IR 05000277/1987010

Insp Repts 50-277/87-10 & 50-278/87-10 on 870324-0409. Violation Noted:Failure to Follow Shutdown Cooling Procedure.Unresolved Items Noted W/Operator Watch Standing Practices

ML20213G301
Person / Time
Site:	Peach Bottom
Issue date:	05/03/1987
From:	Williams J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20213G277	List: IR 05000277/1987010 ML20213G274 ML20213G293
References
50-277-87-10, 50-278-87-10, NUDOCS 8705180224
Download: ML20213G301 (29)

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REGION I

Report No. 50-277/87-10 & 50-278/87-10 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

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Inspection At: Delta, Pennsylvania Inspection Conducted: March 24, 1987 to April 9, 1987 Inspectors: T. P. Johnson, Senior Resident Inspector, Peach Bottom o C. C. Warren, Senior Resident Inspector, Shoreham M. G. Evans, Reactor Engineer, DRS L. E. Briggs, Lead Reactor Engineer, DRS R. J. Urban, Resident Inspector, Peach Bottom B. M. Hillman, Reactor Engineer L. L..Scholl, Reactor Engineer J. F. Wechselberger, Resident Inspector, Oyster Creek D. K. Allsopp, Resident Inspector, Hope Creek S. V. Pu11ani,'. Fire Protection Engineer, DRS L. J. Wink, Rea'ctor Engineer, DRS D. J. 'Florek, Lead. Reactor Engineer, DRS

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J. A. Prel1, Reactor Engineer, DRS

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', F. J. Crescenzo, Reactor Engi,neer Examiner Reviewed By: N!87 J. H. WilliQm), Project Engineer date

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Projects Section 2A Reviewed By: i C. J. Cowgi%Q Acting Chief, Reactor date Projects Section 2A '

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Approved By: /F14"'_ f 3 7 W. MaIlo, Chi f ' ~

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, actor Project ranch 2, Division of Reactor Projects c

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8705180224 870512 U

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PDR ADOCK 050002775 G PDR g

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b.S.NUCLEARREGULATORYCOMMISSION

REGION I

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Report No. 50-277/87-10 & 50-278/87-10 Docket No. 50-277 & 50-278 i 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: March 24, 1987 to April 9, 1987 Inspectors: T. P. Johnson, Senior Resident Inspector, Peach Bottom C. C. Warren, Senior Resident Inspector, Shoreham M. G. Evans, Reacto* Engineer, DRS L. E. Briggs, Lead deactor Engineer, DRS R. J. Urban, Resident Inspector, Peach Bottom B. M. Hillman, Reactor Engineer L. L. Scholl, Reactor Engineer J. F. Wechselberger, Resident Inspector, Oyster Creek D. K. Allsopp, Resident Inspector, Hope Creek S. V. Pullani, Fire Protection Engineer, DRS L. J. Wink, Reactor Engineer, DRS D. J. Florek, Lead Reactor Engineer, DRS J. A. Prell, Reactor Engineer, DRS F. J. Crescenzo, Reactor Engineer Examiner Reviewed By:

J. H. Williams, Project Engineer date Projects Section 2A Reviewed By:

C. J. Cowgill, Acting Chief, Reactor date Projects Section 2A

' Approved By:

R. W. Gallo, Chief, date Reactor Projects Branch 2, Division of Reactor Projects

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I Inspection Summary: Sustained and continuous control room and plant observa-tions from March 24 to April 2, 1987. Periodic control room and plant observa-tions from April 2 to April 9, 198 Followup on Unit 3 scrams on March 17 and 25, 1987; EHC troubleshooting activities; Unit 3 startup, power ascension and testing activities. Observations of selected surveillances. Review of Unit 2 refueling activitie (Five hundred and thirty total hours (Unit 2 and 3))

Results: One violation (section 8.4) for failure to follow shutdown cooling procedure. Observations of -control room operators' attentiveness led to unresolved items associated with operator watch standing practice (Sections 4.3, 4.4 and 8.1)

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DETAILS Background On March 17, 1987, Unit 3 auto scrammed from APRM high-high flux caused by pressure spikes due_to turbine control valve fluctuations. The root cause of the EHC malfunction was not known, so the licensee remained shutdown for four days to troubleshoot the EHC system. When no problems were found in the EHC system while in a cold static condition, the licensee restarted Unit 3, with NRC Region I concurrence, to troubleshoot the EHC system while in a hot dynamic conditio On March 21, 1987, when Unit 3 reached approximately 2% power, the licensee noted similar EHC system fluctuations that had caused the scram on March 17, 1987. By March 24, 1987, the licensee had still not identified the root cause of the scram. Also, on this same day, NRC Region I received information that control room operators at Peach Bottom had been observed. sleeping while on duty in the control room and were otherwise inattentive to their license obligations. At this point, NRC Region I management determined that sustained control room and plant observation was needed while pursuing substantiation of the informatie On March 24, 1987, Region I institutea around-the-clock coverage of

' licensee activitie The inspection objective was to provide regional management an opportunity to evaluate the licensee's control room an plant oerformance over a sustained period. Of specific concern were licensed operator activities and EHC system troubleshooting. On March 31, 1987 NRC ordered Philadelphia Electric to shutdown Unit 3 and proceed to cold condition. This was completed at 2335 on March 3 Around-the-clock coverage was suspended on April 2, 1987, at the end of the afternoon shift (3:00 p.m. to 11:00 p.m.). Inspection Methodology and Process The inspection began on March 24, 1987, with a continuous review of plant activities by one to three region based or resident inspectors on a three shift rotation (7:00 a.m. to 3:00 p.m.; 3:00 p.m. to 11:00 p.m.;

11:00 p.m. to 7:00 a.m.). Normal resident inspection coverage resumed on April 3, 1987, with additional hours devoted to backshift and weekend tours by the residents and a region based inspecto Areas inspected during this period included NRC licensed operator shift activities, including surveillance test observations and Unit 2 refueling operations, quality assurance / quality control coverage of control room act.ivities, EHC system troubleshooting, plant events that occurred during the inspection period, and LER cause analysi The inspectors used the following criteria during their reviews:

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Operators are attentive and responsive to plant parameters and condition Plant evolutions and testing are planned and properly authorize Procedures are used and followed as required by plant polic Equipment status changes are appropriately documented and communicated to appropriate shift personne The operating conditions of plant equipment are effectively monitored, and appropriate corrective action is initiated when require Backup instrumentation, measurements, and readings are used as appropriate when normal instrumentation is found to be defective or out of toleranc Logkeeping is timely, accurate, and adequately reflects plant activities and statu Operators follow good operating practices in conducting plant operation The inspection findings are discussed in the following paragraph . Persons Contacted

• J. B. Cotton, Superintendent Plant Services

• A. B. Donnell, Site QA Supervisor

• R. S. Fleischmann, Manager, Peach Bottom Atomic Power Station A. A. Fulvio, Technical Engineer J.-A. Jordan, Results Engineer A. E. Hilsmeier, Senior Health Physicist J. F. Mitman, Radwaste Engineer D. L. Oltmans, Senior Chemist

• K. N.-Mandl, QA Corporate Supervisor J. P. McElwain, Site QC Supervisor

• F. W. Polaski, Operations Engineer S. R. Roberts, Operations Engineer

• 0. C. Smith, Superintendent Operations J. E. Winzenried, Staff Engineer Other licensee employees and licensed operators were also contacte *Present at exit interview on site for summation of preliminary findings.

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'4 Shift 0perations Review an'd Observations

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4.1 Routine Observations The inspectors observed plant operations during tours each shif The following areas were inspected:

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Control Room (essentially full time for certain periods as previously noted)

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Cable Spreading Room

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Switchgear and Battery Rooms

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Reactor Buildings

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Turbine Buildings

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Radwaste Building

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Recombiner 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 4. Control Room and facility shift staffing was frequently checked for compliance with 10 CFR 50.54 and Technical Specifications. Presence of a senior licensed operator in the control room was verified during each visit to the Control Room. (See Section 4.3 for details.)

4. The inspectors frequently observed that selected control room instrumentation indicated values that were within Technical Specification requirements and normal operating l imi t's . ECCS switch positioning and valve lineups were verified based on control room indicators and plant obser-vations. Observations included flow setpoints, breaker positioning, PCIS. status, and radiation monitoring in-strument . 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. In addition, the applicable alarm cards were checked for accuracy. The operators were knowledgeable of alarm status and plant condition . The inspectors checked for fluid leaks by observing sump status, alarms, and pump-out rates; reactor coolant system leakage was discussed with licensee personnel.

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4. Shift relief and turnover activities were monitored each shift while on continuous control room coverage, and periodically thereafter, to ensure compliance with administrative procedures and regulatory guidanc .1. 6 ~ The inspectors observed the main stack and both reactor building 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 occurre . The inspectors observed control room indications of fire detection instrumentation and fire suppression cystems, monitored use of fire watches and ignition source controls, checked a sampling of fire barriers for >

-integrity, and observed fire-fighting equipment station . The inspectors. observed overall facility housekeeping conditions, including control of combustibles, loose trash and debris. Cleanup was spot-checked during and after maintenanc Plant housekeeping was generally acceptabl . The inspectors observed the nuclear instrumentation subsystems-(source range, intermediate range and power range monitors) and the reactor protection system to verify that the required channels were operabl .1.10 The inspectors frequently verified that the required off-site electrical power startup sources and emergency on-site diesel generators were operable. A loss of #3 startup source occurred on April 7, 1987 (see section 11.5).

4.1.11 The inspectors 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 pcsitionin 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 identifie _ . . _ . , . _ _

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4.2 Logs and Records The' inspectors reviewed logs and records for accuracy, completeness, abnormal conditions, significant operating changes and trends, required entries, operating and night order propriety, correct equip-ment 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 Logs, 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, Temporary Circuit Modification Log, and Ignition Source Control Checklists. Control Room logs were compared against Administrative Procedure A-7, Shift Operations. Frequent initialing of entries by licensed operators, shift supervision, and licensee on-site management constituted evidence of licensee review. No unacceptable conditions were identifie .3 Operator Alertness The on-shift inspectors observed control room demeanor, operator alertness and attentiveness, and compliance with other requirements for operator performance as stated in section 4.4 of this report. The inspectors did not observe any licensed operators sleeping while on dut No observations of operators reading non job-related material occurred. The inspectors did not observe any non job-related reading material in the control roo Operators were alert and generally attentive to duties. However, the following observations were made by shift inspectors regarding operator watchstanding practices:

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Several instances of coffee cups and soda cans sitting on various control panels were note At times, the reactor operators were observed with their feet up on the computer console and leaning back in their chair, giving a perception of inattentio On March 27, 1987, at approximately 5:30 p.m., when the chief operator selected shell warming, he did not notice the position of the Unit 3 Number 3 turbine control valve (TCV). System procedure S.6.3.1.A, " Main Turbine Generator Start-Up", Rev. 19, requires the operator to check that the TCVs are fully open. On March 27, 1987, at approximately 2:30 a.m., the shift superin-tendent and supervisor noticed that the Number 3 TCV was close The test engineer responsible for EHC troubleshooting stated that the EHC system had not been touched for several days. He also stated that the logic card for the Number 3 TCV was pro-bably damaged two days earlier during troubleshootin __ _ _ , _ _ _ __ _ _ _ _ _ _ . . _ _ , . .

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On Unit 3 at 10:00 p.m. on March 30, 1987, average power range monitor (APRM) "E" remained bypassed unnecessarily for about 30 minutes after the reactor engineer completed troubleshooting a failed LPRM. APRM "E" was subsequently re-turned to service. Technical Specifications Table 3. require at least two operable APRMs per RPS channel. The inspector verified that APRMs "A" and "C" were operabl During the 11:00 p.m. to 7:00 a.m. shift on March 31 - April-1, 1987, the Unit 3 RHR pump 3B failed to start after two attempts when initiating the RHR shutdown cooling mod After troubleshooting, the on-shift operators determined that the cause for failure to start was that the equivalent Unit 2 RHR pump (28) was in service in the shutdown cooling mode. The two RHR pumps (28 and 38) powered from the same diesel generator are interlocked so that only one may be run at a time. Ap-parently, neither the Unit 3 reactor operator nor the control room shift supervisor realized this fac Failure to follow the shutdown cooling operating procedure on March 31, 1987, resulted in a group IIB primary containment isolation on Unit 3. This is an apparent violation. (See Section 10.4).

