IR 05000277/1989019

Onsite Regular,Backshift & Deep Backshift Special Power Ascension & Restart Insps 50-277/89-19 & 50-278/89-19 on 890618-0729.No Violations Noted.Major Areas Inspected: Accessible Portions of Units 2 & 3 & Physical Security

ML20247B892
Person / Time
Site:	Peach Bottom
Issue date:	08/22/1989
From:	Doerflein L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20247B875	List: IR 05000277/1989019 ML20247B871
References
50-277-89-19, 50-278-89-19, GL-83-08, GL-83-8, IEIN-89-042, IEIN-89-42, NUDOCS 8909130174
Download: ML20247B892 (51)

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U.;S., NUCLEAR-REGULATORY COMMISSION- i

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Docket / Report No.' 50-277/89-19

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License No. OPR-44-50-278/89-19 DPR-56 Licensee: Philadelphia' Electric Company Y -Correspondence Control Desk P. O. Box 7520 Philadelphia, Pennsylvania 19101 Facility.Name: Peach Bottom Atomic Power Station Units 2 and 3 F Inspection At: Delta,' Pennsylvania -

' Dates: June 18 - July 29, 1989

. - 'Inspectorsi T.-P. Johnson, Senior Resident Inspector R. J, Urban, Resident Inspector L.-E. Myers, Resident Inspector J. Gadzala, Resident Inspecto M. Dev, Reactor Engineer J. H. Williams, Project Enginee K. R. Mikkelsen, Licensing Engineer

~ Woodard,. Reactor Engineer R.,E. Martin, Project Manager D. L. Caphton, Senior Technical Reviewer

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M. J. Riches, Licensing Engineer L.' M. Kolonauski, Reactor Engineer

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C. E. Sisko, Operations Engineer Approved Byj ., 2 j L.-T. Doerflein Chief, ,

date Raactor Project Section 2B, Division of Re ctor' Projects

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, Summary Areas Inspected: Routine, on site regular, backshift and deep.backshift-special power ascension-and restart inspection (701 hours0.00811 days <br />0.195 hours <br />0.00116 weeks <br />2.667305e-4 months <br /> Unit 2; 215 hours0.00249 days <br />0.0597 hours <br />3.554894e-4 weeks <br />8.18075e-5 months <br />

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Unit 3) of. accessible portions of Unit 2 and 3, operational safety, radiation protection, physical security, control room activities, licensee y.Tnts, surveillance testing, refueling and outage activities, maintenance,

modifications and outstanding item Results: A Unit 2 automatic scram occurred on July 21, 1989, caused by an

' electro-hydraulic control (EHC) malfunction when an engineer removed an electronics card (section 4.2.5). Other events were reviewed (section 4.2)

and licensee follow-up was determined to be conservative and in accordance with. requirements. Licensed operator periodic walkdown of control room boards was noted to be weak in several instances (section 4.1). One l

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radiological related allegation was unsubstantiated (section 3.0).

Licensee on site, off site, and special review committees were effective in assessing performance (sections 4.5,4.6,11.2). The power ascension program was noted as being well conducted (sections 5.1,5.2,11.1). The licensee has satisfactorily addressed emergency diesel generator fuel oil concerns (section 5.3). The conduct of maintenance and surveillance activities was effectively controlled (sections 7.0 and 8.0). Performance in the security area continues to improve (section 10.0).

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TABLE OF CONTENTS Page 1.0 Persons Contacted............................................ 1 L 2.0 Facility and Unit Status..................................... 1

3.0 Allegation Follow-up.......................................... 2 4.0 Plant Operations Review...................................... 2

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4.1 Operational Safety Verification and Station Tours....... 2

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4.2 Follow-up On Events Occurring Ouring the Inspection. .. .. 4 4.3 Log s a nd R e co rd s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 4.4 Engineered Safeguards Features System Walkdown.......... 12 4.5 Plant Operations Committee Review (P0RC)................ 12 4.6 Nuclear Review Board.................................... 13 5.0 Engineering and Technical Support Activities. . . . . . . . . . . . . . . . . 13 5.1 Power Ascension Test Program............................ 13 5.2 Powe r Ascensi on Test Re sul ts. . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 5.3 Emergency Diesel Generator Fuel 011..................... 15 5.4 Modification..... ..... ................................. E2 6.0 Review of Licensee Event Reports............................. 22 6.1 LER Review............ ................................. 22 6.2 LER Follow-up...... ................... ................ 23 7.0 Surveillance Testing......................................... 23 8.0 Maintenance Activities... ... ........ ...................... 23 9.0 Radiological Controls........................................ 24 10.0 Physical Security............... .. .................... .... 25 11.0 Assurance of Quality......................................... 25 12.0 Review of Periodic and Special Reports....................... 26 13.0 NRC Information Notice... ......... .................... .... 27 14.0 Safety Is sues Management Systems (S1MS) . . . . . . . . . . . . . . . . . . . . . . 27 15.0 Management Meetings............ ............................. 29 Attachment 1 - STs Observed Attachment 2 -' PECo/NRC Meeting List of Attendees on July 18, 1989 Attachment 3 - PECo/NRC Meeting Handouts on July 18, 1989 i

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0^ -DETAILS L 1.0- Persons Contacted-L G.-A.-Bird, Nuclear Security Specialis 'J. B. Cotton, Superintendent, Operations

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• T; E. Cribbe,. Regulatory Engineer

• • G. F. Daebeler, Superintendent, Technical

• J. Davenport,- Maintenance Engineer

• J. F. Franz,',lant Manager

• • T. P.- Gotzis, Manager, Installations

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D. P. LeQuia, Superintendent, Services

• • J. B. McLaughlin, Modifications D. R. Meyers, Support Manager

• • G. D. Morgan, Installations F. W. Polaski, Assistant Super' ntendent, Operations

• • K. P.. Powers, Project Manager

• • • J. M. Pratt, Manager, Peach Bottom QA G..R. Rainey, Superintendent, Maintenance-

• • R. E. Simpson, Supervisor, Mechanical Installation

• • D..M.. Smith, Vice President, Peach Bottom Other licensee and contractor employees were also contacte *Present at exit interview on July 31, 1989, and for summation of preliminary finding **Present at exit interview on July 25, 1989, regarding modification *** Attended both meetings 2.0 Facility and Unit Status 2.1 Unit 2 At the beginning of the period, Unit 2 was at 3?% power. On June 19, 1989, the generator was taken off line due to a potential transformer fuse failure (see section 4.2.1). The unit was returned to service on June 20, 1989. The t'ait was authorized ascension to 70% power on June 28, 198 '

.fter reactor feed pump testing was completed at 45% power, reactor power was raised to 68%'on July 1, 1989. Major testing per'ormed at this plateau were a runback of the recirculation pu'.sps, a recirculation pump trip and a reactor fecd pump trip. A';ter successful completion of this testing, reactor power was ircreased to 68% power. On July 6,1989, another fuse blew in t'ie main generator potential

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transformer circuit. The licensee reduced power to 20% to remove .

the turbine generator from service, replaced all similar fuses, and power was returned to 68% on July 8,1989. The unit was authorized ascension to 100% power on July 21, 198 l l

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On July 21, 1989, the unit scrammed from 79% power. The unit restarted on July 27, 1989. At the end of the period the unit was at 90% powe .2 Unit 3 Unit 3 continued in its seventh refueling outage that t,egan October 1, 198 Unit 3 outage work included maintenance and modification activitie Control rod drive exchange was completed during the perio .0 Allegation Follow-up (RI-A-89-0077) (71707)

An allegation was receiYed that a worker was placed in a "very

• ' gerous situation" while working on a " push or pull" problem under

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the Unit 2 reactor vessel during reactor operation. The inspector reviewed operating and health physics (HP) logs, radiation work permits (RWP), maintenance request forms (MRF) and dosimetry records for all recent Urit 2 drywell entries. This included the period from April 26, 1989, when the licensee received authorization from the NRC Region 1 Administrator to proceed with an approved restart power testing program up to 35% power to June 20, 1989, when the allegation was made. There were two occasions when work was performed under the Unit 2 reactor vessel. This work was repair and replacement of nuclear instrumentation on April 27, 1989, and replacement of a safety relief valve on May 11-12, 1989. In both cases, the reactor was in a shutdown mode with all control rods full, inserted and not at power. All drywell entries were made consistent with procedures, RWPs and personnel safety. The radiation dose received by the workers during these entries was low, the highest being 65 mrem. This allegation is unsubstantiated and is considered close .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 The inspectors performed 699 total hours of on site backshift time, including 466 hours0.00539 days <br />0.129 hours <br />7.705026e-4 weeks <br />1.77313e-4 months <br /> of deep backshift and weekend tours of the facility.

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l ' Shift Observations Around-the-clock shift coverage _ occurred during the periods June

?8 to. July 9, and July 21 to the end of the period. Based on

'arvations during this shift coverage, the inspectors made the lowing conclusions:

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. Operations, plant, and corporate management continue to be strongly involved in operational activitie Technical Specification compliance is conservative.

