IR 05000277/1985012

Insp Repts 50-277/85-12 & 50-278/85-12 on 850316-0510. Violations Noted:Improper Shift Relief Procedures, Unrestrained Seismic Backup Nitrogen Bottle & Inadequate Control of Security Badges

ML20127P369
Person / Time
Site:	Peach Bottom
Issue date:	06/21/1985
From:	Beall J, Gallo R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20127P150	List: IR 05000277/1985012 IR 05000316/2005010 ML20127P148
References
50-277-85-12, 50-278-85-12, NUDOCS 8507020398
Download: ML20127P369 (25)

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U. S. NUCLEAR REGULATORY COMMISSION

REGION I

Report No. 50-277/85-12 & 50-278/85-12 Docket No. 50-277 & 50-278 License No. DPR-44 & DPR-56 Licensee: Philadelphia Electric Company 2301 Market Street Philadelphia, Pennsylvania 19101 Facility Name: Peach Bottom Atomic Power Station Units 2 and 3 Inspection at: Delta, Pennsylvania Inspection conducted: Ma'rch 16 - May 10, 1985 Inspectors: T. P. Johnson, Sr. Resident Inspector J. H. Williams, Resident Inspector H. W. Kerch, Lead Reactor Engineer

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Reviewed by:

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[bh E~ Beall, Froject Engineer 7!8f date Approved by: /M h2//M I (o/21/A5 R6bert M. Ga'110, Chief ' ~ date DRP, Section 2A Inspection Summary; Routine, on-site regular and backshift resident inspection (182 hours0.00211 days <br />0.0506 hours <br />3.009259e-4 weeks <br />6.9251e-5 months <br />, Unit 2; 157 hours0.00182 days <br />0.0436 hours <br />2.595899e-4 weeks <br />5.97385e-5 months <br />, Unit 3) of accessible portions of Unit 2 and 3, operational safety, radiation protection, physical security, control room activities, licensee events, surveillance testing, refueling and outage activities, maintenance, and outstanding item Results: Except as follows, activities appeared to be conducted safely and in accordance with regulations: (1) improper shift relief procedures (Detail 4.3),

(2) unrestrained seismic backup nitrogen bottle (Detail 4.1.10), and (3) inadequate control of security badges (Detail 10).

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DETAILS Persons Contacted B. L. Clark, Senior Engineer J. F. Mitman, Maintenance Engineer R. S. Fleischmann, Station Superintendent A. E. H11smeier, Senior Health Physicist F. W. Polaski, Outage Manager S. R. Roberts, Operations Engineer

• D. C. Smith, Assistant Station Superintendent S. A. Spitko, Administrative Engineer D. C. Smith, Assistant Station Superintendent J. E. Winzenried, Technical Engineer Other licensee employees were also contacte *Present at exit interview on site and for summation of preliminary findings. , Plant Status 2.1 Unit 2 Unit 2 has been shutdown since April 28, 1984, for pipe replacement and refueling. At the beginning of this report period the entire core was off-loaded in the spent fuel poo The licensee began flushing the new recirculation and RHR piping on March 23 and completed the flush on March 24. Reactor vessel filling was begun but stopped when leakige of about 6 gpm from the RHR injection line manual block valve (818) was discovered. The valve was repaired and vessel fill completed on March 28 (See Detail 4.4.4).

Control Rod Drive (CRD) exchange began April 3 and was completed April 1 Forty-five CRD's were changed out. A licensee designed shield-can resulted in total man-rem exposures significantly less than in the past and somewhat less than estimated (see Detail 8).

Emergency Service Water (ESW) piping to the ECCS rooms was disassembled and the piping common to the ECCS rooms was cleaned and put back in service on April 1 Flow testing was then performed and showed that there was no flow to any of the core spray rooms and no flow to the "B" and "D" RHR pump seal coolers. The licensee found that lines which previously had flow were now plugged. It was decided to disassemble the piping and clean all ESW piping to the ECCS rooms. This work started on April 22 and was still in progress at the end of this report perio Fuel loading began May 2 and was still in progress at the end of this report period (See Detail 4.4.3 and 4.4.4). The major outage

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milestones remaining for Unit 2 restart are: complete fuel load, complete repairs to ESW, RPV assembly, Recirc/RHR low flow testing, RPV hydro, ILRT, loss of power test, and pre-startup testin .2 Unit 3 The Unit began the inspection period at 90% power, limited by off gas activity levels and end of core life fuel depletion. On March 27, 1985, Unit 3 implemented cycle 6 extended core flow operations (see Detail 5). Unit 3 remained in this coastdown mode operating condition during the remainder of the inspection perio On April 8, 1985, during surveillance testing of main steam isolation valve (MSIV) scram input to the reactor protection system, an instrument channel failure occurred. A special procedure was implemented to allow continued safe operations (see Detail 4.2.1).

On April 10, 1985, during core spray system logic testing, an inadvertent ESF actuation occurred (two emergency diesel generators

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started). The plant operators decreased power to 50% in anticipation of a possible transient; however, plant recovery was effected, and power was returned to 90% (see Detail 4.2.2).

By April 20, 1985, reactor power had coasted down to 87%. Power was reduced to 50% and the fifth stage feedwater heaters were removed from service in accordance with the extended core flow procedur Power was then returned to 90%. At the end of the inspection period, Unit 3 was operating at 86% power, continuing in the extended core flow / power coastdown mode. Refueling is currently scheduled for July, 198 . Previous Inspection Item Update 3.1 (Closed) Violation 277/84-33-01 and 278/84-27-01. Inadequate emergency action levels (EALs). Emergency Plan Implementing Procedure EP-101, Revision 9, dated October 9, 1984, was inadequate in that the specified EALs for the reactor building ventilation and main stack radiation monitors were above full scale for the instruments and, the value for the Alert for the ventilation stack high range monitor was incorrect. The licensee responded to this violation by letter dated March 8, 198 The radiation monitoring instrumentation drawer displays a digital value and that in turn feeds an analog recorder. EP-101 did not specify which value (analog recorder or digital drawer) should be utilized for the EAL. The licensee revised EP-101 (Revision 10, dated November 6, 1984) to incorporate the on-scale EAL values associated with the analog recorder. The inspector reviewed the revised EP-101 EALs and discussed this item with the licensee. The EP-101 EALs are now consistent with the recorder full scale capabilities. The inspector had no further questions. This item is close .