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On March 27, 1987 between 4 and 5 p.m., a senior licensed individual not on the shift watch list was observed operating equipment on the Unit 3 cormole. The individual did not appear to be under the supervision of tne assigned ifcensed operato These above items except for the apparent violation are collectively grouped as an unresolved item (UNR/277/87-10-01; 278/87-10-01)

4.4. Administrative Requirements for the Performance of NRC-Licensed Individuals While on Duty The requirements and guidelines for the on duty performance of NRC licensed individuals is addressed in the following documents:

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10 CFR 50.54 k, m and 10 CFR 55

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IE Circular 81-02

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IE Information Notice 85-53

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IE Information Notice 79-20, Revision 1

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NRC Regulatory Guide 1.114

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The licensee implements these items in administrative procedure A-7,

" Shift Operations", and in " Nuclear Plant Rules". The inspector reviewed these documents. The following table summarizes the licensee's implementation of these requirements and guidelines:

Item / Requirement Where Implemented Aware of and responsible for A-7, section 7. plant status Formal watch turnover and relief A-7, section 7.1.5 and Alert and attentive A-7, section 7. Remain in areas of responsibility A-7, section 7.1.5, Prohibit distractirig activities A-7, section 7. No reading that is not job A-7, section 7.18 and Nuclear related Plant Rules Control Room access limited A-7, section The inspector noted that the licensee neither administratively defines what constitutes " attention to duty" nor were the licensed control room operators able to verbally define " inattention to duty".

Appropriate procedure revisions and training upgrades to improve the knowledge and clarify the definition of attentiveness are neede This item is unresolved (UNR/277/87-10-02; 278/87-10-02). Refueling Operations 5.1 Unit 2 Core Offload Unit 2 core offload began on March 23, 198 The inspector reviewed licensee prerequisites for core offload. A review of the related refueling documentation was performed and is included in Attachment The inspectors monitored the following items associated with core offload through direct observation of fuel handling activities on the refueling floor and in the control roo 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,

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Fuel and component accountability in the spent fuel pool and I

in the reactor core, .

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Reactor mode switch locked in " refueling" position,

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

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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).

No violations were note .2 Stuck Fuel Assembly (49-40)

When attempting to remove Unit 2 fuel assembly 49-40 from the reactor core, the double blade guide appeared to be caught with the bundle. An unsuccessful attempt was made to free the bundle with special procedure SP-993. With the aid of an underwater camera, the fuel support piece was found raised out of the guide tube. Another special procedure SP-994 was used in an unsuccessful attempt to seat the raised fuel support piece. Continued efforts to seat the fuel support piece and dislodge the bundle nose piece were temporarily abandoned for engineering analysis. The offload sequence was changed to allow fuel movement to continue in parallel with resolution of this fuel assembly removal proble t-"-**P ~ H"' "" "

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The inspector. reviewed procedures SP-993 and SP-994 and discussed them with licensee engineers and operators. The inspector will continue to follow the attempts to remove and the causes for the stuck bundl 'No violations were identified'. Surveillance Testing The inspectors observed surveillance tests to verify that testing had been properly scheduled, approved by shift supervision, control room operators were knowledgeable regarding testing in progress, approved procedures were being used, redundant systems or components were available for service as required, test instrumentation was calibrated, work was performed by qualified personnel, and test acceptance criteria were met. Portions of the surveillance tests listed in Attachment 3 were observe The inspector determined that test performance and results review was good, and should be considered a licensee strengt No inadequacies were identifie . Quality Assurance / Quality Control (QA/QC)

The Peach Bottom QA Plan Volume III, Operations Phase, Revision 5, delineates the quality assurance program requirements. Section "S0",

Shift Operations states the following:

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QC for shift operations is assured by first and second line supervisor operational monitoring and review of Shift Operations is provided by the Superintendent, Operations; the Operations Engineer; and the PORC/NR QA audits and surveillances are performed by the Quality Assurance Division (QAD).

In addition to the above requirements, the licensee's on-site QC group performs monitoring and inspection of shift operations activitie Thus, the assurance of quality for shift operations is provided by reviews performed by (1) the operations line organization, (2) by the PORC and NRB oversight committees, and (3) by the independent QAD onsite QA and QC t

group The inspector reviewed the Quality Assurance Trending and Tracking System (QATTS) printout of QA and QC findings since October 1986. These findings include: QA audits, QA surveillances, QC inspections, and QC monitoring.

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The findings are categorized as either nonconformance reports (NCRs),

significant NCRs (SNCRs), recommendations, or QC detailed monitoring checklists (DMCs) reports. There were no documented negative findings with respect to control room operator alertness and attentivenes The inspector questioned the onsite QAD QA and QC site supervisors with respect to control room and licensed operator reviews, particularly during the weekends and backshift periods. The inspector could not identify any case where QA personnel monitored control room activities during the week-end or backshift periods. QC performs periodic detailed monitoring check-lists and independent verifications for I&C surveillances. QC was present in the Control Room for the Unit 3 startup during the period March 10 through 11, 1987. QC personnel provided continuous monitoring, including backshift observations. In addition, QC was present in the Control Room when performing independent verifications signoffs for surveillance test procedures, which included backshift presence (afternoon shift 3-11 p.m.)

in the Control Room on the following days (since October 1986):

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October 7, 9, 14, 16, 23, 18, 30 (1986)

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November 6, 13, 18, 20, 25, 27 (1986)

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December 2, 4, 9, 11, 16, 18, 23 (1986)

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January 6, 13, 15, 18, 20, 27, 29 (1987)

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February 3, 5, 10, 12 (1987)

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March 16, 20, 23, 25 (1987)

As previously stated no negative findings related to operator alertness were documented by QC personne No violations were note . Event Analysis 8.1 Unit 3 Scram on March 17, 1987 Unit 3 auto scrammed from 86% power at 2:54 a.m. on March 17, 1987, due to APRM high-high flux. The unit had reduced power on March 16, 1987 from 100% to 86% due to an internal leak in the C2 feedwater heater. Conditions were normal on the scram. The reactor feed pumps (RFPs) recovered the reactor water level decrease. No ECCS were initiated. A group II and III primary containment isolation occur-red, due to the reactor level decrease, which was reset. The recir-culation pumps tripped on the 13 KV non-vital bus fast transfer.