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Testing and major evolutions are conducted wel procedural compliance by control room operators continues to be stron Effective teamwork and coordination among all work groups was noted. However, one example was noted where information concerning a residual heat removal (RHR) system water hammer event was slow-in being communicated to the Shift Manage (section 4,2.7).

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Shift mana;.sar and shift supervisor command and control was noted as being effectiv Special procedure status is not kept up to date in the~ control !

room (section 4.3).

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Shift turnover activities were noted as being thoroug A walkdown of control room panels at shift turnover is thoroug However, periodic walkdowns of panels during the shift at times was noted as being weak (see below).

Examples of noted weak periodic walkdowns of control room panels during the course of the shift included the following:

'(1) A lightning strike occurred on July 27, 1989; however, a detailed panel walkdown was not initiated for almost 15 minute (2) ~ On July 28, 1989, dui ., afternoon shift, four control room

.. chart recorders were ennibiting malfunctions that were not noted (drain cooler flow - FR2050; offgas rad monitor -

RR-2-17-154; generator frequency; and, turbine vibration -

VR-2657).

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(3) On July 29, 1989, at 3:37 p.m., the "A" recirculation pump outboard seal pressure was oscillating between 450 to 750 psi, and thic was not noted by the operator . - - - - _ - - _ _ . - - -_- - - - _ _ _

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.-The inspector also noted occasions where thorough periodic. review of control room indications resulted in operators quickly detecting abnormal condition For example:

(1) On July 30, 1989, the "B" reactor feedpump.' flow indication dropped slightly, causing about a one inch change in reactor level. This occurred four time ~(2) Main turbine reactive power (MVAR) was varyin abnormally on June 19,1989 (see section 4.2.1).

(3) On July 5,1989, during afternoon. shift, condensate storage tank (CST) level recorder (LR 2217) was observed upscale and the problem was traced to a shorted level transmitter caused by rain wate These items were discussed with plant, operations, and shift management personnel. The licensee committed to address the specific weaknesses and these will be reviewed in a future-

-inspection.

y 4.2 Follow-up On Events Occurring During the Inspection (93702)

4. Main Generator potential Transformer Fuse Failures Failure of main generator potential transformer (PT) tuses occurred at 3:15 a.m. on June 19, 1989, and again at 3:05 p.m. on July 6, 1989. The inspector noted good operator response in both case During the first occurrence, the voltage regulator was placed in manual control when the operator noted reactive power (MVAR)

oscillations. In the second case, a fuse in a different set of pts failed and the associated generator protective relays were declared inoperable. The licensee discussed the contingency plan to replace the PT fuses on priority basis. Adequate spare fuses were not'available on the first PT fuse failur The blown fuse was replaced with one from Unit 3. On the second occurrence,

.the licensee obtained adequate spares and replaced all three phase PT fuses on both units. In both cases, power was reduced y to about 20% the main generator was taken off the line pnd the reactor steamed to the condenser via the bypass valves. After replacement of fuses the main generator was synchronized to the g-id and reactor power was increased to the authorized platea The licensee is continuing to pursue the cause of the fuse failure The inspector observed operator actions, maintenance activities and recovery operations. No unacceptable conditions were note . Diesel Driven Fire Pump (DDFP) Failure On July 3,1989, the DDFP failed during performance of periodic Surveillance Test (ST) 6.17. The licensee performed an investi-

.gation into this failure. The licensee concluded the root cause to be a loose hose clamp on a cooling line for the engine that

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L L 5 was apparently further loosened during work near the DDFP or due to engine vibration. This cooling line became disconnected, resulting in a loss of cooling and a catastrophic failure of the DDF The licensee entered Technical Specification (TS) 3/4.14. which requires a special report in 31 days and periodic testing of the motor driven fire pump (MDFP). The licensee contacted the DDFP vendor (Cummins) and repairs were initiated. The DDFP was tested satisfactorily and declared operable on July 14, 198 Licensee corrective actions included:

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Install double hose clamps, where possibl Review failure analysis with Maintenance and Operations personne j

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Revise the operational ST to document the coolant inspec-tion and to have the operator verify there are no coolant leaks immediately after the diesel start Revise the annual maintenance ST to include verification of hose clamp tightness by maintenance personne The inspector performed the following items reviewing this DDFP l failure event: I

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Observed licensee immediate actions in responding to the loss of the DDF i

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Veri M compliance with T Inspected damage associated with DDF Reviewed licensee root cause analysi l

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Verified corrective action Discussed failure with licensee personne !

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Reviewed associated test, operating and maintenance proce-dure Attended investigatory meeting on July 20, 1989, with operations, system engineering, maintenance and security ,

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The inspector concluded that the licensee performed an adequate root cause analysis and corrective actions were initiated to prevent recurrenc . Unit 2 Shutdown Initiated and Terminated At 2:18 p.m. on July 12, 1989, the licensee began shutting down Unit 2 as required by Technical Specifications (TS)

Limiting Conditions for Operation (LCO). The E-3 diesel generator had been out of service for its annual mainte-nance outago since July 9,1989. At 1:20 p.m. during the required deily testing of emergency core cooling and containment systems, residual heat removal (RHR) system motor operated valve (MOV) 2-10-34B tripped on magnetic overload. This MOV provides the "B" loop of RHR with full flow test and torus cooling flow paths. The licensee entered TS LC0 3.5.F.1 which requires the unit to be in cold shutdown in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. An Emergency Notifi-cation System (ENS) call was made at 2:14 The licensee determined the problem to be a motor failure. An equivalent motor from Unit 3 was obtained to replace MOV 2-10-348. Repairs and testing were completed at 8:40 p.m., and the MOV was declared operable. A follow-up ENS call was made at 9:30 p.m. to inform the NRC that the TS LC0 was exite The inspector observed licensed operator actions from the control room and maintenance activities locally. The inspector verified proper TS LCO implementation. The inspector verified that post maintenance testing was adequate and that appropriate LCO log entries were made. The inspector also verified that the NRC notifications were consistent with regulatory requirement The inspector concluded licensee actions were appropriat . Reactor Core Isolation Cooling (RCIC) System Inoperability On July 17, 1989, the licensee declared the RCIC system inoperable per Technical Specification (TS) 3/4.5.D.2. This was a seven day limiting condition for operation and the high pressure coolant injection (HPCI) system was verified to be operable as require The RCIC system failed during performance of Surveillance Test (ST) 6.11-B. The ST starts the system when aligned from the torus in order to test the operability of the suction check valv On RCIC system ntart, a low suction pressure trip occurre The licensee investigated this RCIC failure and concluded the following: A suction pressure transient occurs during RCIC start from the torus that initiates the low suction pressure trip at 15 inches Hg vacuum. The apparent cause of this low L-__--___-_____-___-______---____-_-_--_ -- __ _ - - _ _ - _

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pressure is due to a lower suction head than when aligned in the normal lineup from the condensate storage tank (CST). A review of ST 6.11-B historical test results shows that the ST had been successful in the past. However, the licensee recently vented air from the pressure switch instrument vent pot. This was done due to noted fluctuations on a RCIC flow instrumen The licensee believes that venting air from the low suction ,

pressure switch instrument removed a " snubbing" effect and the !

result was a low pressure switch trip on system star Further licensee review included a check of the FSAR, TS, design documents, and similar systems at other BWRs. Also, PECo's Nuclear Engineering Department (NED).was contacted. The Plant Operations Review Committee (PORC) met on several occasions to review this RCIC abnormality. The licensee revised existing operating and ST procedures to ensure a continuous " keep full" system was aligned to maintain adequate suction pressure when RCIC suction is lined up to the torus. Longer term corrective actions included NED pursuing a possible time delay for the low suction pressure trip snd/or a permanent " keep full" syste The inspector observed ST performance, walked down the RCIC system, reviewed related documents, verified TS compliance, attended PORC meetings, verified corrective actions and proce-dure changes and discussed this item with licensee personne No unacceptable conditions were note . Unit 2 Automatic Scram on July 21, 1989 Sequence of Events and Licensee Actions At 10:31 p.m. on July 21, 1989, Unit 2 automatically scrammed from 79% power due to main steam isolation valve (MSIV) closur The MSIV closure (group I containment isolation) occurred on low main steam line pressure with the reactor mode switch in RU The licensee was performing troubleshooting activities in the

. electro-hydraulic control (EHC) cabinet due to a pressure set-point drift between the "A" and "B" EHC regulators. An engineer was in the process of removing an electronics card in a cabinet in the cable spreading room which resulted in the EHC system responding to a false sensed high reactor pressure. This resulted in opening of the turbine bypass valves which reduced reactor pressure to 850 psig. A group I containment isolation and MSIV closure resulted as designed. Reactor level decreased to -35 inches and was recovered by the reactor feed pumps. Reactor pressure subsequently increased on the MSIV closure. The maximum pressure noted was about 1100 psig and two safety relief valves (SRV) automatically lifted. The operators responded to the event by using multiple emergency operating procedures. Reactor pressure and level were controlled by manually opening the SRVs and by

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manually starting ...e reactor core isolation cooling and high pressure coolant injection systems. The licensee made an ENS e t1 On July 22, 1989, at 11:10 a.m. a full scram signal occurred while the plant was in hot shutdown condition. A half scram on channel "A" had been inserted due to two intermediate range monitor (IRM) problems. A half scram on channel "B" subsequently occurred when an average power range monitor (APRM) spiked due to a failed local power range monitor (LPRM) input. This action resulted in a full scram signal. The licensee made an ENS call, troubleshoot and repaired the spiking IRM, and bypassed the spiking LPRM input to the affected ApR The licensee maintained the plant in hot shutdown condition and initiated an outage work lis Troubleshooting and repairs to the EHC system were completed on July 23, 1989. The licensee believes that when the engineer wiggled the EHC card during removal, a voltage power supply was momentarily interrupted which caused the "A" EHC regulator to be placed in service and to fail high. This action explains the EHC system response including the opening of the bypass valves and resultant low reactor pressur In preparation for startup, nuclear instrumentation tett p indicated a malfunction of the "B" source r ange monitor (SNM).

