IR 05000277/1987002

Insp Repts 50-277/87-02 & 50-278/87-02 on 870103-31.No Violations Noted.Major Areas Inspected:Operational Safety, Radiation Protection,Physical Security,Control Room Activities,Qa,Licensee Events & Surveillance Testing

ML20211F641
Person / Time
Site:	Peach Bottom
Issue date:	02/13/1987
From:	Gramm R, Scholl L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20211F623	List: IR 05000277/1987002 ML20211F617
References
50-277-87-02, 50-277-87-2, 50-278-87-02, 50-278-87-2, NUDOCS 8702250156
Download: ML20211F641 (18)

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U. S. NUCLEAR REGULATORY COMMISSION

REGION I

Report No. 50-277/87-02 & 50-278/87-02 Docket No. 50-277 & 50-278 License No. DPR-44 & DPR-56 Licensee: Philadelphia Electric Company 2301 Market Street Philadelphia, Pennsylvania 15'101 Facility Name: Peach Bottom Atomic Power Station Units 2 and 3 Inspection At: Delta, Pennsylvania Inspection Conducted: January 3 - 31, 1987 Inspectors: T. P. Johnson, Senior Resident Inspector J. H. Williams, Resident Inspector R. J. Urban, Resident Inspector i

A. A. Weadock, Radiation Specialist Reviewed By: /MB/ #-/ 3 -# 7 holl," Reactor Engineer date Approved By: l [ W /b!Tr-)

Rf A. Gramm, Acting Chief, date

Reactor Projects Section 2A, t

Division of Reactor Projects i Inspection Summary: Routine, on-site regular and backshift resident inspection

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(94 hours0.00109 days <br />0.0261 hours <br />1.554233e-4 weeks <br />3.5767e-5 months <br /> Unit 2; 88 hours0.00102 days <br />0.0244 hours <br />1.455026e-4 weeks <br />3.3484e-5 months <br /> Unit 3) of accessible portions of Unit 2 and 3, operational safety, radiation protection, physical security, control room

activities, Quality Assurance, licensee events, surveillance testing, mainte-nance, and outstanding item Results: Operator response to the 2A reactor feedwater pump trip was goo TS Table 3.2.A for the main steam line leak detection instrumention is confusing to the operators. INPO training accreditation has been completed and some positive impacts have been noted. The annual winterization procedure (RT 6.0) was not completed as specified in the licensee's procedure. QA/QC

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activities have been expanded on-site. The System Engineer and Plant Performance Monitoring programs are adequately functioning. The surveillance testing program

enhancements have increased the assurance that tests will be performed when j required.

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DETAILS 1. Persons Contacted 1.1 The following personnel were contacted during the inspection:

B. L. Clark, Administrative Engineer

• J. 8. Cotton, Superintendent Plant Services G. F. Dawson, Maintenance Engineer

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

• D. C. Smith, Superintendent Operations J. E. Winzenried, Staff Engineer Other licensee employees were also contacte *Present at exit interview on site and for summation of preliminary finding .2 Personnel contacted at a NRC/QA meeting on January 15, 1987:

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J. M. Pizzola, E&R QA J. T. Wilson, Nuclear Ons QA A. B. Donnell, Nuclear Ops QA J. S. Moore, E&R QC E. P. Troy, Nuclear Ops QC J. P. Evans, E&R QA l J. J. McElwain, Nuclear Ops QC 2. Plant Status l 2.1 Unit 2

l Unit 2 began the inspection period operating at or near full reactor power. A load drop occurred on January 16, 1987, to leak test condenser water boxes and to adjust the control rod patter The unit returned to full power on January 19, 1987. On January 28, 1987, the 2A reactor feedwater pump tripped (see detail 4.2.1)

resulting in a manual run back to 80% reactor power. The unit remained at 80% reactor power with the 2A RFP out of service for the remainder of the period.

