IR 05000277/1989016: Difference between revisions

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==REGION I==
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  ! Docket /ReportNo.(50-277/89-16'
L50-278/89-16 License No. DPR-444 DPR-56
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    ,        q Licensee: . Philadelphia Electric Company
    ' Correspondence Control Desk
    .P. O. Box 7520 Philadelphia, Pennsylvania'.19101
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Facility Name:  Peach Bottom Atomic' Power. Station ~ Units 2 and 3 L
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l- Inspection At: Delta, Pennsylvania u              ,
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Dates: May 7 - June 17;.1989-
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  : Inspectors: .T. P. Johnson, Senior Resident Inspector
    . J. Urban, Resident Inspector L'. E. Myers,; Resident. Inspector      ,
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J. Gadzala, Reactor Engineer      1 J. H.' Williams,. Project Engineer      !
    -M.~ Dev, Reactor Engineer      .
L. Larson,iLicensing Engineer      1 R. E. Martin, NRR Project Manager
    ' D. Draper, Licensing En    eer .
Reviewed By:    m,    h  L!72 !By
    .J  1a  ,; Project Engineer  / 'd 9te Approved By:  db 2rw
    . T .,Ke ' jAct)1hg Chief,
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    .R6 acto
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rojects Section 2A,    e/dat/
Division' of Reactor Projects
  ~ Summary
,  Areas Inspected: -Ro'utine, on site regular, backshift and deep backshift special restart team and resident inspection (821 hours Unit 2; 232 hours Unit 3) of accessible portions of Unit 2 and 3, Unit 2 power ascension transient testing.. Unit 2 steady state. operation at the 35% power plateau, operational
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safety,' radiation protection, physical security, control room activities, licensee events, surveillance testing, Unit 3 refueling and outage activities, maintenance, and outstanding item Results: One violation associated with failure to follow modification      I installation, QC inspection and acceptance testing procedures was identified (sections 6.2.1 and 11.2). Two other NRC identified violations were identified; however, they met the criteria for not issuing a Notice of Violation. One was      1 8907060115 890626 PDR ADOCK 05000277 Q-  PDC
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associated with emergency core cooling system room drains (section 5.4.1) and the other was associated with high radiation door controls (section 5.4.2).
 
Two examples of a licensee identified violation for missed Technical Specification surveillance requirements were also noted (section 6.2.2). Several events, including an automatic reactor trip, were reviewed (section 4.2).      NRC shift coverage observations determined that: (1) licensed operator performance was adequate and control room activities were formally conducted, with one minor exception, (section 5.2); (2) logkeeping (section 5.3), shift turnover and communications (section 5.5), and control room staffing and training (section 5.6) were adequ~ ate; (3) Technical Specification (TS) compliance, deportability (section 5.7), and response to off-normal conditions (section 5.10) were conservative; (4) test and special evolution control (section 5.8) and teamwork (section 5.11) were effective; and, (5) procedure adherence by licensed control room operators was good; however, several procedural errors by non-licensed operators, reactor engineers and health physics personnel occurred (see section 5.9). Security and operations response to a bomb threat was timely and conservative actions were taken (section 10.2). Plant Management was noted as being involved in plant operations (section 11.1) and operations oversight continued to be effective (section 11.4). An increased maintenance backlog has occurred as indicated by control room annunciators in an alarmed condition and malfunctioning instruments. Licensee self assessment capability was demonstrated as evidenced by the Nuclear Review Board Meeting (section 4.3), the Station Review Meeting, conducted on June 9, 1989, and the Management Oversight Team Meeting (section 11.3).
 
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TABLE OF CONTENTS Page 1.0 Persons Contacted............................................      I 2.0 Facility and Unit Status.....................................      1 3.0 Previous Inspection Item Update..............................      2 4.0 Plant Operations Review..............-........................      '3 4.1 Operational -Safety Verification and Station Tours.......      3 4.2 Follow-up on Events.....................................      4 4.3 Nuclear Review Board (NRB)    Meeting....................... Il 5.0 Shift Activities and Observations............................      11 5.1 NRC Shift Coverage......................................      11 5.2 Operator Performance, Attentiveness and Formality.......      12 5.3 Logs and Records........................................      12 5.4 Plant Tours....................................    ......... 13 5.5 Shi f t Turnover and Communications. . . . . . . . . . . . . . . . . . . . . . . 17 5.6 Control Room Staffing and Training......................      17 5.7 Technical Specification Compliance and Deportability....      18 5.8 Test and Special Evaluation Contro1.....................      18 5.9 Procedure Adherence.....................................      18 5.10 Response to Off-Normal    Conditions...-.................... 19 5.11 Teamwork..................... ..........................      20 5.12 Human Factors Engi nee ri ng . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 6.0 Review of Licensee Event Reports..............................      21 6.1 LER Review..............................................      21 6.2 LER Follow-up...........................................      22 7.0 Surveillance Testing........................................      26 8.0 Maintenance Activities......................................      29 L  8.1 Routine Observations....................................      29 l  8.2 Unit 2 Maintenance Backlog..............................      30 9.0 Radiological Controls........................................      31 9.1 Routine Observations....................................      31 9.2 Allegation Associated with Radiation Work Permits.......      31 10 . 0 Phy s i c a l S e c u r i ty . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 l  10.1 Routine Observations......... ..........................      32 30.2 Bomb Threats............................................      32 11.0' Assurance of Quality.................... ....................      33 12.0 NRC Bulletin and Information Notices.........................      34 13.0 Unresolved Items.............................................      35 14.0 Management Meetings....... ..................................      35
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DETAILS 1.0 Persons Contacted
    *J. W. Austin, Superintendent, Modifications  {
G. A. Bird, Nuclear Security Specialist-J. B. Cotton, Superintendent, Operations
    *T. E. Cribbe, Regulatory Engineer  i G. F. Daebeler, Superintendent, Technical  i
    *J. F., Franz,. Plant Manager D. P. LeQuia, Superintendent Services G. Lipsey, Power Ascension Manager D. R. Meyers, Support Manager J. T. Netzer,. Superintendent, Planning, Scheduling and Reporting D. L. Oltmans, Station Chemist 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
    *P. Sawyer, Actir.g Senior Health Physicist D. M. Smith, Vice President, Peach Bottom Atomic Power Station Other licensee and contractor employees including all six Shift Managers were also contacte *Present at exit interview on site and for summation of preliminary !
finding '
2.0 Facility and Unit Status    !
2.1 Unit 2 This inspection period began with Unit 2 at rated pressure and at 3%
power. A High Pressure Coolant Injection (HPCI) system wiring error was being reviewed (see section 6.2.1). HPCI was subsequently tested satisfactorily from the alternate shutdown panel on May 8,198 Safety. relief valve (SRV) testing was performed on May 9, 1989; however, SRV 71L failed to reclose initially and three SRVs had position indication problems. A drywell inspection at 450 psig reactor pressure occurred on May 10, 1989. One valve had a packing steam leak which was repaired. The licensee concluded that SRV 71L required replacement during subsequent SRV testing on May 11, 198 The licensee shut down Unit 2 on May 11, 1989. SRV 71L was replaced and the unit restarted on May 13, 1989. SRV retesting was completed satisfactorily on May 14, 1989 (see section 7.4).
 
l    During reactor heatup to rated conditions on May 14, 1989, problems I
were noted with the electro-hydraulic control (EHC) system. The reactor was taken subtritical and the EHC system was repaired (see
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section 4.2.1). The reactor was restarted and the reactor achieved rated _ pressure conditions (920 psig) on May 15, 198 On May 19, 1989, at 7:22 a.m., the Unit 2 reactor automatically tripped from about 20% power. The cause of the trip was a failed
    "three element / single element" control' switch in the feedwater level control . system. This malfunction resulted in a low reactor water L    level tri Safety systems reacted automatically to this condition and licensee emergency actions were appropriate. Upon completion of
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the licensee's root cause analysis and corrective actions, Unit 2 restarted on May 21, 1989 (see section 4.2.2).
 
On May 22, 1989, the turbine generator was started up and synchronized with the grid at 21% reactor power later that day. A malfunction in the offgas recombiner system caused the licensee to shut down the turbine generator and reduce power to 5%. The licensee traced the problem to a high steam flow input combined with a restricted drain line from the offgas recombiner condenser (see section 4.2.3). The licensee subsequently restarted the turbine generator and synchronized to the grid on May 24, 1989. Successful turbine generator overspeed trip testing was completed on May 25, 198 Power ascension continued to 33% power during the remainder of the period. During the period May 25 to June 1,1989, the licensee dealt with problems associated with the traversing in-core probe system, with the drywell to torus bypass leakage test (see section 7.5) and with a failed potential transformer in the emergency electrical E-22 bus cubicle (see section 4.2.5). On June 1, 1989, the plant attained 33% powe This power level is the licensee's administrative limit for the NRC's modified Order which requires a 35% reactor power hold poin .2 Unit 3 The licensee continued the seventh refueling outage on Unit 3, which began October 1, 1987, including maintenance and modification activitie Repairs to the reactor pressure vessel manway access cover began on June 5, 1989. The next milestone for Unit 3 is the control rod drive exchang .3 Common The annual emergency plan exercise was held on June 14, 198 The exercise was evaluated by an NRC tea .0 Previous Inspection Item Update (92701, 92702)
3.1 (Closed) Unresolved Item (277/88-28-04; 278/88-28-04). This item  I pertains to the ',ack of documentation to verify the completion of the Nuclear Review Board (NRB) action items by licensee managemen The h .h ma_ _ _ _ _ - - _ _ _ - _ _ _ _ _ _ _ _ _ _ - . - - . a - - - - -
 
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  ' inspector! reviewed various minutes of NRB meetings and documentation supporting- the closure of'the NRB's action items for Units 2 and 3, and found them satisfactory.- Review of the current listing of the Commitment Tracking System indicated that there are no outstanding NRB open items pending resolution by Peach Bottom management. Based-on review and discussion with licensee representatives, the inspector
  . determined that licensee action was adequate. This item is considered close ' (Closed) Unresolved Item'(277/89-07-10; 278/89-07-10). This item pertains to the misapplication of fuses in 125 VDC panel 2BD306
  . circuits 29-BD-30604 and 29-80-30605 (Unit 2), and, panel 3DD306 circuit .29-3DD-30605 (Unit 3). In accordance with single line diagram E-26, Sheet 1, Revision 1, these fuses were specified as type
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  "FRN'!-30 Amp, but the installed fuses were type ."NON" and ''KON".
 
The' licensee investigated the causes.of the above discrepancies and'
  ..determi'ed n that the single line diagram was. revised to meet 10 CFR 50, Appendix R, Fire' Protection requirements. However, the replacement of these fuses was not accomplished and there was no' firm
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  ' schedule to replace these fuses at that time. Later, these fuses were replaced with' correct fuses as designated in single line diagram E-2 The inspector verified that the fuses. currently installed in the above circuits are type "FRN-R-30". Also, to preclude a similar misapplication from happening in the future, the licensee is in the process of establishing a plant wide listing of approved fuses used in' electrical protective devices. The licensee will verify and update the status of all such fuse Based on the above review and discussion with the cognizant plant
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support engineers, the inspector determined that the licensee's corrective action was adequate. This unresolved item is close .3 (Closed)UnresolvedItem(277/89-15-02). High Pressure Coolant Injection system modification system wiring error (see section 6.2.1).
 
4.0 Plant Operations Review 4.1 Operational Safety Verification and Station Tours (71707)
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 verification of safety system status and limiting conditions for operation, corrective actions, and review of facility records and log Specific comments and conclusions are addressed in section The inspectors performed 700 total hours of on site backshift time, including 330 hours of deep backshift and weekend tours of the
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t    4 facility. Deep backshift inspections included around-the-clock coverage from May 7 to June 2, 198 .2 Follow-up On Events Occurring During the Inspection (93702)
4. Unit 2 Electro-Hydraulic Control (EHC) Malfunction on May 14, 1989    I On May 14, 1989, during reactor heatup and pressurization to rated (920 psig), ' abnormalities were experienced with the electro-hydraulic control (EHC) system. The EHC pressure setpoint controller malfunctioned and EHC indicated pressure (reactor steam) was about 80. psi lower than actual reactor pressure. The licensee decided to insert control rods and to depressurize at 8:40 p.m. on May 14, 1989, in order to troubleshoot the EHC system while the reactor was subcritical, The Superintendent of Operations reported to the site and proceeded to the control room to assist the operations shif Licensee troubleshooting activities identified a loose gear on the EHC setpoint. controller drive motor as the cause of the malfunction. The gear was tightened, and other similar devices were checked satisfactorily. Calibration checks for the EHC pressure transmitters PT 2864 and 2865 found them within tolerance; however, they were recalibrates. A management. meeting was held in the control room to discuss the non-linear calibration curve for these pts versus actual reactor pressure. A GE engineer stated that a 50 psi deviation at mid-range (450-500 psig) was normal. The licensee restarted the reactor and criticality was attained at 11:23 a.m. on May 15, 198 The inspector monitored licensee actions during problem identification and troubleshooting activities. The inspector determined that the licensee acted conservatively in taking the reactor subcritical without EHC availabl Operations management was also noted as being involved in operations oversight and direction. The inspector sttended the EHC management meeting and noted that plant min'gement was also involved in this even No unacceptable conditions were note . Unit 2 Automatic Reactor Scram on May 19, 1989 The Unit 2 reactor automatically tripped from about 20%
power at 7:22 a.m. on May 19, 1989. The trip occurred after the reactor operator shifted the feedwater level control system (FWLCS) from single element to three element control. This action caused the one operating reactor feed pump to increase spee _ _ - _ ____---
 
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The increased feedwater flow resulted in a low suction pressure trip of the feed pum Reactor level then decreased to the automatic trip and containment isolation setpoint of 0 inches. Before a feed pump could be returned to service, the water level continued to decrease to about minus ,42 inches. The alternate rod insertion (ARI) system actuated and both reactor recirculation pumps tripped. The high pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC) systems did not automatically initiate. These safety systems all actuate at a reactor level of minus 48 inches; however, HPCI and RCIC did not actuate because their trip logic is different. The licensee recovered
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reactor water level with the reactor feed pump, reset the trip and containment isolations, and made an ENS call at-8:16 The licensee determined that the root cause of the trip was a defective single to three element switch in the FWLCS. When the switch was placed in the three element position, its contacts apparently did not close, resulting in a perceived low level condition. The operating feed pump increased speed and feed flow, causing a low suction pressure trip. Water level decreased to -42 inches resulting in a reactor trip at zero inche The licensee confirmed that the HPCI and RCIC system initiation logic at-48 inches was different than the alternate rod insertion and the recirculation pump trip logic. An ENS call was made at 10:17 a.m. on May 20, 1989, to report that the reason RCIC and HPCI did not auto start was because the logic was not fully actuated. Other ENS calls were made at 2:45 p.m. on May 20, 1989, to report inoperability of the 2A core spray loop minimum flow valve while in hot shutdown; and, at 10:40 p.m., on May 20, 1989, to report that this core spray valve and the respective loop were returned to servic The inspector was in the control room at the time of the reactor trip. The inspector noted that there was a discussion between the reactor operator (RO) and Shift Supervisor (SS) prior to moving the switch to the three element position of FWLCS operation. This operation was being performed in accordance with GP-2, " Plant Startup" and the system operating (S0) procedure. When the FWLCS malfunction occurred, operator response was adequate. The R0 informed the SS of the problem and impending trip. The l  RO was unable to reset a feed pump to recover level prior to the tri The SS adequately implemented the transient response implementation plan (TRIP) or emergency operating procedures T-100, T-101, and T-99. The Shift Manager was
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l  conducting turnover for non-licensed operators and he -l L  reported to the control room a few minutes after the trip L  occurre After the unit was stabilized in the hot shutdown '
condition, the inspector reviewed control room instruments, j computer alarm print outs and the preliminary upset repor The operators on shift were interviewed and the inspector attended several trip debrief / root cause analysis meeting During trip recovery, a fire was reported to the control L room at 8:20 a.m. This required the fire brigade to b called out. An electrical cord was overheating in the turbine buildin Licensee actions were adequate in response to the fir After the unit was stabilized, the licensee noted that the control room total feedwater flow recorder was not operating. It was drawing a straight line ink trac The difference between total steam and feedwater flow was small. However, the individual feedwater flow recorder was operating and indicating correct feedwater flow. The licensee repaired the total feedwater flow recorde Licensee actions in response to this trip included the following:
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performing a root cause analysis and completing corrective actions,
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checking the FWLCS calibrations,
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PORC review of the completed GP-18 " Scram Review Procedure",
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completing operations incident report 2-89-51 on the trip,
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determining how the FWLCS was to be operated
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comparing the HPCI/RCIC initiation logic with the alternate rod insertion logic, and
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briefing the NRC restart team prior to startu Licensee post trip review and analysis determined that failure of the three element to single element switch was the root cause of the event. Licensee testing found that the switch did not close completely at all times when placed in the three element positio In addition, the switch's application is being reviewed. A new switch was installed in the control room panel. Other similar switches were also checked and no abnormalities were noted.
 
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Calibration checks on the FWLCS electronic cards found that two cards (104 and 107) associated with feed flow amplification were out of calibration. The licensee recalibrates these cards and determined that they had no effect on the transien The licensee reviewed the HPCI/RCIC initiation logic and recent associated surveillance test of instrumentation L  setpoints. Reactor water level decreased to -42 inches as indicated by three separate control room chart recorder The "as found" trip setpoints for the four trip' logics (A,B,C,D) indicated that the order of logic initiation was A-B-D-C, with a maximum difference of about 2.5 inche Also, all four logic trip devices were within the test acceptance criteria of -42 to -45 inches and all were within-Technical Specification limits of greater than -48 inches. The alternate rod insertion logic was confirmed to be:
    (A or C) and (B or D)
The HPCI/RCIC initiation logic was confirmed to be:
    (A or B) and (C or D).
 
