the seismic monitoring syste .The licensee was experiencing numerous spurious alarms
, in the-control room that were believed to have been caused by. electrical interference. After discussions with the vendor representative, electronic noise
. filters were purchased and installed in the seismic monitoring system. However, difficulties with the m system were still being experienced. The vendor representative came to the site to troubleshoot.the system and de'3rmined that the older style circuit boards were not totally compatible with the noise filters. The licensee had updated circuit boards in stock, so the old boards were replaced. After functional tests of the seismic system were conducted, an additional problem was found with the Unit 2 foundation accelerometer. The accelerometer was replaced, operability testing wcs performed, and the system was declared operable. The entry in the LCO log was subsequently removed. Since installation of the noise filters, the number of spurious alarms has decreased. Shortwave radio use is a known cause of spurious alarms in the seismic monitoring system. The licensee will try to pinpoint the location of short wave radio use after the next spurious alar !
During preparations for startup, the inspector _noted j that the RHR head spray valves (MO-32, 33) and the i shutdown cooling outboard valve (MO-17) were blocked (closed and power removed). These are group II primary containment isolation valves per TS Table 3.7.1. The !
inspector questioned whether or not these valves were l operable and would be logged in the LC0 log. Although d j
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the valves were closed and deactivated, the licensee concluded that the valves were inoperable. Appropriate entries were made into the'LC0 log per TS:3.7.D.2. The valve positions are also being recorded daily per TS 4.7.D.2. The inspector verified licensee's actions and reviewed.the appropriate TS requirements. The inspector concluded that reactor mode changes could occu The inspector also reviewed'the status of locked valves
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prior to startup. The Unit 2 and the common check off lists were complete prior to startup. The inspector had no further questions in this are .3.8 Operating Procedures (71707)
The inspector reviewed the status of operating-procedures necessary to support startup. Selected system operating (50) procedures, general plant (GP)
procedures ano special procedures (SP) were reviewed:
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GP-2, Normal Plant Start-U GP-2-2. Appendix-1, Startup Rod Withdrawn Sequence Instructions
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SP-1167,' Unit 2 Post Cycle Seven Restart Power Testing
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SP-1166, Program Controls for Restart Power Testing - Post Cycle Seven
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SP-1248, Unit 2 Post Cycle Seven Restart Criticality fjo unacceptable conditions were note .3.9 Review of Operator Overtime (71707)
'l A change in the plant's Technical 5 specifications (TS)
regarding control of operator overtime became effective on March 22, 1989. The inspector reviewed the methods used by the licensee to implement this change and records of' operator hours to verify compi f ance. The licensee's administrative procedure to control overtime (A-40) was revised and issued May 1, 1989.
l The shift clerks presently schedule and control l operator work hours in accordance with these TS 1 requirements. The shift clerks appeared knowledgeable l about these new requirements. No operators were found to have exceeded the overtime requirements since the shift clerks began applying the new TS requirement _ _ _ _ _ _ _ . _ _ _ - _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ -
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. Operator overtime reversed a declining trend set'during j-the final quarter of 1988 and started to increas '
Average overtime hours per week and total hours for .
- licensed operators during the first quarter of 1989:
were:
Per Week ' Average ' Overtime - Total Hours Per Operator Per Week January 1989 4.9- 769 t . February 1989 '
March 1989 L During this period, the number of licensed operators increased from 36 to 41. This area was discussed with operations management. This situation appears to be
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attributable to. making preparations for Unit 2 startu .3.10 Source Range Monitor (SRM) Countrate (71711)
During the eighth refueling outage approximately 25% new fuel was loaded into the Unit 2 reactor. The SRM A count-rate observed during the two year outage was-less'than'three
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counts per second (CPS) with all control rods fully inserte The licensee performed a regression analysis and provided a projected countrate for all SRMs in support of startup of Unit 2. The analysis assumed that the activation product in the core is predominantly Curium 242 with half-life of 160 days which dominatas the overall decay rate with approx-imately' constant source level due to isotopes with-long half lives. Accordingly, the licenseu amended the facility's
. Technical Specifications to justify reduced SRM countrates y during startup and refueling based on increased signal'to
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noise ratio. The amendment was approved by the NRC (Amend-ment No.140, dated Siarch 16,1989). General Electric's Sereice Information Letter (SIL) Wo. 478, dated December 16, 1988, slso indicated that the BWR plants which have not operated for an extended period could have lower SRM signals than one following a shorter, routine shutdow The inspector reviewed the surveillance test SI2N-600-ALN-A1A0, Source Range Monitor A Drawer Alignment, and the Shutdown Margin data collected during the seventh refueling outage. SRM A countrate was less than three CPS before the alignment, and was approximately ten CPS afterwards. The documentation indicated that the SRM A drawer alignment properly adjusted the gain of SRM A. Thus, the inspector concluded that the previous SRM countrates were
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adequate. The inspector did not have any further questions at this tim No unacceptable conditions were note .3.11 Review of Maintenance Request Forms (MRF) (62703)
The inspector reviewed.the " Report of Unit 2 Non Restart Work Orders Showing Q Listed Work -Items Only" to determine if any of the work items listed needed
' completion before Unit 2 startup. One~ item on the list concerning 125 VDC- battery grour.ds (MRF 8903003) was identified as requiring resolution prior to startup and
.was subsequently corrected by the license No other abnormalities were note .3.12 Plant Operations Review Committee (PORC) and Management Oversight (40500)
The inspector attended several PORC meetings and management meetings that reviewed Unit 2. status prior to startup. .The PORC meetings reviewed neutron monitoring Technical Specifications and HPCI-operability (section 4.3.1).
