IR 05000277/1985030

Insp Repts 50-277/85-30 & 50-278/85-27 on 850727-0906.Major Areas Inspected:Operational Safety,Radiation Protection, Physical Security,Control Room Activities,Licensee Events, Surveillance Testing & Unit 3 Refueling/Outage Activities

ML20137Y739
Person / Time
Site:	Peach Bottom
Issue date:	10/01/1985
From:	Beall J, Gallo R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20137Y703	List: IR 05000277/1985030 ML20137Y698
References
TASK-2.B.2, TASK-TM 50-277-85-30, 50-278-85-27, NUDOCS 8510080080
Download: ML20137Y739 (28)

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U. S. NUCLEAR REGULATORY COMMISSION

REGION I

Report No. 50-277/85-30 & 50-278/85-27 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: July 27, 1985 - September 6, 1985 Inspectors: T. P. Johnson, Sr. Resident Inspector J. H. Williams, Resident Inspector J. E. Beall, Project Engineer S. D. Reynolds, Lead Reactor Engineer J. P. Rogers, Reactor Engineer Reviewed by: < fo/L loll N J. E. Beall, Project Engineer

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date Approved by: b (0 i Robert M. Gallo, Chief da'te Reactor Projects Section 2A DRP Inspection Summary: Routine, on-site regular and backshift resident inspection (160 hours0.00185 days <br />0.0444 hours <br />2.645503e-4 weeks <br />6.088e-5 months <br /> Unit 2; 126 hours0.00146 days <br />0.035 hours <br />2.083333e-4 weeks <br />4.7943e-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, Unit 3 refueling and outage activities, maintenance, and outstanding item Results: The NRC identified concerns regarding the maintenance repair prccedures and the quality of the spare parts for the Walworth motor operated RHR valve,

'M0-2-10-154 In addition, errors were identified in Licensee Event Report 2-85-03 (Detail 4.2.6.)

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1 DETAILS Persons Contacted J. K. Davenport, Supervising Engineer Maintenance

• R. S. Fleischmann, Manager Peach Bottom Atomic Power Station A. A. Fulvio, Technical Engineer A. E. Hilsmeier, Senior Health Physicist D. L. Oltmans, Senior Chemist F. W. Polaski, Outage Planning Engineer S. R. Roberts, Operations Engineer

• D. C. Smith, Superintendent Operations

• J. E. Winzenried, Superintendent Plant Services Other licensee employees were also contacte *Present at exit interview on site and for summation of preliminary finding . Plant Status 2.1 Unit 2 The unit began the report period in post outage startup testing at 80% powe Power ascension continued and the unit achieved 100%

power on August 2, 198 On August 5, 1985, the unit scrammed from 98% during turbine control valve testing (see detail 4.2.1). The unit restarted, and on August 7,1985, a scram on IRM high flux occurred (see detail 4.2.2). The unit was restarted on August 8, 1985.

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On August 12, 1985 and again on August 19, 1985, the unit was shutdown due to an inoperable diesel generator and one RHR loop (see detail 4.2.3). A reactor scram occurred during restart on August 26, 1985, while placing a pressure transmitter in service (see detail 4.2.4).

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The unit was restarted on August 26, 1985. The unit remained at full power throughout the remainder of the inspection period except for a reduction in power as required by Technical Specifications during inoperability of the Containment Atmosphere Dilution System (see detail 4.2.5) on September 6, 198 . 2 Unit 3 .

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Unit 3 remained in a refueling / outage status during the entire report perio ,

Major items completed during the inspection period were reactor vessel disassembly, core offload, fuel sipping and inspection, control rod blade exchange, control rod drive changeout, and

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miscellaneous plant modifice ions. Major items in progress are fuel reconstitution, diesel generator annual inspections, RHR and recirculation piping NDE inspections and in vessel inspections. (See detail 4.4)

Startup is scheduled for November 26, 198 . Previous Inspection Item Update 3.1 (0 pen) Unresolved Item (50-277/85-04-02): Licensee to review the acceptability of the weldments containing transverse molecular alignment indications as stated in its letter (John Moskowitz - PECo to Stewart Ebneter - NRC) dated June 12, 1985. In this letter the licensee discusses the destructive testing results of one weld having the aforementioned indications and explains its technical opinion that the indications are due to diffraction of x-radiation due to lengths of the penetrating radiation being similar in dimension to lattice spacing. The licensee also indicated that the indications observed do not meet the direction and crack morphology characteristics of weld metal solidification mechanics crackin The inspector concurs with the licensee's metallurgical assumption concerning solidification crack morphology. On January 17, 1985 the inspector requested copies of the radiographic film showing

" transverse molecular alignment indications." This item is considered open pending NRC receipt and review of copies of the radiographic fil .2 (Closed) Unresolved Item (278/85-07-02): Simultaneous inoperability of one diesel generator (DG) and one loop of the containment cooling (torus spray and cooling portion) subsystem. An Enforcement Conference was held in response to NRC Inspection 278/85-07 regarding the simultaneous inoperability. The NRC issued a meeting summary dated July 9, 1985. The licensee reviewed the design bases for the Peach Bottom loss of coolant accident, and determined that the containment cooling subsystem is not required to prevent exceeding the primary containment design limits. The inspector reviewed the Peach Bottom FSAR Section 14.6.3 and concurs that the containment response is independent of containment cooling availability. Based on this FSAR review, the Enforcement Conference and summary letter, this item is close .3 (Closed) Inspector Follow Item, Bulletin (277/79-BU-18, 278/79-BU-1B): Environmental Qualification of Class IE Equipmen The subject bulletin has been superseded by 10 CFR 50.49, regarding the environmental qualification of electric equipment important to safety for nuclear power plants. The licensee's Environmental Qualification Program will be the subject of a separate NRC inspec:. ion, and this item is therefore close .