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Operators restarted both recirculation pumps. The licensee made an

'NS call and notified the Senior Resident Inspecto _

The licensee determined that the cause of the scram was APRM high-high flux caused by EHC induced turbine control valve fluctua-tions. The unit proceeded to cold shutdown to repair a leak in the C2 feedwater heater to perform other maintenance and to investigate the EHC system malfunction (see section 11.0).

The inspector arrived in the control room at about 6:00 a.m., on March 17, 1987. The unit was in hot shutdown at 400 degrees F with cooldown in progress. The inspector verified that all control rods were full in as indicated by the process computer OD-7 printout and the full core display. The inspector reviewed control room indica-tors, logs, and discussed the event with the on-shift operator Reactor water level dropped to -40 inches as indicated on water level recorders LR-110A and The RFPs recovered level within 25 second The inspector noted that several parameters and their control room strip chart recorders indicated that multiple transients had occurred during the one and a half hours prior to the automatic scram. The

"up and down" spiking (fast oscillations) were apparently caused by the EHC fluctuations. These parameters, instrument numbers and mag-nitude of oscillations are as follows:

MAGNITUDE OF OSCILLATION INSTRUMENT N INCHES  % SCALE NR-46A-F/APRM Flux 1/4" noise and 85 i 13% reactor power 1/2" oscillations FR-98/ Steam Flow 0" noise and 1 .2 x 10' lbm/hr 1/8" oscillations PR and FR-97/ Reactor 1/16" noise and (1) 11.0 0.4 x 10' lbm/hr Pressure and Turbine 1/4" oscillations (2) 980 5 psig Steam Flow POR-3660/ Turbine 0" noise and 44 1 4% open Control Valve 1/16" oscillations Position NOTE: There were also oscillations on recorder JR-3157 (Generator MWe).

Based on interviews with shift personnel, the inspector concluded that the operators had not noticed the transients (apparently caused by EHC induced turbine control valve oscillations) prior to the automatic scram. No annunciator nor alarm typer alarms were as-sociated with these recorder indications. Licensee management also noted this apparent inattention to control room indications. As a

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result, the licensee issued a memo to all control room operations personnel on March 19, 1987, reminding them of the need to periodi-cally scan all control room parameters. The specific operators involved were counselled. The issue of operator inattentiveness to instrument recorders is unresolved (UNR/277/87-10-03; 278/87-10-03).

The inspector also reviewed the control room. computer alarm typer and sequence of events log, the draft Upset Report, GP-18 (Scram Review Procedure), and attended PORC meetings on March 19-20, 1987, to re-view the scram. The PORC concluded that the scram was caused by EHC induced oscillations that resulted in turbine control valves (TCVs)

cycling open then closed. On one TCV closing, a pressure spike was sufficient to cause an APRM flux spike high enough to cause a scram on high-high APRM flux. Five of the six APRMs initiated scram sig-nals. APRM Channel D, which did not trip was later tested satis-factorily by the license At the March 19 and 20, 1987, PORC meetings, Unit 3 restart and an EHC test program were approved. The test program consisted of EHC monitoring during bypass valve operation; bypass and turbine valve testing at 25% power; and, EHC monitoring during power ascensio The PORC also approved special procedure SP-991, " Response to Unit 3 Reactor Parameter Abnormalities", Rev. O. SP-991 provided operators with instructions if EHC problems reoccurre As part of the scram reduction program, the ISEG is writing an Event Report. The inspector will review the Event Report, the final Upset Report, an'd the LER, when they are issue .2 Unit 3 Scram on March 25, 1987 After a four day outage following the scram on March 17, 1987, the unit was restarted on March 21, 1987. Prior to the restart, the EHC system was tested in cold, static conditions and no abnormalities were observed. To facilitate testing of the EHC system under hot, dynamic conditions, the reactor was subsequently placed in a hot standby conditio The investigation of the EHC system malfunction continued on March 21 through 25, 1987. A special operating instruction was in place on March 21, 1987, to provide the operating staff instructions, should reactor parameter abnormalities occur similar to those experienced prior to the scram on March 17, 198 The spiking of the turbine bypass valves reappeared during the hot standby condition on March 21 through 23, 1987. In order to facilitate the EHC investigation, certain electronic circuit cards in the EHC system were pulled or replaced with similar ones from Unit 2 (see section 9 of this report, for details). With this configuration, the spiking of the bypass valves stopped at approximately 10:30 p.m., on March 23, 198 .

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However, turbine bypass valve oscillation (cycling) was observed on March 24, 1987, when the reactor pressure was increased to the normal pressure control setpoin The unit auto scrammed on low reactor water level at 4:02 a.m., on March 25, 198 Prior to the scram, the reactor was in a hot standby condition, with reactor at rated pressure and 1/4 bypass valve open (power level less than one percent). Troubleshooting was in progress on the EHC system to determine the reascn for the noted bypass valve oscillations observed on March 24, 1987. A test engineer lifted an EHC lead in the electronic circuit (see section 9 of this report, for details) causing all bypass valves to open. The resulting level swell in the reactor caused a high level trip of the C reactor feedwater pump (RFP) which was the only RFP then runnin The loss of the RFP and the blowdown due to the open bypass valves caused the reactor level to drop to about -35 inches. The unit scrammed on low reactor water level and primary containment group II and III isolations occurred at 0 inches. The operator restarted the C RFP and recovered the reactor level. No ECCS actuated and condi-tions were normal on the scram. The unit was maintained in a shut-down condition to conduct further EHC troubleshooting.