Periodic management meetings occurred daily prior to restart at 9:00 a.m. and 5:00 p.m. with corporate and plant management in attendance. Pre-startup.open items were discussed and tracked until completio Overall, the inspector concluded that these PORC and management meetings were effective in addressing restart open issues and resolutions. No unacceptable conditions were note .3,13 Dryweil Closecut (71707)
l On /pril 21, 1989, the inepector and the project section chief toured the Unit 2 drywell prior to fina?
closeout. The NRC personnel were accompanied by the ,
drywell coordinator, the A-30 compilance coordinator and I the shift manager. Several pieces of trash and debris were found and were picked up. All moveable equipment was found to be securely fastened in place.
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The inspectors identified a bent rod on a spring can .
and a leaking hydraulic snubber. The shift manager J also found another leaking hydraulic snubber. The restart staff questioned the licensee concerning their ,
drywell closecut procedure and if it addressed snubber I conditions. The licensee does not have a formal 1
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drywell closecut inspection check list, but a final
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drywell inspection- tour to determine _ general conditions is required by GP-2, " Normal Plant Startup". .In addition, there is a sign-off in GP-2 by.the system engineer that snubbers are operable. The system
< engineer bases his sign-off on the last performance of the snubber surveillance tests. The drywell snubbers were surveyed at the end'of March, and both of the leaking snubbers were satisfactory at that time. The system engineer and a QC inspector entered the drywell on April 24, 1989, to inspect both leaking snubbers and
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most of the other snubbers in the drywell (90%). No other snubbers were found to be damaged. The inspector was informed that both snubbers were definitely damaged sometime between the end of March and April 21, 198 The licensee repaired the snubbers and the system
. engineer is investigating the possibility of conducting a special inspection of snubbers in the drywell'just prior to drywell closeou '4.3.14 Alternate Rod Insertion Modification (37700)
Modification (MOD) 865 added an alternate rod insertion (ARI) system and revised the recirculation pump trip
'(RPT) on Units 2 and 3. The ARI provides redundant scram air header exhaust valves that are diverse from the reactor protection: system including sensor output to the final activation device. The RPT was modified to' ensure that the RPT and ARI system actuation occur- ;
simultaneousl The inspector reviewed the modification and acceptance test packages, and the safety evaluation report MOD 865 bas been completed on both units. Testing has been completed on Unit 2. Unit S will not be tested until
.later during the current outage. The operational, surveillance, and alarm response c:ard procedures were reviewed. In addition, the lesson plan and training records were reviewed. The inspector had no further
- questions or concerns regarding MOD 86 .3.15 Chemistry, Radwaste and Health Physics Readiness The inspector reviewed the licensee's chemistry, radwaste and health physics groups to determine the operational state of each group to support startup of l! nit 2. Each group was determined to be in a state of
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l readiness. Chemistry has initiated resin changes in condensate demineralized which should be more efficient 1 in removing copper. Health Physics' completed i operational training for all technicians as noted in !
NRC inspection report 89-0 .3.16 Control Room Panels, Instruments and Alarms (71707)
The inspector performed a walkdown of all Unit 2 and common control room and cable spreading room safety related panels. Items checked included panel cleanliness; wiring and relay conditions; presence of temporary plant alteration (TPA) tags, equipment trouble tags (ETTs) and blocking tags; and, overall panel acceptability for restart. The inspector noted that some ETTs that were out of date and the licensee subsequently removed them. No unauthorized blocking tags nor TPA tags were noted. Overall panel internal and external cleanliness was good. No wiring, relay, or terminal block problems were note The inspector reviewed the status and acceptability of control room safety related instruments and annunciator alarm The licensee tracks out of service instruments and abnormal alarms in the daily plant status (TRIPOD)
document. These items are also discussed during the daily 8:30 a.m. control room management meeting and at the daily 11:00 a.m. TRIPOD meeting. In addition, GP-2, Startup Procedure, requires a check of alarm and instrument status. The inspector confirmed that all safety related instruments were operable. One abnormal alarm (control rod drive high temperature) was being addressed by jumpering the inoperable temperature sensing points. Other existing alarms did not affect system operation The inspector concluded that existing control room panels, instruments and alarm status was adequate to support startu .3.17
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Fire Protection (64704)
The inspector performed an evaluation of the overall adequacy and implementation of the licensee's approved fire protection and prevention program. This consisted of a review of the approved fire protection program l documentation; evaluation of the implementation of !
guidelines provided in that program; verification of the operability of fire protection systems by walking down various systems; and evaluating the readiness of personnel to prevent and fight fires by interviewing fire watches and other personnel and checking manual
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l fire fighting equipment. The inspector also observed the performance of fire protection check off list-
.S13.2.1.A revision 0, t Several fire protection deficiencies were noted in the-implementation of the program including:
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A number of combustibles (mostly copier paper) was noted behind the Unit 2 Nuclear Instrumentation cabinet in the control: roo .