The licensee determined that the A and B logic initiated, and the C and D did not initiate. This explains why alternate rod insertion actuated and why HPCI/RCIC did no The NRC restart staff reviewed the licensee's root cause analysis of the trip; monitored troubleshooting and repair activities; and, reviewed the licensee's upset and incident reports (2-89-51), GP-18 reactor trip review procedure, and corrective actions. The NRC restart staff provided 24 hour coverage of licensee post trip and pre-startup activitie The licensee restarted the unit on May 21, 1989, and criticality was achieved at 6:53 The FWLCS was subsequently shifted to three element control at 9:02 on May 25, 1989. Three element control of reactor water level was as expected in automatic FWLCS operatio .2.3 Offgas Recombiner Abnormality on May 22, 1989 At 12:56 p.m., on May 22, 1989, the turbine generator (TG)
was synchronized with the grid at 21?s reactor powe During afternoon shift on May 22, 1989, at about 8:15 p.m.,
high level and high pressure occurred in the offgas recombiner condenser. With the potential for problems with ,
condenser vacuum, the licensee tripped the TG at 10:15 p.m., and reduced power to 5?s
 
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4    8 due to this offgas recombiner abnormality. During this transient, a small gaseous release occurred into the recombiner building and out through the Unit 3 reactor building ventilation stack. This release was calculated to be 1.67% of the whole body and 0.3% of'the skin dose Technical Specification limit The reactor remained at 5%
power until troubleshooting and repairs to the offgas recombiner system were complete Licensee actions included a complete walkdown of the offgas and recombiner systems, review of operational data from the recombiner transient, review of the release flow path, inspection of the recombiner condenser for possible tube leaks, and review of the system design and operating procedure The licensee concluded that a high steam input (9200 versus-7500 pounds mass per hour) to the jet compressor caused high level and high pressure in the offgas condenser shell side. This caused a flow backup in the offgas stream and could have caused a loss of main condenser vacuum. No tube leaks were found in the recombiner condenser. The licensee confirmed the release path to be from the offgas recombiner condenser shell side relief valve to the recombiner building sumps and into the ventilation system. The licensee placed the offgas and recombiner systems back in service at 6:30 a.m. on May 24, 1989, to monitor its operation. No further difficulties were note The inspector observed licensee actions in the control room and in the health physics office. The licensee evacuated the recombiner building as required by procedure ON-104,
  " Vent Stack High Radiation". Immediate and follow-up actions were consistent with procedures and were conservative. The inspector observed licensee troubleshooting activities and attended several meetings at which system operations were discussed. The inspector also walked down the affected system with the system engineer and the plant Manager. The inspector concluded that the licensee took adequate immediate actions, determined the root cause and initiated appropriate corrective action .2.4 Unit 2 Torus Level Increase on May 26, 1989 At about midnight on May 26, 1989, the inspector noted an increasing level in the Unit 2 torus. Level was 14.75 f and was increasing slowly. The reactor operator (RO) had also noted the increase. Several minutes later the high level alarm occurred at 14.80 ft. The RO began to pump down the torus, and alerted the Shift Supervisor and Shif t
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Manage All possible inputs into the torus were evaluated. The R0 noted that the A loop of RHR was tested during the preceding shift and that the C RHR pump discharge check valve sometimes fails to fully seat. The RO sent a non-licensed operator to the C RHR room to check closed the external actuator arm on the check valve. Torus' level l  peaked at 14.87 ft. which is below the TS limit and entry
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condition for T-102, " Containment Control" (14.90 ft.).
l  The inspector calculated that the input from the RHR stayfull system via the condensate storage tank was about 15,000 gallons. This closely corresponded to an increase in torus level of about two inches (from 14.70 ft. to 14.87 ft.).
The inspector discussed the event with control room
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personnel. The Shift Manager directed the STA to write an incident repor Licensee corrective actions were adequat !
4.2.5 E-22 Emergency Bus Potential Transformer (PT) Failure on May 31, 1989 At about 5:10 a.m., on May 31, 1989, a guard and a non-licensed operator each reported an acrid smell in the E-22 4KV bus room. Shift management discussed corrective actions while the source of the smell was investigated. At 6:10 a.m., the fuses isolating the pts in the E-222 breaker compartment were pulled and no abnormalities were foun At shift turnover, at about 7:00 a.m., the oncoming licensee operations shift reviewed and discussed the situation, and prepared a contingency plan to shut down the reactor due to a possible anticipated transient caused by  ,
an inoperable E-22 bus. The E-22 bus may have had to be taken out of service to investigate this acrid odor in the switchgear cabinets. The E-22 bus supplies safety-related station load and control. According to the plan, the PT fuses were removed from circuit breaker E-22 bus compartment at 8:40 a.m. The plant generation support  i staff identified PT-2-54-1606 in the E-22 bus as damage The licensee entered a Technical Specification (TS)
limiting condition for operation (LCO) in accordance with TS Table 3.2.B. TS Table 3.2.B is related to the availability of the 4KV emergency bus undervoltage relays and the 4KV emergency bus sequential loading relays for the core and containment cooling system At 9:35 a.m., the E-22 4KV bus was returned to its original condition without any repair or replacement of damaged E-22 bus PT 1606. The NRC was notified via the ENS of a one hour notification due to an initiation of plant shut
 
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i down within 24 hours. The licensee initiated a maintenance request form (MRF) 8904467 to replace PT 1606 with a similar PT obtained from Unit 3. At 2:02 p.m., the licensee initiated a second TS LCO action statement, and the repair / replacement of the PT was' completed by 2:27 p.m. System operability was verified and the E-22 bus was returned to service. The NRC was notified and the LCO was cleared at 2:30 l The inspector examined the failed PT (GE type JVM-3,  l 4400V/120V) during licensee troubleshooting. The inspector also observed replacement work and verified that QC performed an independent verification of quality control replacement activities for the P The inspector attended the licensee briefing and review of the contingency plan related to the E-22 bus PT replacement and the facility's Technical Specification constraints. The inspector concluded that licensee actions were conservative and no unacceptable conditions were note .2.6 Local Power Range Monitor (LPRM) Spiking During the restart power testing program, Unit 2 experienced five LPRM detector failures of the 60 new NA-300 type detectors installed. The failures consisted of momentary spikes with indicated LPRM power level high enough to trip the reactor protection system (RPS) and generate a half reactor trip conditio Each time this occurred, the operating shift adequately responded to the half reactor trip, bypassed the malfunctioning LPRM, reset the RPS and verified the minimum number of LPRMs were operable. None of the 112 older LPRMs currently installed have exhibited this phenomeno Interviews with licensee personnel and GE representatives revealed that similar problems have occurred at other plants with NA-300 series type LPRMs. The detector vendor l  believes that the cause of this spiking is due to a uranium l  coating instability in the detector which produces a fine l  uranium powder with marginal adherence to remainder of coating. This powder is responsible for producing the random spikes as it breaks apart. The manufacturing process has since been changed to correct this coating instability and newer NA-300 detectors are not subject to this proble The vendor has found that by performing a voltage plateau curve test on the detector, the uranium powder is burned off the cathode and the spiking problem either stops or is reduce The licensee is planning on running this plateau l
 
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curve test on all 60 of their NA-300 LPRMs. The inspector will review the results of those test .3 Nuclear Revi9w Board (NRB) Meeting (40500)
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The corporate Nuclear Review Board (NRB) held meeting number 241 at the Peach Buttom Station on May 11, 1989. The inspector attended the meeting and observed that a quorum (including the principal NRB
,    members and NRB consultants) was present. The meeting was conducted in accordance with a detailed agenda which encompassed the scope of issues specified for NRB review in the Technical Specifications (TS).
 
The inspector noted that the current NRB meeting frequency is three times greater than required by the T Topics discussed included, but were not limited to the following:
readiness of the plant to proceed with the startup test program; operating abnormalities; unanticipated deficiencies; the emergency cooling tower test results; voltage regulation study concerns; reports by the Plant Manager, the Shift Manager, Plant Services, and the. Nuclear Services Division; reports on plant tours; LERs; PORC meeting minute reviews; Nuclear Quality Assurance audits; and ISEG activitie The NRB considered the results of operating experience from an event at Limerick by reviewing the Peach Bottom program for use of hoists and cranes. The licensee demonstrated its self assessment / independent assessment capability by reviewing whether the generic implications of specific incidents are systematically considere Consideration of generic implications, in this regard, would involve whether the root cause for given incidents is also applicable to other plant activities or equipment not involved in the specific inciden This topic was addressed by the Plant Manager and several of the consultants to the NRB. A consultant suggested that several LERs (2-89-02 and      ,
2-89-04) offered no discussion of the generic implications of the      1 subject incident and that such consideration should be give The inspector concluded that the NRB meeting appeared to be effective      '
and no deviations from TS or procedural requirements were observe .0 Shift Activities and Observations (71707, 71715)
5.3 NRC Shift Coverage The NRC restart team began 24 hour continuous shift coverage on April 26, 1989 (see NRC inspection 277/89-15,278/89-15). This inspection coverage continued until 11:00 p.m. on June 2, 1989, when the licensee had been at a steady state 35% power level for approximately      '
48 hours. During the Memorial Day weekend from 7:00 p.m. Saturday, May 27 until 7:00 p.m. Monday, May 29, 1989, continuous inspection
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coverage.was suspended due to steady-state plant conditions. During this period of non-continuous coverage, unscheduled random backshift i inspections and tours were performed by the NRC restart tea .2 Operator Performance, Attentiveness and Formality The inspectors routinely monitored licensed operator alertne~s, s attentiveness and job performance in accordance with the requirements of the appropriate sections of the Operations Manual. No instances of operator inattentiveness were note Operational activities were conducted formally as noted during shift turnover, during routine j control panel monitoring, and during off-normal and emergency '
situations. Several times during the shift coverage, inspectors noted that the unit reactor operator was performing administrative duties including answering the phone at the console, performing paperwork, etc. These duties could have the potential to distract an operator.from his licensed duties. The inspector checked the Operations Manual section 7 which describes the frequency of panel checks. These required panel checks were performed. This item was also discussed with operations management who had also noted two instances of excessive administrative workload for reactor operator ~
One instance of a brief loss of decorum by a Chief Operator (common unit reactor operator) was noted by the inspector at 10:20 a.m. on May'26, 1989. A discussion between the operator and the Shift Manager was in progress when the operator elevated his voice and 'used body / hand gestures. The duration of this episode was brief, i.e., a few seconds; and at no time was the operator inattentive to his common unit electrical / radiation monitoring panels. Following the outburst, the Shift Manager relieved the operator temporarily, and held a discussion in his office. After about ten minutes, the operator resumed his Chief Operator duties. After the meeting with the Shift Manager, the operator acted professionally in all his licensed duties and activities. Further follow-up and discussions with the operator, the Shift Manager, and operations management were held. The inspector concluded that the Shift Manager's actions were prudent and timely with respect to disciplining the operato Apparently the outburst was caused by the operator's lack of understanding why the reactor pressure narrow range recorder was not being kept on-scale between 950-1050 psi The reason for a change in operating the reactor pressure setpoint during startup in GP-2 was apparently not communicated to the operators. Licensee management reviewed this item and provided the technical reasons for this change to operating personnel. The inspector had no further questions at this tim .3 Logs and Records (71707)
The inspector reviewed logs and records for accuracy, completeness, abnormal conditions, significant operating changes and trends,
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required entries, temporary plant alterations, conformance with
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Limiting Conditions for Operations, and proper reporting. The following logs and records were reviewed: Control Room Shift Supervisor Log, Reactor Engineering Logs, Unit 2 Reactor Operator Log, Unit 3 Reactor Operator Log, Chief Operator Log, STA Log, QC Shift Monitor Log, Radiation Work Permits, Locked Valve Log, Maintenance Request Forms, Temporary Plant Alteration Log, Special Procedures Log, Information Tag Log, Annunciator Mode Log, Plant Status List, and Ignition Source Control Checklist Control Room logs were compared with Administrative Procedure A-7, Shift Operations, and the Operations Manual. Frequent initialing of entries by licensed operators, shift supervision, and licensee site management constituted evidence of licensee revie Logkeeping by control room operators was generally thorough and accurate and in accordance with the Operations Manual. However, several minor instances of poor logkeeping were noted. During the 11 p.m. to 7 a.m. shift on May 16, 1989, the reactor operator did not log the noted operational problems with the position indication for the RCIC discharge check valve and the vibration alarm on th reactor recirculation pump. Other occasions of poor logkeeping included two instances of write overs without initialling. These instances were discussed with the respective operator, and with shift and operations management. Further reviews of operator logs by the inspector indicated improvement .4 Plant Tours Each shift inspector conducted random tours of plant areas. These tours included inspection of plant equipment, non-licensed operator performance, work activities, health physics controls and securit During these tours the following items were note . Floor and Equipment Drains During a tour of the Unit 2 Reactor Core Isolation Cooling (RCIC) system pump room on May 14, 1989, the inspector noted that equipment drain plug DRN-2-208-2062 was removed. !
A tygon tube was connected between the RCIC pump pedestal drain and the equipment drain. No one was in the immediate j are The inspector returned to the control room and obtained the I most recent copy of GP-2, " Normal Plant Start-Up". Step 3.5.9 stated that all floor and equipment drains in the reactor building were closed per RT 13.9. The inspector questioned shift management concerning the type of I administrative controls in effec The temporary plant !
alteration (TPA) log did not contain an active TPA log entry that removed the plu I
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l Emergency core cooling system (ECCS) floor and equipment drain plugs are to be strictly controlled due to potential flood paths that could be. opened between various ECCS rooms-and the reactor building sump. Plugging floor-and equipment drains was done in response to nonconformance report (NCR)
P 88-123-213. Abnormal operating procedure A0-20A.1,
" Removing a Floor Drain Plug, Equipment Drain Plug or Cleanout Cover," was also written so that these plugs could be removed without the use of a TPA. Shift management approval is needed to open a drain (as stated on a-tag by each and every drain), and A0-20A.1 Attachment 1 is to be filled out. The procedure also states that anytime a drain is opened during reactor operation, a person must be st6tioned in the vicinit Failing to follow procedure A0-20A.1 is an NRC identified violation of Technical Specification 6.8.1 (277/89-16-01).
 