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3.2 (Closed) Violation 277/82-09-0 Failure to follow refueling procedures for Senior Licensed Operator (SLO) supervising core alterations. A control rod blade was inadvertently hooked and nearly raised out of the spent fuel pool during spent fuel pool operations in April, 1982. The licensee revised FH-6C, " Fuel Movement and Core Alteration Procedure During a Fuel Handling Outage" and FH-35, " Fuel Pool Accountability" to include the following items: monorail and frame mounted hoists have a jamming button attached to the cable to prevent upward motion when within seven feet of the top of the fuel pool water level; an HP qualified person is required to be present and to survey items prior to removal from the spent fuel pool or reactor cavity area; and, reinforcement of fuel handling SLO dutie The inspector reviewed FH-6C, Revision 17, dated October 24, 1984, and FH-35, Revision 4, dated December 2, 1982; and verified that these procedural changes were in place. In addition, several observations of fuel handling, spent fuel handling and other core alteration activities were monitored during the Unit 2 refueling /

outage period. No inadequacies were identified. This item is close .3 (Closed) Unresolved 278/77-05-05. Refueling equipment tnining. Licensed operator training had included " hands on" training as indicated by reviewing documentation of individual training records. However, the licensee had not previously established written requirements to perform this training. The inspector reviewed Procedure A-50, Training Procedure, Revision 10, August 2, 1984, and the Operator Training Manual dated July 30, 198 Refueling equipment " hands on" training is now required as documented in the Trairing Manual and verified by the inspecto In addition, the inspector discussed this subject with the license Licensed operators are required to receive training (a " perform" item) on the refueling bridge from a qualified Senior Licensed Operator and from the Reactor Engineer. The inspector had no further question This item is close .4 (Closed) Unresolved Item 277/79-26-01 and 278/79-26-01. Unit 2 and Unit 3 Reactor Operator operating boundaries as defined in plant procedure A-7. The inspector reviewed the revised procedure A-7, Revision 20, " Shift Operations", dated April 30, 1984, and noted that the operating boundaries were more clearly defined. After discussing the boundaries with the licensee the inspector had no further questions. This item is close .5 (Closed) Inspector Follow Item (278/83-05-03). HPCI inoperable due to water in exhaust line. The HPCI rupture disc modification is designed to alleviate the problem of water in the exhaust line and was reviewed in detail in Inspection 277/85-08 and 278/85-08, Detail 6.2.1. This item is close .

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3.6 (Closed) Unresolved Item 277/82-24-02. Administrative Procedure A-50 does not reflect training requirements of 10 CFR 50, Appendix The inspector reviewed Procedure A-50, Training Procedure, Revision 10, dated August 2, 1984. The A-50 procedure delineates fire protection training requirements including initial training, refresher training, site training, regular meetings, drills, records and off-site support training consistent with 10 CFR 50, Appendix R, section I. This item is close .7 (Closed) Inspector Follow Item 277/84-2E'04. Inadequate Housekeeping During Pipe Replacement. During the team inspection of July 16 - 27, 1984, housekeeping was determined to be a weakness. This item was further reviewed during subsequent resident inspections and specialist inspections. Routine inspections of the Unit 2 drywell were performed to monitor cleanliness conditions with improvements noted toward the end of the Unit 2 outage. This area has received additional licensee attention and management addresses the situation routinely. Specific housekeeping deficiencies are routinely discussed by the licensee at the daily outage meetings. This item is close .8 (Closed) Inspector Follow Item 278/84-31-02. Diesel Generator (DG)

Check Off List (COL) Discrepancies. The licensee revised procedure S.8.4.A to correct the discrepancies regarding the DG COL. The inspector reviewed S.8.4.A, Revision 2, dated January 17, 1985, and found the COL adequate. This item is closed.

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3.9 (0 pen) Inspector Follow Item 277/84-39-01 and 278/84-32-01. System l operating procedures for the 125 VDC battery and 13.KV AC system The identified deficient conditions regarding voltage checks for an out of service battery charger have not been incorporated into proce-dural revisions. This item remains ope .10 (Closed) Inspector Follow Item 277/84-38-01. Daily surveillance instrument checks. The licensee revised the ST-9.1 procedures. The inspector reviewed the revised surveillance procedures and found them l to be adequate with respect to the identified deficiencies and correct implementation of Technical Specifications. This item is closed.

l l 3.11 (C'nsed) Inspector Follow Item 277/84-38-02. HPCI procedural l dit,repancies. The licensee revised the two noted procedures. The inspector reviewed S.3.3.H, Revision 5, dated December 7, 1984, and ST.6.5-B, Revision 3, December 7, 1984. Both procedures corrected the deficient conditions regarding the setpoint for HPCI auto initiation and incorrect wording for prerequisites. This item is close .

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4. Plant Operations Review 4.1 Station Tours The inspector observed plant operations during daily facility tour The following areas were inspected:

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Control Room

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Cable Spreading Room

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Reactor Buildings

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Turbine Buildings

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Radwaste Building

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Pump House

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Diesel Generator Building

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Protected and Vital Areas

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Security Facilities (CAS, SAS, Access Control, Aux SAS)

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High Radiation and Contamination Control Areas

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Shift Turnover

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Unit 2 Drywell 4. Control Room and facility shift staffing was frequently checked for compliance with 10 CFR 50.54 and Technical Specification Presence of a senior licensed operator in the control room was verified frequently (See Detail 4.3.2).

4. The inspector frequently observed that selected control room instrumentation confirmed that instruments were operable and indicated values were within Technical Specification requirements and normal operating limits. ECCS switch positioning and valve lineups were verified based on con-trol room indicators and plant observations. Observations included flow setpoints, breaker positioning, PCIS status, and , radiation monitoring instrument . Selected control room off-normal alarms (annunciators) were discussed with control room operators and shift supervision to assure they were knowledgeable of alarm status, plant conditions, and that corrective action, if required, was being taken. Example control room alarms discussed included APRM flow bias off-normal, System II RHR containment spray on, and Drywell radiation monitor trouble. In addition, the applicable alarm cards were checked for accuracy. The operators were knowledgeable of alarm status and plant condition . The inspector checked for fluid leaks by observing sump status, alarms, and pump-out rates; and discussed reactor coolant system leakage with licensee personne .