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3.4 (0 pen) Unresolved Item (278/85-22-01): Apparent inattentive Unit 3 Reactor Operator. An Enforcement Conference was held at the NRC Region I office on June 21, 1985. NRC letter dated July 17, 1985, provided a summary of the Enforcement Conference and requested the licensee to respond in writing regarding the corrective actions discussed at the conference. The licensee responded in a letter dated August 16, 1985. The inspector reviewed the licensee's response letter and will review the documented corrective actions in a future inspectio This item remains ope .5 (Closed) TMI Action Plan (TAP) Item II.B.2.3: Plant Shielding -

Equipment Qualification. The subject TAP item will be examined during a separate team inspection in accordance with 10 CFR 50.4 This TAP item is close .6 (Closed) Inspector Follow Item (277/84-35-02): Inspection and correction of problems associated with cracking of the Unit 2 recirculation inlet safe ends (N-2 nozzles). A similar open item (277/84-24-01) was closed in Inspection 277/85-25 detail 3.9 .

Closure was based on licensee replacement of the N-2 safe ends and NRC Inspections 277/84-36, 277/85-01, 277/85-04. This item is close .7 (0 pen) Inspector Follow Item (278/84-29-03): Inspection and correction of problems associated with cracking of the recirculation inlet safe ends (N-2 nozzles). Unit 3 has conducted inservice inspections of the N-2 safe end to thermal sleeve and the F-2 safe end to pipe welds. The crack indications are currently unuer investigation by the licensee. A meeting was held between the NRC and the licensee on September 5, 1985, to discuss the N-2 crack findings and other Unit 3 NDE indication Licensee and NRC evaluation is in progress. This item remains ope . 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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thit 3 Drywell 4. Control Room and facility shift staffing were frequently checked for compliance with 10 CFR 50.54 and Technical Specifications. Presence of a senior licensed operator in the control room was verified frequentl . 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 limit ECCS switch positioning and valve lineups were verified based on control room indicators and plant observation 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 Rod Block, Drywell Radiation Monitor Trouble, and Torus Water Hi Temp / Failure. In addition, the applicable alarm cards were checked for accuracy. The operators were knowledgeable of alarm status and plant condition On July 30, 1985, the inspector noted that Unit 2 torus water high temperature / failure alarm was annunciated. A review of the alarm card, operating procedure and Technical Specification 3.2.F and 4.2.F was performed by the inspector to ensure that the suppression pool temperature monitoring system (SPOTMOS) was operable. The inspector

., noted the SPOTMOS system operating procedure, S.3.9.5, Revision 1, was applicable to Unit 3 only. Both units have identical SPOTM05 systems and the modification on Unit 2 was recently completed this past outage. The inspector discussed this with the licensee. A revised procedure to include Unit 2 applicability was approved on July 29, 1985, by the PORC. The inspector verified that this revised SPOTMOS procedure, S.3.9.5, Revision 2, was applicable to both units and in the Control Room system operating procedure files. No violations were identifie l

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4. The inspector checked for fluid leaks by observing sump status, alarms, and pump-out rates; and discussed reactor coolant system leakage with licensee personne . Shift relief and turnover activities were monitored daily, including backshift observations, to ensure compliance with administrative procedures and regulatory guidance. No inadequacies were identifie . 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 use of fire watches and ignition source controls, checked a sampling of fire barriers for integrity, and observed fire-fighting equipment stations. No inadequacies were identifie A review of the Peach Bottom manning of the fire brigade leader was performed by the inspector, and additionally this item was discussed with the licensee at a meeting in NRC Region I on August 1, 1985. A list of attendees appears in detail Peach Bottom's fire brigade is referred to as the " Fire and Damage Team" per the Peach Bottom Emergency

/ Plan. The interim Fire and Damage Team Leader is assigned by the Shift Superintendent per administrative procedure A-7, Shift Operations. Emergency plan procedure EP-206A, Fire Fighting Group, Revision 6, 1/10/84, specifies that the Shift Superintendent assigns the "Outside" Shift Supervisor or other member of shift supervision. This assigned interim leader is either a utility (extra day shift) SR0 qualified Shift Supervisor or Shift Superintendent, or the "Outside" Shift Supervisor (currently manned 10 shifts a week), or the Inside Shift Supervisor (Control Room Supervisor), or a plant operato Prior to assigning the Control Room Supervisor (Inside Shift Supervisor) as the interim Team Leader, the Shift Superintendent relieves the Control Room Supervisor as the SRO in the Control Room. The licensee stated that the Shift Superintendent is knowledgeable of current plant conditions on his shift since he conducts the pre-shift turnover meeting and remains abreast of ongoing activitie This information was presented by the licensee and verified by routine observations by the inspector. No violations were identifie ___ . - - _ - - - - _ - - - - - - - - _ - _ - - - _ - - - _ _ - - - _ _ - - - - - - - - - - - - - - - - - . - - - - - - . - - - - - - l

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4. The inspector observed overall facility housekeeping conditions, including control of combustibles, loose trash and debris. 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 availability, operating procedures, plant drawings, instrumentation 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 detected. The inspector reviewed selected blocking permits (tagouts) for conformance to licensee procedure No inadequacies were identified.