.However, no Notice of Violation will be issued in accordance with Enforcement Guidance Memorandum (EGM)
88-08, dated November 13, 1988. Discretion can be exercised if all of the following exists:
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Severity level V;
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Appropriate corrective actions were initiated prior to the close of the inspection;
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Non willful; and
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Non recurren The licensee determined that the root cause of the violation was failing to inform shift operations of the new drain control policy and newly written procedure A0-20 Immediate corrective action consisted of replacing the drain plug. Corrective action to prevent recurrence consisted of holding a critique, writing an incident report, providing a letter to shif t operations informing operators of the drain policy and A0-20A.1, and publishing this same information in the operations section newslette Future corrective action will consist of replacing A0-20 with a less restrictive administrative procedure and hanging new tags on all the drains that will require shift management approval for entry into the drain system in accordance with a soon to be written administrative procedur The inspector reviewed the licensee's letter, operations section newsletter, the draft incident report and attended the critiqu Tnese corrective actions were found to be satisfactor The inspector will review the remaining corrective actions in a future repor _ - -
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5.4.2 High Radiation Area Control At 9:55 p.m. on May 16, 1989, a shift inspector found a door labelled Locked High Radiation Area (HRA) opened with no individual providing positive door control. The door provided access to the containment personnel air lock and to .the outboard main steam isolation valve (OBMSIV) room on the 135 foot elevation of the reactor building of Unit The containment is a designated locked HRA and the OBMSIV room is potentially a locked HRA. The inspector immediately questioned nearby test engineers regarding whether any individuals were within the HRA and the responsibility for providing positive control for the opened door. The test engineers responded to the inspectors concern by calling security and health physics (HP). A security guard responded to the call, but took no action apparently because it was an HP problem. At 10:10 p.m. an HP technician arrived at the door. He explained that he had left the area 15 minutes earlier to start an air sample requested by his supervisor. He closed the open HRA door. The shift in:pector, satisfied that an apparent immediate safety concern was corrected continued with his tou HP supervision had decided before plant restart to control HRAs by locking all the areat that had the potential to become high radiation areas during reactor power operation ,
This would allow a check of the new procedures for control 9 of keys to locked HRAs to determine the adequacy of procedural controls and training efforts. However, this management decision was apparently ineffectively communicated to the HP technicians as some HP technicians were unaware of the decision. The technicians were confused over the existing posting and control of areas that were designated as locked HRAs. These areas would not become locked HRAs until the unit was at a higher power leve The attitude of the HP technicians led to reduced sensitivity to the posting and control of the designated locked HRA The requirements for positive control of locked HRAs are specified in Technical Specification (TS) 6.13. In ,
implementing these requirements, several procedures were not j followed by licensee personnel:  )
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A-114, Rev. O, " Locked High Radiation Controls"
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A-111, Rev. O, " Duties and Responsibilities of Health Physics Personnel"
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A-116, Rev. O, " Radiation Worker Responsibilities"  !
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HP-215, Rev. 5, " Establishing and Posting l
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The HP technician had the responsibility and authority to'
change posting based on radiation levels which he knew by surveys to be only a radiation area where the HP technician was directed.to obtain an air sample by an HP supervisor, he did not change the posting but left the door ope The incident was investigated by the licensee per procedure A-110, Rev 2, " Radiological Occurrence Reports (ROR)". A completed ROR was reviewed by the inspector on May 19, 1989. The inspector determined that the immediate corrective actions were adequate. However, weaknesses were noted with both the long term corrective actions and the root cause analysis This was discussed with the licensee and the licensee indicated that a revised ROR would be initiate The inspector noted that additional licensee commitments were made for root cause analysis and for corrective actions. The inspector considers these to be adequat Failure to follow procedures A-114, A-111, A-116 and HP-215 is an NRC identified violation of Technical Specification 6.8.1 (277/89-16-02). However, no Notice.of Violation will be issued in accordance with Enforcement Guidance Memorandum (EGM) 88-08, dated November 13, 1988, since the following conditions exist:
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Severity level V;
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Appropriate corrective actions were -
initiated prior to the close of the .
inspection;
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Non-willful; and
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Non-recurren The inspector had no further questions at this tim .5 Shift Turnover and Communications Shift turnover activities, and operator control room and external verbal communications were observe Shift turnover activities were professionally conducted. All required information was passed on either verbally or documented in the turnover checklis Shift Manager turnover briefings were effective in informing operating personnel of plant status, problems and planned activitie Face-to-face communications were confirmed by repeating back the message to the originator. Operator communications with other work groeps was also reviewed and was effective. No unacceptable condit ons were note !
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5.6 Control Room Staffing and Training Control' room staffing was checked and found to be in accordance with Technical Specifications 6.2.2 and 10 CFR 50.54(k), (1), and (m). On May 19, 1989, the licensee informed the shift inspector that one reactor operator was temporarily removed from licensed duties due.to an abnormal medical evaluation. The licensee replaced this-operator with a. reactor operator from another shift. -This action maintained    ,
          ~
two fully qualified reactor operators on each of.the six operating shifts. .At the end of_the period, the licensee ~ maintained a staffing level of 18 senior reactor operators and 24 reactor operators for the -
six shift Of the total number of licensed operators, 13 have restricted li cen se s ~. These individuals are working on their reactivity manipulations and operating time above 20's powe T_he licensee tracks completion af reactivity manipulations and the time spent with the reactor above 20?4 power. .The Superintendent of Operations developed guidance to ensure that reactivity manipulations meet NUREG 1021 guidance. The inspector reviewed this guidance dated May 15, 1989, and concluded that NUREG 1021 guidance is being met. A tracking form (SP-1166, Exhibit T-1) is maintained for each    ,
  . individual. These forms are filed for each shift and maintained in    i the control room offices. Surveillance and routine test. performance is also tracked for trair.ing purposes and documentation. The shift test coordinator maintains these records. When an operator with a restricted license completes his required items, the forms are assembled and sent to the training department. The inspector reviewed selected files and discussed program implementation with licensee personnel. No unacceptable conditions were note .7 Technical Specification (TS) Comp ia ge and Deportability The inspector reviewed the li'cm ee's interpretation, 'mp"ementation and use of the plant TS, ind uding limiting conditions fr operation and action statements. The inspector determined that the licensee was using conservatism in declaring TS related equipment inoperable due to system malfunctions. Examples included the following: safety relief valve 71L, the HPCI system, E-22 bus relays and protective trips, intermediate range monitors, the core spray minimum flow valve, a reactor water level recorder, and the RCIC flow controller. All required ENS reports were made on the ENS phon No unacceptable conditions were note .8 Test and Special Evolution Control The Shift Manager and Shift Test Coordinator provided the operations staff with effective pre-test briefing Examples included the
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l\;  18 following: safety relief valve 71L testing and subsequent retesting; feedwater and condensate pump startup, turbine generator startup, synchronization and overspeed testing; and HPCI/RCIC system testin Tests and evolutions were well coordinated and professionally
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conducted. Several of the tests required temporary procedure changes. These changes were made in accordance with administrative controls. No unacceptable conditions were note .9 Procedure Adherence Procedure adequacy., compliance, and adherence was reviewe Control room licensed operators were adhering to operating procedures. No instances of procedural noncompliance by licensed operators were note The operators used the temporary change (TC) process when require ,
Permanent TCs were noted as being kept in the procedure cart in the control room. In a few instances, the operators displayed difficulty in locating a procedure that had a TC in effect. However, all TCs were eventually located and' adequately implemente Two cases of procedure noncompliance were noted by the inspector  .
during plant tourt (see section 5.4). One was by a non-licensed  '
operator due to lack of training and the other was by a health physics technician. The licensee also identified an instance where a non-licensed operator placed the drywell instrument nitrogen system in service without using the system operating procedur The licensee reviewed this event, prepared incident report #2-89-48 and implemented corrective actions. The licensee determined that poor communications and misunderstanding by the operator contributed to this event. The inspector reviewed the incident report including the root cause and corrective actions, and discussed the item with shift and operations management personnel. The inspector concluded that the licensee's review was adequat The inspector observed a traversing in-core probe system (TIPS)
operation in the control room on May 25, 1989. Two reactor engineers attempted to start the system but were unsuccessful. They then obtained system operating procedures S.5.4.1.A and S.S.4.1.B. One of the engineers missed a procedure step which requires waiting for the
  " Ready" light to come on before attempting to insert a detector. The light would not illuminate, but he pressed Auto Start to begin detector insertion. The system did not respond. A more experienced reactor engineer then informed the other two of several inadequacies in the TIPS procedures and advised them of the correct way to operate the syste Procedure S.5.4.1.8 is missing instructions for operating the X-Y plotter which caused the engineers to miss a trace during a TIPS run and necessitated repeating the run. Some of the TIPS panel labelling
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I is inconsistent with procedure terminology and several switches on the panels are either not labelled or have some unlabelled position The inspector was informed that a complete rewrite of the TIPS )
procedures is planned. In the interim, TIPS will be operated using i the existing approved procedures. However, these procedures require 4 the engineer's knowledge of the system for implementation. These deficiencies were identified to the licensee for corrective action During surveillance test ST 6.1.2-1 performed on May 20, 1989, a non-licensed operator noted that he had an out of date revision of the procedure in use. He stopped the test, acquired the correct i revision and performed the test satisfactoril The reason for the out'of date revision was that the ST was revised after the test was ,
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issued to operations for performance. The operator apparently did not check the ST index for the correct revision. However, he did later note the error and obtained the current ST revisio The inspector determined that the way in which STs are issued could cause out of.date revisions to be used. The ST coordinator issues a group of STs on Fridays prior to the week they are scheduled for performance. The ST Coordinator checks that each ST is current aginst the ST index. However, if a new revision was to be issued prior to ST performance and if the individual performing the ST failed to check the ST index, an outdated revision would be used. To correct this situation, a letter has been issued to remind individuals to check for current revision In addition, the ST Coordinator now checks for issued, out of date ST revisions when he receives a newly revised ST. These new licensee practices have noted two discrepancies during the last two weeks of this inspection period. The inspector had no further question .10 Response to Off-Normal Conditions Operator response to off-normal conditions was timely, conservative, and in accordance with operating / emergency procedure Examples included the following: reactor trip (section 4.2.2), EHC malfunction (section 4.2.1), loss of offgas recombiner (section 4.2.3), bomb threat (section 10.2), and E-22 bus room acrid smell (section 4.2.5).
 
Once the plant was stabilized, equipment troubleshooting, maintenance or repair, and equipment control was adequately performed. One instance of an unexpected result of a troubleshooting control form (TCF) occurred on May 23, 1989. During implementation of an approved TCF for the EHC system, the bypass valves opened unexpectedl Operator response was adequate and the troubleshooting was suspende i i
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In general, operating problems or concerns eventually result in positive corrective action, such as procedure changes, troubleshooting, or maintenanc .11 Team Work Each shift team was evaluated as being effective in accomplishing assigned tasks. The control room operations crew worked well together including coordination and direction of non-licensed operator activities (outside control room). The operators were also noted as working well with rther site groups including: system and reactor engineers during testing and troubleshooting; maintenance personnel during equipment turnover, repair and testing; health physics personnel; and independent oversight groups and managemen .12 Control Room Human Factors Engineering The licensee completed a control room design review on February 28, 1986, which addressed many human engineering deficiencies (HED) in need of correction. More than 70's of these HEDs have since been    ;
corrected. The majority of these were corrected during Modification    -
2132. 'The inspector noted some additional minor items which appear to have been misse Some examples include:
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low pressure turbine instruments are arranged in three rows corresponding to the three stages; except for inlet pressure indicatio high pressure turbine first stage pressure indication is marked " Turbine Inlet" even though the documentation such as the FSAR refers to it as first stage pressur oxygen sample switch (SS-2981) information label lists position 1 as middle torus and position 2 as upper toru The actual positions are opposit the primary containment isolation system status panel is not consistent in the arrangement of its indicating lights as to whether left is inboard or right is inboar t Other examples exist but these are representative of the issue. The    f licensee is continuing to address this deficienc Based on  l interviews with operators and management personnel, none of these    i discrepancies are considered to be significant. The licensee's    ;
progress will continue to be monitored and an update provided in a    1 future repor j j
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6.0 Review of Licensee Event Reports (LERs)
6.1 LER Review (90712)
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 site follow-up. The following LERs were reviewed:
LER N LER Date Event Date Subject 2-87-08, Rev. 1 Control room radiation monitor incorrect 5/25/89 configuration-5/29/87 2-88-07, Rev. 1 Inadequate surveillance due to test procedure 05/24/89 deficiency 10/26/88
  "2-89-05 Motor control center terminal blocks mir. sing 05/08/89 hold down bolts (see NRC Inspection 04/06/89 277/89-15, 278/89-15)
  *2-89-06 Containment atmosphere pneumatic tubing 02/09/89 improperly installed (see NRC Inspections 05/09/89 277/89-81 and 15, 278/89-81 and 15)
  *2-89-07 Excessive grease on emergency 4KV switchgear 05/09/89 fuse clip contacts (see NRC Inspection 04/11/89 277/89-15, 278/89-15)
  *2-89-08 Unit 2 containment isolation due to personnel 05/15/89 error (see NRC Inspection 277/89-15, 04/15/89 278/89-15)
  *2-89-09 HPCI wiring error 06/05/89 05/05/89
  *2-89-10 RSCS Surveillance test missed 06/09/89 05/14/89
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  *2-89-11  Scram discharge volume valves surveillance l4  05/30/89  test missed 04/26/89 03-88-03, Rev. 2 Unit 3 containment isolation due to RPS 05/19/89  alternate feed trips 05/20/88 6.2 LER Follow-up (92700)
For LERs selected for follow-up and review denoted by asterisks above, the inspector verified that appropriate corrective action was taken or responsibility was assigned and that continued operation of the facility was conducted in accordant with Technical Specifications and did not constitute an unreviewed safety question as defined in 10 CFR 50.59. Report accuracy, compliance with current reporting requirements and applicability to other site systems and components were also reviewe . LER 2-89-09 concerns a licensee identified High Pressure Coolant Injection (HPCI) system wiring error discovered during surveillance operability testing on May 5, 1989. This operability test noted a lack of automatic governor valve control when HPCI was initially tested at 150 psig reactor pcessure. The governor valve was full open with HPCI flow rate greater than the rated 6000 gp This condition also occurred when the HPCI flow controller was switched to manual. A wiring error was identified as an unresolved item (277/89-15-02) in a previous NRC Inspection 277/89-15, 278/89-15. (See section 3.3.)
 
The licensee performed an investigation and root cause analysis of the wirirg error event. The licensee determined that the root cause of this event was failure to follow installation instructions by craft electricians during the implementation of Modification 5061. This modification installed an analog signal isolator which provides electrical isolation for fire protection concerns on the HPCI flow controlle The installation error (by a contract journeyman electrician) resulted in a discrepancy in the configuration  e of the analog isolator. The polarity was reversed between  i
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the flow controller and the ramp generato The causes of this discrepancy were as follows:
 
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The electrician made field wiring connections using the industry standard practice of. color
,  matching (white to white, black to black, etc) in b
lieu of point to point as specified in installation procedure CD 5.3; and,
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The electrician applied the industry standard practice of positive (+) to black and negative (-) to white when bench wiring the isolator without regard to the external wiring color conventio The licensee also concluded that there were three c. contributing factors for this event:
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Inadequate Inspection post installation inspection was inadequate due to the failure of the Quality Control (QC) inspector to verify that the wiring installation was in accordance with the work instructions per procedure CD 5.3 and drawin Inadequate Field Wiring Check - The Field Installation Engineer used color coding to perform the point to point wiring check and therefore, failed to identify the installation error Communications used during the check were not specific with regard to wire number, cable number, or terminal poin Inadequate Modification Acceptance Test (MAT)
Procedure - MAT 5061 utilized Surveillance Procedure SI-2F-23-82-XXC0 " Calibration Check of HPCI Flow Instruments" to verify the instrument loop from flow controller to ramp generator and signal converter. The SI procedure did not provide sufficient overlap of tested components to assure the required portions of the loop were teste Licensee corrective actions completed included the following:
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HPCI was declared inoperable, redundant systems (reactor core isolation cooling and automatic depressurization) were satisfactorily tested, the wiring error was corrected, and HPCI was retested satisfactoril Supervisory personnel associated with implementation of modifications were briefed on this even ._ __ __ -____ _ _
 
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The specific individuals. involved in the installation, inspection, and testing of the isolator have been counseled on this event and the significance of the errors committe Installation Checklists for open electrical modifications have been changed to require the l  first line supervisor or the Site Lead Man (Job
,  Foreman) to verify correct installation of the
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work prior to QC inspection.
 
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In addition, corrective actions planned include:
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Review the event with construction, inspection, test, and plant personnel associated with the implementation of modifications and MATS. Areas to be discussed include: adherence to procedures / instructions, wiring color standards, use of wire tags as a construction aide only, and attention to detail regardless of apparent simplicity of the installatio Revise Construction Division Procedure, CD 5.3,
  " Procedure fo~r the Installation of Electrical Equipment" to require the Site Lead Man to verify the correct installation of the work prior to QC inspectio Enhance the modification process to further ensure that when an SI or other standard test is to be used to functionally test an electrical installation, the test adequately encompasses the components required to be teste Instruct personnel performing wiring checks in use of proper communications practices when performing wire checks or other similar task The inspector reviewed this LER; attended the licensee's critique and root cause meeting; reviewed operations incident report #2-89-44; reviewed the associated drawings and field installation; and, discussed this item with licensee engineering, management, and QA/QC personnel. The i'
inspector concluded that the licensee performed an in-depth investigation and root cause analysi Technical Specification (TS) section 6.8.1 requires written procedures in accordance with ANSI N18.7-1972 and NRC Regulatory Guide 1.33. These documents require procedures for modification installation, inspection and testin On May 5,1989, during HPCI testing and troubleshooting the licensee noted that MOD 5061 was inadequately installed, inadequately inspected by QC, and inadequately tested by engineering and I&C personnel. These successive failures of modification installation, inspection and testing procedures are collectively a violation of TS 6. !
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  (277/89-16-03). The unresolved item is administratively l  closed (277/89-15-02).
 
Since the overall modification process has been noted as a weakness by both the licensee and the NRC (see NRC Inspection 277/89-81,278/89-81), a Notice of Violation is being issued in this instance of a licensee identified-violatio . LERs 2-89-10 and 11 are two examples of licensee identified violations for failure to perform Technical Specification (TS) surveillance requirements (277/89-16-04). LER 2-89-10 concerns a failure to test the rod sequence control system (RSCS) at 50% control rod density as required by TS 4.3.B.3.a during a Unit 2 reactor startup conducted on May 14, 1989. The licensee determined that a personnel errcr by shift management during review of GP-2, " Plant Startup" was the root cause. The licensee also determined that the event had no safety consequences based on the following considerations: RSCS was adequately backed up by both the control rod pull sheet per GP-2 and by an operable .od worth minimizer system; the missed surveillance test (ST 10.6.2) was satisfactorily performed two weeks prior to ''1: disenvery; ST 10.6.2 was performed satisfactorily upon discovery; and, the control rod pull sheets in GP-2 vers adequately followe LER 2-89-11 concerns a failure to test the trip discharge volume vent and drain valves per ST 9.22 prior to Unit 2 startup on April 26, 198 This testing is required by TS 4.3.A.2.c. The licensee determined that'the cause was partly due to an omission from procedure GP-11C, " Mode Switch to Refuel" and partly due to the ST " Master File" requiring the test to be performed only at power.. The licensee determined that the consequences of this item were minimal based on the following considerations: ST 9.22 was satisfactorily performed on April 29, 1989, when the missed test was identified; a historical review to 1985 noted that these valves have demonstrated adequate stroke times; and, that the valves are tested monthly when the TS require a quarterly tes The licensee reviewed the ST " Master File" and did not find any other missed ST The inspector reviewed licensee corrective actions and determined them to be adequate to prevent recurrence. The inspector determined that failure to perform TS surveillance requirements meet the criteria for licensee identified violations. The inspector had no further questions at this tim )
 
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7.0 Surveillance Testing (61726, 71707)
7.1 Surveillance Observation The inspector observed surveillance tests to verify that testing had been properly scheduled, approved by shift supervision, control room operators were knowledgeable regarding testing in progress, approved procedures were being used, redundant systems or components were available for service as required, test instrumentation was calibrated, work was performed by qualified personnel, and test-acceptance criteria were me Daily surveillance tests including instrument channel checks, jet pump operability, and control rod operability were verified to be adequately performe Parts of the tests listed in Attachment I were observed. Specific comments are-noted in the following section . 2 Core Spray System and Cooler Operability (ST 6.6.1 and ST 6.7.1)
Surveillance Test (ST) procedures 6.6.1 and'6.7.1 provide for the    i operability test of core spray system loops A and B and the room coolers when a core spray pump, a low pressure coolant injection (LPCI) subsystem, or a diesel generator is inoperable. The inspector witnessed a surveillance test of the core spray system performed ~
based on the inoperability of the high pressure coolant injection (HPCI) in accordance with the requirements of Technical Specifications (TS) 3.5.C.2. Review of the procedure indicated that
  'HPCI inoperability was not factored into the ST as a requirement for the core spray system surveillance test. The inspector discussed the concern with the cognizant operations staff and was informed that the subsequent revision of the procedure will incorporate the requirements delineated in TS 3.5. During core spray loop A operability testing, full flow test motor operated valve M0-02-14-026A did not stroke fully closed with the 2C pump running. The licensee's investigation confirmed inadequate setting of the torque switch which prevented the valve from seating properly when stroking to the closed position. Maintenance request form (MRF) 89-03841 was initiated to adjust the torque switch. The torque switch thrust was readjusted to 66,000 ft-lbs and the valve was successfully stroked and proper valve seating was verifie During core spray loop B operability testing, the control switch for normally open outside containment discharge valve MO-02-14-011B had to be held for approximately two seconds for the valve to strok Although no operability problem was encountered, the control room operator tagged the valve switch with an information ta These core spray operability tests were adequately coordinated and interfaced between plant operations and test personnel. The tests were i
'
successfully completed and the test results were acceptable. The inspector did not have any further questions at this tim _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ - - _  -
 
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7.3 HPCI Logic System Functional (ST1.1) and HPCI Flow Rate Test At 150 psig (ST 10.1)
ST 1.1 provides for the verification of the HPCI system logic to initiate and sustain the automatic operation of the HPCI system during a design basis accident condition. ST 10.1 provides for the operability test and performance of the HPCI system at 150 psig steam pressure. The inspector witnessed these HPCI . system tests conducted in accordance with the STs. Two temporary changes (TCs) 89-0901 and 89-0902 were adequately initiated to modify the test steps of ST in order to complete the test satisfactoril During the HPCI operability test per ST 10.1, the system did not respond to the flow controller signal. Troubleshooting detected that the newly installed Analog Isolator was not properly field wired per an installation procedure contained in MOD 5061 for this installation (see section 6.2.1). The polarities were found reversed at the Analog Isolator resulting in erroneous output signal. As such, the HPCI governor valve had continuous' signal of full open regardless of the system flow or the flow controller setpoint. However, during the surveillance test for system operability, the miswiring of the system was identifie The HPCI system was declared inoperable and the licensee rotified the NRC in accordance with administrative procedures, A-31, Notification to the NRC, and A-86, Corrective Action. Subsequently, the wiring connection was modified and system operability was retested satisfactorily 7.4 Relief Valves Manual Actuation (ST 10.4)
ST 10.4 provides for the inservice testing of the eleven main steam relief valves RV-2-01-71 A through L. The inspector witnessed the testing of the relief valves with reactor pressure at 175 psig and three bypass valves open. During the test, relief valves 71 A, G, H and L did not operate properly as required by the procedur Troubleshooting indicated that the acoustic monitors that provide valve position were loose. In addition, the thermocouple sensor for relief valve 71 H was incorrectly wires  Subsequently, the acoustic monitors were tightened and the thermocouple wiring was modifie Retesting of relief valves 71 A, G and H was successful. However, relief valve 71 L failed to close initially during the retes Consequently, the valve was declared inoperable in accordance with Technical Specification 3.6.D.1 and A thirty day limiting condition for operation action statement was entere Special Procedure SP-779 was initiated to allow ECCS to be defeated with the reactor mode switch in shutdown. Relief valve 71 L was replaced per maintenance procedure M-1.6 and MRF 890397 This relief valve was retested successfull Based on the review of the surveillance test and the valve replacement documentation, and discussion with the
;    cognizant operations personnel, the inspector determined that I    licensee action was conservative, adequate and timely. The inspector did not have any further questions at this time.
 