These were remove Tr.e Unit 2 " Turbine Bearings 2-9 Sprinkler-
. System" supervisory alarm nitrogen bottle was found disconnected. The licensee reconnected the bottl Portable foam trucks located throughout the site do not carryLfire inspection tag Though the Cardox hoses in the control room have been blanked per Modification 5041, two procedures (S13.2.2.0 and J) still require their use. The licensee is making th change Fire extinguishers in contaminated or high
radiation areas are not included-in the station's inspection program and consequentl not being inspected. The licensee indicated that.this was changed.by a revision to RT 24.40 effective May 1,,198 These. deficiencies were identified to the licensee'for corrective action The inspector concluded that the sfire protection program was adequate to support q restar During routine tours of plant after restart, the
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following fire protection program deficiencies were L note Two control room fire protection supervisory alarms (#209-D4 and DS) were annunciate One was being tracked in the plan of the day and the other was not. The inspector verified that procedures were being
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implemented to ensure the local alarm panel l was checked daily. One alarm was subsequently cleared on May 5, 1989. The licensee indicated that repairs were scheduled to address the remaining alar '
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- Two fire doors in the RCIC room were found open at 4:00 p.m.-on May 3, 1989. The
, . inspector closed the doors and informed the shift manage Several equipment trouble tags (two were-dated 1986) were noted inside the control room fire alarm cabinet. .The inspector informed the licensee of this conditio Licensee review determined that all these ETTs were identifying previous problems that had been correcte The ETTs were remove The inspector discussed these fire protection issues with licensee managemen The permanent-position of-Fire Protection, Supervisor, is currently vacan The licensee is'in the process of filling this positio The licensee acknowledged these fire protection concerns. These fire protection issues are collectively unresolved (277 and 278/89-15-01).
4.3.18 System Check-Off-Lists -(COL)
The licensee uses a COL for each system to determine its status. One list for each system contains the valves, breakers and instrumentation valves for the system and lists the desired. position for each; The I&C personnel check the valve lineup for the instrumentation valves using the appropriate system COL, Operators check the rest-of the system valves and the breakers. For safety systems,.two identical COLs are used and they are perfonned independentl . Initials after each valve or breaker indicates that the as-found position agrees with that shown .on the CO , in the event-that the positions do not agree, a nate is written on the COL anci a secr#d operttor verifles the note, If necessary, e procedure change form is completed to show that the different lineup is adequat One person per shift (a Shif t Superviscr) was responsible for the COLs and any changes to them, as well as maintaining the status list. Tha status list contained a list of all COLs which indicates system COLs are considered to be safety systems (i.e., require double verification)'. From the status list it was possible to determine when a particular COL and double verification was in progress, ready for review by shift management, and complete !
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The inspector reviewed COL implementation and concluded that the system works well and allows a very complex '
process to be organized. No unacceptable conditions were note .4 Engineered Safeguards Features (ESF) System Walkdown (71710)
The inspector performed a detailed walkdown of portions of the common (Unit 2 and 3) Emergency Diesel Generator (EDG) and the Unit 2 Residual Heat Removal (RHR) systems in order to
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independently verify operability. The EDG and RHR system walkdowns included verification of the following items:
-- Inspection of system equipment condition Confirmation that the system check-off-list (COL)
and operating procedures are consistent with plant drawing Verification that system valves, breakers, and switches are properly aligne Verification that instrumentation is properly valved in and operabl Verification that valves required to be locked have appropriate locking device Verification that control room switches, indications and controls are satisfactor Verification that surveillance test procedures !
properly implement the Technical Specification surveillance requirement The' inspector noted that the EDG drawing did not reflect the existence of vent valve HV-10059 on the diesel lube oil filte A Maintenance Request Form (MRF) tag (8901001) was also hcnging-on the E-3 diesel standby coolant circulation pump even though the work was complete and the MRF was closed. Upon notification, l the licensee submitted a drawing change to update the plant' i drawing and removed the out-of-date MRF ta ,
The RHR system walkdown revealed a leak in the 28 pump seal cooler piping downstream of the cyclone separator. The licensee l identified the cause to be a cracked fitting which was j subsequently repaired. A large number of Equipment Trouble Tags !
(ETT) were hanging on various components in the 28 and 2D RHR rooms. Some identify minor problems such as small valve packing leak; and loose handwheels while others address deficiencies such as a room temperature thermocouple hanging loose (ETT 014281),
the' air supply pipe to A0 2-33-2335G broken away from the wall (ETT 017013), and wrong type gland seal piping attached to the RHR pumps (ETT 010668).
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The inspector identified additional deficiencies including one missing and one stripped valve handwheel, and one valve label which fell off its associated valve. Housekeeping in general
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appeared weak.with several items of equipment laying adrift including a.large stepladder, a disconnected air hose, a valve
' wrench and minor debris. Additionally, a large plastic drape and a piece of plywood were laying on.the 2D pump discharge check valve. The housekeeping issues were subsequently corrected by the licensee. This area will.be. reviewed in a future inspectio . An Information Tag was noted on the 2C RHR pump controller handle in the control room indicating' that the discharge check ~ valve sticks open. The inspector discussed this with the licensee to determine the safety significance. Although stayfull backleakage through the valve would cause torus water level to increase, the licensee has demonstrated that running the 2A RHR pump will seat the valve. The valve does not drift off its seat once seated and a Maintenance Request Form (MRF 8903210) has been initiated to repair the valve. Other similar valves in the system do not exhibit this~ sympto One step-in RHR operating procedure 50 10.1.A-2.A, RHR A Loop Check Off List, contained a temporary change which was not identified on its attached Temporary Change Traveler form. This was provided to the licensee for correctio The inspector determined that none of these findings affected system operability. Discu'ssions were held with licensee management and the system engineers. The licensee intends to address these items during the routinely scheduled system outages which are to begin ir May 198 .5 Initial Criticality and Training Startups (72502, 71707, 41701,
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The reactor was initially mada critical at 5:44 a.m. on April 27, 198 l The inspector verified that the rod pul's were in accordance with procedure GP-2. Once criticality was achieved, po n r was increased to about 100,000 counts per second (upper limit) of the source ranys monitors (SRMs). Several intermediate range monitors (IRMs) showed response on range 1. The licensee exited procedure GP-2 at step 5.1 to enter Special Procedure (SP) 1248, " Unit 2 Post Cycle Seven Restart Criticality". This was in accordance with procedures, however SRM/IRM overlap was not verified. The reactor was then made subcritical to prepare for training startup On the subsequent startup per SP-1248, IRM overlap was verifie However, IRMs B, C, and F did not respond and did not exhibit overlap. The licensee declared these three IRMs inoperable and took appropriate actions required by TS including the insertion
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of a half scram on channel B. Licensee troubleshooting determined probable IRM detector failure. The licensee then proceeded to shut-down to repair these IRMs on April 28,1989, at 4:41 a.m. (see section 8.1).