4.2 Followup On Events Occurring During the Inspection 4. Unit 2 Scram During Turbine Control Valve Testing At 9:31 p.m. on August 5, 1985, with Unit 2 at 98% power, the reactor scrammed during turbine control valve (TCV)

testing. The scram signal was TCV fast closure. The licensee declared an Unusual Event and reported the event in accordance with 10 CFR 50.7 The specific cause of the turbine trip signal was not initially determined and the unit remained shutdown during the licensee's investigation. The inspector reviewed the recorder traces, operator logs and the completed GP-18,

" Scram Review Procedure". The inspector discussed the event with operators and supervisors and monitored licensee's preparations for startup. The cause of the scram was identified by the licensee as a loss of EHC trip system oil pressure when the "CV-3" TCV was reopened during the testing, and combined with a setpoint drift in the conservative direction of the "CV-4" TCV pressure switc The "CV-3" TCV caused an RPS "A" trip and the "CV-4" TCV caused an RPS "B" trip, thus a full automatic scram occurred. The unit was restarted on August 7, 198 No unacceptable conditions were identifie l

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4. Unit 2 Scram On IRM High Flux At 1:39 p.m. on August 7, 1985, with Unit 2 at about 3%

power, the reactor scrammed due to IRM upscale readings on instruments in both channels of the Reactor Protection System (RPS). The licensee declared an Unusual Event and reported the event in accordance with 10 CFR 50.7 The unit had started up in recovering from the August 5, 1985, scram but delays in restoring the EHC system prevented the use of the turbine system bypass valves. The operator was maintaining reactor pressure in a band above the 100 psig setpoint for HPCI low pressure isolation using control rod motion. With pressure at about 105 psig and decreasing, the operator withdrew a control rod. The operator tried to insert _the rod back in as power and pressure increased, but the control rod did not initially move due to low drive pressur .

An automatic reactor half-scram was received as one IRM instrument went upscale and, as the operator tried to increase control rod drive pressure, an IRM instrument in the other RPS channel generated an upscale trip before the operator could uprange the switch. A full reactor scram resulted, and the unit responded normally to the transien The EHC system was restored, the unit was started up, and the generator was on line at 3:20 a.m. on August 8,- 198 The inspector reviewed the recorder traces, operator logs and the completed GP-18, " Scram Review Procedure". The inspector discussed the event with operators and supervisors, and monitored the licensee's preparations for startup. No unacceptable conditions were identifie .2.3 Unit 2 Shutdowns Due to Inoperable Diesel Generator and RHR System

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The licensee began a controlled shutdown of Unit 2 from 100% power at 11:00 a.m. on August 12, 1985, when testing of the "A" RHR LPCI system revealed an inoperable isolation valve (MO-2-10-154A) with the E-3 diesel generator out of service for its annual inspection. The motor operated valve did not open when operated from the control room and could not be manually opened locally. Shutdown was required by Technical Specification paragraph 3.5.F. An

" Unusual Event" was declared on August 12, 1985, and terminated on August 13, 1985, with the unit in cold shutdown. MO-2-10-154A was repaired and the E-3 diesel generator returned to service prior to startup on August 15, 198 On August 19, 1985, with Unit 2 at 100% power

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and with the E-2 diesel generator out of service for its annual inspection, the M0-2-10-154A valve again failed to open during testing and a controlled shutdown was initiated. An Unusual Event was declared on August 19, 1985, and terminated on August 20, 1985, with the unit in cold shutdown. Discussion of the problem with the M0-2-10-154A valve is in detail 4.2.6 of this repor After repair of the MO-2-10-154A valve and the return of the E-2 diesel generator to service, the unit was restarted on August 26, 1985. Within the scope of the review of the unit shutdowns, no unacceptable conditions were identifie . Unit 2 Scram when Placing Pressure Transmitter In Service Unit 2 scrammed at 12:14 a.m. on August 26, 1985, while a pressure transmitter was being valved into service. The scram occurred during the Unit 2 startup with the reactor critical in the intermediate range at 600 psig. The etartup began at 5:05 p.m. on August 25, 1985, after the E-2 diesel generator and RHR valve M0-2-10-154A were repaired and tested satisfactorily (see detail 4.2.3). The pressure transmitter, PT-6-53B, used for indication and feedwater control, caused an instrument line pressure transient. This pressure transmitter shares a common reactor vessel tap with lesel switches LS-101C and D. The pressure transient in the common tap therefore affected both of the level switches and resulted in a spurious full scram from low reactor water level. All systems responded normally during the scram transient. The licensee declared an Unusual Event and made an ENS call in accordance with 10 CFR 50.7 The resultant scram, and group II and III primary containment isolations were reset. The licensee commenced a reactor startup, and the reactor was critical at 4:14 a.m. on August 26, 1985. The inspector reviewed the completed GP-18, " Scram Review Procedure" for the event, reviewed control room logs and traces, reviewed the computer sequence of events and post trip logs, and dis-cussed the event with the licensee. The licensee will submit an LER for this event. No unacceptable conditions were identifie .2.5 Unusual Event Due To Inoperable Unit 2 CAD The licensee declared an Unusual Event at 12:05 p.m. on September 6, 1985, due to failure to meet Technical Specification 3.7.A.6.C limiting condition for operation regarding the Containment Atmosphere Dilution (CAD) system hydrogen and oxygen analyzers. With Unit 2 at 100% power,

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the licensee initiated a shutdown and made a one hour report to the NRC in accordance with 10 CFR 50.72. The Torus CAD hydrogen analyzer 2A was declared inoperable due to inability of the system to pass adequate flo The Torus CAD hydrogen analyzer 20 was declared inoperable due to inability to adequately calibrate. The licensee repaired the 2A CAD hydrogen analyzer by cleaning the rotometer, performed a calibration and returned it to service. The Unusual Event was terminated at 12:50 p.m. on September 6, 1985, with Unit 2 at 96% power. The 2D CAD hydrogen analyzer remained inoperable and out of service at the time the Unusual Event was terminate The inspector reviewed the control room logs to verify that a controlled shutdown had commenced. The ENS call was monitored at the resident office. The inspector reviewed the completed calibration surveillance on the repaired 2A CAD analyzer, ST 9.19, CAD 0xygen and Hydrogen Analyzer Calibration, Revision 10, performed on September 6, 198 The 2D CAD analyzer was repaired and calibrated satisfactorily on September 10, 1985, and returned to service. The inspector also reviewed the completed procedure ST 9.19 performed on the 20 CAD analyzer on September 10, 198 Within the scope of this review, no unacceptable conditions were identifie . Failure of the Unit 2 "A" Loop RHR Injection Valve MO-2-10-154A Background On June 1, 1985, RHR system outboard injection valve, M0-2-10-154A failed to open upon signal from the control room during Unit 2 hydrostatic testing. MO-2-10-154A is a normally open valve, however it is closed during surveillance testing of valve M0-2-10-26A. During remote operation of the M0-2-10-154A valve, a system overcurrent alarm sounded. The valve is a Walworth 24 inch angle valve, model No. A-12337-M-2D. (Refer to Attachment 1 for identification of valve component parts). Upon investigation the valve disc was determined to be 1/2 inch off its seat, and the valve could not