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' 7 4. Shift relief and turnover activities were monitored daily, including backshift observations, to ensure compliance with administrative procedures and regulatory guidance (See Detail 4.3.2.).

4. The inspector observed main stack and ventilation stack radiation monitors and recorders, and periodically reviewed traces from backshift periods to verify that radioactive gas release rates were within limits and that unplanned releases had not occurred. No inadequacies were identifie . The inspector observed control room indications of fire detection instrumentation and fire suppression systems, monitored for proper use of fire watches and ignition source controls, checked a sampling of fire barriers for integrity, and observed fire-fighting equipment station No inadequacies were identifie . The inspector observed overall facility housekeeping condi-tions, including control of combustibles, loose trash and debris; and cleanup was spot-checked during and after maintenance. Plant housekeeping was generally acceptabl . The inspector verified operability of selected safety related equipment and systems by in plant checks of valve positioning, control of locked valves, power supply avail-ability, operating procedures, plant drawings, instrumenta-tion, and breaker positioning. Selected major components were visually inspected for leakage, proper lubrication, cooling water supply, operating air supply, and general conditions. No significant piping vibration was detecte The inspector reviewed selected blocking permits (tagouts)

for conformance to licensee procedure .1.10 While touring the Fan Room on the Rad Waste Building 165 foot elevation on April 8, 1985, the inspector noted that nitrogen bottle 0B55385 was out of its seismic restraint rack. The nitrogen bottle supplies backup nitrogen to the dampers for the Emergency Ventilation System. The bottle was connected and valved into the backup nitrogen system, but was restrained only by one piece of rop Surveillance Test Procedure ST 7.9.2, Rev. 5, March 17, 1983, " Daily Check of Seismic Gas Supply Bottle Pressures," requires an operator to check that the seismic restraints for gas bottles are secured. Completed ST 7.9.2 indicates that a new nitrogen bottle, 0855385, was placed in service on March 5,1985, and daily checked as satisfactory through April 8, 1985. A note written on March 24, 1985, on the ST indicates the bottle would not fit into the restraint rack, but was secured. A similar note on April 6 and April 7, 1985, indicated that the rack needed to be modified for the

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bottle to fit. When informed by the inspector the licensee promptly replaced the bottle with one that was properly restrained. The inspector expressed concern that the problem existed for over one month. FSAR Section 10.14 indicates that the Emergency Ventilating Systems for the Emergency Switchgear and Battery Rooms are seismically qualified and the associated dampers are on the Peach Bottom Project Q-list, Revision 20. ST 7.9.2 requires visual verification that each bottle is seismically restrained. Failure to maintain the seismic qualification of nitrogen bottle 0B55385 as required by procedure is a violation (277/85-12-01; 278/85-12-01).

The control dampers for the ventilation supply and return system for the Switchgear and Battery Rooms fail closed on loss of air to the damper operators. Ventilation to these rooms is required to maintain temperatures at acceptable levels for equipment qualificatio FSAR section 10.1 states that the Emergency Ventilating System equipment is designed to seismic Class I criteria. The licensee's safety analysis indicates that upon loss of ventilation, the room temperatures rapidly increase above the design maximum of 105 F. Two bottled nitrogen stations are provided to allow continued operation of the required fan systems after a seismic event. Each nitrogen station consists of two bottles and supplies gas to separate damper operators. The licensee's safety analysis indicates that one bottle is sufficient to allow system operation after a seismic even During previous NRC inspections, in April 1982 and January 1983, seismically qualified nitrogen bottles have been found unrestrained . The licensee's corrective action for the first incident was to revise ST 7.9.2 to include veri-fication of system integrity by visual inspection of seis-mic bottle restraint Corrective action for the second incident was to revise ST 7.9.2 to more closely require and detail that all bottles be seismically restrained and include an individual " restraint secured" check off for each bottl .2 Followup On Events Occurring During the Inspection 4. Unit 3 Reactor Protection System Instrument Channel ,

Failure During routine surveillance testing of the Reactor Protec-

tion System (RPS), the "A" main steam isolation valve (MSIV)

closure scram input failed to give a trip. During the 11:00 p.m. to 7:00 a.m. shift on April 8, 1985, ST-9.7, "MSIV Partial Closure and RPS Input Functional Test," was per-formed. The "A" main steam line, inboard MSIV (AO-3-2-80A)

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closure limit switch failed to give a channel B1 scram input when operated in conjunction with test pushbutton switch SA-S12F. Test switch SA-S12F simulates closure of

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an MSIV in the C main steam line. The RPS is designed with two channels (A and B) and further subdivided into two subchannels (A1, A2 and B1, B2). Each of the eight MSIVs has two closure limit switch inputs into RPS. The ST- functionally tests all 16 inputs to ensure a trip (scram)

occurs. The RPS logic requires two MSIVs to close (less than 90% open) in order to trip one RPS subchannel (A1, A2, B1,B2). The ST-9.7 checks the subchannel trips by using a pushbutton to simulate one MSIV closed concurrently with the actual slow closure of another MSI While simulating MSIV A0-3-2-80C or 86C closure by de-energizing relay K3F and slow closing MSIV A0-3-2-80A, RPS relay K3B failed to de-energize, thus failing to de-energize relays K13F and K13 De-energizing relays K13F and K13B gives a B1 subchannel trip (i.e., reactor half scram).