The "A" SRM has been out of service since initial startu Iha licensee made a drywell entry to repair bith SRMs and the "A" intermediate range monito NRC Review and Conclusions The inspector observed licensed operator response to the scram from the control room. The Shift Supervisor quickly established the control room command function. Communications were clear, concise, and repeat backs were used. The teamwork and discipline of the crew was excellen Emergency procedure compliance, usability and transition between procedures was noted as being effective. In all, overall operator response was effectiv Prior to the scram, the inspector monitored licensee actions taken to deal with the drifting EHC regulator problems. The inspector attended a management meeting and a briefing held by the Shift Manager. The troubleshooting form developed to place the "B" EHC regulator in service and to pull the "A" EHC regulator steam line resonance compensator card was reviewe These activities were well planned and discussed prior to their accomplishmen ___

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e s-The inspector. questioned licensee plant-and cperatiens' manage-ment regarding their knowledge of the drifting EHC pressure

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regulator problem, especially since it was not mentioned during-i-

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the telephone briefing.with the NRC on July 20, 1989. 1he'

licensee responded by stating;that the EHC. regulator problem was discussed during test review group and PORC' meetings and at both Management Oversight Team meetings on July 12 and 19.1989 (section 11.2). The licensee had initiated periodic monitoring

" of the EHC pressure regulator and made adjustments as necessar ._3 The control room operators were given itiformation regarding this-issue via the night orders and a letter from the respective-system engineer on July 18 and 19, 1989. On July 21, 1989, the licensee contacted a GE engineer and the decision was made the afternoon on that day to shift to the "B" EHC regulator and repair the "A" EHC regulator. Based on this, the-inspector N

concluded that the licensee had adequately reviewed this condi-tion and had taken appropriate actions. The licensee had not considered this to be either a major or immediate concern until after the NRC telephone call.on July 20,.198 The inspector reviewed the licensee's-investigation into the scram by performing the following activities:

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Reviewed control room logs, computer alarm typers, computer sequence of events log, and control chart recorders.

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Verified implementation of emergency operating procedure . Attended post scram critique and review meeting Attended post scram PORC meeting Reviewed startup program data acquisition system chart-recorder ! --

-Discussed scram with operators, engineers and managemen Reviewed the licensee's incident report and GP-18, " Scram Review Procedure".

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Independently determined sequence of events and root caus Reviewed EHC electrical schematic drawing The inspector noted that plant, station and corporate management were involved in post scram review activities. They were also noted as being involved in outage work activitie ,

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The inspector attended' a PORC meeting. onily 24, 1989, to y

f" review source. range monitor (SRM) operability for startup.

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Technical: Specification (TS) 3.3.B.4 requires two SRMs whereas-m

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TS Table.3.2.C requires three SRMs. The PORC reviewad the FSAR,

. standard TS and 1.imerick TS, and concluded that three SRMs were-necessary for startup. ' Corporate licensing is pursuing a TS change for consistency. The inspector concluded that the 'PORC displayed good conservatism in reaching this decisio Overall, in reviewing the licensee's actions tha inspector concluded that there was:

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Adequate monitoring of the EHC pressure regulator dri(ting, including troubleshooting activities that resulted in the ,

scram; a

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Excellent operator actions in response to the scram, including recovery actions; and

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Effective follow-up and review of the scram, including root cause analysis.and initiation of corrective action .2.6- Unit 2 Shutdown Initiated on July 29, 1989 At 5:55 p.m. on July 29, 1989, the number four traversing in l core probe (TIP) machine became stuck and the detector would not withdraw. The licensee entered TS 3.7.0 due'to the TIP contain- .j ment isolation ball valve being open. The licensee. initiated a ]

shutdown, made an ENS call at 11:29 p.m., and initiated-TIP t ciachine repairs. By 1:00 a.m., on July 30, 1989, repairs were complete and the TIP machine was successfully operated and the R ball valve was closed. A follow-un ENS call was made at 1:05 a.n., to raport that the TS limiting condition for operation-had W '

been exite Power was then returned to 90%.

- The inspector verified TS compliance and observed maintenance 1 and health ~ physics (HP) activities. The inspector concluded I that licensee actions were appropriate. Effective teamwork was displayed among operations, maintenance and HP personnel during j troubleshooting, repair and testing activities, j 4. Unit 2 Residual Heat Removal (RHR) Water Hammer on July 21, 1989 At about .10:00 a.m., on July 21, 1989, during performance of 5T 6.8-2, RHR "A" Operability Test, the control room was notified by floor operators thet a water hammer occurred when the "A" RHR pump had been started. The "A" loop RHR discharge relief valve lifted and a test gauge was found damaged. The licensee determined I

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that the "C'! RHR' pump dischaYge check valve apparently had stuck

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open causing the line to drain. When the "A" RHR pump was started, a water hammer occurre The licensee inttiated actions to walk down the RHR system piping and supports. No visible damage was noted; however,:a

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more detailed walkdown was initiated by the Maintenance ISI group. -The licensee also revised the,ST to insure the system is kept fulluof water 'during testing.. In addition,'the "C" RHR check

• valve external; operating arm packing nut was loosened. This y allowed the check valve to move more freely and decreased the

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repaired.

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. and in' dependently walked down portions of the RHR system. Later E 4 0 that day,.the inspector questioned the Shift Manager on the

, status of. maintenance walkdown. However, he was not' aware of the , status. :The walkdown was :ompleted by the licensee per yc procedure SWD 19 at 6:00 p.m., on July 22, 198 ' The inspector, expressed concern regarding the timeliness of con.tleting the walkdown' by the Maintenance ISI group; and, the lack ~ cf information ghen the Shift Manager. A meeting was neld

~ to discuss this . item on July 25,1989. The licensee agreed-that

'1 the walkdown should have been. completed in a more timely manner.

N However, Unit '2 scrammed at 10:31 p.m. , on July 21, 1989, (section 4.2.5) and this probably was the reason for the dela . ,

Also, ths-licensee 1 agreed maintenance and engineering personnel-were deficient in keeping the Shift Manager informed of the

~ statust of the RHR walkdown. The licensee indicated that appropriate personnel would'be informed of this event h an A effort to prevent recurrenc *

- Logs _andRecords(71707)

.The inspector reviewed logs and records for accuracy, completerest, abnormal conditions, significant or.erating changes and. trends, required entries, correct equipment and lock-out status, jumper log validity, conformance with Limiting Conditions for Operations, and proper reporting. The following logs and records were reviewed:

Control Room Shift Suparvisor Log, Reactor Engineering Logs, Unit ?.