.The inspector asked why SRM/IRM overlap wasn't verified on the initial startup. The licensee stated that GP-2 and SP-1248 allowed not per-forming this step. However, the licensee indicated that procedure changes would;be made to GP-2 and SP-1248 to ensure SRM/IRM overlap is checked on'every startup. In addition, guidance was proceduralized 4' to ensure that all IRMs are checked on range and indicating prior to achieving range four of all IRM The inspector verified these corrective actions. The inspector reviewed the IRM strip chart recorders, discussed SRM/IRM' overlap with licensed operators and operations management personnel, and verified adequate SRM/IRM overlap. during additional startup 'The licensee restarted Unit 2 on April 30, 1989, and continued with criticality trainin During the period April 27 to May 2,1989, a total of eleven criticalities were performed: 'eight by recently licensed R0s and SR0s; and three by hot licensed R0s. Of.the six recently licensed R0s/SR0s who did not perform a startup, the; follow-ing information was provided by the licensee: two had previously
. performed a'startup (before the March 1987 shut down) and the other
, four had observed one of the recent startups. The licensee committed to performing training startups for all available recently licensed operators. When questioned, the licensee indicated that their inten-tion was not to have every recently licer. sed operator to perform a startup during this period, but destgr. ate a specific time period (i.e., 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />) to perform such training for as many as possibl The individuals not performing these startups will be required to perforru similar type reactivity manipulations. These manipulations will be reviewed prior to removing the restrictions from the operator's license .6 Technical Specification (TS) Limiting Condition for Operatior!
(LC0_). Log (71707)
The inspectors verified TS LCO compliance when safety systems and components were declared inoperable. The licensee maintains an LC0 log as required by the Operations Management Manual, section 12. On May 3,1989, at 10:15 p.m. , the licensee logged RCIC inoperable. The surveillance test (see section 7.2) had failed; however, RCIC had met the TS acceptance criteria. In addition, the RCIC barometric condenser condensate pump was tripping electricall Further licensee review determined that RCIC was operable. The TS LCO entry was not cleared until 4:45 a.m., on May 4, 198 ;
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The inspector stated that the licensee was not effectively keeping the LC0 log up-to-date. Additional entries were verified adequate E Lincluding when HPCI was declared inoperable _on May 5,_1989, due to flow controller malfunctio .7 Power Ascension Oversight and Assessment (40500, 35502)
As part of the Peach Bottom Restart Power Testing Program submitted on February 3, 1989, the licensee developed a program entitled "Ver-ification of Management Processes and Personnel Performance " The .
program' includes participation by: line management;.the Nuclear Quality Assurance (NQA) Auditing,-Technical Monitoring, Quality Services-(QS), Independent Safety Quality Engineering Group (ISEG), and Per-formance Assessment Division (PAD); the management' oversight group;.
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and an' industry observer. The inspector interviewed personnel on site, made observations and reviewed documents concerning the NQA role in the program since mid-April 1989. A previous NRC inspection (50-277/89-11 and 50-278/89-11) reviewed related areas in early April 198 The NQA Technical Monitoring section's scope includes observation of shift crew control room performance, safety system lineups, surveil-lance and routine tests, modification acceptance tests and other-activities. This section has performed 116 technical observations covering operations, maintenance, instrumentation and control, modif-ications, services and security functional areas. These.are performed in accordance with written guidance and summary reports are provided on a monthly basis. The NQA audit section will perform two audits during the power ascension program to verify the compliance of three rpe;ific systems with Technical Specification requirements. Tne audJt section will also perform an overall audit to verify compliance with commitments made to the NR ISEG's review includes certain special procedures, surveillance tests, reactor engineering tests, observation of-test activities in the control room and Test Review Board activitie PAD's review includes four around-the-clock assessments of five days ,
duration each covering cont: o1 room activities, chemistry, radiologi-cal protection, maintenance and certain surveillance tests.