Thus, an MSIV trip function for RPS subchannel B1 was inoperabl The unit was placed into Technical Specification (TS)

action statement 3.1.1. TS 3.1.1 requires placing an inoperable RPS sensor channel in the safe (tripped) condi-tion. At 3:00 a.m. on April 8, 1985, the licensee input a auto half scram in RPS channel B. This was noted by the inspector at 8:00 a.m. on April 8,1985, by verifying the channel B auto scram alarm energized, de-energization of B scram solenoid lights and de-energization of 81 scram relays K13F and K13 In order to effect functional sur-veillance testing on the RPS with RPS channel B in a tripped condition, Special Procedure (CP)-798 was imple-mented at 11:00 a.m. on April 8, 1985. SP-798 places the MSIV 3-2-80A closure limit switch in the safe (tripped)

condition by pulling RPS fuse SA-F3B in panel 30C1 Pulling this fuse de-energizes relay K3B. With relay K3B de-energized, RPS is aligned so that closure of either MSIV 3-2-80C or 86C would cause a RPS channel B1 trip. The inspector reviewed SP-798 and associated RPS electrical schematic drawings, M-I-S-54 sheet 7 Rev. 61, sheet 8 Re , sheet 9 Rev. 63, sheet 10 Rev. 63, sheet 11 Rev. 61 and sheet 12 Rev. 61. The inspector reviewed the requirements of Technical Specifications 3.1 and 4.1 and discussed the special procedure with the licensee. The inspector also reviewed implementation of SP-798, including visual verifi-cation that fuse SA-F3B was pulled and blocked, and that RPS relay K3B was de-energized. The licensee initiated a maintenance request form (MRF) to repair the faulty MSIV 80A limit switch when drywell access is availabl .

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Within the scope of the review of this event, no unaccep-table conditions were identifie . Unit 3 Engineered Safeguard Features (ESF) System Actuation At 12:25 p.m. on April 10, 1985, Unit 3 experienced an ESF actuation while at 90% power. The E-1 and E-3 (division I)

emergency diesel generators (DG) started and the drywell fans and coolers tripped. The DGs did not energize their respective emergency 4 KV buses as the buses remained powered from off-site startup and emergency power source With the loss of drywell cooling, the drywell pressure and temperature began to increase. As a precautionary measure, the operators reduced power to 50% by lowering reactor recirculation flow to minimum. Reactor water level and pressure responded as expected to the downpower transient and then returned to norma The inspector reviewed control room recorder traces shortly after the event. Reactor water level increased to 30 inches initially and then returned to the normal level of 23 inche Reactor pressure decreased to 970 psig and then returned to normal. Average Power Range Monitor (APRM) traces indicated that power had decreased rapidly (due to the operator runback on recirc flow) to about 50%. The licensee made a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> ENS notification as required by 10 CFR 50.72 at 2:25 Monthly surveillance testing was in progress on ECCS actua-tion instrumentation. ST-2.10.12, Functional Check of the ECCS A/C-1 Card File, March 1,1984, Revision 8, was being performed by instrument technicians. This test verifies the operability and checks setpoints of various ECCS actua-tion instrumentation and trip units. Testing was being performed on the core spray division I initiation logic which includes drywell pressure and reactor level signal The test requires plugging a test box into test jack 14A-J1A at panel 30032 (local ECCS relay panel in cable sprea-ding room). When this test box was plugged in, core spray initiation logic relay 14A-K11A energized causing DGs E-1 and E-3 to start and causing the tripping of the drywell cooling equipment. The division I core spray pumps (A and C) did not start as reactor pressure was normal. The inspector reviewed the core spray electrical schematic M-I-S-40 sheet 2, Revision 40, October 17, 1984, to verify that the core spray pumps did not receive a start signa Review of the electrical schematic confirmed that the core spray pumps would not start on 2 psig high drywell pressure (relay 14A-K32A) unless a 450 psig low reactor pressure condition (i.e., relay 14A-35A energized) occurred concur-rentl .

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Th'e inspector inquired how the test box being plugged into test jack 14A-J1A caused the ESF actuation. The licensee stated that investigation had revealed that the test box insulation was off one wire and this exposed wire touched another wire causing a short. This short occurred across test points "C and D" on test jack 14A-J1A, and resulted in the energizing of relays 14A-K32A and 14A-K11A, and signals to start the E-1 and E-2 DGs and to trip the drywell cooling equipment. The licensee inspected all similar test boxes and found no other problems. In discussions with the licensee, the licensee indicated that the test equipment will be checked routinely to ensure that degraded condi-tions are noted and corrected as necessary (IFI 278/

85-12-02).

The inspector reviewed the plant event recovery by the on shift operator Due to the loss of drywell cooling, drywell pressure and temperature increased from 0.6 to 0.9 psig and 129 to 136 F, respectively. The licensee reduced power to 50% with recirculation flow. The E-1 and E-3 DGs were stopped when it was determined they were not required. The technicians performing the test removed the faulty test equipment and the plant operators returned drywell cooling to service. Drywell temperature and pressure then returned to normal. Reactor power was then increased to the pre-event level of 90%.

Within the scope of this review and followup of the event, no violations were identifie .3 Logs and Records 4. The inspector reviewed logs and records for accuracy, com-pleteness, abnormal conditions, significant operating changes and trends, required entries, operating and night order propriety, correct equipment and lock-out status, jumper log validity, conformance to Limiting Conditions for Operations, and proper reporting. The following logs and records were reviewed: Shift Supervision Log, Reactor Engineering Log, Reactor Operator's Log (Unit 2), Reactor Operator's Log (Unit 3), Control Operator Log Book and STA Log Book, Night Orders, Radiation Work Permits (RWP's),

Maintenance Request Form;, and Ignition Source Control Checklists. Control Room logs were compared against Administrative Procedure A-7, " Shift Operations". Frequent initialling of entries by licensed operators, shift super-vision, and licensee on-site management constituted evi-dence of licensee revie _