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The inspector will review the LER when it is issued. No violations were note .3 Unit 2 Primary Containment Isolation on March 28, 1987 A group IIB primary containment isolation occurred on Unit 2 while in cold shutdown at 10:20 a.m., on March 28, 1987. The isolation caused the RHR shutdown cooling suction valves M0-17 and MO-18 to close. Shutdown cooling was not in service (RHR pump was secured)

at the time of the isolatio Fuel movements were in progress on the unit. The cause of the isolation was pulling two fuses associated with the blocking for the scheduled 4160 volt E-12 bus outage. At 10:40 a.m., the licensee replaced the fuses, reopened valves MO-17 and 18, and changed the blocking to lifting leads for the E-12 bus electrical isolation. An ENS call was initiated for the required four hour notification. The unit was in day 17 of the 71 day scheduled refueling outage, with core offload about 45%

complet The inspector reviewed control room logs, the suspected licensee event report (LER), and the electrical schematic drawings. Fuses 10A-F1A and 10A-F2A were pulled as part of the blocking permit (tagout) for MRF No. 2-54L8607538. Pulling these two fuses caused relay 10A-K114A to de-energize which resulted in a group IIB primary containment isolation on 75 psig reactor pressure. This caused RHR valves MO-17 and 18 to clos .

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The inspector attributes the cause of the event to a blocking error by the licensed operator. The licensee made the required four hour ENS call, recovered the shutdown cooling capability within 20 minutes, and intends to submit an LER for the event. The LER and associated corrective actions will be reviewed in a future inspectio No violations were note .4 Unit 3 Primary Containment Isolation on March 31, 1987 A group IIB primary containment isolation. occurred on Unit 3 at '

9:25 p.m., on March 31, 1987. The operator was preparing to place shutdown cooling into service in accordance with procedure-S.3.2.C.1, " Shutdown Cooling Mode - Manual Start and Shutdown",

Rev. 17. While performing the system flush prior to starting shutdown cooling, suction valves M0-17 and 18 isolated on high reactor pressure signal (75 psig). The licensee determined that an in-rush of reactor water and subsequent flashing to steam {

caused a pressure spike and the 75 psig isolation to actuat Actual reactor pressure was approximately 45 psig. The licensee reset the isolation and established shutdown cooling by reopening valves MD-17 and 1 The inspector monitored control room operations, actions, and reviewed control room logs. The preliminary licensee event report (LER), the electrical schematic drawings, and procedu're S.3.2.C.1,

" Shutdown Cooling Mode - Manual Start and Shutdown", Rev. 17, were also reviewed. Procedure S.3.2.C.1 step #7 requires a flush of 40 inches (reactor level) through the shutdown cooling lines to the toru Valves are required to be operated in the following order:

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Close M0-13

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Open M0-18

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Open M0-17

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Open M0-15

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Open MO-39

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Jog open M0-34 The apparent reason for this order is to minimize a possible water hammer and inrush effect. The inspector noted that the operator opened M0-15 prior to opening MO-17 and 18. This apparently caused the inrush of reactor water and resulted in actuation of the 75 psig group IIB primary containment isolatio E'

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Technical Specification 6.8.1 requires that written procedures be established, implemented, and maintained per ANSI N18.7-1972 (sections 5.1 and 5.3) and per Appendix "A" of Regulatory Guide 1.33 (November 1972). Regulatory Guide 1.33, Appendix A, Section C states that procedures for the Shutdown Cooling System shall be prepared. Section 5.3.4.2 of ANSI N18.7-1972 requires procedures for shutdown including decay heat removal. Failure.to follow step Number 7 of procedure S.3.2.C.1 in the correct order is an apparent violation of TS 6.8.1 (278/87-10-04).

The licensee made the required ENS call, established shutdown cooling, and intends to submit an LER for the even The LER and associated corrective actions will be reviewed in a future inspectio .5 Loss of Number 3 Startup Offsite Power Source on April 7, 1987 At 12:18 a.m., on April 7, 1987, Peach Bottom lost the Number 3 startup (SV) source. This was apparently caused by a loss of a 220 KV transmission line in the grid, with subsequent load dispatcher switching,' causing a trip of the 220-34 line (the source of offsite power for the #3 SU). Thus, a loss of one of the two offsite power sources occurred. The E-1 diesel generator (DG) was running at the time for weekly surveillances and was carrying the E-13 bus in parallel with the #3 SU (normal power supply). When the #3 SU source tripped, the E-1 DG picked up the emergency buses that were being supplied (normally) by #3 SU. These buses included two for Unit 2 (E-22 and E-42) and two for Unit 3 (E-13 and E-33). Two of the non-vital 13 KV buses normally supplied by the 3# SU source (#2 and

1. 3 bus) were also lost. The E-1 DG was loaded to about 3500 KWe (rated for 3100 KWe) and frequency dropped to about 57-58 Hz. Since there was no loss of power on the bus no load shedding occurred which caused the diesel overload condition. (The E-1 DG was subsequently inspected with no noted problems.) The lower frequency caused the 2B RPS MG set (Unit 2) and the 3A RPS MG set (Unit 3) to trip. This resulted in a half scram on both units, a half group I isolation on both units, an outboard isolation group III on Unit 2, and an-inboard isolation group III on Unit The half scrc.u and half group I isolations did not cause any actions. The group III half (inboard or outboard) isolations caused a loss of normal reactor building ventilation and an isolation of normal containment ventilation. The standby gas treatment system (SGTS) was in service at the time, supplying ventilation for the Unit 2 refueling floor and the Unit 3 drywell. Both units were in the cold condition as required by NRC Orde No fuel movements were in progress on Unit 2 at the time. The licensee reset the group III half isolations, restored power to the non vital Number- 2 and 3 buses, and aligned the emergency buses per plant procedures (all emergency buses were swapped over to the Number

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2 SU source, and the E-2 DG was started to supply the E-22 bus). At 6:30 a.m., the Number 3 SU source was returned to service. The licensee then realigned the emergency and non-vital buses to the normal shut down lineup. The licensee determined that this event should have been reported due to the group -III half isolations. At 11:05 a.m., an ENS call was mad The inspector discussed this event with control room operators and operations engineers. The inspector reviewed control room logs, operating procedures, and electrical schematic drawings. The inspector had no further questions at this time. The LER will be reviewed in a future inspectio . Turbine Electro-Hydraulic Control (EHC) System Troubleshooting As discussed in section 8.2, the licensee, in an attempt to isolate and correct the spiking (rapid opening and closing of turbine control valves) observed on the control room recorders (section 8.1), replaced various printed circuit boards (cards) in the Unit 3 EHC system with cards from the Unit 2 EHC system. Unit 2 is currently in a refueling outage. The following is a general chronology of actions:

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March 17-20, 1987, shutdown testing of EHC did not identify any problem March 21, 1987, plant startup and heatup, dynamic testing starte Spiking of bypass valve noted which caused opening of about one second duratio March 22, 1987, various cards pulled and replaced, (no clear record of which cards) spiking remaine March 23, 1987, changed Pressure Load Gate (PLG) card, no change in oscillations noted. Noted bypass valte oscillations of about 5% one and one-half hours after PLG changed. Individually removed the "A" and "B" Steam Line Resonance Compensation (SLRC) cards, spiking remaine March 23, 1987, at approximately 10:30 p.m., the licensee replaced both the A and 8 pressure amplifier cards and the A and 8 SLRC cards with the cards from the Unit 2 EHC system at which time the spiking stoppe From the above period until approximately 10:00 p.m., on March 24, 1987, the plant was cooled down to reduce pressure to less than 600 psig to bypass the low condenser vacuum trip to allow warming of the low pressure turbine shaf _ _ - - _ - _ _ _ - -

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March 24, 1987, 10:00 p.m., number one (1) bypass valve was observed oscillating between 50 and 75 percent open with the plant at normal operating pressure. Troubleshooting was initiate March 25, 1987, 4:02 a.m., reactor scram when lead was lifted during troubleshooting. The reactor scram occurred as described in section 8.2 of this report. The lead had been lifted in accordance with procedure A-42.1, " Temporary Circuit Modifications During Troubleshooting of Plant Equipment".

Subsequent to the scram the licensee determined that all bypass valves opened when lead number TB 702-14 (Electrical Schematic M2-560 Sheet 1 -

Revision 5) was lifted because lifting the lead caused a large increase in the output of the bypass valve amplifie Following the scram the licensee decided to: (1) replace the PLG with the original card because oscillations observed on March 23, 1987, occurred after the Unit 2 card was installed. (2) Calibrate the Unit 2 cards (A that were to remain in the

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UnitB 3pressure EHC. Itamplifiers and the was originally A&B SLRC thought that the cards)' Unit 2 cards were cali-brated to the same attenuation settings as Unit 3 cards. It was later determined that Unit 3 SLRC settings were different than Unit 2. (3)

Replace the EHC cooling fan Five out of nine cooling fans had been identified as out of service on March 23, 198 The inspectors observed that the calibration activities being conducted by the licensee were in accordance with the General Electric Turbine Line Up Instruction Number 170 x 387 and 170 x 388. The licensee had 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> coverage being supplied by a corporate PEco EHC engineer and a vendor representativ During discussions and review of SLRC alignment data, the inspector learned that the SLRC card was basically a notch filter that attenuated the magnitude of pressure oscillations of the steam line natural frequency of 0.9 hertz and several harmonics. The Unit 2 and 3 steam lines have the same natural frequency but the Unit 3 SLRC card re-quires more attenuation indicating that oscillations are of a larger magnitude than at Unit Licensee representatives stated that the oscil-lations experienced on March 24, 1987, could have been the result of using the Unit 2 SLRC cards. No theory about the cause of the original spiking which caused the trip on March 17, 1987, had been formulated. All cards removed from the Unit 3 EHC system will be sent to vendor for dynamic testin Subsequent to the calibration of the EHC cards the licensee connected a 13 point transient tape recording device and a 12 channel strip chart recorder. During the plant startup and heatup on March 26 and 27,1987, the inspectors and the licensee observed the recorder traces which were steady. At about 1:00 a.m., on March 27, 1987, the last new ventilation fan was installed. During this activity several spikes and oscillations were observed on the recorder char The parameters that were affected were:

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Points 1 and 2, pressure sensor inputs to A and B pressure amplifier circuit Points 10 and 11, A and B pressure amplifier output Point 12, bypass valve positio The spiking was discussed with the on-duty test engineer. He also noted that during previous troubleshooting activities on March 23, 1987, he had heard noises such as EHC panel ventilation fan blades hitting the fan housings which seemed to correspond to EHC spikes. Ventilation fans observed to be defective were disabled at that time. During the same period the A and B pressure amplifiers and the A and B SLRC cards were replace EHC spiking stopped later on March 23, 198 The inspector agreed with the licensee test engineer that, although not conclusive, it appeared that the March 17, 1987, scram could hav'e been caused by the electrical noise induced by defective EHC ventilation fan Oscillations in the bypass valve position observed on March 24, 1987, could have been caused by the differences in calibration settings of the Unit 2 SLRC cards installed in the Unit 3 EHC syste 'The inspectors observed the recorder traces to be very steady after the fan was electrically connecte The licensee is required to submit LERs regarding both the March 17 and March 25, 1987 scram No violations were identifie . LER Analysis 10.1 Scope The inspector conducted a specia! review of LERs submitted to the NRC for the period 1985 to present for both Units 2 and 3. The review determined the time of day for those LERs involving personnel error. This includes personnel error induced events, and those events that were initiated by other root causes (i.e., non personnel error) which may have been complicated or made worse by subsequent personnel error. For the reportable events occurring on the back shifts (primarily 11:00 p.m. to 7:00 a.m.) or on the weekends, the review determined if the reported personnel error was caused or made worse by any operator inattentiveness to the control .2 Conclusion The inspector reviewed all Peach Bottom LERs from 1985 to presen Attachment 2 lists all LERs that involve personnel error based on NRC root cause analysis during previous routine inspection For the LERs caused by or made worse by licensed operator errors

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during backshift times, the inspector identified one case on a backshift where operator inattention to duty was potentially involved (LER 3-85-02) other than the scram on March 17, 1987 -

section 8.3. The majority of-the backshift errors occurred during plant startups, : shutdowns, or equipment blocking evolutions, which do not appear to have been related to operator inattentivenes Further, NRC action regarding personnel errors is unresolved pending a licensee review of all reportable events for indications of operator inattentivenes (277/87-10-04; 278/87-10-05)