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The personnel resources involved in these NQA activities appear to be substantial. NQA supports the routine baseline QA programs as augmented to address the power ascension program. About twenty people are involved in the direct activities with full shift coverage being provided by ISEG through the 35% power hold '
point and by PAD during their four assessments. Some overlap is apparent in that several of the NQA groups provide coverage of the same activities. NQA activities are coordinated by the QS section including weekly meetings of the NQA groups. The NQA findings are to be provided through the General Manager-NQA to the management oversight tea Several NQA managers, including
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the Peach Bottom Quality Manager and the Manager-PAD, appear to ;
serve dual roles in that they are part of NQA's monitoring program and also serve as members of the management oversight tea In summary, at the conclusion of the first two weeks of the scheduled 14 week power ascension program, and NQA activities appear to be supported at an edequate resource level and the scope of issues considered appears to be reasonably broad with some overlap and possible resultant duplication of the effort -
between several of the NQA groups being realize q 5.0 Engineering and Technical Support Activitie_s y
5.1 Torus Water Level During a Loss of Coolant Accident (LOCA)
(71707)
During review for startup of another PECo facility (Limerick 2),
a question was raised concerning the. definition of post-LOCA torus water leve Post-LOCA torus water level drawdown occurs as a result of emergency core cooling system (ECCS) operation transferring torus. water into the reactor vessel and then into the drywell through the break. This phenomenon was not accounted for in the original design calculation On February 2,1989, the licensee made a four hour notification to the NRC concerning the above unanalyzed condition that could significantly affect plant safety. General Electric and Bechtel began analyses to determine the potential impacts on the following areas:
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Hydrodynamic loads,
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HPC1/RCIC turbine exhaust sparger submergence,
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Safety Relief Valve quencher instability,
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Post-LOCA dose calculatio?s,
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Containment penetration water seal integrity,
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Containment analysis,.
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Appendix R alternate shutdown method,
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Torus water temperature and level detectors,
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Available net positive suction head (NPSH) for 1 ECCS pumps.
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After a preliminary evaluation of the above items was performed, the only area of concern was NPSH available for the ECCS pump Further analysis was performed by GE to consider "second order" effects that contribute to NPSH. This analysis took credit for post-LOCA containment pressure in determining NPSH, as was done in the original plant design. However, NRC Regulatory Guide states that credit can no longer be taken for containment pressure in determining NPSH. Nevertheless, Peach Bottom was l
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designed prior to issuance of Regulatory Guide 1.1 (11/70) and is not committed to it. GE analysis further stated that operator actions taken during use of the Transient Response Implementation Procedures (TRIP) will further ensure adequate NPSH. GE concluded that no plant modifications or procedural changes are require The inspector reviewed the GE technical report, PECo's safety evaluation report, EWR P-50880, and deportability evaluation forms. The four hour notification to the NRC was also subsequently rescinded. The inspector had no further questions and this item is closa .2 Control Room Habitability (71707)
On December 12, 1988, PECo engineering determined during a review of NRC Information Notice 88-61 that temperatures in the control room would exceed design limits during a high radiation ventilation initiation or during a high-high radiation isolatio During a high radiation signal, control room ventilation would realign to recirculation through high efficiency and charcoal filters without air conditioning. During a high-high radiation isolation, the entire ventilation system would shut down. The design basis outside atmospheric conditions are 95 degrees F and 50% humidity, and the design control room heat limit is 114 degrees FSAR section 7.19 states that during the above scenarios, control room operators would reduce heat loads in the control room to keep temperatures below 114 degrees However, a procedure or heat load reduction list did not exist to allow operators to take proper actio The licenses performed a test ir February 1989 and determined "
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that control room temperatures could exceed 130 degrees F during a high radiation ventilation initiation. Conditions would be worse under a high-high radiation isolatio To correct the situation, the licenste developed an Off-Normal (0N) procedure ON-115, " Loss of Main Control Room Ventilation,"
Rev. 1, 4/5/89. In addition, a safety evaluation was performed to delete the high-high radiation isolation. PECo determined that a high-high isolation of control room ventilation would increase the exposures to control room personnel due to inleakage. Further evaluation also determined that due to any design basis accident, the high-high isolation setpoint would not be reache Therefore, the licensee determined that the modification to delete the high-high isolation could be completed after restar _ _ _ _ _ _ - _ - _ - - - _ - - _ _ _ _ _ _ _ - _ - _ -
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The inspector reviewed LER 2-88-32 (Rev. O and Rev. 1), ON-115, and the safety evaluation for MOD 5112. ON-115 provides direction to reduce heat loads in the control room. MOD 5112 can easily be accomplished during power operation. In addition, the licensee is examining a:long term fix such as providing a seismic, class 1E powered, dedicated air conditioning unit for the control room. The inspector had no further question .3 Emergency Cooling Tower (ECT) (71707, 61726)
. Section'3.7.4 of NRC. Inspection Report 277 and 278/89-08 discusses the ECT.and Emergency Service Water / Emergency Cooling Water (ESW/ECW) system and noted the system's capability to function as designed must be demonstrated prior to restart. This report discusses the performance of special procedure SP-630-2,
" Integrated Test of the Unit 2 ECW System," performed on March 12,.1989. . It was concluded that an integrated test which demonstrated operability had not been done.
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The inspector observed SP-630-2, Rev. 1, dated April 6, 1989, and l
performed April 7 and 8, 1989. The test was completed
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satisfactorily and system operability was demonstrated. In i
addition, the inspector observed the performance of ST 13.21,
"ECW Pump, ECT Fan, ESW Booster Pump Operability IST" performed in parallel with SP-630- During ECT testing, two abnormalities occurred. The first problem occurred during performance of SP-630-2. The A and C RHR pump seal coolers cracked and ESW leaked into the A and C RHR pump rocms. Within a half hour, the leaks through the coolers wers isolated. it.e second problem occurred during performance of ST 13.21. The ESW discharge valve to the river, MO-498, did not completely clos At about 8:*iD a.m. on April 8, ?989, the control room received a report from a worker that the "A" RHR room hcd from six +o eight inches of water on the floor. The reactor operators and their l supervisors responded quickly and thoroughly to the report and promptly identified and isolated the leak. Actions were taken to examine the other ECCS rooms on both units for leakage. No other leakage was found. It was determined that the "A" and "C" RHR
- pump seal coolers had ruptured causing the flooding.