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12 4. On May 7, 1985, upon inspection of the Control Room Supervisor's log, it appeared that no Control Room Super-visor was on duty between 6:30 p.m. and 8:30 p.m. on May 5, 1985. Discussion with the licensee indicated that the Control Room Supervisor and the Senior Licensed Operator (SLO) involved in fuel handling switched positions so the fuel handling SLO could take a break from fuel handling operations. Also, while the Control Room Supervisor's log did not indicate such, a similar change had occurred between approximately 11:00 a.m. and 1:00 p.m. the same day. Technical Specifications require a shift superinten-dent (SLO), a shift supervisor (SLO) and a third SLO to direct all core alterations who has no other concurrent duties. The inspector was concerned that the minimum shift crew as defined in Section 6.2.2.a of the Technical Speci-fications was unavailable during this time. After interviewing all the SL0s involved in switching positions, the inspector concluded that the licensee met the shift staffing require-ment The inspector questioned whether an SLO was in the Control Room during these changes in positions as required by plant procedure A-7, Shift Operations and 10 CFR 50.54(m). Based upon discussions with the Shift Superintendent, Shift Supervisors, and a review of the vital area door log for entries and exits from the Control Room it was concluded that an SLO was in the Control Room at all time Procedure A-7, Rev. 20, " Shift Operations", dated April 30, 1984, requires that for short term relief longer than 1/2 hour the Control Room Supervisor reporting for duty receive a verbal turnover from the off going Control Room Suoerviso The offgoing Control Room Supervisor is required to com-plete and sign a shift turnover checklist. The oncoming Control Room. Supervisor shall document he has reviewed conditions in the Control Room by initialing the Chief Operator, the Unit 2, and the Unit 3 Reactor Operator log books. The oncoming Control Room Supervisor shall also inspect the control panels under his contro Examination of the Control Room Supervisor turnover log indicated only one shift turnover sheet was completed for the afternoon shift (3:00 p.m. to 11:00 p.m.) on May 5, 1985. Interviews with the Control Room Supervisors indicated other turnover requirements were not met such as reading and initialing log books. Failure to complete shift turnover requirements of procedure A-7 is an apparent Violation (278/85-12-03).

The licensee issued a meme andum dated May 7, 1985, to shift supervist.1 describir , responsibilities for shift relief of greater than 1/2 hcur. The inspector reviewed the memorandum. Since immediate and acceptable corrective

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action was taken no additional response is necessary for this apparent violation. The inspector will continue to routinely monitor shift turnover activitie .4 Refueling / Outage Activities 4. Unit 2 RHR Weld Flaws During the RHR and recirculation system piping replacement at Peach Bottom Unit No. 2, an on site review of the non-destructive examination data for weld RHR 10-1A-17-LD (NRC CD-P-362) was performed by the inspector. This consisted of reviewing CBI repair traveler 56R-6, liquid penetrant examination report, and radiograph film during and after repair. The inspector also reviewed the ultrasonic data from all sections of piping from the same heat in order to determine compliance with ASME Section II Two flaws were ultrasonically detected during preservice examination in longitudinal weld RHR-10-1A-17-LD fabricated by Youngstown Welding and Engineering Company. The original ASME Section III code examination was performed and accepted using radiography. The piping material is SA 358, grade 316, with a 1.2" wall thickness; the longitudinal seam was welded from both sides using filler metal. The first flaw was 2.125" in length, .62" in depth and .62" from the edge of the circumferential weld. The second flaw was .5" in length, .62" in depth and 3.5" from the circumferential wel The flaws were classified as rejectable and exca-vated for repair; the excavation revealed mid-wall lack of fusio The above supporting data indicates that the corrective action is acceptable and this action has satisfied the inspector's concern No violations were identifie . Unit 2 Torus Inspection On March 28, 1985, the inspector performed an inspection inside of the Unit 2 toru Items checked included: dry-well vent headers, suppression pool down comers, modifica-tion on torus to drywell vacuum breakers in progress, torus cooling spray ring header, ECCS pumps' suction lines, over-all torus integrity, water clarity and general area cleanli-ness. The inspector noted several items (e.g., poly bottles and tape) floating in the torus water. When the inspector brought these items to the licensee's attention, the licensee promptly removed the No violations were identifie .

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4. Unit 2 Core Reload Unit 2 core reload began on May 2, 1985. The inspector reviewed licensee prerequisites (see Detail 4.4.4) for core load. A review of the following documentation was per-formed:

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FH-6C " Fuel Movement and Core Alteration Procedure During a Fuel Handling Outage," Revision 17, October 24, 198 FH-6C, Appendix 1, " Core Component Transfer Authorization Sheet," Revision 2 S-14.1, " Operation of the Refueling Platform Controls and Interlocks," Rev. O, May 8,198 A-44, "Special Nuclear Material Accountability."

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S-14.2, " Moving Fuel from the Fuel Pool to the Reactor,"

Revision 5, May 8, 198 S-14.3, " Moving Fuel from the Reactor to the Fuel Pool,"

Revision 7, May 8, 198 S-14.4, " Moving Fuel Within the Reactor," Revision 7, May 8, 198 Technical Specifications and Bases, Section 3.10/4.1 GEK 9684, Volume VI, " Service and Handling Equipment."

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S-14.5, " Removing Blade Guides from the Reactor and Placing them in the Fuel Pool," Revision 5, May 8, 198 Fuel Pool Drawings, 6280-MIM-5 thru 1 Instruction Manual, " Refueling Platform Equipment Assembly 796E457," Volume 1, PE #6280-MIM-378- ST-12.1-2, " Refueling Interlock Functional Test,"

Revision 1, October 31. 198 ST-3.1.2, "SRM Core Monitoring Test," Revision 9, January 11, 198 The inspector monitored the following items associated with core reload through direct observation of fuel handling activities:

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The operability of refueling interlocks

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The operability of source range monitoring (SRM)

instrumentation

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Availability of direct communication between the control room and refueling bridge

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The presence of a senior licensed operator supervising fuel handling activities

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The operability of the standby gas treatment system and secondary containment

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The radiological precautions for fuel handling including adherence to the RWP

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The presence of an HP technician in the fuel floor area

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The precautionary measures for preventing the intrusion of foreign objects into the reactor cavity

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The operation of refueling bridge and associated fuel handling equipment

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Reactor vessel and fuel pool water level and clarity requirements

-- Fuel and component accountability in the spent fuel pool and in the reactor core

-- Reactor mode switch locked in " refueling" position

-- The operability and required full insertion of all control rods

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Unit 2 reactor operator cognizance of refueling activities and direct monitoring of SRM levels and changes (count rates and period changes).