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be opened manuall The stem yokenut was found lower than normal on the stem and the stem locknut was backed off of the yokenut. The yokenut keyway was elongated apparently due to impact of the keyway with the Limitorque operator key. The keyway engages the Limitorque operator with the locknut. The locknut top surface was deformed due to contact with the limitorque operator key. Both stem thrust bearings were misaligned with the upper bearing casing cracke A broken wire to the coil for the motor brake was found. The yokenut, locknut, brake, upper and lower thrust bearings were replaced from storeroom stoc The valve was tested and placed back in service June 6, 1985. LER 2-85-03, dated July 3,1985, describes this event.

i On August 12, 1985, the same valve, M0-2-10-154A, would not open during surveillance testing. On

. investigation, the valve was determined to be fully shut, with the yokenut 6 inches lower on the stem than normal and the locknut backed off the yokenut. The upper thrust bearing was cracked. The motor operator

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key had impacted on the bottom of the keyway and the locknut was deformed due to impact with the key. The metal discs of the motor brake were burned and warpe s The locknut and upper and icwer bearings were replaced

+ s' from storeroom stock, and the brake rebuilt with parts from the June 1, 1985, valve failur The valve was tested and placed back into service on August 15, 198 On August 19, 1985, valve M0-2-10-154A again would not open during surveillance testing. On investigation, the valve was found to be fully shut, with the yokenut about 8 inches lower on the stem than normal with the locknut off the yokenut. The yokenut external threads were damaged with horizontal and vertical grooves cut into the threads by the 2 setscrews which are drilled and tapped through the locknut and counterbored into the yokenut to prevent the locknut from backing off the yokenut. The locknut was deformed from impact contact with the Limitorque operator key. The upper thrust bearing was cracked. The wire to the coil of the motor brake had insulation worn off, and another motor wire was broken during disassembly. The yokenut and upper and lower bearings were replaced from storeroom stock. A new locknut and Limitorque operator key were machined by the licensee. The coil assembly for the motor brake was replaced. The valve was tested and placed back in service on August 26, 198 .

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12 Initial NRC Review s

The inspector reviewed the licensee repair and maintenance procedures used for this valve and its Limitorque operator, model No. SMB5T-350, (procedures M-9.1, M-9.3, and M-10.3). No references or documenteJ procedures were found for disassembly and repair specifically for the valve stem engagement area. A cut away view of the entire valve was found on micro film print 6280-M-1028-5 The inspector made a visual inspection of the Unit 3 RHR injection valve M0-3-10-154A since Unit 2 was operating and the torus room was inaccessible. The Unit 3 valve is identical to the Unit 2 valv The valve yokenut appeared larger than the standard Limitorque stem engagement assembly described in site procedures and LER 2-85-03. A review of maintenance history for this valve indicated that no similar failures were identified for the Unit 3 M0-154 valve Similar locknut to yokenut disengagement was found to have occurred on valve M0-2-10-1548 in 1973 and 1976 (as per MRF's B-73-293 and 10-M-76-1).

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Based on discussions with PECo Maintenance personnel, it was determined that between 7:00 p.m. and 11:00 p.m. on June 3, 1985, Maintenance Division personnel removed the Limitorque body from the valve and visually inspected the Limitorque drive gear assembl No further investigation was made of the Limitorque internal The inspector reviewed the licensee's February 1, 1985, response to the Salem ATWS Event Generic Letter 83-28. This response detailed the licensee's progress toward ensuring that maintenance procedures are updated to reflect the latest vendor information. The licensee's response states that maintenance procedure M-10.3, RHR Valve M0-154 Repair, would be reviewed and revised as necessary by August 1,198 C. Licensee and NRC Meeting At the request of the NRC, a meeting was convened on August 30, 1985, with the-following personnel in attendance:

PECo R. S. Fleischmann, Manager, PBAPS W. T. Ullrich, PECo Superintendent, Nuclear Gen. Di C

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J. E. Winzenried, Superintendent, Plant Services A. A. Fulvio, PECo Technical Engineer J. Davenport, PECo Supervisor Engineer, Maintenance H. Abendroth, Atlantic Electric J. Rogenmuser, PECo Engineer C. Kranich, PECo Maintenance W. Pinner, PECo Maintenance N. Alexakos, PECo Maintenance NRC RT Gallo, Chief, Reactor Projects Section 2A, Division of Reactor Projects Region I H. Gregg, Lead Reactor Engineer, Materials and Processes Section, Engineering Branch, Division of Reactor Safety, Region I T. Johnson, NRC, Senior Resident Inspector H. Williams, NRC, Resident Inspector J. Rogers, NRC, Region I (1) Regarding the June 1, 1985 failure the licensee stated that opening valve M0-2-10-154A during a hydrostatic test with a differential pressure (dP) of up to 1000 psi across the seat was the root cause of the failure. The valve disk is rated for operation at a differential pressure of 350 psi. The valve opening occurred during a pressure vessel hydrostatic test per GP-10-2. No steps were taken to relieve the high differential pressure prior to opening the valve. During stroking of M0-2-10-154A on June 1,1985, a packing leak was detected. Investigation of the cause of the packing leak apparently led to discovery of the valve failure. The licensee stated that the hydrostatic test procedure would be revised to prevent stroking the valve under high differential pressure. This item is unresolved pending hydrostatic procedure revisio (UNR 277/85-30-01)