i Severe wall thinning was identified where the covers had cracked.
l The B and D seal cooler covers were also found to have reduced L wall thickness; they were removed. The licensee performed an evalua-L tion and designed, fabricated and pressure tested replacement seal I
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cooler covers for Units 2 and 3. An RHR pump, valve and flow test was successfully run and no leakage was identified. Long term cor-rective action will be to replace the entire seal cooler unit since replacement parts are also no longer availabl The cause of the cracked seal cooler covers was due to a water hammer after the ECW pump started with subsequent discharge valve opening after 35 seconds. ;The ESW booster pumps had about 25 seconds to draw a vacuum in the pipe downstream of the ECW pum This occurred because the ESW booster pump suction pressure
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trip was reduced to prevent inadvertent tripping. A safety evaluation was performed to allow opening the ECW pump discharge valve prior to using the cooling tower; This will allow the ECW pump to inject water immediately upon loss of ESW. The original design for the 35 second delay in discharge valve opening was to prevent pump motor overcurrent due to pump start. However, actual test data did not support this theor The licensee is also investigating future long term corrective action The ESW discharge valve did not completely close because of a higher than expected differential pressure. During normal system operation a 45 psi differential' pressure is expecte The motor operated valve analysis testing system-(MOVATS) set the torque value for 67 psi differential. However, during performance of ST 13.21, different valve operations are used to' perform the test which gives an abnor-mally high differentia 1' pressure (80 psi differential).
To correct the problem, the licensee replaced the springpack and adjusted the torque higher to account for 80 psi differentia A partial test of ST'13.21 was rerun and the ESW discharge valve shut successfully. The inspector had no further questions in this are The inspector concluded that the licensee had conducted an adequate test to prove ECT operabilit .0 Review of Licensee Event Reports ILERs) (90712, 92700)
The inspector reviewed LERs submitted to the NRC to verify that the details were clearly reported, including the accuracy of the description and corrective action adequacy. The inspector determined whether further information was required, whether generic implications were indicated, and whether the event warranted on site follow-u The following LERs were reviewed:
LER N LER Date Event Date Subject 2-88-012, Rev. 1 Inoperable Drywell Radiation Monitors 04/10/89 04/02/88
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2-89-03,-Rev. 1- Primary Containment Isolation and Shutdown 04/26/89 Reactor Scram 02/7/89 2-89-04 High Pressure Coolant Injection System 04/19/89 Inoperable Due to Design Deficiency (See u 03/20/89- Section 4.2.1)
2-89-29, Rev. 1 Inadequate Flood Protection of Emergency 04/19/89 ' Core Cooling System Pump Rooms (See
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11/10/88 Section 3.5)
No unacceptable conditions were note .0 Surveillance Testing (61726, 71707, 72508, 61705, 61707, 72700)
s 7.1 Loss of Off Site power Test On-April 13, 1989, the licensee performed a simulated loss of off site power surveillance test on Unit The procedure implemented was ST 11.6-2, Revision 13, " Diesel Generator Simulated Auto Actuation and Load Acceptance for Unit 2". The inspector observed the test from the control room. The test required many groups of participants who were adequately instructed in their participation in the test. The test was effectively coordinated from the control room by the shift supervisar and the tett coordinato Test performance was determined to be satisfactory.
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7.2 Reactor Core Isolation (ooling (RCIC) System Testing On May 3, 1985, the licensee performeo surveillance test (ST)
10.2, "RCIC Flow Rate At 150 PSIG Steaa Pressure," Rev. 7, 06/01/88. During performance of the ST, the inspector noted-several problems with the procedure. A note prior to step 9 was misplaced; it should have been located in front of step 12. The inspector also noted several errors in the procedure with control panel, instruments and control number designations. Finally, in step 34, the test was stopped because the procedure was written such that RCIC began losing speed when control of the turbine was transferred to the remote shutdown panel. The procedure instructed the operator to turn the flow controller completely counterclockwise to the minimum speed setting of 2200 RP However, the minimum speed of the controller was actually 600 RPM. After the test was stopped, operations also determined that the RCIC' barometric condenser condensate pump did not operate properl The licensee temporarily changed the ST to correct the procedural deficiencies. A permanent revision is being processed. The RCIC condensate pump trouble was traced to a mechanical relay in the
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starting circuit for the pump DC motor. The relay was cleaned
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and aligned successfully. The inspector witnessed troubleshooting and repair of the RCIC condensate pum The remainder of the ST was successfully completed on May 4, 1989. The inspector had no further question .
7.3 High Pressure Coolant Injection (HPCI) System Testing On May 5,1989, HPCI testing per ST 10.2, "HPCI Flow Rate Test at j
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150 psig Steam Pressure" was determined to be unsatisfactory due ;
to HPCI flow controller deficiencies. The licensee declared HPCI !
inoperable at 4:00 a.m., and entered Technical Specification !