i Within the scope of this review, no unacceptable conditions were identifie .4.4 Special Procedures for Unit 2 Recovery Operations The inspector reviewed Special Procedure 781, Replacement Piping Flush Procedure, discussed the procedure with the licensee, and observed portions of the flushing operation The inspector noted that special precautions were taken to l

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backfill and flush instrument lines to prevent clogging and consideration was given to the problem of. plugging CRD filters with resultant slow scram times. No unacceptable conditions were note The inspector reviewed Special Procedure (SP) 800, " Plant Conditions Necessary to Fuel Reload Unit 2," dated April 12, 1985, and met with the licensee to discuss Technical Specification requirements for loading fuel into the reactor ressel. The inspector attended the PORC meeting which reviewed and approved the procedur SP-800 was reviewed in the control room while it was being implemented and after it had been completed. All steps had been completed and signed off satisfactorily. All changes to the SP-800 were handled properly and in accordance with procedures. The inspector questioned the operators on SP-800 and found them knowl-edgeable of the procedure. No unacceptable conditions were foun . Unit 3 Extended Core Flow Operation Unit 3 implemented cycle 6 extended core flow operation on March 27, 198 Extended core flow enables the reactor operator to increase core flow to greater than 100% or 102.5 million pounds mass per hour (MLB/hr) _in order to maintain allowable core thermal power throughout the end of cycle (EOC)

period for Unit The inspector reviewed the following documentation with respect to extended core flow operation:

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General Electric document NEDC-30519, March 1984, " Safety Review of Peach Bottom Atomic Power Station Unit No. 3, at Core Flow Conditions Above Rated Flow Throughout Cycle 6".

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General Electric document SIL No. 370 Category 1, February 1982,

"Possible Fuel Damage from Loss of Feedwater Heaters".

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General Electric document NEDC-20411-P-2, May 1977, " General Electric Reload Fuel Application".

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Letter, D. W. Diefenderfer to L. F. Rubino, " Peach Bottom Power

, Station Unit 3 Increased Core Flow Analysis", dated March 26, 1984, GE No. G-HE-4-13 Technical Specification Figure 3.5.1.E, "K-f" Factor Versus Core Flow Letter, G. R. Hull to L. F. Rubino, " Peach Bottom 3 Cycle 6 Cycle Management Report Supplement 1 - 2000 MWD /T to E0C 6", dated February 9, 1984, GE No. GRH:84-01 _ .

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GP-19-3, Unit 3 Extended Core Flow Operation, Revision 3, March 21, 198 Plant Modification #84-086 regarding process computer "K-f" -

revision performed on September 25, 198 Technical Specification Amendment 107 for Unit 3, dated December 3, 198 The safety evaluation shows that Unit 3 can increase core flow to operate within the region of the operating map bounded by the line between 100%

power, 100% core flow (3293 MWth, 102.5 MLB/hr) and 100% power, 105% core flow (3293 MWth, 107.6 MLB/hr) throughout Cycle 6. Unit 3, after reaching EOC exposure, can continue to operate in the region of the operating map bounded by the constant recirculation pump speed line between 100% power, 105% core flow (3293 MWth,107.6 MLB/hr) and 70% power,110% core flow (2305 MWth, 112.7 MLB/hr) with or without the fifth-stage feedwater heaters valved out-of-service. End of Cycle 6 exposure is defined as the core average exposure at which there is no longer sufficient reactivity to achieve 3293 MWth (100% reactor power) with rated core flow, all control rods withdrawn to position 24 or beyond, all feedwater heaters in service, and equilibrium xeno In order to operate in the extended core flow region of the power flow map, the following plant changes were made:

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Mechanical and electrical stops on the reactor recirculation MG set scoop' tubes adjusted to allow increased core flo Critical Power Ratios (CPR) limits in the process computer changed to allow for extended core operation with an exposure greater than EOC - 2000 megawatt days per metric tonne of uranium (MWD /T) - a value equal to 6080 MWD / "K-f" factor (a multiplier for the operating MCPR limit at less than rated core flows) changes for increased core flow Rod Block Monitor (RBM) flow biased circuits clamped at 107% for core flows greater than 100%.

The inspector reviewed the implementation of procedure GP-19-3, Revision Items reviewed included procedure prerequisites for "K-f" changes, recirculation MG set scoop tube stops adjustments and RBM circuits clampe The procedure is divided into two parts. The first part (I) is for extended core flow between 100% and 105% (102.5 MLB/hr to 107.6 MLB/hr).

The second part (II) is for extended core flow greater than 105% (10 MLB/hr.) through power coastdown to 70% reactor power. The inspector checked that core thermal limits were within Technical Specification limits upon execution of the extended core flow and routinely thereafter. Core thermal limits checked include core thermal power, minimum critical power

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ratio, maximum linear heat generation rate and maximum' average planar linear heat generation rat Core thermal limits were maintained within the Technical Specification limit The inspector questioned how the average power range monitors (APRM) flow biased rod block and scram setpoints would be sdjusted for core flows greater than 100%..The licensee's response was as follows:

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APRM flow biased scram is automatically clamped at 120% for greater ,

than 100% core flo APRM flow biased rod block is clamped procedurally at 108% by adjus-ting APRM gain The inspector verified these licensee responses as follows:

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APRM flow biased scram setpoint is .66 (core flow) % + 54%. At 100%

core flow, this value equals 120% per Technical Specification Table 3.3.3 and Technical Specification 2. The inspector reviewed APRM electrical schematic drawings M-1-5-34 sheet 3 (Rev. 11), sheets 4-9

.(Rev. 21) and GEK 9684 (Volume III - Chapter 9) Power Range Monitoring System. Flow control trip reference unit Z33 performs a signal clamp at 9.6 volts (equivalent to 120% APRM output) thus limiting the signal for core flow to a value of 100% for APRM flow biased scra APRM flow biased rod block setpoint is .66 x (core flow) % + 42%.