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2.2 Unit 3 Unit 3 began the inspection period in cold shutdown for the repair of a steam leak on the high pressure turbine and to perform miscellaneous maintenance. The unit restarted on January 6, 1987, and achieved full reactor power on January 20, 1987. The power ascension to full power was delayed due to leak testing condenser water boxes and regenerating condensate filter demineralizer The unit operated at or near full power for the remainder of the perio . Previous Inspection Item Update 3.1 (Closed) Unresolved Item (277/85-40-05). Shutdown margin with the Unit 2 control rod 22-11 blocked full out. Control rod 22-11 was blocked full out at position 48 to perform maintenance on the hydraulic control unit on December 26, 1985. The related violation was closed in NRC Inspection 277/86-13. The licensee responded to the shutdown margin concern in a letter dated March 13, 1986. The licensee determined that Unit 2 shutdown margin requirements would be met with control rod 22-11 full out at the most reactive time (i.e.,

cold at 68 degrees F and xenon free). The licensee also determined that the shutdown margin requirements would be met if the most reactive rod (i.e., control rod 26-11) remained fully withdrawn and the reactor temperature was lowered to 168 degrees F. The licensee further stated in their response that post scram procedures require verification that control rods are fully inserted after a scram, and that measures would be taken to insert a blocked rod prior to achiev-ing cold shutdown. The inspector reviewed the licensee's response, reviewed the shutdown margin calculations and discussed this with licensee engineers. The inspector also verified completion of corrective actions in the licensee's response. The unresolved item is close .2 (Closed) Unresolved Items (277/85-41-01 and 277/85-40-02).

Licensee actions and cause of cable tray fire in radwaste building on November 10, 1985. The licensee submitted a report dated May 21, 1986 to the NRC regarding the fire. The licensee concluded that the

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cause of the fire was from combustion below the cable tray. However, the precise ignition source was not determined. A consultant's report

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concluded that the fire initiated in the cable tray; however, PECo

, electrical engineering concluded that the fire started below the cable tray (i.e., in the divers cage). The inspector and a regional specialist reviewed the May 21, 1986 report and determined it to be accurate. Licensee corrective actions include the addition of a fire door and barrier on the 165 foot level of the radwaste building, and the addition of cable tray fire detectors (linear heat /protectowire)

in the fan room. The inspector verified that these modifications were complete Based on the licensee's report and the completed modifications, the unresolved items are closed. The inspector will continue to follow the completion of the remainder of the 10 CFR 50, j Appendix R modifications.

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3.3 (Closed) Inspector Follow Item (277/85-44-06). E-2 diesel generator (DG) roots blower failure mechanism and annual inspections. The E-2 DG failed while in service carrying the E-22 and E-23 emergency busses on January 24, 1986. The licensee determined that the cause of the failure of the roots blower was thermal induced creep (deformation) of the rotor and blower assembly at low load. The licensee made a 10 FR 21 report and initiated certain corrective actions. These corrective actions include: a modified blower was installed in the E-2 and E-3 DGs; a modified blower will be installed in the E-1 and E-4 DGs; modification (MOD) 1927 was completed to allow the post accident tripping of all unloaded DGs from the control room after a ten minute time delay; and changes to maintenance pro-cedure M-52.2 to check for roots blower clearances during DG annual outages. The inspector verified these corrective actions and dis-cussed them with licensee engineers and operators. MOD 1927 was completed during the 1986 annual outages for all DGs. The inspector reviewed the MOD 1927 safety evaluation and noted that the DGs would auto restart on loss of power to the emergency busses after the DG had been shutdown. The inspector monitored the E-3 DG blower replacement on August 14, 1986 (NRC Inspection 277/86-13). The inspector follow item is considered close The inspector will continue to follow the E-1 and E-4 DG blower replacement with one currently scheduled for the 1987 DG annual maintenance outag .4 (Closed) Inspector Follow Item (277/86-12-01; 278/86-13-01). Chief Operator may direct the licensed activities of the unit reactor operators, as defined in 10 CFR 55.4(e), without holding a Senior Reactor Operator's (SRO) license. The licensee responded to the