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:"  28 7.5 Unit 2 Containment Bypass Test In response to a drywell to torus low pressure alarm, the licensee decided to perform ST 12.6-1, " Primary Containment Drywell to Torus Bypass Test", Rev. 9. This test is required once per operating cycle by Technical Specifications -(TS) 4.7.A.4.d and when the drywell to torus vacuum breakers indicate not fully seated per TS 3.7. Although neither of these TS criteria were met, the licensee initiated the test. Three tests were conducted between day shift May 29, 1989, and midnight shift May 30, 1989. All of these tests failed the acceptance criteria possibly indicating the existence of a bypass hole of greater than one inch in diameter. TS 3.7.4.B requires that the unit begin a shutdown 24 hours after an open vacuum breakte is noted with an equivalent bypass hole of one inch in diamete Although the licensee did not have an open vacuum breaker, their actions were consistent with TS action requirement During day shift on May 30, 1989, licensee engineering, operations and management personnel met to discuss these test results. They concluded that the test method required improvements to ensure a higher differential pressure (greater than 0.4 psid) was maintained throughout the test. The three previous tests showed an excessive leak when differential pressure dropped below 0.25 psid. When the pressure was greater than 0.25 psid, the previous tests passed the acceptance criteria. The licensee revised the test to increase the pressure, to correct some minor deficiencies and to increase data collection to every five minute A revised ST 12.6-1, Rev. 10, was performed between 10:37 p.m. May 30 ar.d 12:42 a.m. May 31, 1989. Test results were satisfactory. All data points were calculated to be indicative of a hole less than the minimum of one inch in diamete The inspector witnessed each test; attended the licensee's management meeting on May 30, 1989; reviewed FSAR sections 5 and 14 and, reviewed the final test results. The inspector had no further questions and no unacceptable conditions were note .6 Scram Air Header High Pressure Alarm
,
On May 18, 1989, the inspector witnessed performance of ST 9.7, "MSIV
'
Partial Closure and RPS Input Functional Test," Rev. 11, 4/16/89.
 
l The inspector noted that each time a half reactor trip was received, the 75 psig high pressure trip air header alarm would annunciate
'
momentarily and then reset. When observing trip air header pressure on PI-312 in the control room, the pressure would rise to 76 psig immediately after a half reactor trip, and then slowly decrease back to the setpoint of 70 psi The inspector reviewed P&ID M-356, " Control Rod Drive (CRD) Hydraulic System - Part A," to determine the method of trip air header pressure control. According to the P&ID, pressure control valve
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  .(PCV) 4239A or B should be positioned to regulate pressure at 70 psig. The inspector walked down'the CRD system to' determine the actual valve lineup. It appeared that both PCVs were in service at the same time which was in disagreement with the P&I The inspector returned to the control room and obtained the most current check-off-list (COL) 3.1.A-2, "CRD Hydraulic System Startup,"
Rev. 2, which showed that both PCVs were in service at the same tim The inspector discussed this issue with shift operators who agreed that only one PCV should be valved in. However, the Shift Manager wanted to wait until day shift to make sure that the assumption was correc The licensee determined that the P&lD was correct and the COL was  !
incorrect. The valve lineup was corrected such that only PCV-4239A was in service, and the COL was submitted for a revision. Operations also committed to observe the trip air header pressure during the next surveillance test that initiates half reactor trip testing.
 
)  On May 30, 1989, the inspector was observing ST 9.4, " Turbine Stop Valve Closure Functional," Rev. 27, 3/10/89, and ST 9.14, " Turbine Control Valve Fast Closure Scram Functional, Rev. 24, 3/20/89. Each time a "B" channel half reactor trip was received, the high pressure trip air header alarm would annunciate momentarily and then rese The previous observations on May 18, 1989, led to the alarm during both and "A" and "B" half reactor trips. The licensee was questioned concerning this problem indicating in response that PCV-4239A has an internal problem. At the close of the inspection, the licensee was planning to take PCV-4239A out of service and place PCV-4239B in service and observe trip air header pressure during half reactor trips. The inspector will continue to follow this item in a future inspectio .0 Maintenance Activities (62703)
8.1 Routine Observations      j The inspectors reviewed administrative controls and associated documentation, and observed portions of work for maintenance activities. Administrative controls checked included blocking permits, fire watches and ignition source controls, QA/QC involvement, radiological controls, plant conditions, Technical Specifications, equipment alignment and turnover information, post maintenance testing and deportability. Documents reviewed included maintenance procedures (M), maintenance request forms (MRF), item  l handling reports, radiation work permits (RWP), troubleshooting  '
control forms (TCF), material certifications, and receipt  i inspection '
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Document Equipment    Date Observed 4 M1.27  Turbine Cross Around Reliefs  05/10/89 I GP Drywell Inspection    05/10/89 TCF  Emergency Cooling Water Pump  05/10/89 Auto Start Alarm M Safety Relief Valve 71L    05/12/89 TCF  Intermediate Range Monitor E  05/14/89 TCF  EHC Pressure Control Swapping  05/21/89 MRF 89-4330 & Traversing In-Core Probes    05/25-28/89 4388 TCF  Combined Intermediate Valves  05/26/89 TCF  E-22 Bus Potential Transformers  05/31/89 SP-1286  Unit 3 Reactor Vessel Manway  06/6-9/89 Repair MRF 89-4659 Unit 2 A Main Steam Line    06/07/89 Radiation Monitor MRF 89-4703 Unit 2 HPCI Leak Repair    06/15/89 No inadequacies were identifie .2 Unit 2. Maintenance Backlog The inspector reviewed the current maintenance backlog. This l
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included comparing a listing of off-normal control room annunciators and control room instrument deficiencies documented in the Unit 2 TRIPOD daily status report with the annunciators and instruments in the control room. Although the list generally matched the as-found condition, several differences were noted. Two instruments (FR-2522 and PR-8102A) were documented by a maintenance request form (MRF)
without appearing on the lis Several instruments and annunciators
!  were annotated on the list as needing MRF numbers even though their I
deficiency was identified as early as May 5,1989. Several annunciators appear to be alarming spuriously yet are not identified with deficiency tags. Examples include:
    --
B RFPT HI VIBRATION (202/E-2)
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MAKEUP FILTER DRAIN REGENERATION TROUBLE (201/C-2)
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RHR HI TEMPERATURE (224/D-5)
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BLOWDOWN RELIEF VALVE HI TEMPERATURE (227/B-4)
On June 8, 1989, the inspector noted that there were 84 deficiency tags hanging on the Unit 2 control room panels. New deficiencies are apparently occurring at a faster rate than old ones are being correcte The inspector did not find any open maintenance items or MRFs that would make a safety system inoperable other than those already known ar,d allowed to be out of service by Technical Specifications and documented in the LC0 lo _ - __ ___- _
 
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9.0 Radiological Controls (71707)
L 9.1 Routine Observations 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 (RWP) requirements, radiation  4 surveys, radiation protection instrument use, and handling of potentially contaminated equipment and material The inspector observed individuals frisking in accordance with health physics procedures. A sampling of high radiation area doors was verified to be locked as require 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 requirement An NRC identified violation associated with high radiation controls was noted in section 5.4.2 of this repor On May 15, 1989, the Senior Health Physicist or Radiation Protection Manager (RPM) resigned and was replaced by Paul Sawyer, acting Senior Health Physicist. The inspector reviewed the qualifications of the acting RPM and compared those qualifications against the criteria stated in Technical Specification 6.3.1, Facility Staff Qualifications; in ANSI N18.1-1971; and, in Regulatory Guide (September 1975). The inspector concluded that the acting RPM met the appropriate qualification .2 Allegation Associated with Radiation Work Permits (RWP)
  (R1-A-89-0055)
On May 5,1989, the resident inspector received an. anonymous (via phone) allegation stating that a first line supervisor routinely fails to adhere to procedural requirements in RWP instructions and does not follow radiological safety precautions. The caller identified himself as a Health Physics (HP) technician and identified the stpervisor by name. The alleger further stated that the identified individual was working in the plant without authorization of an RW The alleger also stated that when questioned by HP technicians, this individual denied violating any RWP. The alleger r; m d he ;;culd con'.act the NRC Resident Office with further information; rm,.cver, this was never don The inspector evaluated this allegation by interviewing HP technicians  j
        '
who were at the various control points in the Unit 3 work areas on the specified day, and on days before and after the time frame of the allegation. In addition, a security trace of this individual was obtained. This trace indicated that the individual was in these specified areas. However, no RWP adherence concerns were note p
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The inspector also reviewed radiological occurrence reports for the time period and none were found. HP supervisory personnel were also interviewed and no concerns were raised. The inspector also reviewed the associated RWPs, inspected the Unit 3 work areas, and reviewed HP control point logs. Based on this review, the allegation could not be substantiated and it is considered close .0 Physical Security (71707)
10.1 Routine Observations The inspector monitored security activities for compliance with the accepted Security Plan and associatec: implementing procedures, including: security staffing, operation of the central and secondary alarm stations, checks 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, and compensatory measure No inadequacies were identifie .2 Bomb Threats on May 25,-1989 Two telephone calls were received at the Philadelphia Electric
  ' Company (PECo) Corporate Headquarters in Philadelphia, Pennsylvania, on May 25, 1989. The first call at 9:45 a.m. indicated that a van Icaded with explosives would arrive at the Peach Bottom Atomic Power Station at 11:30 (no a.m. or p.m. given). Due to the nature of the PECo telephone system, the licensee was able to determine that the anonymous call had come from their internal CENTREX telephone syste The licensee evaluated the threat as non-credible at 11:00 a.m. How-ever, as a precaution, bomb threat contingency procedures were im-plemented in and around the station which included barricades at the protected area access point, searches of vehicles in the owner-controlled area, establishing owner-controlled area vehicle access control points, posting armed officers at owner-controlled area substations, and positioning lookout The second call at 4:48 p.m. indicated that "you stopped us today, we will get you tomorrow". This call was received by the PECo operator from an outside lin The inspector was informed of the first event by the licensee at 10:25 a.m. on May 25, 1988. The licensee reported the event via the Emergency Notification System (ENS) at 12:30 p.m. The second event was also communicated to the inspector at 5:01 p.m. and the licensee made an ENS call at 5:55 p.m. per 10 CFR 73.71. The inspector and regional staff discussed these matters with the licensee. The licensee considered both threats non-credible. However, they continued to implement heightened security awarenes _ _ - - _ _  -
 
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The inspectors observed the licensee's actions from the control room and from various security facilities. The inspector toured the
:  protected area, and vital areas, and verified the licensee's heightened security actions. Selected guards, security shift assistants and operations personnel were interviewed. The inspector also attended a guard mount (shift turnover meeting) at 5:45 am, on
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May 26, 1989. These contingent security measures were discussed at this guard mount. The inspector had no further questions at this time. The inspector concluded that the licensee's actions were appropriate for the circumstance .0 Assurance of Quality 11.1 Plant Manager's Hold Point Meetings The Plant Manager conducted hold point meetings on May 10 and 16, 1989, prior to releasing the plant from the following startup conditions:
    --
450 psig reactor pressure, and
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reactor mode switch to " DUN", and
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turbine generator startup and synchronizatio These meetings allowed management to review past equipment malfunctions and problems, and to assess the readiness to proceed to the next startup platea The meetings were attended by all plant and station disciplines and organizations, including corporate and independent oversight groups. At the completion of each meeting, the !
licensee concluded that the plant was ready to proceed to the next startup platea The inspector attended each meeting, noting that all site groups were represented. An adequate discussion of all previous hardware malfunctions that occurred was held. Following the reactor mode switch to "RUN" meeting on May 16, 1989, the licensee briefed the NRC Peach Bottom Restart Panel via the telephone. The inspector concluded that licensee plant management demonstrated a high assurance of quality in Peach Bottom operation .2 High Pressure Coolant Injection (HPCI) System Wiring Error A recent electrical modification to the HPCI flow controller occurred due to multiple personnel errors and failures (see section 6.2.1).
 
These successive errors included an installation mistake by contractor electricians; and the failure of QC, of post modification electrical checkout, and of post modification acceptance testing to detect this erro The HPCI surveillance test did however detect this wiring erro _ _ _ _ - __
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34 .3 Management Oversight Team (MOT) Meeting on-June 1, 1989 e    'The licensee conducted a MOT review for the Unit 2 power ascension up to the.35% power plateau. The meeting was held on June'1, 1989, to evaluate 'this startup and transient period. Licensee personnel in
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attendance included M0T members (corporate and site managers, and- an industry observer) and line management'who made presentation The inspector attended the meeting and concluded that the licensee adequately evaluated their performance to date. This included both personnel and equipment evaluations. The licensee formulated strengths.and weaknesses, defined follow-up action items,. and concluded that Unit 2 was satisfactory to proceed to the 35% steady state period for approximately four weeks. The licensee identified the following two significant weaknesses:
I (1) The maintenance backlog trend is increasing and needs to be addressed. Improvement is required to perform scheduled maintenance during the rolling 13 week schedule (2) Numerous surveillance tests are being performed in the grace
    ' pe ri od .
The licensee MOT will meet again after the four week steady state 35%
perio .4 Operations Oversight Plant and operation management including the Shift Manager, the Operations Superintendent and the Assistant Superintendent were noted as being effectively involved in plant operation Specific examples included the following: EHC malfunction (4.2.1); reactor trip follow-up and root cause analysis (4.2.2); offgas recombiner abnormality (section 4.2.3); and, E-22 bus electrical problem-(section 4.2.5).
 
12.0 NRC Bulletin and Information Notice (92703)
12.1 NRC Information Notice 89-44, Hydrogen Storage On the Roof of the Control Room The inspector reviewed the impact of combustible gas storage on safety related structure Peach Bottom has two combustible gas storage tanks. One is a 20,000 gallon liquid hydrogen tank at 150 psig for future hydrogen water chemistry control. The tank is located west of the site,1800 feet from the control room intak This hydrogen water chemistry system is part of a plant modification scheduled for implementation during the current Unit 2 cycle. The NRC reviewed this design in a safety evaluation report dated January 1987.
 
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The other hydrogen storage facility is for the main generator cooling system. This consists of 24 gas cylinders (total volume of 553 cubic
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feet) at 2400 psig. It is located south of Unit 2 turbine buildin The nearest safety related structure is the diesel generator building at a distance of 65 feet. The control room air intake is 520 feet from these hydrogen gas cylinder No unacceptable conditions were note .2 Potential Misapplication of Certain Models of Pressure Transmitters (NRC Bulletin 80-16)
NRC Bulletin 80-16, " Potential Misapplication of Rosemount, Inc.,
Models 1151 and 1152 Pressure Transmitter with Either A or D Output Codes", was issued June 27, 1980. This bulletin informed licensees about a reversal in output signal level when the transmitters are subjected to pressures exceeding 140% of rated maximum pressure. A reversal could result in erroneous presssure indication for safety related application The bulletin suggested several ways the licensee could prevent erroneous indicated pressures. On July 30, 1980, the licensee responded to the bulletin. They committed to two methods of preventing this condition. The pressure transmitters were to be tested at the next calibration time for overpressure respons Also, training was provided for which control room pressure indicator was to be use The bulletin response was reviewed by a regional specialist, and was inspected for implementation by a resident inspector in 1980. The inspector again reviewed the PECo response letter, operating  '
procedures, emergency operating procedures, calibration procedures, and the training record The implementation of the licensee commitment was determined to be satisfactor NRC Bulletin 80-16 is considered close .0 Unresolved Items Unresolved items are items about which more information is required to ascertain whether they are acceptable violations or deviations. An unresolved item is discussed in section .0 Management Meetings 14.1 Preliminary Inspection Findings (30703)
A verbal summary of preliminary findings was provided to the Manager, r 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 inspectors. No written inspection material was provided to the licensee during the inspectio No proprietary information is included in this repor . _ . . ._
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14.2 Attendance at Management Meetings Conducted by Region Based Inspectors (30703)
Inspection Reporting Date Subject Report N Inspector 6/13- Emergency Exercise 89-17/17 Gordon 15/89
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6/8-8/89 Diesel Fuel Oil 89-16/16 Woodard i
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ATTACHMENT 1 Surveillance and Routine Tests (ST/RT) Observed ST 10.16  ST 20.004 ST 6.6-F ST 12.15.2-2  RT 1 ST 6.10-2 ST ST 1.13  ST 6.1.2-1 ST 1 ST ST 6.6.F-2 ST 8.]  ST 9.12-1 ST 19.14-5A !
RT 5.31  ST 6.11-2 SI 2N-60D-B2CW ST 3. ST 12.15.6-2 ST 10. ST 9.21-2  ST 6.5-1  ST 3. SI 2N-600-SRM-A2CX ST 6.5-2  ST ST ST ST ST 3. ST 7.6. ST 13.60 RT 5.13  RT RT RT RT ST 13.47-2 ST 26.7-2  ST ST ST 12.6-1  RT RT 5.14 ST ST 9.14  ST 2.5.40A ST ST 3.5.1-2 ST 3. ST 9.1 ST 6.2-2  ST 9.10 RT 9.1 SI 2K-54-E12-XXFM ST/EP 118 ST 16.35  ST 2.5.40D ST ST 9.11    l
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Revision as of 13:58, 16 February 2021

Restart Safety Insp Repts 50-277/89-16 & 50-278/89-16 on 890507-0617.Major Areas Inspected:Unit 2 Power Ascension Transient Testing & steady-state Operation at 35% Power Plateau,Radiation Protection & Physical Security
ML20246A030
Person / Time
Site: Peach Bottom  Constellation icon.png
Issue date: 06/22/1989
From: Kenny T, Willams J
NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20246A005 List:
References
RTR-REGGD-01.033, RTR-REGGD-1.033 50-277-89-16, 50-278-89-16, IEB-80-16, IEIN-89-044, IEIN-89-44, NUDOCS 8907060115
Download: ML20246A030 (40)
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REGION I

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! Docket /ReportNo.(50-277/89-16'

L50-278/89-16 License No. DPR-444 DPR-56

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, q Licensee: . Philadelphia Electric Company

' Correspondence Control Desk

.P. O. Box 7520 Philadelphia, Pennsylvania'.19101

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Facility Name: Peach Bottom Atomic' Power. Station ~ Units 2 and 3 L

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l- Inspection At: Delta, Pennsylvania u ,

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Dates: May 7 - June 17;.1989-

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Inspectors: .T. P. Johnson, Senior Resident Inspector

. J. Urban, Resident Inspector L'. E. Myers,; Resident. Inspector ,

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J. Gadzala, Reactor Engineer 1 J. H.' Williams,. Project Engineer  !