3.5.C.2 and 4.5.C.2. This allows seven days of reactor operation j as long as RCIC, low pressure emergency core cooling, and j automatic depressurization systems are verified operabl Testing of the RCIC, low pressure coolant injection system (LPCI), core spray system (CS) and automatic depressurization ,
system (ADS) were conducted in accordance with Technical i Specifications. An ENS call was made at 10:49 a.m. to report l this conditio *
The licensee determined that the HPCI flow controller problems were :
due to an incorrectly installed wire in the Alternate Shutdown Con- !
trol Panel. The wire was reconfigure and HPCI retested satisfac- .i torily on afternoon shift May 5, 1989. At 9:45 p.m. HPCI was declared I operable. The wiring error is unresolved pending a review of the !
licensee investigation in a future inspection (277/89-15-02). j l
The inspector observed the initial HPCI test, the troubleshooting j activities and the retest. The final test was effectively run. The j inspector toured the HPCI room during the test and noted that a !
representative from the QA Performance Assessment Division was presen !
No unacceptable conditions were note !
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7.4 Routine Surveillance Observations !
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The inspector observed surveillance tests to verify that testing j L had been properly scheduled, approved by shift supervision, ~
control room operators were knowledgeable regarding testing in progress, approved procedures were being used, redundant systems l or components were available for service as required, test i instrumentation was calibrated, work was performed by qualified i personnel, and test acceptance criteria were met. Daily i surveillance tests including instrument channel checks, jet pump I operability, and control rod operability were verified to be I adequately performe Parts of the following tests were l observed:
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ST 1.6, "RHR Logic A System Functional Test," Re , 4/5/89, performed on 04/12/8 ST 1.7, "RHR Logic B System Functional Test," Re , 4/5/89, performed on 04/13/8 ST 6.8, "RHR Pump, Valve, Flow Unit Cooler Functional," Rev. 37, 3/20/89, performed on 04/15/8 ST 3.3.6, "APRM Hi Flux In Refuel or Startup Mode Functional Test & Calibration Check," Rev. 3, 06/07/83, performed on 04/26/8 ST 9.5, "ECCS Bus Power Monitors Functional Test,"
Rev. 13, 03/24/89, performed 04/27/8 ST 10.5, "RWM Operability Check," Rev. 14, 04/13/89, performed 04/27/8 ST 10.6.1, "RSCS Sequence Mode Functional Test
- During Startup," Rev. O, 03/20/89, performed 04/27/8 ST 3.8.2, " Shutdown Margin (Unit 2 - Cycle 8),"
Rev. 7, 04/08/89, performed 04/27/8 ST 9.21-2, " Jet Pump Operability," Rev. 11, 12/27/88, performed 04/27/8 ST 3.3.2, " Cal. of the APRM System," Rev. 13, 11/15/88, performed 04/29/8 ST 8.1, " Diesel Generator Full Load Test," Re , 03/22/89, performed 05/02/8 SI2N-600-SRM-A2CW, " Source Range Monitor Channel A Calibration / Functional Check," Rev. 1, 04/24/89, performed 05/02/8 SI2N-60C-IRM-A4CW, " Intermediate Range Monitor Channel A Calibration Functional Check," Rev.1, 04/24/89, performed 05/02/8 No inadequacies were identifie .0 Maintenance Activities (62703)
8.1 Equipment Deficiencies During Unit 2 Startup The inspector monitored licensee's actions taken to cope with hardware and equipment deficiencies. This included problem identification, diagnosis and analysis, corrective actions and repair activities, and equipment return to service. Field inspection of maintenance activ-ities was also performed. Technical Specification (TS) compliance ,
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for safety systems out of service was also verifie Prior to initial criticality at 8:45 p.m. on April 26, 1989, the
"B" reactor recirculation pump was tripped by an operator because of scoop tube lock and high vibration on startu The operator took conservative action and tripped the pump. The licensee modified the startup procedure to ensure the manual-automatic (MA) control
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station was set for at least 10% demand signal. The procedure previously required a setpoint of 8%, which is close to the trip setpoint of 6%. The pump was subsequently restarted without any problem On April 30, 1989, the "A" reactor recirculation pump's scoop tube was locked up in accordance with operating procedure SO 2D.7.A-2 because of erratic speed changes. Licensee troubleshooting determined that the controller was operating abnormally and it was exchanged with one from Unit 3. After testing and controller monitoring, the
"A" pump controller was returned to normal on May 2, 198 Intermediate Range Monitors (IRMs) B, C and F failed to respond to power increases during the two startups on April 27,1989 (see section 4.5). During the subsequent shutdown, the licensee replaced all three IRM detectors and performed post maintenance checkou IRM B and F were determined to be satisfactory and were returned to servic IRM C remained inoperable and bypassed because of a cable deficienc The inspector verified that this action was consistent with Technical Specification Control rods 14-55 and 38-43 exhibited problems because of abnormal operation during training startup activities. Control rod 14-55 was determined to have a leaking hydraulic control unit (HCU) accumulato The control rod was declared inoperable. The HCU accumulator was replaced and tested, and the control rod was returned to servic Control rod 38-43 would not move using normal drive pressure nor i under higher drive pressure per 0N-106, Stuck Control Rod Procedur This rod was also declared inoperable, and the licensee evaluated rod indications and parameters that were observed during rod strokin Directional control valves 120, 122 and 123, and the three filters were replace The rod was stroked, declared operable, and returned to servic t l
RCIC and HPCI testing determined some abnormal equipment operation '
during surveillance testing (see sections 7.2 and 7.3). The licensee adequately addressed these during maintenance and troubleshooting activitie The inspector concluded that the licensee effectively addressed all of these equipment deficiencie .2 Routine Maintenance Observations The inspectors reviewed administrative controls and associated documentation including blocking permits, fire watches and ignition source controls, QA/QC involvement, radiological controls, plant conditions, Technical Specification LCOs, equipment alignment and turnover information, post maintenance .
testing and deportability. Documents reviewed, if appropriate, f included maintenance procedures (M), maintenance request forms '
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(MRF), troubleshooting control forms (TCF), item handling
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reports,. radiation work permits (RWP), material certifications, and receipt inspection Portions of the following work activities were observed:
Document Equipment Date Observed
- TL-11-416 'IRM/SRM Checkout 04/28/89 MRF 8901890 Saismic Monitoring Instrument 04/28/89 TCF RCIC Barometric Condenser 05/04/89 Condensate Pump TCF HPCI Flow Controller 05/05/89 No inadequacies were identifie .0 Radiological Controls (71707).