(2) The licensee stated that the stem engagement assembly for valves MO-10-154A and M0-10-1548 of Units 2 and 3 are Walworth Valve Company modifications of a standard Limitorque design made during the construction of Peach Botto The stem locknut is screwed onto the stem yokenut to bring the thrust bearings up into their normal position, therefore the torque requirement for the locknut is critical for proper bearing alignmen Two setscrews 90 degrees apart are used to prevent the locknut from backing off the yokenut. The yokenut housing is keyed to the circular drive gear of the Limitorque drive assembl _ . . - ._ _---_ . - , __ - _

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The licensee stated that they have no documenta- '

tion, technical manuals, or procedures specific  ;

to this Walworth modification to the standard i Limitorque desig The licensee stated that the August 12 and August 19 failures of the valve occurred at rated system pressure and temperatur (3) PECo Maintenance representatives stated that all '

three yokenuts used had different dimensions and different sized keyways. The locknut and motor key now installed on M0-2-10-154A were manufactured by PECo for closa fit to the yokenu For the August 12 failure the licensee initially estimated the yokenut to locknut thread engagement area as 33 percent. The August 19 failure had a yokenut locknut thread engagement area estimate of 56 percen The locknut from the first failure is missing preventing definitive measurements. The locknut no; n use was machined for optimum fit to a yokenut taken out of stock. As now installed, the yokenut to locknut thread engagement area is approximately 90 percent. All available replace-ment parts except for the first yokenut, which is contaminated, have been sent to the PECo Metallurgical Lab in Philadelphia for further test and evaluatio Based on the above information, the licensee believes that the poor tolerances and fit between stem engagement assembly parts caused the August 12 and August 19 failures. All parts were supplied by Walworth Valve Compan The licensee is investigating further to determine the cause of this problem and if the failed parts met original design specification The licensee agreed to provide repair and maintenance procedures to reflect the Walworth stem engagement modification for the four M0-154 valve (4) The following discrepancies were identified relative to LER 2-85-03. The LER states that the MO-2-10-154A valve has a threaded drive sleeve in the stem engagement area. Based on review of princs and visual inspection of the identical Unit 3 valve the inspector determined that no such drive sleeve exists. The first failure occurred on June 1,1985, not on June 3,1985, as stated in the LER. No determination is provided in the LER as to the cause of the valve failur _ - ___ ,_ __ - . _ _ _ _ _ _ _ _ _ . . . _ _ _

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The licensee agreed to revise LER 2-85-03 to reflect the true valve stem engagement and to provide an explanation for the cause of the June 1, 1985 valve failure. Another LER concerning the August 12 and 19, 1985, failures will be submitted by the license The licensee stated that they have not checked and would resist checking the similar M0-154 valves on Units 2 & 3 for proper stem engagement tolerances. According to the licensee, these valves are stroked 40 to 50 times per year with

. very few failure The licensee does not know why parts of the motor brake of the Limitorque for valve M0-2-10-154A failed on June 1, August 12 and August 19. Ding

, Company supplies the motor brake parts and the licensee is investigating further.

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The maintenance repair procedures for the valve stem engagement, the errors in LER 2-85-03, the inadequate Walworth replacement parts, and the failures of the limitorque motor brakes are unresolved pending further NRC review. (UNR 277/85-30-02,277/85-30-03.) Surveillance Testing The inspector reviewed ST 6.8.1 " Daily RHR 'A'

System and Unit Cooler Operability", Rev. 13, performed on July 31, August 1-3, 5, 11, 1985 and

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ST 6.8 "RHR ' A' Pump, Valve, Flow and Unit Cooler Functional," Rev. 26, performed on August 4, 1985, for trends in opening or closing times for

M0-2-10-154 No trends were observe In this review, the inspector noted that ST 6. performed August 3, 1985 and August 12 1985, recorded use of a stopwatch (53-0127) with a past due calibration date of April 17, 198 The licensee checked his records and indicated the calibration due date was April 17, 1985, however, when the inspector examined the stopwatch, it was marked as calibrated on April 17, 1985 and calibration due date April 17, 1986. The inspector discussed with the licensee the need to be aware of correct instrument calibration due dates when performing tests. ST 6.8.1 performed on August 1 and 2, 1985, recorded use of stopwatch 53-0125 with calibration due date of August 17, 1985 and August 1 and calibration due

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date of August 17, 1986 on August The licensee's records indicated a calibration due date of March 21, 1986. This stopwatch was not available for inspectio Since the stopwatch calibrations are normally for one year the recorded data is questionable. The resolution of inconsistencies in the calibration due dates and possible use of uncalibrated equipment is unresolved (UNR 277/85-30-04). The inspector reviewed MRF 2-10-M-85-06032 and MRF 2-10-M-85-06218 for work on the M0-2-10-154A valve including procedures M-9.1 and M-9.3. The inspector noted that the stroke time was measured by maintenance personnel as 23 secords to open and 24 seconds to close which appears significantly different from the stroke times measured in the control room which was typically 18 or 19 seconds. The inspector will examine the reason for this difference in a future inspection (IFI 277/85-30-05).