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Reactor Opsrator Log, Unit 3 Reactor Operator Log, Control Operator Log, STA Log, OC Shift Mcnttor Log, Radiation Work Permits, Locked Veive Log, Maintenance Request Forms, Temporary olent Altaration Log, O Special Procedures (SP) Log, Information Tag Log, Annunciator Mode A

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Log, Plant Stetus List, and Ignition Source Control Checklist Control Room logs were compared with / administrative Procedurt A-7,

"5hift Operations," and the Operations Manual (0M). Frequent initial-ing of entries by licensed operators, shift supervision, and licensee site nunagement constituted evidence af licensee revie \

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The inspector noted that SP log was out of date on July 24, 1989, for both the unit reactor operator and the Shift Supervisor SP logs. The inspector informed shift and operatius managemen No requirement for this log exists in the OM cr administrative procedures. The licensee initiated corrective actions to ensure that the SP log is kept current and up to dat Overall, the inspector determined the logs were generally useful and effective in documenting and relaying operational informatio .4 En_gineered Safeguards Features (ESF) System Walkdown (71710)

The inspector performed a detailed walkdown of portions of 'he E-1 and E-3 diesel generators (DG) in order to independent 3 verify the operability of the Unit 2 and 3 systems. The DG walkdowns included verification of the following items:

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Review of operating, maintenance and testing document Inspection of system equipment condition Confirmation that the system check-off-list (COL) and operating procedures are consistent with plant drawing Verification that system valves, breakers, and switches are properly alligne f

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Verification that instrumentation is properly valved in and operabl Verification that valves required to be locked have appropriate locking device Verification that control room switches, indications and j controls are satisfactor Verification that surveillance test procedures properly inple- I ment the Technical Specifications surveillance requirement '

Eo unacceptable conditions were note .5 PlantOperationsReviewCommittee(PORC)J40500} l

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The inspector attended several PORC meetings during the perio j The meetings were conducted in accordance with Technical j Specifications and Administrative Procedures. The meetings I attended included discussions on RCIC operability (section 1 4.2.4), Unit 2 scram fsection 4.2.5) and SRM requirements for i startup (section 4.2.5). l

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The inspector concluded that the PORC members displayed a I questioning attitude and decisf ons made were conservativ )

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4.6 Nuclear Review Board (NRB) Meeting (4J500)

The inspector attended portions of the NRB Meeting number 244 on July 6,1989. The meeting was held in accordance with Technical Specifications and NRB procedures. An agenda was distributed before the meeting. The inspector concluded that NRB members continue to be aggressive in their questioning of individuals making presentations and the members demonstrate a good safety perspectiv .0 Engineering and Technical Support Activities 5.1 Power Ascension Test Program (72700, 71715)

The inspector witnessed preparation and the conduct of power escala-tion from 35% to 70% in accordance with GP-2, " Normal Plant Startup",

Rev. 54 and special procedures SP-1166 and 1167. To support power escalation, average power range monitors (APRMs) were calibrated in accordance with ST 3.3.2, " Calibration of APRM System," Rev. 13. Also, a traversing incord probe functional ch:ck was conducted in accor-dance with reactor engineering procedure RE 31, " Reactor Engineering Startup/ Load Drop Instructions," Rev. 4. Licensed operators and trainees participated in the reactivity manipulations. Pre-test briefings, test conduct and coordination, and departmental interfaces were determined to be satisfactory. The plant restart management oversight personnel including the Plant Manager, operations line management, Vice Presidents, and other utility observers and consul-tants were available during testing to provide instruction and guidance as necessary. All test deficiencies and nonconformances were properly reviewed and resolved, and the related corrective actions were implemented in a timely manne Licensee actions to assure quality of test activities and to resolve

technical issues were effective. Successful completion of special proceduris (SP) SP-1232 (Reactor Feedpump Trip), SP-1231 (Recirculation Pump Trip) and SP-1230 (Recirculation Pump Runback) demonstrated the ability of the feedwater level control system (FWLCS) to maintain reactor vessel water level and the EHC system to maintair, reactor pressure without causing a reactor scram. These tests were well organized, properly performed, and adequately interfaced. During ,

these tests, plant management and consultants were available to 1 provide instruction and guidance. Test results were appropriately reviewed by the cognizant personnel and were properly documented (see section 5.2).

Surveillance test (ST) procedure 26.1-2, "Feedwater Control Loop Stability / Response Test", Rev. O provided for the verification of ,

the feedwater controller settings to respond to reactor vessel  !

water level and the reactor feedpump (RFP) flow. During the I initial test, RFP "A" and "C" were put into operation with feedwater !

level control system (FWLCS) switch in single element contro !

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RFP flow and the reactor vessel water level were monitored. Data acquisition system strip charts recorded the performance of this tes The test results were acceptable. Tests to verify the I FWLCS response to parallel operair.lon of RFP "B" and "C" with the FWLCS in three-element control was also completed satisfactoril During power escalation testing, the "B" main steam line flow trans- {

mitter DPT-2-02-117C (Rosemount Model 1153) failed upscale. The flow j transmitter and connecting cable were replaced with environmentally i qualified spares. A subsequent downscale failure of the "C" main steam line flow transmitter DPT-2-02-118B delayed testing of PWLCS in accordance with ST 29.1-2, Section B for all three RFPs running. The flow transmitter was also replaced with qualified spares. The Rosemount transmitters appear to have a generic problem (see section 13.1).

5.2 Power Ascension Test Results (72700)

The license 9 initiated a Test Review Group (TRG) to review completed power ascension test results. Weekly meetings have been occurring since Unit 2 initial criticality. TRG membership includes opera-tiens, system engineers, nuclear engineering department, I&C engineers, specialized consultants and maintenance personne The inspector attended the July 10, 1989., TRG weekly meeting. At this meeting, power ascension tests for the 70% transient period  !

were reviewed. Tests included the following:

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ST 26.1-2, Feedwater Stability

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SP 1232, Reactor Feedpump Trip

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ST 26.7-2, Pressure Regulator Stability

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ST 26.6-2, Recirculation Flow Stability

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SP 1231, Recirculation Pump Trip

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SP 1230, Recirculation Pump Runback

.The responsible engineer presented the test results, including test procedure completion, data acquisition tystem charts and data evaluations. All tests met their respective acceptance I criteria. Open items and unexpected results were discusse The inspector reviewed each ccmoleted test including test data l and charts. No unacceptable conditions were noted. The inspector concluded that the TRG performed a thorough revie )

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5.3 Emergency Diesel Generator (EDG) Fael Oil (TI 2515/100)

Background For proper operation of the emergency diesel generators (EDG), it is necessary to ensure the proper quality of the fuel oi Appendix B to 10 CFR 50, as supplemented by NRC Regulatory Guide 1.137, serves as an acceptable basis for licensees to maintain a program to ensure the quality of EDG fuel oi In response to recent industry problems, the NRC issued Information Notice 87-94 on January 16, 1987, to alert licensee personnel of potentially significant problems pertaining to long-term storege of fuel oil, This Information Notice documents the June 27, 1986 Arkanses Nuclear One Unit 2 inoperability of an EOG due to a high concentration of particulate in the fuel oil. Also, at Millstone Unit 3 on November 20, 1987, an EDG was declared inoperable due to particulate matter in the EDG fuel exceeding the Technical Specifi-cation limit of 10 mg/ liter. At that time, the plant was in a refueling outage, the EDG was not in operation, and core alterations were suspended until an acceptable supply of fuel oil was obtaine Discussion Assurance of the proper fuel oil requires purcnasing the correct fuel oil ana receipt inspection to verify that the fuel oil is proper prior to addition to the storage tanks. Since fuel oil degrades with time and external sources centribute contamination, periodic insoection is required to a sure continued fuel oil qualit This inspection w?s performed to determine the licensee's program for the procurement, receipt, storage, handling and control of EDG fuel oil to ensure adequate quelity of the fuel oil. The four EDGs for Peach Bottom Units 2 and 3 are identical including their fuel systems, fuel program, and procedure Technical Specification (TS) 4.9.A contains an extensive program for sampling new and existing fuel oi These specifications and their implementing surveillance test (ST) procedures were reviewed as follows:

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TS 4.9.A.J.d.1 - monthly removal of accumulated water from the day tanks and after each occasion when the EDG is operated for greater than one hour (ST 8.1 Diesel Generator Full Load Test).

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TS 4.9.A.1.d.2 - monthly removai of accumulated water frem the main storage tanks (ST 8.1.16 EDG Main Fuel Storage Tank Water l

Removal).

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15 4.9.A.1.d - Flushing the fuel oil system from the day tank to the EDG injectors if water is suspected to have entered the suction piping (ST 8.1 Diesel Generator Full Load Test).

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TS 4.9.A.1.e - Sampling new fuel oil in accordance with ASTM D4057-81 prior to addition to the main storage tanks (ST 8. ,

Diesel Fuel Sample from Delivery Truck Tank).

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TS 4.3. A.I.e.1 - Verifyirg new fuel oil properties in accordance with ASTM-0975-81 for specific gravity, viscosity, flash point, and clear and bright prior to. addition to the main storage tanks (ST 8.1.8 Diesel Fuel Sample from Delivery Truck Tank).

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TS 4.9.A.I.e.2 - Verifying new fuel properties in accordance with ASTM-D975-El for the other properties within 31 days of obtaining the TS 4.9.A.e sample. (ST 8.1.8 Diesel Generator Fuel Sa;nple from De11very Truck Tank.)

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TS 4.9..A.1.f - Monthly sampling and testing of fuel oil stered in tanks to verify particulate contamination (ST 8.1.13 Diesel Generator Main Fuel Storage Tank Sampling and Analysis).

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TS 4.9.A.I.g - Draining, cleaning and inspection of fuel and storage tanks every ten years (ST 8.1.4A,B,C,D Diesel Generator Inspection).