During the report period, the inspector examined work in progress in both units, including health physics procedures.and controls, ALARA implementation, dosimetry and badging, protective clothing use, adherence-to radiation work permit (Rh'P) requirements, radiation surveys, radiation protection instrument use, and handling of potentially contaminated equipment and material The inspector observed individuals frisking in accordance with HP procedures. A sampling of high radiation area' doors was verified to be locked as required. Compliance .with RWP requirements was verified during'each tour. RWP line entries were reviewed to verify that personnel had provided the required information_'and people working in RWP areas were ' observed to be meeting the applicable requirements. ~ No unacceptable conditions were identifie .10.0 Physical Security (71707)
The' inspector monitored security activities for compliance with the accepted Security Plan and associated implementing procedures, j including: security staffing, operations of the CAS and SAS, checks :
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of vehicles to verify proper control, observation of protected area access control and badging procedures on each shift, inspection of ;
protected and vital area barriers, checks on control of vital area '
access, escort procedures, checks of detection and assessment aids,
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11.0 Assurance of Quality (40500)
11.1 High Pressure Coolant Injection (HPCI) Wiring Error The licensee identified a HPCI system wiring error during system testing at 150 psig reactor presstte (see section 7.3). The wiring error apparently occurred during HPCI system modification work asso-ciated with the alternate shutdown panel. This condition is another example of modification program deficiencies that were originally identified during a 1988-1989 audit and subsequent root cause analysi . The licensee's root cause analysis and subsequent corrective actions were ineffective in identifying or preventing this erro .2 Fire Protection Program Deficiencies The inspector noted fire protection program deficiencies and weaknesses-(section 4.3.17). Some equipment deficiencies had not been identified by the licensee and some fire equipment was not being periodically checke In addition, the position of Fire Protection Supervisor is currently being filled by a temporary assignmen .3 Surveillance Testing (ST) Performance The inspector noted that ST was being effectively coordinated and implemented. This was noted during prestartup testing (section 5.3 and 7.1) and during testing at power (sections 7.2,7.3,7.4).
12.0 Review of Periodic and Special Reports (90713)
The inspector reviewed the following:
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" Peach Bottom Atomic Power Station Monthly Operating Report,"
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"1988 Annual Report on Safety Relief Challenges at Peach j Bottom Atomic Power Station (Report #9)", dated 04/13/89 l --
" Reportable Occurrence - Motor Driven Fire Pump Out of Ser-vice At Peach Bottom Atomic Power Station," dated 05/01/8 No unacceptable conditions were identified.
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13.0 Allegation R1-89A-0025 Follow-up (71707)
The inspector reviewed an allegation received by letter from a former Peach Bottom contractor employee. This individual was concerned about the adequacy of the diesel generator (DG) drawings to reflect the as built conditions. He also stated that he brought this concern to the licensee's attention during an exit interview. He was also concerned that he was not informed of the status of the licensee's investigatio _ _ - _ _ _ _ _ _ _ _ - - - - - - - - _ _ _ _ _ _
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The inspector reviewed the licensee's documentation concerning this ite The licensee had documented the employee's concern on the exit form l AG-31-1 dated September 30, 198 Licensee follow-up included the initi-ation of Quality Concern Checklist form #88-04. The licensee reviewed this item and concluded that a safety concern did not exist. The unmarked test cables in the DG control panels were temporarily installed during initial startup, and they were being identified and then removed in accordance with procedure A-30, " Plant Housekeeping".
The licensee stated that they did not inform this individual of the results
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of his quality exit interview because it was not required by the program at the time. However, the licensee stated that a new program was imple-mented effective January 3, 1989, that requires such exit notification This was reviewed during NRC Inspection 277, 278/88-42. The new employee exit checkout program includes licensee follow-up by letter to inform people of followup actions in response to safety concern The inspector discussed the specifics of the allegation with licensee engineering and QA personnel. The inspector concluded that the licensee had performed adequate follow-up for the concern .0 Unresolved Items Unresolved items are items about which more information is required to ascertain whether they are acceptable, violations or deviations. Unresolved items are discussed in section 4.3.17 and .0 Management Meetings 15.1 Preliminary Inspection Findings (30703)
A verbal summary of preliminary findings was provided to the Manager, Peach Bottom Station at the conclusion of the inspection. During the inspection, licensee management was periodically notified verbally of the preliminary findings by the resident inspector No written inspection material was provided to the licensee during the inspectio No proprietary information is included in this repor .2 Attendance at Management Meetings Conducted by Region Based Inspectors (30703)
Inspection Reporting Date Subject Report N Inspector 4/5-11/89 Power Ascension 89-11/11 Florek 4/5-7/89 Electrical Team 89-13/13 Kosby Follow-up 4/10- Emergency Planning 89-12/12 Amato 14/89 4/5/89 Security 89-14/14 Smith
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