4.3 Logs and Records The ir.spector reviewed logs and records for accuracy, completeness, 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, Unit 2 Reactor Operator's Log, Unit 3 Reactor Operator's Log, Control Operator Log Book and STA Log Book, Night Orders, Radiation Work Permits, Locked Valve Log, Maintenance Request Forms and Ignition Source Control Checklists. Control Room logs were compared against Administrative Procedure A-7, Shift Operations. Frequent initialing of entries by licensed operatccs, shift supervision, and licensee on-site management constituted evidence of licensee review. No unacceptable conditions were identifie .4 Refueling / Outage Activities 4. Unit 3 Piping Non Destructive Examinations TFe licensee is performing inspections of the Unit 3 RHR rnd recirculation piping as required by Generic Letter 84-11 and PECo letter dated December 14, 1984, for intergranular stress corrosion cracking (IGSCC). As of September 13, 1985, 119 of 131 RHR and recirculation system welds have been inspected with 32 confirmed indication Weld overlay repair is planned or in progress on 10 welds;

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included four 24 inch RHR pipe welds, two 12 inch recircu-lation riser pipe welds and four 28 inch recirculation pipe welds. Three system welds are currently being evaluated for overlay repair and 19 welds have been accepted "as is" based on fracture mechanics analysis by the licensee. This includes the 10 recirculation system riser safe end to the thermal sleeve welds (N-2 nozzles).

The inspector attended a meeting among the NRC (NRR), the licensee and General Electric to discuss the status of the IGSCC pipe inspections, crack indications, and repair disposition The licensee will submit to the NRC a report of all IGSCC findings, crack dispositions and related analyses. NRC Region I Inspection 278/85-14 further discusses the Unit 3 inspections and result .4.2 Unit 3 Fuel Sipping, Inspection and Reconstitution 4.4. Unit 3 shut down for the refueling / outage with high off gas activity indicative of possible fuel rod leaks. The off gas activity was withi Technical Specification and off-site dose calculation manual limits. The licensee performed fuel sipping on all of the fuel bundles unloaded from the core. Fuel sipping is the process utilized to detect fuel leak The fuel bundles examined are designated reload 3, 4 or 5. Reload 3 fuel bundles have been utilized for 3 cycles and therefore will not be reloaded into the cor Reload 4 and 5 fuel bundles will be utilized in the core reload for Unit 3, Cycle Fuel bundle sipping resulted in the following results: 40 leaking bundles were identified from reload 3, 3 leaking bundles from reload 4, and no leaking bundles from reload 5. The 3 leaking reload 4 bundles will not be reloaded into the Cor .4. The licensee performed fuel inspections resulting in confirmed crud induced localized corrosion (CILC) on 101 of the reload 4 bundle These fuel inspections included detailed fuel pin inspections by a remote underwater camera. The licensee is currently reconstituting these 101 reload 4 fuel bundles. The reconstitution includes bundle channel and upper tie plate disassembly, fuel pin exchanges from uncorroded reload 3 bundles, and bundle reassembly. NRC Inspection 278/85-32 reviews this fuel reconstitution program.

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4.4. The inspector reviewed the fuel sipping, inspection and reconstitution activities on August 20, 29 and September 4, 198 The following procedures were reviewed:

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FH-GE-7, Fuel Sipping and Pin Inspection, Revision 0, 8/1/85

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FH-26, Sipping, Revision 3, 1/10/84

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FH-59, Fuel Assembly Rechanneling, Revision 1, 11/29/84

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FH-61, Fuel Bundle Upper Tie Plate Removal / Replacement & Individual Rod Handling, Revision 0, 11/29/84

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FH-6C, Fuel Movement and Core Alteration Procedure During a Fuel Handling Outage, Revision 17, 10-24-84

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FH-6C Appendix 1, Core Component Transfer Authorization Sheet, Revision 10, 8/30/8 Within the scope of this review, no unacceptable conditions were identifie .4.3 Unit 3 Drywell Inspection The inspector performed tours of the Unit 3 Drywell on August 27, September 4, and September 11, 198 Items monitored included overall cleanliness and housekeeping, work in progress, radiological controls, equipment conditions and preservation, access control, and overall drywell safet The inspector noted an improvement in drywell cleanliness from the August 27, 1985 to the September 11, 1985 inspectio .4.4 Unit 3 Core Spray Sparger Cracks During the in-vessel remote visual inspection of the core spray piping on August 25, 1985, crack indications were observed. Thru-wall cracks were confirmed to exist by a bubble test. The cracks are located on the pipe side of the pipe to "T-box" junction box weld in the annulus area between the vessel wall and outside the core shroud area during the week of September 1,1985. The licensee intends to conduct in-vessel repairs by draining the reactor vessel,

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weld the pipe and install supports welded to the pipe to prevent pipe and junction box separatio The inspector discussed these cracks with the licensee and the scope of the proposed repairs. The inspector will follow the licensee repair activities. (IFI 278/85-27-01)

4. Unit 3 Fuel Bundle Isolated from a Source Range Monitor (SRM)

During the off-loading of the Unit 3 reactor core, a peripheral fuel bundle was isolated from an SRM. The fuel bundle had been omitted in a temporary change to the fuel handling sequence which was being used to off-load the core. The procedure change had been made to allow continued fuel moves with one inoperable SRM in a quadrant of the core. The licensee suspended fuel handling, notified the senior resident inspector, and convened a PORC meeting to evaluate the condition. Another temporary procedure change was implemented to allow the peripheral fuel bundle to be moved to the spent fuel poo After the bundle was moved, further fuel handling was suspended pending a complete review of the cause of the event and the remainder of the fuel handling sequenc .5 Engineered Safeguard Feature System Walkdown The inspector performed a detailed walkdown of portions of the standby liquid control (SBLC) system on July 30, 1985, in order to independently verify the operability of the Unit 2 SBLC system. The system walkdown included verifications of the following items:

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Inspection of system equipment conditions, including housekeeping around the SBLC syste Confirmation that the equipment was consistent with plant drawing (M-358).