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TS 4.9.A.I.h.1 - Yearly test of the adequacy of fuel oil storage tanks cathodic protection (ST 8.1.15 Diesel Generator Fuel Oil Storage Tank Cathodic Protection System Rectifier Inspection).

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TS 4.9.A.I.h.2 - Bimonthly verification of fuel oil storage tanks cathodic protection rectifiers (ST 8.1.17 Diesel Ganerator Main Fuel Storage Tank Cathodic Protection Operability Test).

In addition to the Technical Specification required procedures the licensee's EDG fuel oil control program includes the following procedures:

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S0 520.3.A - Diesel Fuel Oil Storage Tank Fillin Special Procedure 1162 - EDG Main Fue 011 Storage Tank Bottom Samplin .D.I.A - Diesel Fuel Oil System Normal Operation COL 52D.A-1, A-2, A-3. A-4 - E1, E2, E3, and E4 Diesel Fuel System Operatio COL 520.3.B-1, B-2, B-3, B-4 - El, E2, E3, and E4 Diesel Fuel 011 System Fil _ - - _ - _ _ __ -

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STL8.1.7,' Surveillance Tests'for Non-Tech'nical Specification Testing, Maintenance Diesel Fuel Trending Analysis

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COL- 52D.3.B '- Diesel Fuel . 011 Tank Sampling

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50 52D.3.B - Diesel Fuel Oil System Fill These procedures provide EDG fuel instructions to ensure the control of cleanliness, sampling, proper valve alignment, fire protection, and traceability of fuel for each test not only during fuel ordering and receipt but also during normal operatio + The. inspector determined from a review of the licensee's Technical-Specifications,. specification implementing procedures and supporting station procedures, that the licensee has a well-documented EDG fuel oil program to ensure the quality of the fuel oi The licensee has classified the EDG fuel oil as safety related and it is appropriately included in the licensee's Q-List and quality assurance program for

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contro The purchase' requisition for EDG fuel prcperly includes the requirement for fuel in accordance with specification ASTM D975-81 which meets the fuel requirements specified.in the EDG vendors manual. The fuel supplier is required to furnish a certificate of conformance (C0C) with the fuel delivery and is required to use only certain specified, dedicated single compartment, distillate fuelt only tanker trucks in the delivery of the fuel. A May 30, 1989, delivery C0C and verification was examined with no exceptions noted. Upon arrival and prior to unloading the fuel, the licensee takes three samples for analysis. One sample is promptly analyzed on site for specific gravity, viscosity, flash point, clear and bright prior to unloading. A second sample is sent to an off site laboratory for analysis of the remainder of the ASTM D975 fuel specification parameters. This analysis is performed within 31 days in order to meet Technical Specification requirements. The third sample is extra in case there are problems with either of the other sample By procedure, the licensee controls the unloading of new fuel oil to ensure that it goes into only one of the four EDG fuel main storage tanks. This provides traceability of the fuel until all of its ASTM specification parameters are known (within 31 days).

By procedure, the licensee samples each main fuel storage tank monthly for the complete analysis for the ASTM specification parameters and also conducts monthly tank bottom sampling for water and cru __ - - . _ _ _ _ _ _

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j The'~ Technical Specifications-orovide specific requirements relating i to EDG fuel oil ~in main ~ storage. tanks which does not conform to the j particulate requirements of the ' ASTM D975 fuel specification '

Implementing actions within specific time frames are established for the isolation of the affected tank, maintenance of the required fuel a volume'on site,- sampling the other tanks,-'and the replacement of the

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unacceptable fuel oil or shutdown within.seven days'. The licensee's a procedures currently do not_ require any specific action for EDG main-storage tank fuel parameters'which are'found outside the ASTM D975 fuel specification requirements except-for the particulate nor are there specific action requirements for tank bottom confirmatio During this inspection, tne licensee stated that they would revise ST 8.1.7 for non-technical specification fuel oil testing to include the guidelines of paNgraph B2a of Regulatory Guide 1.137 (Fuel Oil Systems for Standby Diesel Generators) to establish a course of actio Since excessive particulate in the fuel could lead to fuel strainer / filter clogging described in NRC Information Notice 87-04, the inspector reviewed the licensee's fuel system de*ig operational characteristics, and actions taken to minimize the possibility of EDG shutdown due to' fuel particulate contamination. The' fuel system design provides a suction approximately six inches above the bottom the main fuel tank to minimize particulate and water from the tank bottom. .Two independent fuel supply systems to the EDG engine are provide One . system is the engine driven fuel pump, the other is a 125 VDC electric motor driven fuel pump. Either system is capable of supplying the EDG at full loa On each EDG unit there is a fuel strainer ahead of the EDG fuel pump and duplex filter after the fuel pump ahead of- the fuel injector Both the strainer and the filter are instrumented to .

provide differential pressure indication and alarm across them to indicate foulin Individual indication and alarms are provided on the local EDG control panel with a remote alarm on the EDG and a combined trouble alarm in the control room. The EDG fuel filters-are of the duplex type which permits operation on one filter then switching to the other filter without interrupting EDG operation in the event that one of the filters becomes fouled. As further assurance to prevent EDG shutdown from fouled fuel filters, the system design provides for a fuel pressure relief bypass valve around the filters to continue providing fuel to the EDG in the event that the filters' differential pressure continues to '

increase significantly beyond the alarm setpoint and relief is not provided by the operators in changing the filter The inspector reviewed the licensee's actions taken in response !

to NRC Information Notice 87-04 as documented by internal correspondence on file, by interviews with plant chemistry and

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systems engineers and by a review of procedures. The licensee had performed fuel tanks sampling for. biological contamination and had made appropriate evaluations of actions required to address this potential fuel oil problem which could adversely affect EDG operation. From the evaluations, the licensee has developed and implemented procedures to monitor for particulate including establishing Technical Specification requirements wnich require actions for excessive particulate including fuel replacement or shutdown. The licensee addressed the addition of fuel biocide additives to control biological growth. However, additives are not used because of the EDG manufacturer's objection to these additives in the diesel fuel. The licensee concluded that biofouling predominantly occurs at the fuel tanks oil-water interface and that the particulate are due to metabolized fuel oil and dead microbes. As a consequence, procedures are developed and implemented to remove any accumulated water from these tanks and the day tanks at least on a monthly basis. In addition, water is removed from the day tanks after each EDG operation of gi9ater than one hou Both the main fuel storage tank and the day taiK for each EDG unit are instrumented to provide for local level indication and alarms. The EDG control panel has a remote alarm for day tank low level and an EDG combined trouble alarm is in the control roo A review was made of the licensee's EDG fuel system preventive maintenance program to ensure reliable operaticn. The EDG fuel system's preventive maintenance is described in detail in ST 8.1.4.A, B, C, and D - El, E2, E3 and E4 Diesel Generator Inspection. The schedule for this preventive maintenance is entered into the licensee's computerized preventive maintenance scheduling system. A recent print-out covering the EDG fuel system was reviewed for content and schedule. It included cleaning and replacement of both strainers and filters; calibration of all instrumentation; inspection of pump and motor bearings and couplings; and, scheduled ten year draining, cleaning, inspection and repair of the main EDG fuel tanks. The licensee also provides a computerized printout to upper management by system of preventive and corrective maintenance which has not been accomplished. A review was made of a current print-out which did not reveal any significant problem No overdue preventive maintenance was note As part of the preventive maintenance program on the EDG fuel system, the licensee maintains a trending system to provide predictive data for maintenance. Trending is performed in many fuel and related areas including the following: chemistry for fuel in main storage tanks; fuel oil pressures to strainers, pumps, filters, and engine fuel header; fuel oil differential pressure across strainers and filters; engine start times; and,

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cylinder exhaust temperatures and differential temperatures. A review was made of a computer print out of these data and plots generated to provide better visibility. No deficiencies were noted in the licensee's EDG fuel system preventive maintenance pro 5 ra The inspector determined that the Quality Assurance function of the licensee's fuel oil program is to provide audit surveillance of the adequacy of the implementation of the program to assure compliance with EDG fuel oil Technical Specification requirement The audit is required at least annually under the cognizance of the Nuclear Review Board in accordance with Technical Specification 6.5.2.8. The inspector reviewed QA Audit Report PA 89-11 dated April 13, 1989, to assess its coverage and its findings. The audit evaluc-tion was conducted through a combination of test implementation observations and a historical review. Coverage included observation /

inspection of fuel oil sampling and analysis; fuel oil related supply valve manipulations; coordination of activities between work groups (operations, materials, chemistry); safety and housekeeping; and, a review of 1988 EDG fuel oil surveillance tests. Findings included some industrial safety and housekeeping p.oblems, a valve alignment error, minor analysis procedural problems, and a general lack of coordination between work group None of the findings were deemed to have had a major effect on the quality of the EDG fuel. Correc-tive actions were taken with regard to the incorrect valve alignment and recommendations were made to management relative to the need for improvements in fuel oil sampling in the areas of personnel safety, personnel attention to detail and job coordinatio As a part of the overall EDG fuel oil program, the licensee has recently (June 5,1989) established a documented " Materials Section Information Notice: Responsibilities for Receipt of Fuel Oil at PBAPS". This Notice establishes the detailed responsibilities of each section with regards to the monitoring of available fuel, requisitioning fuel, arranging delivery, maintaining documentation, providing security, verifying the delivery ' truck, sampling, analysis, proper alignment of valves and tanks for fuel receiving, certificate of conformance, quality assurance monitoring of operations and chemistry activitie Evaluation of the implementation of this addition to the fuel program was not made due to its newness. However, it is projected by the licensee to improve the overall fuel program by providing clear identification as to who is directly responsible for each activit The EDG fuel storage tanks do not incorporate a fuel recirculation /

filtration system for the removal of particulate from the stored fuel oil. However, the licensee has addressed the detection and removal of particulate in the fuel oil and made other provisions to ensure the reliable continuous operation of the EDG events as follows:

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-- Monthly'and new fuel addition Techn'ical Specification sampling for particulate leve Trending of the~ particulate level in each tank to provide-predictive information in advance of the need to replace th fue Technical Specification action statements which provide means-for continuing EDG operation by valving in one of the other fuel storage tanks while replacing the fuel in a tank with high

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particulate (seven days allowed for the replacement before requiring shutdown).