At 100% core flow, this value equals 108% per Technical Specification Table 3.2.C and Technical Specification 2.1.B. The inspector reviewed ST 3.3.2, APRM System Calibration, Revision 8. This procedure adjusts APRM indicated power-readings based on core thermal power. If core flow is greater than 100% (102.5 MLB/hr), then APRM indicated power is increased by a factor equal to the ratio of the rod block setpoint to 108%.

r No violations were identifie . Review of Licensee Event Reports (LERs)

6.1 The inspector reviewed LERs submitted to NRC:RI to verify that the details were clearly reported, including the accuracy of the descrip-tion and corrective action adequacy. The inspector determined whether further information was required, whether generic implications were indicated, and whether the event warranted on-site followup. The following LERs were reviewed:

LER N LER Date Event Date Subject 3-85-05 Excessive Containment January 29, 1985 Local Leak Rates February 28, 1985

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3-85-06 Incorrect Limitorque Operator February 20, 1985' on RCIC M0V March 22, 1985 (MO-3-13-15)

• 3-85-07 Reactor scram as the March 1, 1985 result of low April'1, 1985 condenser vacuum

• 3-85-08 Suppression Pool March 13, 1985 ' level above Technical April 17, 1985 Specification limits 3-85-09 Possible loss of March 28, 1985 Secondary Containment April 29, 1985 Integrity

• 3-85-10 Automatic Acutation April 10, 1985 of E-1 and E-3 Diesel May 6, 1985 Generators and Temporary Loss of Drywell Cooling 6.2 On-Site-Followup For LER's selected for on-site followup and review (denoted by

' asterisks above), the inspector verified that appropriate corrective action was taken or responsibility assigned and that continued i operations of the facility was conducted in accordance with Technical

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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 No. 3-85-07 concerns a reactor scram on Unit 3 resul-ting from low main condenser vacuum. This event was reviewed in Inspection 277/85-08 and 278/85-0 . LER No. 3-85-08 concerns the suppression pool (torus) water level above the Technical Specification limit on Unit This event was reviewed in Inspection 277/85-08 and 278/

85-0 . LER No. 3-85-10 concerns the automatic actuation of the E-1 and E-2 DGs and temporary loss of drywell cooling, and the event is reviewed in Detail 4.2.2 of this repor . Surveillance Testing The inspector observed surveillance tests to verify that testing had been properly scheduled, approved by shift supervision, control room operators

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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 In addition, a review of the following completed surveillance tests was performed:

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ST 3.1.2, "SRM Core Monitoring Test," Revision 9, dated January 11, 1985, performed on Unit 2 on May 9, 198 ST 10.13, "CRD Scram Insertion Timing of Selected Control Rods,"

Revision 1, April 26, 1984, performed on Unit 3 on March 12, 198 ST 3.3.2, " Calibration of the APRM System," Revision 8, December 28, 1981, performed on March 26, 1985, on April 4, 1985 and April 7, 198 ST 10.11, " Average Scram Times for ODYN/B Minimum Critical Power (MCPR) Ratio Requirements," Revision 5, April 10, 1984, performed on Unit 3 on March 11, 1985 and March 13, 198 During the review of ST 10.13 above the inspector noted the following items:

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ST 10.13 has an incorrect Technical Specification referenc ST 10.13 Figure I has a minor typographical erro ST 10.13 Tables in steps 12 and 13 have typographical error These items were discussed with the licensee who initiated steps to correct the noted minor deficiencie No violations were identifie . Maintenance f On March 15, the inspectors attended a pre-job review of the Control Rod Drive (CRD) exchange work. The licensee discussed various tasks associated with the exchange, introduced the contractor personnel involved, and insured that each work group was aware of their responsibilities and the interfaces. The actual CRD exchange work started on April 3, 198 Selected protions of all phases of the CRD exchange were witnessed by the inspectors including: disconnecting and removing the CRD, CRD transfer to the cask at the drywell hatch, HP surveys, CRD transport from the Unit 2 drywell to the 195 foot elevation of the Unit 3 Reactor Building, CRD flush cage operations CRD rebuild and leak testing, and CRD reinstallatio RWPs were reviewed periodically throughout the work. " Shield cans" were used around the drives at the bottom the reactor vessel which were designed

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l and built by the licensee to reduce radiation doses to workers. Based upon actual exposure data from the last Unit 2 CRD exchange in 1982, the work under the reactor vessel in exchanging 45 CRD would result in an  ;

estimated 190.26 man-rem However, the actual expocure was 56.07 man-rems, a reduction of over 134 man rems. This represents a savings of about 3 man-rems per CRD exchanged. On April 4, licensee QC noted that

"0-rings" being used to rebuild a CRD had an out-of-date shelf life. The inspector was present at the time and noted that all work stopped while the licensee inventoried his boxes of "0-rings" and checked other drives that had been completed. The licensee found a GE letter dated April 28, l 1982, that authorized use of a 20 year shelf life rather than seven years; j however, the inspector noted that the letter identified the part number as i

153B7630P7 whereas it should have been 158B7630P7. GE issued a letter dated April 4, 1985, correcting the part number mistak The inspector reviewed both letters and determined them satisfactor The inspector reviewed the PORC meeting minutes 85-31 dated March 28, 1985, which dealt with changes to procedure M-3.4, " Control Rod Drive Repair." All work stations were checked to ensure that current procedures M-3.1 and M-3.4 were being used. Blocking permits on control rods: 34-23, 38-19, 34-27, and 34-43 were reviewed in the Control Room locally and at the hydraulic control unit On April 11 the inspectors noticed contaminated water on the floor of the 165 foot elevation of the Unit 3 Reactor Building which had spilled down from the 195 foot elevation flush area. The licensee took action to clean up the floor of the 165 foot elevation promptl The inspector reviewed the following procedures associated with the CRD exchange and witnessed various steps in the procedure S.4.2.G, " Returning a CRD to Service After Maintenance with the CRD in the Fully Withdrawn Position (48)," Rev. 3, 9/1/7 S.4.G.1, " Returning a CRD to Service After Maintenance with the CRD in the Fully Withdrawn Position (48) (Short Method)," Rev. 2, 10/3/7 S.4.2.H, " Blocking a CRD in the Fully Withdrawn Position for Maintenance," Rev. 1, 1/24/7 S.4.2.H.1, " Blocking a CRD in the Fully Withdrawn Position for Maintenance with Fuel Unloaded from Control Cell," Rev. O, 5/16/7 S.4.2.K, " Administrative Control for Rod Withdrawl with Empty Fuel Cell," Rev. 3, 2/25/8 M-3.1, " Control Rod Drive Replacement," Rev. 18, 3/21/8 M-3.4, " Control Rod Drive Repair," Rev. 12, 5/2/8 .