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Verification that system valves, breakers, and switches were properly aligne Verification that instrumentation is properly valved in and operabl Verification that valves required to be locked have appropriate locking devices

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Verification that control room switches, indicatices and controls are satisfactor Verification that tank poison levels were within specificatio No unacceptable conditions were identifie .6 Unit 2 Reactor Recirculation Pump Trip Test The licensee conducted a reactor recirculation pump 2A trip test on August 29, 1985. The test was performed in accordance with test procedure MAT-1278-PB2-63, Recirculation Pump Trips at 100% Core Thermal Power, Revision 0. The inspector observed the test from the control room. The pump was tripped from full power at 11:20 Prior to the test initiation, the inspector performed the following:

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Reviewed test procedure MAT-1278-PB2-63, Rev. 0

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Reviewed procedure OT-112, Recirculation Pump Trip, Rev. 0

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Reviewed procedure S.2.3.1.A, Start of a Recirculation Pump, Rev. 6

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Verified test prerequisites and plant conditions were met

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Verified data collection equipment and data recorders were in place

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Verified test personnel and operators were knowledgeable of the test and related implementing procedures The test was initiated by opening the reactor recirculation pump 2A MG set drive motor breaker from the control room. The inspector observed the plant transient on the control room panel recorders, indications, computer data logs and sequence of events, and observed operator actions. Operator recovery actions were in accordance with the test procedure MAT-1278-PB2-63, OT-112 and S.2.3.1.A as verified by the inspector. The inspector observed the recirculation pump restart and independently verified that the differential temperature requirements of Technical Specification 3.6.A.4 were adhered t Upon completion of the test, the inspector reviewed the test procedure to verify that the test was properly completed, that test results were reviewed as required and that test acceptance criteria were me Within the scope of this review, no unacceptable conditions were identifie . . . _ . _ _ . _ . .. ., ._

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5. Status of Peach Bottom Order Modifying License dated June 18, 1984 5.1 Background PECo was issued an order modifying license dated June 18, 1984, requiring the licensee to submit and implement a plan for an appraisal of: (1) the process for performing safety evaluations and reviews of_ procedures pursuant to 10 CFR 50.59 to determine if the process is currently effective, or if improvements are needed; (2)

plant and system operating procedur.es to verify that existing 1 procedures are consistent with Technical Specification bases, and those sections of the FSAR concerning systems necessary to mitigate Design Basis Accidents, and do not involve unreviewed safety questions; and (3) the program for ensuring that employees involved in the review and approval of operating procedures remain cognizant of the licensing base .2 Status of PECo Actions A meeting-was held on August 1, 1985, in the NRC Region I office to discuss the status of the PECo appraisal plans and corrective actions taken in response to the above referenced orde The following personnel were in attendance:

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NRC T. E. Murley, Regional Administrator R. W. Starostecki, Director, DRP

, S. J. Collins, Chief, PB#2 R' M. Gallo, Chief, RPS #2A

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T. P. Johnson, SRI J. E. Beall, Project Engineer J. R. Johnson, Chief, OPS D. J. Holody, Enforcement Specialist PECo W. T. Ullrich, Superintendent, Nuclear Generation R. S. Fleischmann, Manager, PBAPS G. A. Hunger, Nuclear Safety Section W. C. Birely, Senior Licensing Engineer M. B. Ryan, QA Engineer .

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, The licensee has completed the appraisals and has submitted reports 1

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associated with appraisals (1) and (3) above. Appraisal (2) will be completed by an independent contractor during September, 1985, with a final licensee report expected during December, 1985. Upon licensee submittal o.f.the final report, the NRC will review'the completion of the requir4d actions of the orde >

' ' ' ' 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 t description and corrective action adequacy. The inspector determined l , whether further information was required, whether generic implications were indicated, and whether the event warranted on-site followup. The following LERs were reviewed:

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LER Date Event Date Subject -

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3-85-11 Degraded Fire Barrier

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7-22-85

'6-21-85

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3-85-11 Rev. 1 Degraded Fire Barrier

, 8-5-85 6-21-85 .

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3-85-13 Crack Indications in RHR Pipe Welds 8-22-85 _

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7-26-85

"' ' *2-8'5-04 RPS and ESF Actuations On Reactor Low Level While 7-22-85 ,

Returning An Instrument To Service and Backfilling 6-22-85

i 2-85-05- Inoperable IRM Detectors 7-17-85 -

6-12-85 ..

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• 2 285-06 ~ ' Inadvertent Scram On High Neutron Flux with Unit in

,7-26-85 Cold Shutdown 276-27-85

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• 2-85-07 RPS and ESF Actuation On Reactor Low Level Signal 7-31-85 During Instrument Backfilling ,

6-28-85 2-85-08 Inoperable Fire Barrier Penetrations 8-22-85 7-25-85

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Il~ *2-85-09 RPS and ESF Actuation On Reactor Low Level Signal

7-31-85 During Instrument Backfilling 6-29-85

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• 2-85-10 ECCS and DG Initiation On Reactor Low Level Signal

< 7-31-85 During Instrument Backfilling 6-29-85

• 2-85-11 RPS and ESF Actuation During Turbine Testing

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9-3-85 8-5-85 V' 6.2 On-Site-Foilowup For LERs 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

p operations 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 _6. .LERs 2 8.5-04, 06, 07, 09, and 10 all concern reactor (,

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scrams and ESF actuations while the Unit 2 reactor was in

, -i ~ cold shutdown with instrument line backfilling in progres / These events were reviewed in detail 4.2.2 of Inspection 277/85-25 and 278/85-21. No discrepancies were identified relative to these 5 LER ' 6.2.2'

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LER 2-85-11 concerns a scram on Unit 2 during turbine control valve testin Refer to detail 4.2.1 of this report for event followup. No inadequacies were identified relative to this LE . Surveillance Testing 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