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Design of the EDG fuel oil system which provides strainers and duplex filters which can be changed during continuous EDG operation'to provide for removal of particulat Design of the EDG fuel oil system which provides for the bypass relief valve operation around the duplex filters if they become clogged to' permit continued EDG operatio Since continued EDG operation is required during seismic events, the inspector verified that the licensee and procurement specifica-tions for the EDG system. requires that "the equipment and every portion thereof, including supports, shall be designed.for concurrent horizontal and vertical accelerations produced by ground motion due tu an earthquake". The licensee's specification specifically identifies the fuel oil system among those systems included in the EDG syste Conclusion The licensee has addressed the relative importance of the EDG fuel system and fuel oil in maintaining continuing reliable operation of the EDG units by appropriately addressing the following factors:

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Design of the fuel oil system to effectively include back up storage tank capability, redundant fuel pumping by means of the EDG mechanical and e'ectrical pumps, fuel strainers and duplex fuel filtration ahead of the injectors, duplex filter relief bypass and seismic capability, fuel pressure / differential pressure indications and alarms, fuel tanks level indications and alarms, and cathodic protection of fuel storage tank .

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Procurement, delivery and receipt of the proper fuel b/ specify-ing fuel in accordance with the EDG manufacturer's requirements / ASTM specifications, by establishing a que 11fied

. fuel vendor, by requiring dedicated fuel delivery. trucks, by requiring a C0C from the fuel vendor, by assuring fuel quality

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by sample / analysis prior to offloading into the storage tanks, and by control of offloading fuel into a single specified

. storage from a tanker truc ,

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-Operating' instructions to include monitoring and measurements and provide for the removal of water from the fuel storage tanks. Technical Specification fuel quality and fuel system-requirements with appropriate limiting conditions of operation '--

Maintenance program which includes periodic scheduled mainte-nance of all fuel system components including valves, pumps, motors, piping, strainers, filters, injectors, and tank Trending fuel system parameters in order to perform preventive maintenance on a predictive basis fer such activities.as fuel filter / strainer cleaning / replacement and for the replacement of

fuel in the main storage tank There were no adverse findings during the review of the EDG fuel oil progra .4 Modifications (37700)

During this inspection period, the inspectors began a review of the Peach Bottom modification process including involvement with installation engineers, construction crafts, and QA/QC personne Selected personnel were interviewed and modification documentation was reviewed. The following Unit 3 modifications were checked:

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Modification #1660, ADS Nitrogen Accumulations,

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Modification #1457, Reactor Water Level Instrumentation,

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Modification #2106, ESW Pipe Replacement,

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Modification #5061, HPCI Operation from Alternate Control Statio The inspectors will continue to review this area and document the findings in a future inspectio ' 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 k

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' determined whether further information was required, whether generic implications were indicated, and whether the event warranted on site follow-up. The following LER was reviewed:

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Event Date Subject

• 2-89-12 . Unit 2 Automatic Scram on Low Level 06/19/89

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05/19/89 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 accordance 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 2-89-12 concerns a Unit 2 automatic scram on low level that occurred on May 19,-1989. This event was reviewed in NRC inspection 277/89-16. No inadequacies were noted relative to this LE .0 Surveillance Testing (61726, '71707)

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 met. Daily surveillance including instrument channel. checks, jet pump operability, and control rod operability were verified to be adequately performed. Parts of the tests listed.in Attachment I were observe Testing was noted as being well controlled and test results were adequately reviewed. No inadequacies were identifie .0 Maintenance Activities (62703)

The inspectors reviewed administrative controls and associated documenta-tion, and observed portions of work for maintenance activities. Admini-strative controls checked, if appropriate, included blocking permits, fire watches and ignition' source controls, QA/QC involvement, radiological controls, plant conditions, Technical Specification requirements, equipment

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ability. Documents reviewed, .if appropriate, included maintenance procedures (M), maintenance request forms (MRF), item handling reports, L radiation work permits (RWP), material' certifications, receipt inspections, and troubleshooting control forms (TCF).

Portions of the following maintenance activities were observed:

Document Equipment Date(s) Observed ST 8. Diesel Fire Pump July 3-14, 1989 MRF 8905053 Main Generator PT Fuses July 7, 1989 M 1 MO-2-10-34B ' July 12,1989 MRF 8964627 FIS-2139B June 29, 1989 TC DPT-2-2-117C, 118B July 1 and 2,1989 TCF EHC Pressure Regulators Various M-5 E-1 DG - Generator Varicus M-5 E-1 DG - Engine Various SWI-19 . RHR A Walkchwn July 22, 1989 TCF 'EHC Lead Set July' 27, ' 1989 Maintenance activities were well conducted and no inadequacies were identifie . Radiological Controls (71707)

During the report. period, tie 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 surveys, radiation protection instrument use, and handling ef potentially contaminated equipment and material The inspector observed individuals frisking to verify it was in accordance with HP procedures. A sampling of high radiation area doors was verified to be-locked as required. Compliance with RWP' requirements was verified during each tour. RWP lis;e 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 During a tour on June 23, 1989, the inspector noted that an open pipe pit between the water treatment building and the demineralized water storage tank was roped off by signs marked with the standard yellow and magenta radiation symbols. Since the signs did not describe the type of area enclosed, the inspector questioned the licensee about them. An investigation revealed that the radiation signs were used by the construc-tion-division as a means of roping off the area to prevent anyone from accidentally-falling into the pit. The area was not a radiological controlled area. Shift management promptly took action to remove the radiation signs and replace the rope with safety hazard rope colored yellow and blac __- _ _ _ _ _ _ _ _ _ _ - - _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ ___________ ______-__________ __ - __-__ _ - - _ _ _

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.The inspector was temporarily denied access to the plant when his pocket dosimeter indicated an exposure of ten mrem under general RWP 5001A. Ten mrem is an undocumented administrative contro1' limit for RWP 5001A of which the inspector had not been informed. . Additionally,

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two previous occurrences of the inspector obtaining ten mrem under RWP 5001A were not flagged by the licensee. The inspector discussed this with the licensee:regarding accuracy.of the pocket dosimeters, dissemination of undocumented. administrative control limits, and the inspector's' plant access. The licensee evaluated this undocumented policy. _The limit was to_ determine if an individual was exceeding-the intent of the general RWP on a daily basis and whether he.should be on a standing or. specific RWP. The licensee plans to continue this limit by changing procedure A-16, " Radiation Worker Responsibilities" and disseminating the information in general employee trainin .0 Physical Security (71707)

The inspector routinely monitored security activities for compliance L

with the accepted Security Plan and associated implementing procedures, including: security staffing, operations of the central alarm station (CAS) and secondary alarm station (SAS), 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 measures. No inadequacies were: identifie On July -17, 1989, during the period 2:00 - 4:00 p.m., the three resident inspectors performed a detailed review of security facilities and guard force personnel. Adequate personnel were on shift to man the required vital area and protected area station Compensatory posts were set up for the Unit 2 torus room for high radiation controls and for Unit 3 containment access control. Also, one vital area barrier was open and a compensatory guard was posted. Guards were knowledgeable of their dutie A total of 15 guards were interviewed. All expressed enthusiasm and

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support of their management. They stated that post rotation was occurring every one to one and a half hours, and they were working eight hour shift Overtime was non-routine and on a voluntary basis. CAS and SAS operations, vital and protected area barriers, and badging and search processes were all reviewed and no unacceptable conditions were noted. A PEco security shift assistant was interviewed and determined to be knowledgeable, competent and also enthusiasti .0 Assurance of Quality 11.1 Power Ascension Conduct and Oversight (72700)