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M-3.10 " Control Rod Leak Test," Rev. 2, 7/24/8 M-3.13 " Control Rod Drive Shoot Out Steel Removed, Installation and Adjustment," Rev. 0, 6/7/8 A problem developed with the last CRD to be replaced, CRD 30-31, when it '

was lowered down and discovered to be still coupled to the control blad In addition to the CRD's originally replaced, the CRD at location 18-59 was replaced on April 21 because the CRD drifted out to position 48 and would not latch at any partially or fully inserted position. The CRD was disassembled but no obvious causes were foun Further examination is continuin The inspector observed HP and ALARA senior staff personnel reviewing operations early in the work for the purpose of making improvements to reduce exposures and streamlining the operations. The inspector also noted that QC and QA personnel were frequently involved in the work. The job was well coordinated with the licensee working with and providing close supervision of the contractor. Radiation exposures were reduced significantly by the use of the shield can No unacceptable conditions were identifie l Radiation Protection During this report period, the inspector examined work in progress in both units, including the following:

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Health Physics (HP) controls

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Badging

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Protective clothing use

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Surveys

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Handling of potentially contaminated equipment and materials The inspector observed individuals per forming frisking in accordance with Health Physics procedures. A sampling of high radiation door: v:s verified to be locked as required. Compliance with RWP requirements was verified during each tour. 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 . Physical Security 10.1 The inspector monitored for compliance with the accepted Security Plan and associated implementing procedures, including: operations of the CAS and SAS, checks of vehicles on-site to verify proper

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23-control, observation of protected area access control and badging procedures on each shift, inspection of physical barriers, checks on control of vital area access and escort procedure .2 During an off-normal hour inspection on Sunday, April 14, 1985, the inspector noted some security badges unattended outside a vital area door to the Unit 2 reactor building. The inspector notified the Unit 2 drywell security guard who initiated action to retrieve and control the badges. This occurrence was discussed with licensee the following day (April 15,1985). Further investigation is documented in a Region I specialist inspection (Inspection 277/85-16 and 278/85-13).

10.3 Region I letter dated November 6, 1984, from R. W. Starostecki to S. L. Daltroff expressed alleged concerns that security personnel were telling workers to pass through portal monitors faster to avoid setting off the alarm and that security was losing too many dosi-meters. The licensee replied to these concerns on December 5, 198 The inspector reviewed the licensee response and verified proper corrective actio With respect to security personnel telling workers to pass through portal monitors faster to prevent them from alarming, the licensee indicated in the December 5, 1984 letter that security personnel were reinstructed, both verbally and through individual letters to each security employee. Their investigation identified one person who may have so instructed workers. This security worker is no longer employed at Peach Botto The inspector discussed this concern with the licensee and observed workers exiting via the portal monitors at various times over a several month period to assure proper procedures were followed. A written instruction sheet on proper portal monitor operation has been placed at the security post at the plant exit. In addition, a large sign has been posted to instruct people to place both feet on the pad of the portal monito The inspector asked to see a copy of the letter issued to the security staff. No letter could be found, and the inspector expressed concern that no letter was issued when the December 5, 1984 response indicated such a corrective action. A memorandum was subsequently issued on April 11, 1985, and each member of the security staff was required to read and sign a statement that they had read the memorandu The inspector reviewed the memorandum and verified that the staff had read it. The inspector also verified that the meeting of November 14, 1984, for security employees discussed the portal monitor problem. The inspector had further questions about the security function at the portal monito A second issue involved a reportedly upward trend in dosimeters lost by security. The licensee investigated lost dosimetry records for the Harshaw and Eberline TLDs and studied possible trends. As reported in the December 5, 1984 response from the licensee, no increase in lost dosimeters was identified. A review of the licensee's data and studies on lost dosimetry was made. Discussions

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were held with the licensee. No inadequacies were identified and the inspector had no further question An issue related to the two concerns discussed above was the periodic testing and survey of HEPA filters used in the Unit 2 drywell. No requirement exists for sampling HEPA filters from the drywell. If the HEPA filters were sampled, it could not be directly related to meaningful airborne radioactivity levels. The HEPA filters are changed when the pressure drop across the filters becomes too larg The inspector discussed the concerns associated with testing and surveys of HEPA filters, reviewed the plant procedures for test requirements and reviewed historical data on drywell airborne radioactivity at drywell elevations 116, 135 and 157. A large number of air samples are taken in the drywell each day (approximately 64 particulate samples per day and one Iodine sample per week). The inspector had no further questions on this issu Based upon the licensee's response to the concerns expressed in the NRC letter of November 6, 1984, and the subsequent inspection, the inspector considers these issues resolve . In-Office Review of Public and Special Reports The inspector reviewed the licensee report titled " Unit 2 Justification for Continued Operation Following Primary System Piping Replacement", dated April 1985. No deficiencies were identifie . Inspector Follow Items Inspector follow items are items for which the current inspection findings are acceptable, but due to ongoing licensee work or special inspector interest in an area, are specifically noted for future followu Followup is at the discretion of the inspector and regional managemen An inspector follow item is discussed in Detail 4. . Management Meetings 13.1 Preliminary Inspection Findings A verbal summary of preliminary findings was provided to the Assistant Station Superintendent 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 J

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13.2 Attendance at Management Meetings Conducted by Region-Based Inspectors The resident inspectors attended entrance and exit interviews by region-based inspectors as follows:

Inspection Reporting Date Subject Report N Inspector April 10 (Ent) Unit 2 Restart 277/85-15 J. Johnson April 19 (Exit) Team Inspection SRI, Pilgrim April 18 (Ent Security 277/85-16- Dunlap and Exit) 278/85-13 April'24 (Ent) ILRT 277/85-17 Hodson April 26 (Exit) Kucharski

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