-M.~ Dev, Reactor Engineer .

L. Larson,iLicensing Engineer 1 R. E. Martin, NRR Project Manager

' D. Draper, Licensing En eer .

Reviewed By: m, h L!72 !By

.J 1a ,; Project Engineer / 'd 9te Approved By: db 2rw

. T .,Ke ' jAct)1hg Chief,

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rojects Section 2A, e/dat/

Division' of Reactor Projects

~ Summary

, Areas Inspected: -Ro'utine, on site regular, backshift and deep backshift special restart team and resident inspection (821 hours0.0095 days <br />0.228 hours <br />0.00136 weeks <br />3.123905e-4 months <br /> Unit 2; 232 hours0.00269 days <br />0.0644 hours <br />3.835979e-4 weeks <br />8.8276e-5 months <br /> Unit 3) of accessible portions of Unit 2 and 3, Unit 2 power ascension transient testing.. Unit 2 steady state. operation at the 35% power plateau, operational

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safety,' radiation protection, physical security, control room activities, licensee events, surveillance testing, Unit 3 refueling and outage activities, maintenance, and outstanding item Results: One violation associated with failure to follow modification I installation, QC inspection and acceptance testing procedures was identified (sections 6.2.1 and 11.2). Two other NRC identified violations were identified; however, they met the criteria for not issuing a Notice of Violation. One was 1 8907060115 890626 PDR ADOCK 05000277 Q- PDC

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associated with emergency core cooling system room drains (section 5.4.1) and the other was associated with high radiation door controls (section 5.4.2).

Two examples of a licensee identified violation for missed Technical Specification surveillance requirements were also noted (section 6.2.2). Several events, including an automatic reactor trip, were reviewed (section 4.2). NRC shift coverage observations determined that: (1) licensed operator performance was adequate and control room activities were formally conducted, with one minor exception, (section 5.2); (2) logkeeping (section 5.3), shift turnover and communications (section 5.5), and control room staffing and training (section 5.6) were adequ~ ate; (3) Technical Specification (TS) compliance, deportability (section 5.7), and response to off-normal conditions (section 5.10) were conservative; (4) test and special evolution control (section 5.8) and teamwork (section 5.11) were effective; and, (5) procedure adherence by licensed control room operators was good; however, several procedural errors by non-licensed operators, reactor engineers and health physics personnel occurred (see section 5.9). Security and operations response to a bomb threat was timely and conservative actions were taken (section 10.2). Plant Management was noted as being involved in plant operations (section 11.1) and operations oversight continued to be effective (section 11.4). An increased maintenance backlog has occurred as indicated by control room annunciators in an alarmed condition and malfunctioning instruments. Licensee self assessment capability was demonstrated as evidenced by the Nuclear Review Board Meeting (section 4.3), the Station Review Meeting, conducted on June 9, 1989, and the Management Oversight Team Meeting (section 11.3).

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TABLE OF CONTENTS Page 1.0 Persons Contacted............................................ I 2.0 Facility and Unit Status..................................... 1 3.0 Previous Inspection Item Update.............................. 2 4.0 Plant Operations Review..............-........................ '3 4.1 Operational -Safety Verification and Station Tours....... 3 4.2 Follow-up on Events..................................... 4 4.3 Nuclear Review Board (NRB) Meeting....................... Il 5.0 Shift Activities and Observations............................ 11 5.1 NRC Shift Coverage...................................... 11 5.2 Operator Performance, Attentiveness and Formality....... 12 5.3 Logs and Records........................................ 12 5.4 Plant Tours.................................... ......... 13 5.5 Shi f t Turnover and Communications. . . . . . . . . . . . . . . . . . . . . . . 17 5.6 Control Room Staffing and Training...................... 17 5.7 Technical Specification Compliance and Deportability.... 18 5.8 Test and Special Evaluation Contro1..................... 18 5.9 Procedure Adherence..................................... 18 5.10 Response to Off-Normal Conditions...-.................... 19 5.11 Teamwork..................... .......................... 20 5.12 Human Factors Engi nee ri ng . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 6.0 Review of Licensee Event Reports.............................. 21 6.1 LER Review.............................................. 21 6.2 LER Follow-up........................................... 22 7.0 Surveillance Testing........................................ 26 8.0 Maintenance Activities...................................... 29 L 8.1 Routine Observations.................................... 29 l 8.2 Unit 2 Maintenance Backlog.............................. 30 9.0 Radiological Controls........................................ 31 9.1 Routine Observations.................................... 31 9.2 Allegation Associated with Radiation Work Permits....... 31 10 . 0 Phy s i c a l S e c u r i ty . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 l 10.1 Routine Observations......... .......................... 32 30.2 Bomb Threats............................................ 32 11.0' Assurance of Quality.................... .................... 33 12.0 NRC Bulletin and Information Notices......................... 34 13.0 Unresolved Items............................................. 35 14.0 Management Meetings....... .................................. 35

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DETAILS 1.0 Persons Contacted

  • J. W. Austin, Superintendent, Modifications {

G. A. Bird, Nuclear Security Specialist-J. B. Cotton, Superintendent, Operations

  • T. E. Cribbe, Regulatory Engineer i G. F. Daebeler, Superintendent, Technical i
  • J. F., Franz,. Plant Manager D. P. LeQuia, Superintendent Services G. Lipsey, Power Ascension Manager D. R. Meyers, Support Manager J. T. Netzer,. Superintendent, Planning, Scheduling and Reporting D. L. Oltmans, Station Chemist 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
  • P. Sawyer, Actir.g Senior Health Physicist D. M. Smith, Vice President, Peach Bottom Atomic Power Station Other licensee and contractor employees including all six Shift Managers were also contacte *Present at exit interview on site and for summation of preliminary !

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2.0 Facility and Unit Status  !

2.1 Unit 2 This inspection period began with Unit 2 at rated pressure and at 3%

power. A High Pressure Coolant Injection (HPCI) system wiring error was being reviewed (see section 6.2.1). HPCI was subsequently tested satisfactorily from the alternate shutdown panel on May 8,198 Safety. relief valve (SRV) testing was performed on May 9, 1989; however, SRV 71L failed to reclose initially and three SRVs had position indication problems. A drywell inspection at 450 psig reactor pressure occurred on May 10, 1989. One valve had a packing steam leak which was repaired. The licensee concluded that SRV 71L required replacement during subsequent SRV testing on May 11, 198 The licensee shut down Unit 2 on May 11, 1989. SRV 71L was replaced and the unit restarted on May 13, 1989. SRV retesting was completed satisfactorily on May 14, 1989 (see section 7.4).

l During reactor heatup to rated conditions on May 14, 1989, problems I

were noted with the electro-hydraulic control (EHC) system. The reactor was taken subtritical and the EHC system was repaired (see

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section 4.2.1). The reactor was restarted and the reactor achieved rated _ pressure conditions (920 psig) on May 15, 198 On May 19, 1989, at 7:22 a.m., the Unit 2 reactor automatically tripped from about 20% power. The cause of the trip was a failed

"three element / single element" control' switch in the feedwater level control . system. This malfunction resulted in a low reactor water L level tri Safety systems reacted automatically to this condition and licensee emergency actions were appropriate. Upon completion of

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the licensee's root cause analysis and corrective actions, Unit 2 restarted on May 21, 1989 (see section 4.2.2).

On May 22, 1989, the turbine generator was started up and synchronized with the grid at 21% reactor power later that day. A malfunction in the offgas recombiner system caused the licensee to shut down the turbine generator and reduce power to 5%. The licensee traced the problem to a high steam flow input combined with a restricted drain line from the offgas recombiner condenser (see section 4.2.3). The licensee subsequently restarted the turbine generator and synchronized to the grid on May 24, 1989. Successful turbine generator overspeed trip testing was completed on May 25, 198 Power ascension continued to 33% power during the remainder of the period. During the period May 25 to June 1,1989, the licensee dealt with problems associated with the traversing in-core probe system, with the drywell to torus bypass leakage test (see section 7.5) and with a failed potential transformer in the emergency electrical E-22 bus cubicle (see section 4.2.5). On June 1, 1989, the plant attained 33% powe This power level is the licensee's administrative limit for the NRC's modified Order which requires a 35% reactor power hold poin .2 Unit 3 The licensee continued the seventh refueling outage on Unit 3, which began October 1, 1987, including maintenance and modification activitie Repairs to the reactor pressure vessel manway access cover began on June 5, 1989. The next milestone for Unit 3 is the control rod drive exchang .3 Common The annual emergency plan exercise was held on June 14, 198 The exercise was evaluated by an NRC tea .0 Previous Inspection Item Update (92701, 92702)

3.1 (Closed) Unresolved Item (277/88-28-04; 278/88-28-04). This item I pertains to the ',ack of documentation to verify the completion of the Nuclear Review Board (NRB) action items by licensee managemen The h .h ma_ _ _ _ _ - - _ _ _ - _ _ _ _ _ _ _ _ _ _ - . - - . a - - - - -

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' inspector! reviewed various minutes of NRB meetings and documentation supporting- the closure of'the NRB's action items for Units 2 and 3, and found them satisfactory.- Review of the current listing of the Commitment Tracking System indicated that there are no outstanding NRB open items pending resolution by Peach Bottom management. Based-on review and discussion with licensee representatives, the inspector

. determined that licensee action was adequate. This item is considered close ' (Closed) Unresolved Item'(277/89-07-10; 278/89-07-10). This item pertains to the misapplication of fuses in 125 VDC panel 2BD306

. circuits 29-BD-30604 and 29-80-30605 (Unit 2), and, panel 3DD306 circuit .29-3DD-30605 (Unit 3). In accordance with single line diagram E-26, Sheet 1, Revision 1, these fuses were specified as type

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"FRN'!-30 Amp, but the installed fuses were type ."NON" and KON".

The' licensee investigated the causes.of the above discrepancies and'

..determi'ed n that the single line diagram was. revised to meet 10 CFR 50, Appendix R, Fire' Protection requirements. However, the replacement of these fuses was not accomplished and there was no' firm

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' schedule to replace these fuses at that time. Later, these fuses were replaced with' correct fuses as designated in single line diagram E-2 The inspector verified that the fuses. currently installed in the above circuits are type "FRN-R-30". Also, to preclude a similar misapplication from happening in the future, the licensee is in the process of establishing a plant wide listing of approved fuses used in' electrical protective devices. The licensee will verify and update the status of all such fuse Based on the above review and discussion with the cognizant plant

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support engineers, the inspector determined that the licensee's corrective action was adequate. This unresolved item is close .3 (Closed)UnresolvedItem(277/89-15-02). High Pressure Coolant Injection system modification system wiring error (see section 6.2.1).

4.0 Plant Operations Review 4.1 Operational Safety Verification and Station Tours (71707)

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 verification of safety system status and limiting conditions for operation, corrective actions, and review of facility records and log Specific comments and conclusions are addressed in section The inspectors performed 700 total hours of on site backshift time, including 330 hours0.00382 days <br />0.0917 hours <br />5.456349e-4 weeks <br />1.25565e-4 months <br /> of deep backshift and weekend tours of the

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t 4 facility. Deep backshift inspections included around-the-clock coverage from May 7 to June 2, 198 .2 Follow-up On Events Occurring During the Inspection (93702)

4. Unit 2 Electro-Hydraulic Control (EHC) Malfunction on May 14, 1989 I On May 14, 1989, during reactor heatup and pressurization to rated (920 psig), ' abnormalities were experienced with the electro-hydraulic control (EHC) system. The EHC pressure setpoint controller malfunctioned and EHC indicated pressure (reactor steam) was about 80. psi lower than actual reactor pressure. The licensee decided to insert control rods and to depressurize at 8:40 p.m. on May 14, 1989, in order to troubleshoot the EHC system while the reactor was subcritical, The Superintendent of Operations reported to the site and proceeded to the control room to assist the operations shif Licensee troubleshooting activities identified a loose gear on the EHC setpoint. controller drive motor as the cause of the malfunction. The gear was tightened, and other similar devices were checked satisfactorily. Calibration checks for the EHC pressure transmitters PT 2864 and 2865 found them within tolerance; however, they were recalibrates. A management. meeting was held in the control room to discuss the non-linear calibration curve for these pts versus actual reactor pressure. A GE engineer stated that a 50 psi deviation at mid-range (450-500 psig) was normal. The licensee restarted the reactor and criticality was attained at 11:23 a.m. on May 15, 198 The inspector monitored licensee actions during problem identification and troubleshooting activities. The inspector determined that the licensee acted conservatively in taking the reactor subcritical without EHC availabl Operations management was also noted as being involved in operations oversight and direction. The inspector sttended the EHC management meeting and noted that plant min'gement was also involved in this even No unacceptable conditions were note . Unit 2 Automatic Reactor Scram on May 19, 1989 The Unit 2 reactor automatically tripped from about 20%

power at 7:22 a.m. on May 19, 1989. The trip occurred after the reactor operator shifted the feedwater level control system (FWLCS) from single element to three element control. This action caused the one operating reactor feed pump to increase spee _ _ - _ ____---

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The increased feedwater flow resulted in a low suction pressure trip of the feed pum Reactor level then decreased to the automatic trip and containment isolation setpoint of 0 inches. Before a feed pump could be returned to service, the water level continued to decrease to about minus ,42 inches. The alternate rod insertion (ARI) system actuated and both reactor recirculation pumps tripped. The high pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC) systems did not automatically initiate. These safety systems all actuate at a reactor level of minus 48 inches; however, HPCI and RCIC did not actuate because their trip logic is different. The licensee recovered

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reactor water level with the reactor feed pump, reset the trip and containment isolations, and made an ENS call at-8:16 The licensee determined that the root cause of the trip was a defective single to three element switch in the FWLCS. When the switch was placed in the three element position, its contacts apparently did not close, resulting in a perceived low level condition. The operating feed pump increased speed and feed flow, causing a low suction pressure trip. Water level decreased to -42 inches resulting in a reactor trip at zero inche The licensee confirmed that the HPCI and RCIC system initiation logic at-48 inches was different than the alternate rod insertion and the recirculation pump trip logic. An ENS call was made at 10:17 a.m. on May 20, 1989, to report that the reason RCIC and HPCI did not auto start was because the logic was not fully actuated. Other ENS calls were made at 2:45 p.m. on May 20, 1989, to report inoperability of the 2A core spray loop minimum flow valve while in hot shutdown; and, at 10:40 p.m., on May 20, 1989, to report that this core spray valve and the respective loop were returned to servic The inspector was in the control room at the time of the reactor trip. The inspector noted that there was a discussion between the reactor operator (RO) and Shift Supervisor (SS) prior to moving the switch to the three element position of FWLCS operation. This operation was being performed in accordance with GP-2, " Plant Startup" and the system operating (S0) procedure. When the FWLCS malfunction occurred, operator response was adequate. The R0 informed the SS of the problem and impending trip. The l RO was unable to reset a feed pump to recover level prior to the tri The SS adequately implemented the transient response implementation plan (TRIP) or emergency operating procedures T-100, T-101, and T-99. The Shift Manager was

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l conducting turnover for non-licensed operators and he -l L reported to the control room a few minutes after the trip L occurre After the unit was stabilized in the hot shutdown '

condition, the inspector reviewed control room instruments, j computer alarm print outs and the preliminary upset repor The operators on shift were interviewed and the inspector attended several trip debrief / root cause analysis meeting During trip recovery, a fire was reported to the control L room at 8:20 a.m. This required the fire brigade to b called out. An electrical cord was overheating in the turbine buildin Licensee actions were adequate in response to the fir After the unit was stabilized, the licensee noted that the control room total feedwater flow recorder was not operating. It was drawing a straight line ink trac The difference between total steam and feedwater flow was small. However, the individual feedwater flow recorder was operating and indicating correct feedwater flow. The licensee repaired the total feedwater flow recorde Licensee actions in response to this trip included the following:

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performing a root cause analysis and completing corrective actions,

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checking the FWLCS calibrations,

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PORC review of the completed GP-18 " Scram Review Procedure",

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completing operations incident report 2-89-51 on the trip,

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determining how the FWLCS was to be operated

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comparing the HPCI/RCIC initiation logic with the alternate rod insertion logic, and

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briefing the NRC restart team prior to startu Licensee post trip review and analysis determined that failure of the three element to single element switch was the root cause of the event. Licensee testing found that the switch did not close completely at all times when placed in the three element positio In addition, the switch's application is being reviewed. A new switch was installed in the control room panel. Other similar switches were also checked and no abnormalities were noted.

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Calibration checks on the FWLCS electronic cards found that two cards (104 and 107) associated with feed flow amplification were out of calibration. The licensee recalibrates these cards and determined that they had no effect on the transien The licensee reviewed the HPCI/RCIC initiation logic and recent associated surveillance test of instrumentation L setpoints. Reactor water level decreased to -42 inches as indicated by three separate control room chart recorder The "as found" trip setpoints for the four trip' logics (A,B,C,D) indicated that the order of logic initiation was A-B-D-C, with a maximum difference of about 2.5 inche Also, all four logic trip devices were within the test acceptance criteria of -42 to -45 inches and all were within-Technical Specification limits of greater than -48 inches. The alternate rod insertion logic was confirmed to be:

(A or C) and (B or D)

The HPCI/RCIC initiation logic was confirmed to be:

(A or B) and (C or D).