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concern in a letter dated October 20, 1986. The letter stated that only the control room Shift Supervisor (SRO) oversees and directs the licensed activities of the Unit 2 and 3 reactor operator The Chief Operator's duties may include communications and activity coordin-ation, which are supervised by the Shift Superviso In order to stress the importance of 10 CFR 55.4(e), a station management memo was sent to licensed operators. The inspector reviewed the response letter and the memo, and discussed this concern with licensed opera-tors and station management. The inspector follow item is closed.

l 3.5 (Closed) Inspector Follow Item (277/86-12-02; 278/86-l'>-02). Improve l operator control room logs. The licensee responded to the concern in l a letter dated October 20, 1986, and revised A-7, " Shift Operations" l

to reflect the INP0 Good Practices OP-205. The inspector reviewed A-7 and operator logs. The inspector noted an improvement in overall log keeping. The inspector will continue to routinely review control

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room logs. This item is closed.

l 3.6 (Closed) Inspector Follow Item (277/86-12-03; 278/86-13-03). Shift Superintendent administrative duties detracting from plant operation l

oversight responsibilities. The licensee responded to the concern in a letter dated October 20, 1986. The response stated that certified BWR contract engineers are to be added to each operating shift to l

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provide administrative support for the Shift Superintendent. These contract engineers were added to each shift in October 198 In addition, the licensee reviewed the Shift Superintendent's admin-istrative dutie Peach Bottom Enhancement Program action item 4.9 (2) states that position guides for all shift positions will be developed by April 1987. The inspector will review this item when it is completed. The inspector discussed the administrative duties of the Shift Superintendent with licensee engineers and management. During the upcoming Unit 2 outage the licensee intends to supplement each operating shift with an outage coordination assistant. The inspector follow item is considered close .7 (Closed) Inspector Follow Item (277/86-12-17; 278/86-13-17).

Establish a tracking system for the resolution of QA audit recommendativas. The licensee responded to the concern in a letter dated October 20, 1986. The letter committed to a revision to QA procedures to implement the issuance and control of audit recommen-dations by December 15, 1986. The inspector reviewed QA procedure QADP-9, " Procedure for Control of Findings", Revision 13 which was issued in December 1986. QADP-9, Revision 13 became effective January 1,1987. Sections 7.2 and 7.14 of QADP-9 address the issuance, control and tracking of QA audit recommendations. The inspector reviewed QADP-9 and discussed its implementation with QA engineers. The inspector follow item is close .8 (Closed) Inspector Follow Item (277/86-12-18; 278/86-13-18).

Formalize the control room review activities. The licensee responded to the concern in a letter dated October 20, 198 The letter stated that QC would expand their monitoring program (Detailed Monitoring Checklists - DMC) in the area of control room activities review. The inspector reviewed the current QC monitoring schedule and DMC Areas reviewed included the following: valve / switch lineup, shift turnover, permits and blocking, logkeeping, equipment control operator aids, annunciators, technical specification LCOs, and surveillance testing. The inspector reviewed the December 1986 schedule and selected completed DMCs. Negative findings include logkeeping and shift turnover for the Outside Shift Supervisor. Operations has initiated adequate corrective actions in these areas, as verified by later QC DMCs and by the inspector. QC also verifies that the reactor operators, senior reactor operators, shift technical advisors (STA), GE shift engineers, and Independent Safety Engineering Group (ISEG) are performing control room panel walkdowns as require The inspector verified that these control room panel walkdowns are being performed as committed. In addition, the inspector accompanied the STA and ISEG engineers, and the licensed operators on selected control room panel walkdown These walkdowns were determined to be complete and adequate. Also, the inspector verified that QA and QC continue to routinely attend shift turnover briefing In discus-sions with QA and QC engineers, the inspector learned that a QC recommendation for the STAS to log their shiftly panel walkdown was

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incorporated into administrative procedures. Planned QC involvement includes a review of the plant labeling program and a review of future scheduled revisions to the Transient Response Implementation Plan (TRIP) procedure Based on the above, the inspector follow item is close .9 (Closed) Unresolved Item (277/85-44-05). Management controls on overdue surveillance tests. The unresolved item is considered resolved and closed based on detail 7.1 of this repor .10 (Closed) Violation (277/86-12-08; 278/86-13-08). Failure to perform five surveillance tests (ST) on safety related systems. The viola-tion is closed based on the licensee response dated October 1, 1986, and a review of the ST program in detail 7.1 of this repor The overdue tests were completed satisfactorily by the license .11 (Closed) Inspector Follow Item (277/86-12-21; 278/86-13-21).