11. Operations Overtime Station administrative procedure A-40, " Working Hour Restrictions",

Rev. 3, dated October 23, 1985, delineates the working hour restrictions and overtime policy requirements for all personnel, including licensed operators. Overtime limits include the following requirements:

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Maximum of 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> in a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period,

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Maximum of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in a 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> period,

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Maximum of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in a seven day period, and

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Minimum of 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> off between work period Deviations to these requirements may be authorized by management and are documented per form A-46, Exhibit The control room shift clerk tracks overtime for licensed operator Shift clerks are assigned to each operating shift to perform administra-tive duties. The shift clerk tracks hours worked for each operator and maintains a running total for overtime hours to ensure the above require-ments are adhered t If a deviation is required, the shift clerk initiates the A-46, Exhibit I for The inspector reviewed procedure A-40 and discussed its implementation with shift clerks and operations personnel. The inspector also reviewed overtime / work hour records for the period November 1986 through March 1987. The inspector noted the following:

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All on shift licensed reactor operators worked some overtim No operator worked more than 16 consecutive hours without time of Overtime was consistent with A-40 requirement Deviations of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in a 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> period were processed per A-4 r:

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One reactor operator exceeded the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in a week twice (deviation processed per A-40).

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Senior reactor operators worked less overtime than reactor operators and no deviations were needed nor processe The inspector reviewed work hours on the day of the Unit 3 scram due to EHC problems on March 17, 1987 (see section 11.1). This included all control room personnel and related overtime hours for that period. All of the operators worked an eight hour shift (11:00 p.m. - 7:00 a.m.)

that day. Neither the Unit 3 reactor operator nor the senior operators on shift worked any overtime for that period. The inspector concluded that excessive work hours was not a factor in the March 17, 1987, apparent inattention to control room indications and resultant automatic scra The inspector asked the licensee for the average overtime hours for 1986 for licensed operators. This information was not readily available and it will be reviewed in a future inspectio No violations were note . Exit Interview Meeting The inspection ended on April 9, 1987. An exit interview was held on April 9,1987, to discuss the findings and conclusions by the inspection tea . Appendices Attachment 1 - Documents Reviewed Attachment 2 - Personnel Errors, LER Tabulation Attachment 3 - Surveillances Observed l

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ATTACHMENT 1 Documents Reviewed Nuclear Plant Rules, Rev.'2, 1/7/87 A-7, Shift Operations, Rev. 22, 10/3/86

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IE Information Notice No. 79-20, NRC Enforcement Policy - NRC Licensed Individuals, Rev. 1, 9/7/79 IE Information Notice No. 85-53, Performance of NRC-Licensed Individuals While On Duty, 7/12/85 IE Circular No. 81-02, Performance of NRC-Licensed Individuals While On Duty, 2/9/81 NRC Regulatory Guide 1.114, Guidance On Being Operator at the Controls of a Nuclear Power Plant, Rev. 1, 11/76 Shift Brief Attendance Sheets (3/24/87-4/3/87)

A-86, Administrative Procedure for Corrective Action, Rev. 5, 1/16/87 Suspected Licensee Event Reports dated 3/28/87 and 3/31/87 QA Plan Volume III FH-6C " Fuel Movement and Core Alteration Procedure During a Fuel Handling Outage", Revision 17, October 24, 1984 FH-6C, Appendix 1, " Core Component Transfer Authorization Sheet" S-14.1-2, " Operation of the Refueling Platform Controls and Interlocks",

Rev. O, May 8, 1984 A-44, "Special Nuclear Material Accountability" S-14.2, " Moving Fuel from the Fuel Pool to the Reactor", Revision 5, May 8, 1984 S-14.3, " Moving Fuel from the Reactor to the Fuel Pool", Revision 7, May 8, 1984 S-14.4, " Moving Fuel Within the Reactor", Revision 7, May 8, 1984 Technical Specifications and Bases, Section 3.10/4.10 GEK 9684, Volume VI, " Service and Handling Equipment" S-14.5, " Removing Blade Guides from the Reactor and Placing them in the Fuel Pool", Revision 5, May 8, 1984 Fuel-Pool Drawings, 6280-MIM-5 thru 10 Instruction Manual, " Refueling Platform Equipment Assembly 796E457", Volume 1, PE #6280-MIM-378-1 ST-12.1-2, " Refueling Interlock Functional Test (Unit 2)", Revision 1, June 10, 1985 ST-12.1A, "One Rod Permissive Refueling Test", Revision 4, June 21, 1984 ST-3.1.2, "SRM Core Monitoring Test", Revision 9, January 11, 1985

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ATTACHMENT 2 Personnel Errors LER Tabulation (1985 thru 1987)

LER Date/ Time Description 2-85-26 12/26/85, Noon Control rod block full out (R0 error)

2-85-25 11/29/85, 2:00 Auto scram during turbine testing while shutting down (TE errors)

2-85-24 11/3/85, 1:35 Containment isolation blocking error (R0 error)

2-85-21 9/30/85, 9:30 Fire pump out of service (R0 error)

2-85-20 9/24/85, 6:07 Scram while shutdown and draining of reactor to torus (R0 error)

2-85-17 8/25/85, 7:30 Torus lov level (R0 error)

2-85-12 8/7/85, 1:39 Auto scram with EHC out of service (R0 error)

2-85-02 5/30/85, 4:36 Scram while shutdown during excess check valve. testing (TE error)

3-85-26 12/3/85, 4:35 PCIS isolation, when plant operator removed wrong fuse 3-85-24 11/25/85, 8:40 RWCU isolation when plant operator

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removed wrong fuse 3-85-23 11/15/85, 6:30 PCIS isolation when wrong fuse removed during troubleshooting 3-85-19 11/16/85, 9:45 RWCU isolation (I&C technician error)

3-85-12 8/7/85, 8:30 Fuel bundle isolated (Refuel error)

3-85-10 4/10/85, 12:25 Diesel auto start during ST (I&C error)