The licensee determined that the A and B logic initiated, and the C and D did not initiate. This explains why alternate rod insertion actuated and why HPCI/RCIC did no The NRC restart staff reviewed the licensee's root cause analysis of the trip; monitored troubleshooting and repair activities; and, reviewed the licensee's upset and incident reports (2-89-51), GP-18 reactor trip review procedure, and corrective actions. The NRC restart staff provided 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> coverage of licensee post trip and pre-startup activitie The licensee restarted the unit on May 21, 1989, and criticality was achieved at 6:53 The FWLCS was subsequently shifted to three element control at 9:02 on May 25, 1989. Three element control of reactor water level was as expected in automatic FWLCS operatio .2.3 Offgas Recombiner Abnormality on May 22, 1989 At 12:56 p.m., on May 22, 1989, the turbine generator (TG)

was synchronized with the grid at 21?s reactor powe During afternoon shift on May 22, 1989, at about 8:15 p.m.,

high level and high pressure occurred in the offgas recombiner condenser. With the potential for problems with ,

condenser vacuum, the licensee tripped the TG at 10:15 p.m., and reduced power to 5?s

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4 8 due to this offgas recombiner abnormality. During this transient, a small gaseous release occurred into the recombiner building and out through the Unit 3 reactor building ventilation stack. This release was calculated to be 1.67% of the whole body and 0.3% of'the skin dose Technical Specification limit The reactor remained at 5%

power until troubleshooting and repairs to the offgas recombiner system were complete Licensee actions included a complete walkdown of the offgas and recombiner systems, review of operational data from the recombiner transient, review of the release flow path, inspection of the recombiner condenser for possible tube leaks, and review of the system design and operating procedure The licensee concluded that a high steam input (9200 versus-7500 pounds mass per hour) to the jet compressor caused high level and high pressure in the offgas condenser shell side. This caused a flow backup in the offgas stream and could have caused a loss of main condenser vacuum. No tube leaks were found in the recombiner condenser. The licensee confirmed the release path to be from the offgas recombiner condenser shell side relief valve to the recombiner building sumps and into the ventilation system. The licensee placed the offgas and recombiner systems back in service at 6:30 a.m. on May 24, 1989, to monitor its operation. No further difficulties were note The inspector observed licensee actions in the control room and in the health physics office. The licensee evacuated the recombiner building as required by procedure ON-104,

" Vent Stack High Radiation". Immediate and follow-up actions were consistent with procedures and were conservative. The inspector observed licensee troubleshooting activities and attended several meetings at which system operations were discussed. The inspector also walked down the affected system with the system engineer and the plant Manager. The inspector concluded that the licensee took adequate immediate actions, determined the root cause and initiated appropriate corrective action .2.4 Unit 2 Torus Level Increase on May 26, 1989 At about midnight on May 26, 1989, the inspector noted an increasing level in the Unit 2 torus. Level was 14.75 f and was increasing slowly. The reactor operator (RO) had also noted the increase. Several minutes later the high level alarm occurred at 14.80 ft. The RO began to pump down the torus, and alerted the Shift Supervisor and Shif t

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Manage All possible inputs into the torus were evaluated. The R0 noted that the A loop of RHR was tested during the preceding shift and that the C RHR pump discharge check valve sometimes fails to fully seat. The RO sent a non-licensed operator to the C RHR room to check closed the external actuator arm on the check valve. Torus' level l peaked at 14.87 ft. which is below the TS limit and entry

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condition for T-102, " Containment Control" (14.90 ft.).

l The inspector calculated that the input from the RHR stayfull system via the condensate storage tank was about 15,000 gallons. This closely corresponded to an increase in torus level of about two inches (from 14.70 ft. to 14.87 ft.).

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personnel. The Shift Manager directed the STA to write an incident repor Licensee corrective actions were adequat !

4.2.5 E-22 Emergency Bus Potential Transformer (PT) Failure on May 31, 1989 At about 5:10 a.m., on May 31, 1989, a guard and a non-licensed operator each reported an acrid smell in the E-22 4KV bus room. Shift management discussed corrective actions while the source of the smell was investigated. At 6:10 a.m., the fuses isolating the pts in the E-222 breaker compartment were pulled and no abnormalities were foun At shift turnover, at about 7:00 a.m., the oncoming licensee operations shift reviewed and discussed the situation, and prepared a contingency plan to shut down the reactor due to a possible anticipated transient caused by ,

an inoperable E-22 bus. The E-22 bus may have had to be taken out of service to investigate this acrid odor in the switchgear cabinets. The E-22 bus supplies safety-related station load and control. According to the plan, the PT fuses were removed from circuit breaker E-22 bus compartment at 8:40 a.m. The plant generation support i staff identified PT-2-54-1606 in the E-22 bus as damage The licensee entered a Technical Specification (TS)

limiting condition for operation (LCO) in accordance with TS Table 3.2.B. TS Table 3.2.B is related to the availability of the 4KV emergency bus undervoltage relays and the 4KV emergency bus sequential loading relays for the core and containment cooling system At 9:35 a.m., the E-22 4KV bus was returned to its original condition without any repair or replacement of damaged E-22 bus PT 1606. The NRC was notified via the ENS of a one hour notification due to an initiation of plant shut

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i down within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The licensee initiated a maintenance request form (MRF) 8904467 to replace PT 1606 with a similar PT obtained from Unit 3. At 2:02 p.m., the licensee initiated a second TS LCO action statement, and the repair / replacement of the PT was' completed by 2:27 p.m. System operability was verified and the E-22 bus was returned to service. The NRC was notified and the LCO was cleared at 2:30 l The inspector examined the failed PT (GE type JVM-3, l 4400V/120V) during licensee troubleshooting. The inspector also observed replacement work and verified that QC performed an independent verification of quality control replacement activities for the P The inspector attended the licensee briefing and review of the contingency plan related to the E-22 bus PT replacement and the facility's Technical Specification constraints. The inspector concluded that licensee actions were conservative and no unacceptable conditions were note .2.6 Local Power Range Monitor (LPRM) Spiking During the restart power testing program, Unit 2 experienced five LPRM detector failures of the 60 new NA-300 type detectors installed. The failures consisted of momentary spikes with indicated LPRM power level high enough to trip the reactor protection system (RPS) and generate a half reactor trip conditio Each time this occurred, the operating shift adequately responded to the half reactor trip, bypassed the malfunctioning LPRM, reset the RPS and verified the minimum number of LPRMs were operable. None of the 112 older LPRMs currently installed have exhibited this phenomeno Interviews with licensee personnel and GE representatives revealed that similar problems have occurred at other plants with NA-300 series type LPRMs. The detector vendor l believes that the cause of this spiking is due to a uranium l coating instability in the detector which produces a fine l uranium powder with marginal adherence to remainder of coating. This powder is responsible for producing the random spikes as it breaks apart. The manufacturing process has since been changed to correct this coating instability and newer NA-300 detectors are not subject to this proble The vendor has found that by performing a voltage plateau curve test on the detector, the uranium powder is burned off the cathode and the spiking problem either stops or is reduce The licensee is planning on running this plateau l

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curve test on all 60 of their NA-300 LPRMs. The inspector will review the results of those test .3 Nuclear Revi9w Board (NRB) Meeting (40500)

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The corporate Nuclear Review Board (NRB) held meeting number 241 at the Peach Buttom Station on May 11, 1989. The inspector attended the meeting and observed that a quorum (including the principal NRB

, members and NRB consultants) was present. The meeting was conducted in accordance with a detailed agenda which encompassed the scope of issues specified for NRB review in the Technical Specifications (TS).

The inspector noted that the current NRB meeting frequency is three times greater than required by the T Topics discussed included, but were not limited to the following:

readiness of the plant to proceed with the startup test program; operating abnormalities; unanticipated deficiencies; the emergency cooling tower test results; voltage regulation study concerns; reports by the Plant Manager, the Shift Manager, Plant Services, and the. Nuclear Services Division; reports on plant tours; LERs; PORC meeting minute reviews; Nuclear Quality Assurance audits; and ISEG activitie The NRB considered the results of operating experience from an event at Limerick by reviewing the Peach Bottom program for use of hoists and cranes. The licensee demonstrated its self assessment / independent assessment capability by reviewing whether the generic implications of specific incidents are systematically considere Consideration of generic implications, in this regard, would involve whether the root cause for given incidents is also applicable to other plant activities or equipment not involved in the specific inciden This topic was addressed by the Plant Manager and several of the consultants to the NRB. A consultant suggested that several LERs (2-89-02 and ,

2-89-04) offered no discussion of the generic implications of the 1 subject incident and that such consideration should be give The inspector concluded that the NRB meeting appeared to be effective '

and no deviations from TS or procedural requirements were observe .0 Shift Activities and Observations (71707, 71715)

5.3 NRC Shift Coverage The NRC restart team began 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> continuous shift coverage on April 26, 1989 (see NRC inspection 277/89-15,278/89-15). This inspection coverage continued until 11:00 p.m. on June 2, 1989, when the licensee had been at a steady state 35% power level for approximately '

48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. During the Memorial Day weekend from 7:00 p.m. Saturday, May 27 until 7:00 p.m. Monday, May 29, 1989, continuous inspection

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coverage.was suspended due to steady-state plant conditions. During this period of non-continuous coverage, unscheduled random backshift i inspections and tours were performed by the NRC restart tea .2 Operator Performance, Attentiveness and Formality The inspectors routinely monitored licensed operator alertne~s, s attentiveness and job performance in accordance with the requirements of the appropriate sections of the Operations Manual. No instances of operator inattentiveness were note Operational activities were conducted formally as noted during shift turnover, during routine j control panel monitoring, and during off-normal and emergency '

situations. Several times during the shift coverage, inspectors noted that the unit reactor operator was performing administrative duties including answering the phone at the console, performing paperwork, etc. These duties could have the potential to distract an operator.from his licensed duties. The inspector checked the Operations Manual section 7 which describes the frequency of panel checks. These required panel checks were performed. This item was also discussed with operations management who had also noted two instances of excessive administrative workload for reactor operator ~

One instance of a brief loss of decorum by a Chief Operator (common unit reactor operator) was noted by the inspector at 10:20 a.m. on May'26, 1989. A discussion between the operator and the Shift Manager was in progress when the operator elevated his voice and 'used body / hand gestures. The duration of this episode was brief, i.e., a few seconds; and at no time was the operator inattentive to his common unit electrical / radiation monitoring panels. Following the outburst, the Shift Manager relieved the operator temporarily, and held a discussion in his office. After about ten minutes, the operator resumed his Chief Operator duties. After the meeting with the Shift Manager, the operator acted professionally in all his licensed duties and activities. Further follow-up and discussions with the operator, the Shift Manager, and operations management were held. The inspector concluded that the Shift Manager's actions were prudent and timely with respect to disciplining the operato Apparently the outburst was caused by the operator's lack of understanding why the reactor pressure narrow range recorder was not being kept on-scale between 950-1050 psi The reason for a change in operating the reactor pressure setpoint during startup in GP-2 was apparently not communicated to the operators. Licensee management reviewed this item and provided the technical reasons for this change to operating personnel. The inspector had no further questions at this tim .3 Logs and Records (71707)

The inspector reviewed logs and records for accuracy, completeness, abnormal conditions, significant operating changes and trends,

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required entries, temporary plant alterations, conformance with

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Limiting Conditions for Operations, and proper reporting. The following logs and records were reviewed: Control Room Shift Supervisor Log, Reactor Engineering Logs, Unit 2 Reactor Operator Log, Unit 3 Reactor Operator Log, Chief Operator Log, STA Log, QC Shift Monitor Log, Radiation Work Permits, Locked Valve Log, Maintenance Request Forms, Temporary Plant Alteration Log, Special Procedures Log, Information Tag Log, Annunciator Mode Log, Plant Status List, and Ignition Source Control Checklist Control Room logs were compared with Administrative Procedure A-7, Shift Operations, and the Operations Manual. Frequent initialing of entries by licensed operators, shift supervision, and licensee site management constituted evidence of licensee revie Logkeeping by control room operators was generally thorough and accurate and in accordance with the Operations Manual. However, several minor instances of poor logkeeping were noted. During the 11 p.m. to 7 a.m. shift on May 16, 1989, the reactor operator did not log the noted operational problems with the position indication for the RCIC discharge check valve and the vibration alarm on th reactor recirculation pump. Other occasions of poor logkeeping included two instances of write overs without initialling. These instances were discussed with the respective operator, and with shift and operations management. Further reviews of operator logs by the inspector indicated improvement .4 Plant Tours Each shift inspector conducted random tours of plant areas. These tours included inspection of plant equipment, non-licensed operator performance, work activities, health physics controls and securit During these tours the following items were note . Floor and Equipment Drains During a tour of the Unit 2 Reactor Core Isolation Cooling (RCIC) system pump room on May 14, 1989, the inspector noted that equipment drain plug DRN-2-208-2062 was removed. !

A tygon tube was connected between the RCIC pump pedestal drain and the equipment drain. No one was in the immediate j are The inspector returned to the control room and obtained the I most recent copy of GP-2, " Normal Plant Start-Up". Step 3.5.9 stated that all floor and equipment drains in the reactor building were closed per RT 13.9. The inspector questioned shift management concerning the type of I administrative controls in effec The temporary plant !

alteration (TPA) log did not contain an active TPA log entry that removed the plu I

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l Emergency core cooling system (ECCS) floor and equipment drain plugs are to be strictly controlled due to potential flood paths that could be. opened between various ECCS rooms-and the reactor building sump. Plugging floor-and equipment drains was done in response to nonconformance report (NCR)

P 88-123-213. Abnormal operating procedure A0-20A.1,

" Removing a Floor Drain Plug, Equipment Drain Plug or Cleanout Cover," was also written so that these plugs could be removed without the use of a TPA. Shift management approval is needed to open a drain (as stated on a-tag by each and every drain), and A0-20A.1 Attachment 1 is to be filled out. The procedure also states that anytime a drain is opened during reactor operation, a person must be st6tioned in the vicinit Failing to follow procedure A0-20A.1 is an NRC identified violation of Technical Specification 6.8.1 (277/89-16-01).

.However, no Notice of Violation will be issued in accordance with Enforcement Guidance Memorandum (EGM)

88-08, dated November 13, 1988. Discretion can be exercised if all of the following exists:

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Severity level V;

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Appropriate corrective actions were initiated prior to the close of the inspection;

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Non willful; and

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Non recurren The licensee determined that the root cause of the violation was failing to inform shift operations of the new drain control policy and newly written procedure A0-20 Immediate corrective action consisted of replacing the drain plug. Corrective action to prevent recurrence consisted of holding a critique, writing an incident report, providing a letter to shif t operations informing operators of the drain policy and A0-20A.1, and publishing this same information in the operations section newslette Future corrective action will consist of replacing A0-20 with a less restrictive administrative procedure and hanging new tags on all the drains that will require shift management approval for entry into the drain system in accordance with a soon to be written administrative procedur The inspector reviewed the licensee's letter, operations section newsletter, the draft incident report and attended the critiqu Tnese corrective actions were found to be satisfactor The inspector will review the remaining corrective actions in a future repor _ - -

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5.4.2 High Radiation Area Control At 9:55 p.m. on May 16, 1989, a shift inspector found a door labelled Locked High Radiation Area (HRA) opened with no individual providing positive door control. The door provided access to the containment personnel air lock and to .the outboard main steam isolation valve (OBMSIV) room on the 135 foot elevation of the reactor building of Unit The containment is a designated locked HRA and the OBMSIV room is potentially a locked HRA. The inspector immediately questioned nearby test engineers regarding whether any individuals were within the HRA and the responsibility for providing positive control for the opened door. The test engineers responded to the inspectors concern by calling security and health physics (HP). A security guard responded to the call, but took no action apparently because it was an HP problem. At 10:10 p.m. an HP technician arrived at the door. He explained that he had left the area 15 minutes earlier to start an air sample requested by his supervisor. He closed the open HRA door. The shift in:pector, satisfied that an apparent immediate safety concern was corrected continued with his tou HP supervision had decided before plant restart to control HRAs by locking all the areat that had the potential to become high radiation areas during reactor power operation ,

This would allow a check of the new procedures for control 9 of keys to locked HRAs to determine the adequacy of procedural controls and training efforts. However, this management decision was apparently ineffectively communicated to the HP technicians as some HP technicians were unaware of the decision. The technicians were confused over the existing posting and control of areas that were designated as locked HRAs. These areas would not become locked HRAs until the unit was at a higher power leve The attitude of the HP technicians led to reduced sensitivity to the posting and control of the designated locked HRA The requirements for positive control of locked HRAs are specified in Technical Specification (TS) 6.13. In ,

implementing these requirements, several procedures were not j followed by licensee personnel: )

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A-114, Rev. O, " Locked High Radiation Controls"

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A-111, Rev. O, " Duties and Responsibilities of Health Physics Personnel"

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A-116, Rev. O, " Radiation Worker Responsibilities"  !

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HP-215, Rev. 5, " Establishing and Posting l

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The HP technician had the responsibility and authority to'

change posting based on radiation levels which he knew by surveys to be only a radiation area where the HP technician was directed.to obtain an air sample by an HP supervisor, he did not change the posting but left the door ope The incident was investigated by the licensee per procedure A-110, Rev 2, " Radiological Occurrence Reports (ROR)". A completed ROR was reviewed by the inspector on May 19, 1989. The inspector determined that the immediate corrective actions were adequate. However, weaknesses were noted with both the long term corrective actions and the root cause analysis This was discussed with the licensee and the licensee indicated that a revised ROR would be initiate The inspector noted that additional licensee commitments were made for root cause analysis and for corrective actions. The inspector considers these to be adequat Failure to follow procedures A-114, A-111, A-116 and HP-215 is an NRC identified violation of Technical Specification 6.8.1 (277/89-16-02). However, no Notice.of Violation will be issued in accordance with Enforcement Guidance Memorandum (EGM) 88-08, dated November 13, 1988, since the following conditions exist:

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Severity level V;

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Appropriate corrective actions were -

initiated prior to the close of the .

inspection;

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Non-willful; and

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Non-recurren The inspector had no further questions at this tim .5 Shift Turnover and Communications Shift turnover activities, and operator control room and external verbal communications were observe Shift turnover activities were professionally conducted. All required information was passed on either verbally or documented in the turnover checklis Shift Manager turnover briefings were effective in informing operating personnel of plant status, problems and planned activitie Face-to-face communications were confirmed by repeating back the message to the originator. Operator communications with other work groeps was also reviewed and was effective. No unacceptable condit ons were note !