Power escalation activities to increase reactor power to the 70% 1 plateau were well organized and effectively implemented. The associated power ascension tests were conducted in accordance

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with approved test procedures, and met procedural requirements. All-test nonconformances were properly reviewed by the cognizant plant personnel and the related corrective actions were implemented

. adequately and in a timely manne Management oversight during the power escalation' activities was effective. Corporate, site and plant management were present during

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the tests, and provided guidance and instructions as necessar Coordination and interfaces between the cognizant plant groups and individuals performing the quality controlled activities were satis-factory. The power escalation activities and test program provided a training opportunity for' operators to meet hot license prerequisites, and augmented their training on plant response and procedure .2 Management Oversight Team (MOT) Meetings (40500)

The inspector attended the licensee's MOT meetings to review Unit 2 l performance as follows:

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June 23, 1.989 - 35% steady state period

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' July 12,1989 - 70% transient period

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' July 19, 1989 - 70% steady state period L Licensee personnel in attendance included MOT members (corporate and station management, and an industry observer) and line management personnel who made presentation The inspector attended the meeting and concluded that the licenseo I

'

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 per their approved startup pla .0 Review of Periodic and Special Reports (90713)

The inspector reviewed the following periodic and special reports to verify the'information reported by the licensee was technically adequate and satisfied the applicable reporting requirements established in the Technical Specifications, the license, and 10 CFR:

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Peach Bottom Unit 2 Inservice Inspection, dated July 25, 198 Annual 10 CFR 50.59 Report, dated July 17, 198 June 1989 Monthly Operating Report, dated July 14, 198 Progress Report for Implementation of Control Room Enhancements, Unit 2, dated June 30, 198 No unacceptable conditions were note . _ _ _ _ - - _ - _ _ _ -___-_-_--- _ - _ _ _ - - _ - _ - _ _ _ _ _ _ - _ _ _ _ - _ - - - - - _ - - - _ _ - - _ _ _ .

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13.0 NRC Information Notices (92703)

13.1 Failure of Rosemount Flow Transmitters Model 1153 During reactor power escalation from 35% to 70% two consecutive failures of a Rosemount flow transmitter Model 1153 occurred. On July 2,1989, DPT-2-02-117C channel "C" on main steam line "B" f ailed

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upscale. Subsequently, within the next 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> DPT-2-02-1188 channel "B" of main steam line "C" failed downscale. Licensee troubleshooting determined that these Rosemount transmitters were inoperable. In each case, the licensee initiated a half group one containment isolation per Technical Specification 3.2. A. The flow transmitters were replaced by environmentally qualified similar transmitters and the failed transmitters were sent to the vendor for root cause analysis. The failures appear to be generic in natur The vendor (Rosemount) had earlier notified the licensee and the NRC of the problem associated with Rosemount transmitter Models 1153 and 1154, in accordance with 10 CFR 21, Reporting of Defects end Noncompliance. NRC Information Notice (IN) 89-42, April 21, 1989, was also issued to the licensee for review and verification of its applicability pertaining to the use of the Rosemount transmitters. The licensee's review of IN 89-42 concluded that they did not utilize Model 1154 Rcsemount transmitters. Also, the model 1153 transmitters used at Peach Bottom were determined to be from the suspect lot identified by the vendor. The licensee also acknowledged that any impending failure of these transmitters could be detected through. implementing surveillance testing (ST), trending program and daily monitoring of redundant channels of instrument loops per ST 9.1.2 and 9.1. 3. Further review by the licensee of the Rosemount transmitter 1153 failure mechanism and the vendor root cause analysis is warranted to determine the adequacy and effectiveness of the implemented corrective action The inspector observed licensee actions to insert a half isolation i per TS requirements. Maintenance and testing activities were also monitored. The inspector reviewed the IN, the licensee's internal response documentation and their corrective action The inspector discussed this item with licensee engineering and maintenance personnel. The inspector had no further questions. The licensee's i failure analysis for the transmitters will be reviewed in a future inspectio .0 Safety Issue Management System (SIMS)

The following licensing actions were selected for verification of imple-mentation at Peach Bottom:

o Diesel Generator Fuel 011, MPA A-15 (TI 2515/93),

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o Mark I Drywell Vacuum Breaker Mods, MPA D-20 (T1 2515/96),

o BWR Recirculation Pump Trip, MPA C-02 (TI 2515/95).

The purpose of the verification was to satisfy the verification require-ments of SIM Diesel Generatur Fuel Oil (TI 2515/93)

.In a letter dated January 7,1980, the licensee was requested to review the quality assurance program with respect to diesel generator fuel oi The letter requested the licensee to include emergency standby diesel generator fuel oil in Quality Assurance Programs subject to the require-ments of Appendix B to 10 CFR Part 50. The letter further indicated that

- Regulatory Guide (RG) 1.137, " Fuel Oil Systems For Standby Diesel

- Generators' described an acceptable method for adequately ensuring the

- quality of diesel generator fuel oil. A letter from the licensee dated April 4,-1980, addressed their complianc Subsequently, by application dated October 1, 1981. as supplemented and amer.ded on November 15, 1984, November 24, 1986, September 2 and hovember 18, 1987, and March 30, 1988, the licensee proposed an amendment to Technical Specifications in response to the guidance of Regulatory Guide 1.137. This amendment,-specifying the quality criteria for fuel properties, the sampling and testing requirements and the actions. required when.the quality criteria are not met, was

- issued on May 31, 1988. The staff concluded that these changes for the diesel fuel oil system complied with the intent and purpose of RG L137 and were acceptabl MPA A-15's objective is that, as a consumable item for which quality is necessary for functional performance of safety related components, the fuel oil should also be classified as safety related and thus subject to applicable. provisions of Appendix B to.10 CFR Part 50 by inclusion.on the Q List or in the QA program. The purpose of TI ,

2515/93 is to verify that the requirements as identified in MPA A-15 are me The Peach Bottom Project Q List, Revision 23 was reviewed and found to contain Diesel Fuel 011. Based upon the issuance of the license amendment referenced above and inclusion of fuel oil in the Q List, the inspector concluded that the licensee fully complies with the intent and purpose of MPA A-15 (see section 5.3).

Drywell Vacuum Breaker Modifications (TI 2515/96)

Generic Letter 83-08, " Modification of Vacuum Breakers on Mark I Containments" dated February 2, 1983, was sent to all licensees with Mark I containments. The Generic Letter requested information related to a potential failure mode of the drywell-to-torus vacuum breakers during the chugging and condensation oscillation phase of a

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loss-of-coolant accident. In a response' dated March 25, 1983, the licensee stated that a Peach Bottom plant' unique report had been prepared by Continuum Dynamic, Inc. (CDI) in September 1982. The-l licensee concluded that the wetwell to drywell vacuum breakers at Peach Bottom would not actuate during the chugging transients and, l: therefore, valve modifications were not require .

In a letter to the licensee dated June 20, 1985, the NRC reported the results of its review of the licensee's position and concluded that no design modifications were needed. Accordingly, the staff indicated that it had completed its review of the Multi-Plant Action D-20 .

associated with this issu The purpose of TI 2515/96 is to verify that vacuum breaker modifications required in response to MPA D-20 have been accomplished. Since no modifi-cations were required the inspector also concicdes that all implementation aspects of MPA D-20 have been complete BWR Recirculation Pump Trip (TI'2515/95)

On January 9, 1979, the NRC staff met with BWR licensees and provided the bases for requiring recirculation pump trip (RPT) under r anditions of high vessel pressure or low reactor water level. The ou yse of TI

'2515/95 is to verify that the licensee has installed such an RPT and that actions addressed by multi plant action C-02 are implemente The inspector noted that a previous inspection report (50-277/86-19; 50-278/86-20) discusses in detail the provisions currently established for' tripping of the recirculation pumps under conditions of high j vessel pressure or low water level. This is the Anticipated Transient Without Scram (ATWS) conditions. That report discussed the actuation logic,-the sensors used, the breakers involved, maintenance, surveillance tests and applicable drawings related to the currently installed ATWS-RPT at Peach Botto FSAR section 7.9.4 a' iso confirms that RPT on high reactor pressure or low water level is incorporated into the design. On these bases the inspector concludes that the licensee complies fully with the intent and purpose of MPA C-02 and that all implementation aspects of MPA C-02 have been complete .0 Management Meetings 15.1 Preliminary Inspection Findings (30703)

A verbal summary of preliminary findings was provided to the Manager, Peach Bottom Station at the conclusion of the inspection. During the i inspection, licensee management was periodically notified verbally of the preliminary findings by the resident inspector No written inspection material was provided to the licensee during the inspec-tion. No proprietary information is included in this report.

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l 15.2 Engineering Management Meeting On July 18, 1989 On July 18, 1989, members from PECo ifcensing and nuclear engineering met with Region I personnel at King of Prussia, PA to discuss the reorganization of the corporate Nuclear Engineering Division (NED).