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being'used, redundant systems or components were available for service as required, test instrumentation was calibrated, work was performed by

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qualified personnel, and test acceptance criteria were me Parts of the following tests were observed:

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ST 6.8.1, Revision 14, Daily RHR System A and Unit Cooler

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Operability, performed on 9/3/85 on Unit ~

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ST 6.9.1, Revision 16, Daily RHR System B and Unit Cooler Operability, performed on 9/3/85 on Unit p

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ST 6.10-2, Revision 4, HPSW Pump and Valve Operability and Flow Rate Test - Unit 2, performed on 9/3/85

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ST 3.4.1, Revision 19, LPRM Gain Calibration and OD-1, performed on 8/27 and 28/85 on Unit No inadequacies were identifie . Maintenance 8.1 For the following maintenance activities the inspector spot-checked administrative controls, reviewed documentation, and observed portions of the actual maintenance:

Maintenance Procedure /

Document Equipment Date Observed M-52.1, Rev. 5 Diesel Generator 9-4-85 M-52.2, Rev. 17 Diesel Engine 9-4-85 M-3.4, Rev. 12 CRD Repair 8-26-85 M-3.1, Rev. 18 CRD Replacement 8-26-85 Administrative controls checked included maintenance requests, blocking permits, fire watches and ignition source controls, item handling reports, and shift turnover information. Documents reviewed included procedures, material certifications and receipt inspections, welder qualifications and weld information data sheets. No unacceptable conditions were identifie .2 On August 15, 1985, the inspector observed the conduct of the Control Rod Drive (CRD) training in preparation for the CRD exchange wor The licensee has a CRD mechanism for workers to practice disassembling and reassembling. In addition, there is an on-site-mock up of the under the reactor vessel CRD, including CRD Housing, CRD, position indication probe and shield cans. Students were instructed on and practiced the under vessel work. Maintenance i procedures M-3.1, " Control Rod Drive Replacement" and M-3.4 " Control Rod Drive Repair" and a diagram of the CRD were available for use by the students. The class was informal, with emphasis on hands-on practice. QC hold points were noted while reassembling the CRD. The inspector noted that some of the students had worked on the Unit 2 CRD exchange earlier this year. The licensee indicated that approxi-mately 7D% of the contractor workers had worked on the Unit 2 jo Inspection Report 277/85-12 discusses an inspection of the Unit 2 CRD exchange, t

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Within the scope of this inspection, no unacceptable conditions were identifie .3 'On July 30, 1985, the inspector examined corrective maintenance on the E-1 diesel generator (DG) involving cutting off the interpolar connecting bars on the generator. This corrective maintenance was the result of a problem identified at Calvert Cliffs Nuclear Station Unit 1. The inspector noted that licensee QC personnel were inspecting the on going work and procedures for the job were available and being followed including equipment tag out or blocking procedures. The inspector observed that care was being taken to prevent the metal filings from getting into the generato Housekeeping was goo The inspector verified that the licensee proved operability of the remaining diesel generators and low pressure emergency core cooling systems daily while the diesel was out of service as required by Technical Specification paragraph 3. and 3.9.B.3. The E-1 diesel generator was taken out of service at 8:10 p.m. on July 28, 1985 and returned to service at 2:50 p.m. on August 4, after proper testing (ST 8.1.3, ST 8.1.6). No unacceptable conditions were note . 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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Adherence to Radiation Work Permit (RWP) requirements

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Surveys

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Handling of potentially contaminated equipment and materials The inspector observed individuals frisking in accordance with Health Physics procedures. Selected high radiation doors were verified to be locked as required. Compliance with RWP requirements was verified during each tour. RWP line entries were reviewed to verify that personnel had provided tne required information and people working in RWP areas were observed to be meeting the applicable requirements. No unacceptable conditions were identifie F

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1 Physical Security The inspector monitored security activities 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 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 procedures. No inadequacies were identifie . In-Office Review of Public and Special Reports The inspector reviewed the following:

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Supplemental Reload Licensing Submittal for Peach Bottom Unit 2, Reload 5, June, 1984

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Supplemental Reload Licensing Submittal for Peach Bottom Unit 3, Reload 6, March, 1985 No inadequacies were identifie . Unresolved Items Unresolved items are items about which more information is required to ascertain whether they are acceptable violations or deviation Unresolved items are discussed in Detail 4. . Inspector Follow Items Inspector follow items are items for which the current inspection findings are acceptable, but due to on going licensee work or special inspector interest in an area, are specifically noted for future follow-u Follow-up is at the discretion of the inspector and regional management. An inspector follow item is discussed in Detail 4. . Management Meetings 14.1 Preliminary Inspection Findings A verbal summary of preliminary findings was provided to the 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 inspection. No proprietary information is included in this repor f

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

Inspection Reportir.,

Date Subject Report N Irspector July 29 (Ent) Transportation 277/85-31 Bicehouse August 1 (Exit) 278/85-28

' August 5 (Ent) -Security 277/85-32 Bailey August 9 (Exit) 278/85-29 August 12 (Ent) Maintenance 277/85-33 Chung August 16 (Exit) 278/85-30 August 12 (Ent) Allegation 278/85-31 Kottan August 17 (Exit) Follow Up August 12 (Ent) ISI 277/85-34 Gray August 16 (Exit)

14.3 Attendance at Other Management Meetings Date Subject August 1, 1985 NRC:RI/PECo meeting to discuss the status of the June 18, 1984 Order Modifying License (see detail 5 of this report)

August 30, 1985 NRC:RI/PECo meeting to discuss the RHR motor operated MO-2-10-154A valve (see detail 4.2.6 of this report)

September 5, 1985 NRC:NRR/PECo meeting to discuss the status of Unit IGSCC indications and resolutions (see detail 4.4.1 of this report)

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