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5.6 Control Room Staffing and Training Control' room staffing was checked and found to be in accordance with Technical Specifications 6.2.2 and 10 CFR 50.54(k), (1), and (m). On May 19, 1989, the licensee informed the shift inspector that one reactor operator was temporarily removed from licensed duties due.to an abnormal medical evaluation. The licensee replaced this-operator with a. reactor operator from another shift. -This action maintained ,

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two fully qualified reactor operators on each of.the six operating shifts. .At the end of_the period, the licensee ~ maintained a staffing level of 18 senior reactor operators and 24 reactor operators for the -

six shift Of the total number of licensed operators, 13 have restricted li cen se s ~. These individuals are working on their reactivity manipulations and operating time above 20's powe T_he licensee tracks completion af reactivity manipulations and the time spent with the reactor above 20?4 power. .The Superintendent of Operations developed guidance to ensure that reactivity manipulations meet NUREG 1021 guidance. The inspector reviewed this guidance dated May 15, 1989, and concluded that NUREG 1021 guidance is being met. A tracking form (SP-1166, Exhibit T-1) is maintained for each ,

. individual. These forms are filed for each shift and maintained in i the control room offices. Surveillance and routine test. performance is also tracked for trair.ing purposes and documentation. The shift test coordinator maintains these records. When an operator with a restricted license completes his required items, the forms are assembled and sent to the training department. The inspector reviewed selected files and discussed program implementation with licensee personnel. No unacceptable conditions were note .7 Technical Specification (TS) Comp ia ge and Deportability The inspector reviewed the li'cm ee's interpretation, 'mp"ementation and use of the plant TS, ind uding limiting conditions fr operation and action statements. The inspector determined that the licensee was using conservatism in declaring TS related equipment inoperable due to system malfunctions. Examples included the following: safety relief valve 71L, the HPCI system, E-22 bus relays and protective trips, intermediate range monitors, the core spray minimum flow valve, a reactor water level recorder, and the RCIC flow controller. All required ENS reports were made on the ENS phon No unacceptable conditions were note .8 Test and Special Evolution Control The Shift Manager and Shift Test Coordinator provided the operations staff with effective pre-test briefing Examples included the

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l\; 18 following: safety relief valve 71L testing and subsequent retesting; feedwater and condensate pump startup, turbine generator startup, synchronization and overspeed testing; and HPCI/RCIC system testin Tests and evolutions were well coordinated and professionally

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conducted. Several of the tests required temporary procedure changes. These changes were made in accordance with administrative controls. No unacceptable conditions were note .9 Procedure Adherence Procedure adequacy., compliance, and adherence was reviewe Control room licensed operators were adhering to operating procedures. No instances of procedural noncompliance by licensed operators were note The operators used the temporary change (TC) process when require ,

Permanent TCs were noted as being kept in the procedure cart in the control room. In a few instances, the operators displayed difficulty in locating a procedure that had a TC in effect. However, all TCs were eventually located and' adequately implemente Two cases of procedure noncompliance were noted by the inspector .

during plant tourt (see section 5.4). One was by a non-licensed '

operator due to lack of training and the other was by a health physics technician. The licensee also identified an instance where a non-licensed operator placed the drywell instrument nitrogen system in service without using the system operating procedur The licensee reviewed this event, prepared incident report #2-89-48 and implemented corrective actions. The licensee determined that poor communications and misunderstanding by the operator contributed to this event. The inspector reviewed the incident report including the root cause and corrective actions, and discussed the item with shift and operations management personnel. The inspector concluded that the licensee's review was adequat The inspector observed a traversing in-core probe system (TIPS)

operation in the control room on May 25, 1989. Two reactor engineers attempted to start the system but were unsuccessful. They then obtained system operating procedures S.5.4.1.A and S.S.4.1.B. One of the engineers missed a procedure step which requires waiting for the

" Ready" light to come on before attempting to insert a detector. The light would not illuminate, but he pressed Auto Start to begin detector insertion. The system did not respond. A more experienced reactor engineer then informed the other two of several inadequacies in the TIPS procedures and advised them of the correct way to operate the syste Procedure S.5.4.1.8 is missing instructions for operating the X-Y plotter which caused the engineers to miss a trace during a TIPS run and necessitated repeating the run. Some of the TIPS panel labelling

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I is inconsistent with procedure terminology and several switches on the panels are either not labelled or have some unlabelled position The inspector was informed that a complete rewrite of the TIPS )

procedures is planned. In the interim, TIPS will be operated using i the existing approved procedures. However, these procedures require 4 the engineer's knowledge of the system for implementation. These deficiencies were identified to the licensee for corrective action During surveillance test ST 6.1.2-1 performed on May 20, 1989, a non-licensed operator noted that he had an out of date revision of the procedure in use. He stopped the test, acquired the correct i revision and performed the test satisfactoril The reason for the out'of date revision was that the ST was revised after the test was ,

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issued to operations for performance. The operator apparently did not check the ST index for the correct revision. However, he did later note the error and obtained the current ST revisio The inspector determined that the way in which STs are issued could cause out of.date revisions to be used. The ST coordinator issues a group of STs on Fridays prior to the week they are scheduled for performance. The ST Coordinator checks that each ST is current aginst the ST index. However, if a new revision was to be issued prior to ST performance and if the individual performing the ST failed to check the ST index, an outdated revision would be used. To correct this situation, a letter has been issued to remind individuals to check for current revision In addition, the ST Coordinator now checks for issued, out of date ST revisions when he receives a newly revised ST. These new licensee practices have noted two discrepancies during the last two weeks of this inspection period. The inspector had no further question .10 Response to Off-Normal Conditions Operator response to off-normal conditions was timely, conservative, and in accordance with operating / emergency procedure Examples included the following: reactor trip (section 4.2.2), EHC malfunction (section 4.2.1), loss of offgas recombiner (section 4.2.3), bomb threat (section 10.2), and E-22 bus room acrid smell (section 4.2.5).

Once the plant was stabilized, equipment troubleshooting, maintenance or repair, and equipment control was adequately performed. One instance of an unexpected result of a troubleshooting control form (TCF) occurred on May 23, 1989. During implementation of an approved TCF for the EHC system, the bypass valves opened unexpectedl Operator response was adequate and the troubleshooting was suspende i i

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In general, operating problems or concerns eventually result in positive corrective action, such as procedure changes, troubleshooting, or maintenanc .11 Team Work Each shift team was evaluated as being effective in accomplishing assigned tasks. The control room operations crew worked well together including coordination and direction of non-licensed operator activities (outside control room). The operators were also noted as working well with rther site groups including: system and reactor engineers during testing and troubleshooting; maintenance personnel during equipment turnover, repair and testing; health physics personnel; and independent oversight groups and managemen .12 Control Room Human Factors Engineering The licensee completed a control room design review on February 28, 1986, which addressed many human engineering deficiencies (HED) in need of correction. More than 70's of these HEDs have since been  ;

corrected. The majority of these were corrected during Modification -

2132. 'The inspector noted some additional minor items which appear to have been misse Some examples include:

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low pressure turbine instruments are arranged in three rows corresponding to the three stages; except for inlet pressure indicatio high pressure turbine first stage pressure indication is marked " Turbine Inlet" even though the documentation such as the FSAR refers to it as first stage pressur oxygen sample switch (SS-2981) information label lists position 1 as middle torus and position 2 as upper toru The actual positions are opposit the primary containment isolation system status panel is not consistent in the arrangement of its indicating lights as to whether left is inboard or right is inboar t Other examples exist but these are representative of the issue. The f licensee is continuing to address this deficienc Based on l interviews with operators and management personnel, none of these i discrepancies are considered to be significant. The licensee's  ;

progress will continue to be monitored and an update provided in a 1 future repor j j

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6.0 Review of Licensee Event Reports (LERs)

6.1 LER Review (90712)

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 site follow-up. The following LERs were reviewed:

LER N LER Date Event Date Subject 2-87-08, Rev. 1 Control room radiation monitor incorrect 5/25/89 configuration-5/29/87 2-88-07, Rev. 1 Inadequate surveillance due to test procedure 05/24/89 deficiency 10/26/88

"2-89-05 Motor control center terminal blocks mir. sing 05/08/89 hold down bolts (see NRC Inspection 04/06/89 277/89-15, 278/89-15)

  • 2-89-06 Containment atmosphere pneumatic tubing 02/09/89 improperly installed (see NRC Inspections 05/09/89 277/89-81 and 15, 278/89-81 and 15)
  • 2-89-07 Excessive grease on emergency 4KV switchgear 05/09/89 fuse clip contacts (see NRC Inspection 04/11/89 277/89-15, 278/89-15)
  • 2-89-08 Unit 2 containment isolation due to personnel 05/15/89 error (see NRC Inspection 277/89-15, 04/15/89 278/89-15)
  • 2-89-09 HPCI wiring error 06/05/89 05/05/89
  • 2-89-10 RSCS Surveillance test missed 06/09/89 05/14/89

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  • 2-89-11 Scram discharge volume valves surveillance l4 05/30/89 test missed 04/26/89 03-88-03, Rev. 2 Unit 3 containment isolation due to RPS 05/19/89 alternate feed trips 05/20/88 6.2 LER Follow-up (92700)

For LERs selected for follow-up and review denoted by asterisks above, the inspector verified that appropriate corrective action was taken or responsibility was assigned and that continued operation of the facility was conducted in accordant with Technical Specifications and did not constitute an unreviewed safety question as defined in 10 CFR 50.59. Report accuracy, compliance with current reporting requirements and applicability to other site systems and components were also reviewe . LER 2-89-09 concerns a licensee identified High Pressure Coolant Injection (HPCI) system wiring error discovered during surveillance operability testing on May 5, 1989. This operability test noted a lack of automatic governor valve control when HPCI was initially tested at 150 psig reactor pcessure. The governor valve was full open with HPCI flow rate greater than the rated 6000 gp This condition also occurred when the HPCI flow controller was switched to manual. A wiring error was identified as an unresolved item (277/89-15-02) in a previous NRC Inspection 277/89-15, 278/89-15. (See section 3.3.)

The licensee performed an investigation and root cause analysis of the wirirg error event. The licensee determined that the root cause of this event was failure to follow installation instructions by craft electricians during the implementation of Modification 5061. This modification installed an analog signal isolator which provides electrical isolation for fire protection concerns on the HPCI flow controlle The installation error (by a contract journeyman electrician) resulted in a discrepancy in the configuration e of the analog isolator. The polarity was reversed between i

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the flow controller and the ramp generato The causes of this discrepancy were as follows:

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The electrician made field wiring connections using the industry standard practice of. color

, matching (white to white, black to black, etc) in b

lieu of point to point as specified in installation procedure CD 5.3; and,

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The electrician applied the industry standard practice of positive (+) to black and negative (-) to white when bench wiring the isolator without regard to the external wiring color conventio The licensee also concluded that there were three c. contributing factors for this event:

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Inadequate Inspection post installation inspection was inadequate due to the failure of the Quality Control (QC) inspector to verify that the wiring installation was in accordance with the work instructions per procedure CD 5.3 and drawin Inadequate Field Wiring Check - The Field Installation Engineer used color coding to perform the point to point wiring check and therefore, failed to identify the installation error Communications used during the check were not specific with regard to wire number, cable number, or terminal poin Inadequate Modification Acceptance Test (MAT)

Procedure - MAT 5061 utilized Surveillance Procedure SI-2F-23-82-XXC0 " Calibration Check of HPCI Flow Instruments" to verify the instrument loop from flow controller to ramp generator and signal converter. The SI procedure did not provide sufficient overlap of tested components to assure the required portions of the loop were teste Licensee corrective actions completed included the following:

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HPCI was declared inoperable, redundant systems (reactor core isolation cooling and automatic depressurization) were satisfactorily tested, the wiring error was corrected, and HPCI was retested satisfactoril Supervisory personnel associated with implementation of modifications were briefed on this even ._ __ __ -____ _ _

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The specific individuals. involved in the installation, inspection, and testing of the isolator have been counseled on this event and the significance of the errors committe Installation Checklists for open electrical modifications have been changed to require the l first line supervisor or the Site Lead Man (Job

, Foreman) to verify correct installation of the

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work prior to QC inspection.

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In addition, corrective actions planned include:

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Review the event with construction, inspection, test, and plant personnel associated with the implementation of modifications and MATS. Areas to be discussed include: adherence to procedures / instructions, wiring color standards, use of wire tags as a construction aide only, and attention to detail regardless of apparent simplicity of the installatio Revise Construction Division Procedure, CD 5.3,

" Procedure fo~r the Installation of Electrical Equipment" to require the Site Lead Man to verify the correct installation of the work prior to QC inspectio Enhance the modification process to further ensure that when an SI or other standard test is to be used to functionally test an electrical installation, the test adequately encompasses the components required to be teste Instruct personnel performing wiring checks in use of proper communications practices when performing wire checks or other similar task The inspector reviewed this LER; attended the licensee's critique and root cause meeting; reviewed operations incident report #2-89-44; reviewed the associated drawings and field installation; and, discussed this item with licensee engineering, management, and QA/QC personnel. The i'

inspector concluded that the licensee performed an in-depth investigation and root cause analysi Technical Specification (TS) section 6.8.1 requires written procedures in accordance with ANSI N18.7-1972 and NRC Regulatory Guide 1.33. These documents require procedures for modification installation, inspection and testin On May 5,1989, during HPCI testing and troubleshooting the licensee noted that MOD 5061 was inadequately installed, inadequately inspected by QC, and inadequately tested by engineering and I&C personnel. These successive failures of modification installation, inspection and testing procedures are collectively a violation of TS 6. !

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(277/89-16-03). The unresolved item is administratively l closed (277/89-15-02).

Since the overall modification process has been noted as a weakness by both the licensee and the NRC (see NRC Inspection 277/89-81,278/89-81), a Notice of Violation is being issued in this instance of a licensee identified-violatio . LERs 2-89-10 and 11 are two examples of licensee identified violations for failure to perform Technical Specification (TS) surveillance requirements (277/89-16-04). LER 2-89-10 concerns a failure to test the rod sequence control system (RSCS) at 50% control rod density as required by TS 4.3.B.3.a during a Unit 2 reactor startup conducted on May 14, 1989. The licensee determined that a personnel errcr by shift management during review of GP-2, " Plant Startup" was the root cause. The licensee also determined that the event had no safety consequences based on the following considerations: RSCS was adequately backed up by both the control rod pull sheet per GP-2 and by an operable .od worth minimizer system; the missed surveillance test (ST 10.6.2) was satisfactorily performed two weeks prior to 1: disenvery; ST 10.6.2 was performed satisfactorily upon discovery; and, the control rod pull sheets in GP-2 vers adequately followe LER 2-89-11 concerns a failure to test the trip discharge volume vent and drain valves per ST 9.22 prior to Unit 2 startup on April 26, 198 This testing is required by TS 4.3.A.2.c. The licensee determined that'the cause was partly due to an omission from procedure GP-11C, " Mode Switch to Refuel" and partly due to the ST " Master File" requiring the test to be performed only at power.. The licensee determined that the consequences of this item were minimal based on the following considerations: ST 9.22 was satisfactorily performed on April 29, 1989, when the missed test was identified; a historical review to 1985 noted that these valves have demonstrated adequate stroke times; and, that the valves are tested monthly when the TS require a quarterly tes The licensee reviewed the ST " Master File" and did not find any other missed ST The inspector reviewed licensee corrective actions and determined them to be adequate to prevent recurrence. The inspector determined that failure to perform TS surveillance requirements meet the criteria for licensee identified violations. The inspector had no further questions at this tim )

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7.0 Surveillance Testing (61726, 71707)

7.1 Surveillance Observation The inspector observed surveillance tests to verify that testing had been properly scheduled, approved by shift supervision, control room operators were knowledgeable regarding testing in progress, approved procedures were being used, redundant systems or components were available for service as required, test instrumentation was calibrated, work was performed by qualified personnel, and test-acceptance criteria were me Daily surveillance tests including instrument channel checks, jet pump operability, and control rod operability were verified to be adequately performe Parts of the tests listed in Attachment I were observed. Specific comments are-noted in the following section . 2 Core Spray System and Cooler Operability (ST 6.6.1 and ST 6.7.1)

Surveillance Test (ST) procedures 6.6.1 and'6.7.1 provide for the i operability test of core spray system loops A and B and the room coolers when a core spray pump, a low pressure coolant injection (LPCI) subsystem, or a diesel generator is inoperable. The inspector witnessed a surveillance test of the core spray system performed ~

based on the inoperability of the high pressure coolant injection (HPCI) in accordance with the requirements of Technical Specifications (TS) 3.5.C.2. Review of the procedure indicated that

'HPCI inoperability was not factored into the ST as a requirement for the core spray system surveillance test. The inspector discussed the concern with the cognizant operations staff and was informed that the subsequent revision of the procedure will incorporate the requirements delineated in TS 3.5. During core spray loop A operability testing, full flow test motor operated valve M0-02-14-026A did not stroke fully closed with the 2C pump running. The licensee's investigation confirmed inadequate setting of the torque switch which prevented the valve from seating properly when stroking to the closed position. Maintenance request form (MRF) 89-03841 was initiated to adjust the torque switch. The torque switch thrust was readjusted to 66,000 ft-lbs and the valve was successfully stroked and proper valve seating was verifie During core spray loop B operability testing, the control switch for normally open outside containment discharge valve MO-02-14-011B had to be held for approximately two seconds for the valve to strok Although no operability problem was encountered, the control room operator tagged the valve switch with an information ta These core spray operability tests were adequately coordinated and interfaced between plant operations and test personnel. The tests were i

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7.3 HPCI Logic System Functional (ST1.1) and HPCI Flow Rate Test At 150 psig (ST 10.1)

ST 1.1 provides for the verification of the HPCI system logic to initiate and sustain the automatic operation of the HPCI system during a design basis accident condition. ST 10.1 provides for the operability test and performance of the HPCI system at 150 psig steam pressure. The inspector witnessed these HPCI . system tests conducted in accordance with the STs. Two temporary changes (TCs) 89-0901 and 89-0902 were adequately initiated to modify the test steps of ST in order to complete the test satisfactoril During the HPCI operability test per ST 10.1, the system did not respond to the flow controller signal. Troubleshooting detected that the newly installed Analog Isolator was not properly field wired per an installation procedure contained in MOD 5061 for this installation (see section 6.2.1). The polarities were found reversed at the Analog Isolator resulting in erroneous output signal. As such, the HPCI governor valve had continuous' signal of full open regardless of the system flow or the flow controller setpoint. However, during the surveillance test for system operability, the miswiring of the system was identifie The HPCI system was declared inoperable and the licensee rotified the NRC in accordance with administrative procedures, A-31, Notification to the NRC, and A-86, Corrective Action. Subsequently, the wiring connection was modified and system operability was retested satisfactorily 7.4 Relief Valves Manual Actuation (ST 10.4)

ST 10.4 provides for the inservice testing of the eleven main steam relief valves RV-2-01-71 A through L. The inspector witnessed the testing of the relief valves with reactor pressure at 175 psig and three bypass valves open. During the test, relief valves 71 A, G, H and L did not operate properly as required by the procedur Troubleshooting indicated that the acoustic monitors that provide valve position were loose. In addition, the thermocouple sensor for relief valve 71 H was incorrectly wires Subsequently, the acoustic monitors were tightened and the thermocouple wiring was modifie Retesting of relief valves 71 A, G and H was successful. However, relief valve 71 L failed to close initially during the retes Consequently, the valve was declared inoperable in accordance with Technical Specification 3.6.D.1 and A thirty day limiting condition for operation action statement was entere Special Procedure SP-779 was initiated to allow ECCS to be defeated with the reactor mode switch in shutdown. Relief valve 71 L was replaced per maintenance procedure M-1.6 and MRF 890397 This relief valve was retested successfull Based on the review of the surveillance test and the valve replacement documentation, and discussion with the

cognizant operations personnel, the inspector determined that I licensee action was conservative, adequate and timely. The inspector did not have any further questions at this time.