Attachment 2 is a-list of attendees and Attachment 3 is a copy of__the meeting handouts. The new organization has been. streamlined by-reducing several layers of management and by grouping functions'.

Designers and engineers have been combined under one manager in'the new NED organization. In addition to reporting'to the Project Manager at both Peach Bottom and Limerick, the installation function has sec'ondary reporting responsibilities to the NED installation manage In addition, installation is no longer responsible for minor modifications. Project management was a line function in the previous NED organization, but now reports directly to the Vice President at both Peach Bottom and Limerick. The new NED organiza-tion and its effectiveness will be examined in future NRC inspection _ - - _ _ - - _ _ _ _ - _ _ _

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ATTACHMENT 1 STs Observed ST 3.3.2, APRM Calibration ST 26.1-2, Feedwater Control Loop Stability ST 3.3.1 APRM Functional SI2F-23-77-XXC2, Calibration Check of HPCI Steam Line High Flow Instrument DPIS-2-23-77 ST 6.10-2, HPSW Pump and Valve Operability and Flow Rate Test ST 9.2, Control Rod Exercise Test ST 6.8, RHR A Functional Test ST 6.9, RHR B Functional Test ST 9.21.2, Jet Pump Operability RT 5.11, Power Load Unbalance Test SI2F-61-117-CICO, MSL DPT Calibration ST 4.6, MSL Monitor Functional and Calibration Test ST 26.6-2, Recirc Pump Stability Test ST 26.7-2. EHC Pressure Regulator Stability Test ST 4.11-2, RHR Head Spray Accumulator Check RT 5.8, Combined Intermediate Valve Closure Test ST 3.3.2A, APRM Calibration and Thermal Limit Check for Single Loop SI2P-14-44-A1C1, Core Spray DP Functional Test RE-31, TIP Calibration SI2M-2-400-AIC1, RPS Ripple Power Supply Test ST 6.6, Core Spray A Functional Test ST 6.7, Core Spray B Functional Test ST 8.1, DG Full Load Test for (E-1, E-4, E-2)

ST 6.11-2, RCIC Pump Valve, Flow and Cooler Test ST 6.10-1, Containment Cooling System Test ST 6.8-2, RHR "A" Operability Test ST 8.1.6, DG Annual Inspection Post Maintenance Test (E-1 DG)

SI2L-3-231-B3FM, Functional Test of Scram Discharge Volume Level High Instrument-ST-21.9, MSIV DC Solenoid Check

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Attachment 2 Management Meeting, July 18, 1989 List of Attendees PEco S.~ J. Kowalski, Vice President, Nuclear Engineering A. R. Diederich, Manager, Project Management Peach Bottom G. A. Hunger, Jr. , Director, Licensing Section J. A. Basilio, Senior Engineer, Licensing Branch NRC W. F. Kane, Director, Division of Reactor Projects B. A. Boger, Acting Director, Division of Rector Safety J. C. Linville, Jr., Chief, Reactor Projects Branch 2 J..R. Strosnider, Chief, Materials and Processes Section L. T. Doerflein,- Chief, Reactor Projects Section 2B R. J. Urban, Resident Inspector,. Peach Bottom R. A. McBrearty, Reactor Engineer, Materials and Processes Section l

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ATTACHMENT 3

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t PECo. - NRC MEETING JULY 18,1989 AGENDA PREVIOUS ORGANIZATION FOR MODIFICATION

-

ENGINEERING

-

INSTALLATION

-

PROJECT MANAGEMENT PERFORMANCE IMPROVEMENT PROJECT

-

OBJECTIVES

-

COMPOSITION

-

PRODUCTS NEW ORGANIZATION FOR MODIFICATIONS

-

ENGINEERING

-

INSTALLATION

-

PRO.IECT MANAGEMENT NED QUALITY IMPROVEMENT EFFORT

.

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PERFORMANCE IMPROVEMENT PROJECT ORGANIZATION OBJECTIVES

- REDUCE LAYERS OF MANAGEMENT (4 LEVELS)

- INCREASE SPAN OF CONTROL (MINIMUM OF 3)

- DEFINE RESPONSIBILITIES

- ENHANCE ACCOUNTABILITY

- MINIMlZE COMMUNICATION PATHS PROCESS OBJECTIVES

- ENHANCE CONFIGURATION MANAGEMENT / CONTROL

- DEVELOP MOD TEAM CONCEPT

- INCREASE' EFFICIENCY

- ASSURE CONSISTENCY

- ENCOURAGES PLANNING PROJECT COMPOSITION

-

15 PECo MANAGERS, SUPERVISORS, ENGINEERS '

- ALL DEPARTMENTS IN NUCLEAR GROUP

- SPONSORED BY NUCLEAR GROUP EXECUTIVES

- SIX MONTH DURATION

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- FUNCTIONAL 'RESPONSIBIL'lTIES DEFINITIONS

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- FUNCTIONAL & PROJ. ACCOUNTABILITIES DEFINE .

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PROJECT PRODUCTS (PROCESS)

- DESIGN CHANGES vs REPLACEMENTS

- BASIC ELEMENTS (13) FLOW CHARTED'

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EACH EXPANDED BY FLOW CHART AND NARRATIVE

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SITE MOD MANAGEMENT GROUP

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SENIOR PLANT STAFF

- SCREENS INPUT ~ O PROCESS

- ESTABLISHES PRIORITIES

- APPROVES MODS FOR DESIGN MOD TEAMS

- PM, ENGINEER, INSTALLATION, SYSTEM ENGINEER

- ADDITIONAL MEMBERS AS NECESSARY

- DETERMINES SCOPE AND OBJECTIVES

- REVIEWS CONCEPTUAL DESIGN, INITIAL DESIGN AND FINAL DESIGN PROCESS STEPS FOR

- ALARA, CONSTRUCTABILITY, MAINTAINABILITY REVIEWS

- CLOSEOUT DOCUMENTATION WITH FINAL DESIGN

- PL ANNING

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INCREASED EMPHASIS ON PROGRAMS

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INTERIM ORGANIZATIONS FOR 2-3 YEARS INSTALLATION

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FUNCTIONS LIMITED TO INSTALLATION

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MAINTENANCE GROUP

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-- ESTABLISHES PRIORITIES

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CONTROLS SITE ACCESS TO PERSONNEL NED SINGLE POINT ACCOUNTABILITY FOR MODIFICATION-COST, SCHEDULE, QUALITY

- COMMONALITY BETWEEN PLANTS

- CONTROLS PROCESS

- FOCUS ON EXECUTION

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. NED QUALITY IMPROVEMENT EFFORT BACKGROUND

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• PERFORMANCE BASED NQA AUDITS l CONDUCTED

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PBAPS MOD PROCESS AND A/E INTERFACE

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HARDWARE ADEQUACY ADDRESSED (IATI)

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SHORT-TERM PROCESS IMPROVEMENTS IMPLEMENTED

• ROOT CAUSE EVALUATIONS IDENTIFIED NEED FOR PROCESS IMPROVEMENTS

• LONG-TERM PROGRAM CREATED

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NEW QUALITY INITIATIVES INTEGRATED WITH ONGO!NG DEVELOPMENTAL EFFORTS (eg. CONFIGURATION MANAGEMENT)

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l LONG TERM z

QUALITY IMPRO EMENT PROGRAM

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o CUSTOMER-ORIENTED PRODUCT IMPROVEMENT EFFORT

• OBJECTIVES

- INTEGRATE NEW & ONGOING IMPROVEMENT

- INSTITUTIONALIZING SELF-IDENTIFICATION OF PROBLEMS AND CORRECTIVE ACTIONS

- DEVELOP QUALITY-ORIENTED CULTURE STRESSING PRIDE OF OWNERSHIP &

CONTINUAL IMPROVEMENT

• PROGRAM BREAKDOWN : 4 SUBPROGRAMS

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ENGINEERING PROCESSES & j PROGRAMS /

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NED QlP METHODOLOGY e EACH SUBPROGRAM WILL: -

-IDENTIFY ONGOING & PLANNED IMPROVEMENT ACTIVITIES

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-IDENTIFY STRENGTHS & WEAKNESSES /

ROOT CAUSES

- ASSESS ADEQUACY OF ONGOING &

PLANNED ACTIVITIES TO ADDRESS WEAKNESSES & SUSTAINIMPROVEMENT

- PLAN & IMPLEMENT NEW / REVISED IMPROVEMENT TASKS AS NEEDED e EACH SUBPROGRAM WILL INCLUDE :

- PERFORMANCE EXPECTATIONS

- PROVISIONS TO MONITOR

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EFFECTIVENESS OFIMPROVEMENTS

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I NUCLEAR ENGINEERING DEPARTMENT l

l l-PEOPLE : \

QUALITY

- ORGANIZATION :

QUALITY I

- PROCESS :

QUALITY

- TOOLS : , ,

QUALITY i

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- FEEDBACK :

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