Adequacy of CO2 weight required in cardox system. Technical Speci-fication 3.14.8 requires 2,400 lbs for the HPCI cardox; 11,000 lbs for the control room, cable spreading room and computer room; and 2,200 lbs for the diesel generator (DG) rooms. Two 12,000 lb cardox tanks supply the HPCI rooms, the cable spreading room, the control room and the computer room. One 5,500 lb cardox tank supplies the DG rooms. Sixty percent minimum tank levels are required per licensee procedures ST 16.2.1, and S13.2.2G and H. This allows 3,300 lbs for the DG cardox system; and 14,400 lbs for HPCI, cable spreading room, control room and computer room. The licensee has evaluated that 4 these minimum tank levels are adequate as described in a July 2,1986, memo. The inspector reviewed the July 2,1986 memo, TS 3.14.8, the above procedures, and discussed this item with licensee operators and engineers. Based on the above, the inspector follow item is close . Plant Operations Review 4.1 Station Tours The inspector observed plant operations during daily facility tours.

, The following areas were inspected:

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Control Room

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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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Protected and Vital Areas i

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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 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 frequentl .1.2 The inspector frequently observed that selected control room instrumentation confirmed that instruments were operable and indicated values were within Technical Specification require-ments and normal operating limits. ECCS switch positioning and valve lineups were verified based on control room indi-cators and plant observations. Observations included flow setpoints, breaker positioning, PCIS status, and radiation monitoring instruments.

During control room log reviews, the inspector noted that a one half group 1 isolation occurred on Unit 2 on January 19,

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1986, at 3:42 p.m. A full group 1 isolation causes all eight main steam isolation valves (MSIVs) to close. The cause of the half isolation signal was a failed temperature element (TE/TS 4931A) which measures the duct return temperature from the outboard MSIV room. Sixteen temperature elements (resistance temperature detectors) measure main steam area temperatures. A high temperature trip (greater than 200 degrees F) from channel A concurrent with a channel B trip will cause a full group 1 isolation. The licensee replaced the electronics card, tightened the temperature element con-nections, performed a surveillance test (ST), and declared the isolation logic operable.

The inspector reviewed the control room logs, operator response, electrical schematics, technical specification (TS)

table 3.2.A, and instrument location drawings. The inspector also monitored main steam area temperatures at panels 2AC270 and 2BC270. The inspector verified that the required actions of TS table 3.2.A were followed for an inoperable temperature element, and the inspector reviewed completed ST 2.3.04A,

" Calibration Check of TE-TS4931A".

TS Table 3.2.A includes four instrument channels for the " main steam line leak detection high temperature" and four instru-ment channels for the " main steam line tunnel exhaust duct high temperature". FSAR section 7.3 states that there are 16 temperature detectors. The inspector verified that there are actually 16 temperature detectors arranged in two isolation channels (A and B). Each channel has two subchannels, and each subchannel has four detectors. Four detectors measure main steam line tunnel exhaust duct temperature and 12

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detectors measure main steam line area temperature. Thus, TS table 3.2.A for the " main steam line leak detection" is somewhat confusing (e.g., four channels vs. 12 detectors).