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" 28 7.5 Unit 2 Containment Bypass Test In response to a drywell to torus low pressure alarm, the licensee decided to perform ST 12.6-1, " Primary Containment Drywell to Torus Bypass Test", Rev. 9. This test is required once per operating cycle by Technical Specifications -(TS) 4.7.A.4.d and when the drywell to torus vacuum breakers indicate not fully seated per TS 3.7. Although neither of these TS criteria were met, the licensee initiated the test. Three tests were conducted between day shift May 29, 1989, and midnight shift May 30, 1989. All of these tests failed the acceptance criteria possibly indicating the existence of a bypass hole of greater than one inch in diameter. TS 3.7.4.B requires that the unit begin a shutdown 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after an open vacuum breakte is noted with an equivalent bypass hole of one inch in diamete Although the licensee did not have an open vacuum breaker, their actions were consistent with TS action requirement During day shift on May 30, 1989, licensee engineering, operations and management personnel met to discuss these test results. They concluded that the test method required improvements to ensure a higher differential pressure (greater than 0.4 psid) was maintained throughout the test. The three previous tests showed an excessive leak when differential pressure dropped below 0.25 psid. When the pressure was greater than 0.25 psid, the previous tests passed the acceptance criteria. The licensee revised the test to increase the pressure, to correct some minor deficiencies and to increase data collection to every five minute A revised ST 12.6-1, Rev. 10, was performed between 10:37 p.m. May 30 ar.d 12:42 a.m. May 31, 1989. Test results were satisfactory. All data points were calculated to be indicative of a hole less than the minimum of one inch in diamete The inspector witnessed each test; attended the licensee's management meeting on May 30, 1989; reviewed FSAR sections 5 and 14 and, reviewed the final test results. The inspector had no further questions and no unacceptable conditions were note .6 Scram Air Header High Pressure Alarm

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On May 18, 1989, the inspector witnessed performance of ST 9.7, "MSIV

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Partial Closure and RPS Input Functional Test," Rev. 11, 4/16/89.

l The inspector noted that each time a half reactor trip was received, the 75 psig high pressure trip air header alarm would annunciate

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momentarily and then reset. When observing trip air header pressure on PI-312 in the control room, the pressure would rise to 76 psig immediately after a half reactor trip, and then slowly decrease back to the setpoint of 70 psi The inspector reviewed P&ID M-356, " Control Rod Drive (CRD) Hydraulic System - Part A," to determine the method of trip air header pressure control. According to the P&ID, pressure control valve

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.(PCV) 4239A or B should be positioned to regulate pressure at 70 psig. The inspector walked down'the CRD system to' determine the actual valve lineup. It appeared that both PCVs were in service at the same time which was in disagreement with the P&I The inspector returned to the control room and obtained the most current check-off-list (COL) 3.1.A-2, "CRD Hydraulic System Startup,"

Rev. 2, which showed that both PCVs were in service at the same tim The inspector discussed this issue with shift operators who agreed that only one PCV should be valved in. However, the Shift Manager wanted to wait until day shift to make sure that the assumption was correc The licensee determined that the P&lD was correct and the COL was  !

incorrect. The valve lineup was corrected such that only PCV-4239A was in service, and the COL was submitted for a revision. Operations also committed to observe the trip air header pressure during the next surveillance test that initiates half reactor trip testing.

) On May 30, 1989, the inspector was observing ST 9.4, " Turbine Stop Valve Closure Functional," Rev. 27, 3/10/89, and ST 9.14, " Turbine Control Valve Fast Closure Scram Functional, Rev. 24, 3/20/89. Each time a "B" channel half reactor trip was received, the high pressure trip air header alarm would annunciate momentarily and then rese The previous observations on May 18, 1989, led to the alarm during both and "A" and "B" half reactor trips. The licensee was questioned concerning this problem indicating in response that PCV-4239A has an internal problem. At the close of the inspection, the licensee was planning to take PCV-4239A out of service and place PCV-4239B in service and observe trip air header pressure during half reactor trips. The inspector will continue to follow this item in a future inspectio .0 Maintenance Activities (62703)

8.1 Routine Observations j The inspectors reviewed administrative controls and associated documentation, and observed portions of work for maintenance activities. Administrative controls checked included blocking permits, fire watches and ignition source controls, QA/QC involvement, radiological controls, plant conditions, Technical Specifications, equipment alignment and turnover information, post maintenance testing and deportability. Documents reviewed included maintenance procedures (M), maintenance request forms (MRF), item l handling reports, radiation work permits (RWP), troubleshooting '

control forms (TCF), material certifications, and receipt i inspection '

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Document Equipment Date Observed 4 M1.27 Turbine Cross Around Reliefs 05/10/89 I GP Drywell Inspection 05/10/89 TCF Emergency Cooling Water Pump 05/10/89 Auto Start Alarm M Safety Relief Valve 71L 05/12/89 TCF Intermediate Range Monitor E 05/14/89 TCF EHC Pressure Control Swapping 05/21/89 MRF 89-4330 & Traversing In-Core Probes 05/25-28/89 4388 TCF Combined Intermediate Valves 05/26/89 TCF E-22 Bus Potential Transformers 05/31/89 SP-1286 Unit 3 Reactor Vessel Manway 06/6-9/89 Repair MRF 89-4659 Unit 2 A Main Steam Line 06/07/89 Radiation Monitor MRF 89-4703 Unit 2 HPCI Leak Repair 06/15/89 No inadequacies were identifie .2 Unit 2. Maintenance Backlog The inspector reviewed the current maintenance backlog. This l

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included comparing a listing of off-normal control room annunciators and control room instrument deficiencies documented in the Unit 2 TRIPOD daily status report with the annunciators and instruments in the control room. Although the list generally matched the as-found condition, several differences were noted. Two instruments (FR-2522 and PR-8102A) were documented by a maintenance request form (MRF)

without appearing on the lis Several instruments and annunciators

! were annotated on the list as needing MRF numbers even though their I

deficiency was identified as early as May 5,1989. Several annunciators appear to be alarming spuriously yet are not identified with deficiency tags. Examples include:

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B RFPT HI VIBRATION (202/E-2)

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MAKEUP FILTER DRAIN REGENERATION TROUBLE (201/C-2)

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RHR HI TEMPERATURE (224/D-5)

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BLOWDOWN RELIEF VALVE HI TEMPERATURE (227/B-4)

On June 8, 1989, the inspector noted that there were 84 deficiency tags hanging on the Unit 2 control room panels. New deficiencies are apparently occurring at a faster rate than old ones are being correcte The inspector did not find any open maintenance items or MRFs that would make a safety system inoperable other than those already known ar,d allowed to be out of service by Technical Specifications and documented in the LC0 lo _ - __ ___- _

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9.0 Radiological Controls (71707)

L 9.1 Routine Observations 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 (RWP) requirements, radiation 4 surveys, radiation protection instrument use, and handling of potentially contaminated equipment and material The inspector observed individuals frisking in accordance with health physics procedures. A sampling of high radiation area doors was verified to be locked as require 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 requirement An NRC identified violation associated with high radiation controls was noted in section 5.4.2 of this repor On May 15, 1989, the Senior Health Physicist or Radiation Protection Manager (RPM) resigned and was replaced by Paul Sawyer, acting Senior Health Physicist. The inspector reviewed the qualifications of the acting RPM and compared those qualifications against the criteria stated in Technical Specification 6.3.1, Facility Staff Qualifications; in ANSI N18.1-1971; and, in Regulatory Guide (September 1975). The inspector concluded that the acting RPM met the appropriate qualification .2 Allegation Associated with Radiation Work Permits (RWP)

(R1-A-89-0055)

On May 5,1989, the resident inspector received an. anonymous (via phone) allegation stating that a first line supervisor routinely fails to adhere to procedural requirements in RWP instructions and does not follow radiological safety precautions. The caller identified himself as a Health Physics (HP) technician and identified the stpervisor by name. The alleger further stated that the identified individual was working in the plant without authorization of an RW The alleger also stated that when questioned by HP technicians, this individual denied violating any RWP. The alleger r; m d he ;;culd con'.act the NRC Resident Office with further information; rm,.cver, this was never don The inspector evaluated this allegation by interviewing HP technicians j

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who were at the various control points in the Unit 3 work areas on the specified day, and on days before and after the time frame of the allegation. In addition, a security trace of this individual was obtained. This trace indicated that the individual was in these specified areas. However, no RWP adherence concerns were note p

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The inspector also reviewed radiological occurrence reports for the time period and none were found. HP supervisory personnel were also interviewed and no concerns were raised. The inspector also reviewed the associated RWPs, inspected the Unit 3 work areas, and reviewed HP control point logs. Based on this review, the allegation could not be substantiated and it is considered close .0 Physical Security (71707)

10.1 Routine Observations The inspector monitored security activities for compliance with the accepted Security Plan and associatec: implementing procedures, including: security staffing, operation of the central and secondary alarm stations, checks 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, and compensatory measure No inadequacies were identifie .2 Bomb Threats on May 25,-1989 Two telephone calls were received at the Philadelphia Electric

' Company (PECo) Corporate Headquarters in Philadelphia, Pennsylvania, on May 25, 1989. The first call at 9:45 a.m. indicated that a van Icaded with explosives would arrive at the Peach Bottom Atomic Power Station at 11:30 (no a.m. or p.m. given). Due to the nature of the PECo telephone system, the licensee was able to determine that the anonymous call had come from their internal CENTREX telephone syste The licensee evaluated the threat as non-credible at 11:00 a.m. How-ever, as a precaution, bomb threat contingency procedures were im-plemented in and around the station which included barricades at the protected area access point, searches of vehicles in the owner-controlled area, establishing owner-controlled area vehicle access control points, posting armed officers at owner-controlled area substations, and positioning lookout The second call at 4:48 p.m. indicated that "you stopped us today, we will get you tomorrow". This call was received by the PECo operator from an outside lin The inspector was informed of the first event by the licensee at 10:25 a.m. on May 25, 1988. The licensee reported the event via the Emergency Notification System (ENS) at 12:30 p.m. The second event was also communicated to the inspector at 5:01 p.m. and the licensee made an ENS call at 5:55 p.m. per 10 CFR 73.71. The inspector and regional staff discussed these matters with the licensee. The licensee considered both threats non-credible. However, they continued to implement heightened security awarenes _ _ - - _ _ -

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The inspectors observed the licensee's actions from the control room and from various security facilities. The inspector toured the

protected area, and vital areas, and verified the licensee's heightened security actions. Selected guards, security shift assistants and operations personnel were interviewed. The inspector also attended a guard mount (shift turnover meeting) at 5:45 am, on

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May 26, 1989. These contingent security measures were discussed at this guard mount. The inspector had no further questions at this time. The inspector concluded that the licensee's actions were appropriate for the circumstance .0 Assurance of Quality 11.1 Plant Manager's Hold Point Meetings The Plant Manager conducted hold point meetings on May 10 and 16, 1989, prior to releasing the plant from the following startup conditions:

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450 psig reactor pressure, and

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reactor mode switch to " DUN", and

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turbine generator startup and synchronizatio These meetings allowed management to review past equipment malfunctions and problems, and to assess the readiness to proceed to the next startup platea The meetings were attended by all plant and station disciplines and organizations, including corporate and independent oversight groups. At the completion of each meeting, the !

licensee concluded that the plant was ready to proceed to the next startup platea The inspector attended each meeting, noting that all site groups were represented. An adequate discussion of all previous hardware malfunctions that occurred was held. Following the reactor mode switch to "RUN" meeting on May 16, 1989, the licensee briefed the NRC Peach Bottom Restart Panel via the telephone. The inspector concluded that licensee plant management demonstrated a high assurance of quality in Peach Bottom operation .2 High Pressure Coolant Injection (HPCI) System Wiring Error A recent electrical modification to the HPCI flow controller occurred due to multiple personnel errors and failures (see section 6.2.1).

These successive errors included an installation mistake by contractor electricians; and the failure of QC, of post modification electrical checkout, and of post modification acceptance testing to detect this erro The HPCI surveillance test did however detect this wiring erro _ _ _ _ - __

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34 .3 Management Oversight Team (MOT) Meeting on-June 1, 1989 e 'The licensee conducted a MOT review for the Unit 2 power ascension up to the.35% power plateau. The meeting was held on June'1, 1989, to evaluate 'this startup and transient period. Licensee personnel in

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attendance included M0T members (corporate and site managers, and- an industry observer) and line management'who made presentation The inspector attended the meeting and concluded that the licensee adequately evaluated their performance to date. This included both personnel and equipment evaluations. The licensee formulated strengths.and weaknesses, defined follow-up action items,. and concluded that Unit 2 was satisfactory to proceed to the 35% steady state period for approximately four weeks. The licensee identified the following two significant weaknesses:

I (1) The maintenance backlog trend is increasing and needs to be addressed. Improvement is required to perform scheduled maintenance during the rolling 13 week schedule (2) Numerous surveillance tests are being performed in the grace

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The licensee MOT will meet again after the four week steady state 35%

perio .4 Operations Oversight Plant and operation management including the Shift Manager, the Operations Superintendent and the Assistant Superintendent were noted as being effectively involved in plant operation Specific examples included the following: EHC malfunction (4.2.1); reactor trip follow-up and root cause analysis (4.2.2); offgas recombiner abnormality (section 4.2.3); and, E-22 bus electrical problem-(section 4.2.5).

12.0 NRC Bulletin and Information Notice (92703)

12.1 NRC Information Notice 89-44, Hydrogen Storage On the Roof of the Control Room The inspector reviewed the impact of combustible gas storage on safety related structure Peach Bottom has two combustible gas storage tanks. One is a 20,000 gallon liquid hydrogen tank at 150 psig for future hydrogen water chemistry control. The tank is located west of the site,1800 feet from the control room intak This hydrogen water chemistry system is part of a plant modification scheduled for implementation during the current Unit 2 cycle. The NRC reviewed this design in a safety evaluation report dated January 1987.

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The other hydrogen storage facility is for the main generator cooling system. This consists of 24 gas cylinders (total volume of 553 cubic

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feet) at 2400 psig. It is located south of Unit 2 turbine buildin The nearest safety related structure is the diesel generator building at a distance of 65 feet. The control room air intake is 520 feet from these hydrogen gas cylinder No unacceptable conditions were note .2 Potential Misapplication of Certain Models of Pressure Transmitters (NRC Bulletin 80-16)

NRC Bulletin 80-16, " Potential Misapplication of Rosemount, Inc.,

Models 1151 and 1152 Pressure Transmitter with Either A or D Output Codes", was issued June 27, 1980. This bulletin informed licensees about a reversal in output signal level when the transmitters are subjected to pressures exceeding 140% of rated maximum pressure. A reversal could result in erroneous presssure indication for safety related application The bulletin suggested several ways the licensee could prevent erroneous indicated pressures. On July 30, 1980, the licensee responded to the bulletin. They committed to two methods of preventing this condition. The pressure transmitters were to be tested at the next calibration time for overpressure respons Also, training was provided for which control room pressure indicator was to be use The bulletin response was reviewed by a regional specialist, and was inspected for implementation by a resident inspector in 1980. The inspector again reviewed the PECo response letter, operating '

procedures, emergency operating procedures, calibration procedures, and the training record The implementation of the licensee commitment was determined to be satisfactor NRC Bulletin 80-16 is considered close .0 Unresolved Items Unresolved items are items about which more information is required to ascertain whether they are acceptable violations or deviations. An unresolved item is discussed in section .0 Management Meetings 14.1 Preliminary Inspection Findings (30703)

A verbal summary of preliminary findings was provided to the Manager, r 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 inspectors. No written inspection material was provided to the licensee during the inspectio No proprietary information is included in this repor . _ . . ._

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14.2 Attendance at Management Meetings Conducted by Region Based Inspectors (30703)

Inspection Reporting Date Subject Report N Inspector 6/13- Emergency Exercise 89-17/17 Gordon 15/89

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6/8-8/89 Diesel Fuel Oil 89-16/16 Woodard i

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ATTACHMENT 1 Surveillance and Routine Tests (ST/RT) Observed ST 10.16 ST 20.004 ST 6.6-F ST 12.15.2-2 RT 1 ST 6.10-2 ST ST 1.13 ST 6.1.2-1 ST 1 ST ST 6.6.F-2 ST 8.] ST 9.12-1 ST 19.14-5A !

RT 5.31 ST 6.11-2 SI 2N-60D-B2CW ST 3. ST 12.15.6-2 ST 10. ST 9.21-2 ST 6.5-1 ST 3. SI 2N-600-SRM-A2CX ST 6.5-2 ST ST ST ST ST 3. ST 7.6. ST 13.60 RT 5.13 RT RT RT RT ST 13.47-2 ST 26.7-2 ST ST ST 12.6-1 RT RT 5.14 ST ST 9.14 ST 2.5.40A ST ST 3.5.1-2 ST 3. ST 9.1 ST 6.2-2 ST 9.10 RT 9.1 SI 2K-54-E12-XXFM ST/EP 118 ST 16.35 ST 2.5.40D ST ST 9.11 l

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