3-85-09 3/28/85, 11:00 SGTS blocking error (R0 error)

3-85-08 3/13/85, 9:45 Torus High Level (Reactor Operator Error)

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, 2 3-85-02 2/20/85, 4:00 Reactor mode switch wrong position during refuel. Potential operator inattentiveness to dut (R0 blocking error)

2-86-01 1/1/86, 8:27 Auto scram on moisture separator high level (STA Error)

2-86-11 3/26/86, 9:00 RWCU isolation (I&C error)

2-86-18 8/26/86, 4:00 Reactor water level transmitter out-of-service (I&C Error)

2-86-21 8/13/86, 11:45 Work on core spray valves without safety blocking (maintenance error)

3-86-02 2/17/86, 12:40 RWCU isolation while removing leads (I&C Tech)

3-86-03 2/19/86, 8:40 PCIS isolation when wrong fuse was removed (Plant Operator error)

3-86-05 3/06/86, 3:30 Low level scram during startup involving reactor feedwater pump speed control. Low speed stop setting found too low. Personnel error compounded by equipment failur (R0 error)

3-86-09 3/18/86, 1-2:30 Out-of-sequence control rod during startup NRC issued $200,000 Civil Penalty (R0/SR0 Errors)

3-86-10 4/11/86, 8:16 Reactor low level scram while using RCIC for level control while shutting down (R0 error)

3-86-12 4/26/86, 9:50 Auto scram while testing 500 KV line fault detection circuit (I&C error)

3-86-13 4/26/86, 7:06 Shutdown scram during testing (R0 error)

3-86-14 4/26/86, 7:22 Shutdown scram during testing (R0 error)

3-86-21 10/21/86, 8:00 Torus high level (R0 error)

3-86-23 11/4/86, 8:30 Auto scram during turbine shell warming (R0 error) e ,

3-87-01 3/17/87, 2:54 Auto scram due to EHC oscillations operators inattentiva to their dutie (RO-SRO error)

3-87-02 3/25/87, 4:00 Scram during EHC trcubleshooting (TEerror)

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Surveillance and Routine Tests Observed

Routine Test (RT) 5.9, " Exercising of Turbine Bypass Valves", Rev.1,

._, performed on Unit 3 on 3/27/87 i' RT 5.14, " Closure of Control Valves", Rev'. 12, performed on Unit 3 on

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3/27/87 RT 5.0, " Individual Full Closure of Main Turbine Stop Valves", Rev.12, performed on Unit 3 on 3/27/87 Surveillance Test (ST)' 6.6.1, "Dailj Core Spray "A" System & Cooler (_ Operability", Rev. 10, performed on Unit 3 on 3/27/87

'r ST 6.7.1, " Daily Core Spray "B" System & Cooler Operability", Rev. 12, performed on Unit 3 on 3/27/87 ST 6.8.1, " Daily RHR "A" System & Unit Cooler Operability", Rev. 22,

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performed on Unit 3 on 3/27/87 ST 9.21-3, " Jet Pump Operability", Rev. 9, performed on Unit 3 on 3/28/87 ST 2.10.15 " Functional Check of the RPS B Card File", Rev. 6, performed on Unit 3 ST 2.10.17, " Functional Check of the RPS 0 Card File", Rev. 6, performed on Unit 3 ST 6.10.1, "HPSW System Operability", Rev. 8, performed on Unit 3 on 3/28/87 ST 6.6.1, " Daily Core Spray "A" System & Cooler Operability", Rev. 10, performed on Unit 3 on 3/27/87 ST 6.7.1, " Daily Core Spray "A" System & Cooler Operability", Rev. 10, performed on Unit 3 on 3/27/87 ST 3.5.1-3, "RBM Functional & Calibration Test", Rev._4, performed on Unit 3 on 3/28/87 ST 6.8.1, " Daily RHR "A" System & Unit Cooler Operability", Rev. 22, performed on Unit 3 on 3/28/87 ST 8.1.3, " Daily Diesel Generator Full Load Test", Rev. 13, performed 3/29/87 ST 6.6.1, " Daily Core Spray "A" System & Cooler Operability", Rev. 10, performed on Unit 3 on 3/29/87 ST 6.7.~1. " Daily Core Spray "B" System & Cooler Operability", Rev. 12, performe4 on Unit 3 on 3/29/87 ST 4.6, " Main Steam Line Monitor Functional & Calibration Test", Rev. 13, performed on Unit 3 on 3/29/87 ST 6.8.1, " Daily RHR "A" System & Unit Cooler Operability", Rev. 22, performed on Unit 3 on 3/29/87 ST 6.9.1, " Daily RHR "B" System & Unit Cooler Operability", Rev. 23, performed on Unit 3 on 3/29/87 ST 3.3.1, "APRM Functional & Calibration Test (Scram & Rod Block)", Rev. 20, performed on Unit 3 on 3/29/87 ST 12.1.B, " Refueling Interlock Functional Test with Inability to Move Control Rods", Rev. 1, performed on Unit 2 on 3/29/87 ST 8.1.3, " Daily Diesel Generator Full Load Test", Rev.13, performed 3/30/87 ST 9.7, "MSIV Partial Closure & RPS Input Functional Test", Rev. 9, performed on Unit 3 on 3/30/87

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1 ST 6.6.1, (ST) 6:6.1, " Daily Core Spray "A" System & Cooler Operability", Rev. 10, performed on Unit 3 on 3/30/87 ST 6.7.1, (ST) 6.6.1, " Daily 1 Core Spray "A" System & Cooler

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Operability", Rev. 12, performed on Unit 3 on 3/30/87 ST 11.6-2, " Diesel Generator Simulated Automatic Actuation & Load Acceptance Test, "Rev. 8, performed 3/30/87

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sST 8.1.3, " Daily Diesel Generator Full Load Test", Rev. 13, performed

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,. ST 6.6.1, " Daily Core Spray "A" System & Cooler Operability", Rev. 10,

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performed on Unit 3 on 3/31/87 ST 6.7.1, " Daily Core Spray "A" System & Cooler Operability", Rev. 12, performed on Unit 3 on 3/31/87

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