The licensee is initiating action to correct the confusio No violations were note .1.3 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 condi-tions, and that corrective action, if required, was being take In addition, the applicable alarm cards were checked for accuracy. The operators were knowledgeable of alarm status and plant condition .1.4 The inspector checked for fluid leaks by observing' sump status, alarms, and pump-out rates; and discussed reactor ,

coolant system leakage with licensee personnel. The Unit 3 N unidentified leak rate was frequently verified to be less #, .

than the limit of 2.0 gp .1.5 Shift relief and turnover activities were monitored daily, including backshift observations, to ensure compliance with *

administrative procedures and regulatory guidance. No inade- -

quacies were identifie .1.6 The inspector observed the main stack and both reactor build-ing ventilation stack radiation monitors and recorders, and

! periodically reviewed traces from backshift periods to verify i that radioactive gas release rates were within limits and that unplanned releases had not occurred. No inadequacies were identifie .1.7 The inspector observed control room indications of fire detec-tion instrumentation and fire suppression systems, monitored l use of fire watches and ignition source controls, chedked a sampling of fire barriers for integrity, and observed fire-t fighting equipment stations. No inadequacies were identifie .1.8 The inspector observed overall facility houseieeping condi-tions, including control of combustibles, loose trash and l debris. Cleanup was spot-checked during and~dfter maintenanc Plant housekeeping was generally acceptable.

l 4.1.9 The inspector observed the nuclear instrumentation subsystems l

(source range, intermediate range and power range monitors)

I and the reactor protection system to verify that the required channels were operabl '

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4.1.10 The inspector frequently verified that the required off-site electrical power startup sources and emergency on-site diesel generators were operabl .1.11 The inspector monitored the frequency of in plant and control room tours by plant and corporate management. The tours were generally adequat .1.12 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, opera-ting procedures, plant drawings, instrumentation and breaker positionin Selected major components were visually inspec-ted for leakage, proper lubrication, cooling water supply, operating air supply, and general condition No significant piping vibration was detected. The inspector reviewed selected blocking permits (tagouts) for conformance to licen-see procedures. Systems checked included the Unit 2 and 3 low pressure coolant injection systems. No inadequacies were identifie .2 Followup On Events Occurring During the Inspection 4.2.1 Unit 2 2A Reactor Feedwater Pump (RFP) Trip On January 28, 1987, at 12:11 p.m., with Unit 2 at 100%

reactor power, the 2A RFP tripped. Several high vibration alarms had been received earlier in the shift and the RFP speed was lowered to clear the high vibration alarms. When the 2A RFP tripped, the reactor operator manually lowered reactor recirculation MG speed from 82% to 65%. Reactor power decreased to approximately 80% and the transient caused reactor level to drop to 18 inches (normal level is 23 inches). The feedwater level control system, with the 28 and 2C RFPs in auto, recovered reactor level to norma The inspector reviewed the control room operator logs, the instrument chart recorders, the computer alarm typer; and, discussed the event with on-shift operating personnel. The inspector determined that operator response was timely and actions were in accordance with procedures. The inspector also reviewed the licensee's draft upset repor The cause of the 2A RFP trip was apparently due to a failure of the overspeed trip mechanism causing a loss of control oi In addition, damage to the coupling was noted. The licensee initiated repairs to the 2A RF No unacceptable conditions were note .

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4.3 Logs and Records The inspector 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 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 .4 Cold Weather Preparations The inspector reviewed the licensee's program of protective measures for extreme cold weather. The inspector reviewed the following items: Routine Test (RT) 6.0, " Winterizing Procedure", Rev. 2, dated November 15, 1982; IE Bulletin 79-24, concerning frozen line The licensee's winterizing procedure states that RT 6.0 shall be performed every November. The inspector determined that the pro-cedure had not been started. After discussions with licensed operations personnel, it was determined that the procedure was submitted to typing in September 1986 for a revision. The pro-cedure was apparently misplaced for several months until after the inspector questioned its completion statu The procedure is currently being performed by operations and should be complete in a couple of weeks. The inspector will complete this review in a future inspection. The inspector did not note any occurrence of frozen lines caused by cold weather during the i 1986-1987 winte .5 Status of INPO Training Accreditation In late 1982 Philadelphia Electric Company made the decision to seek INP0 accreditation for Peach Bottom. A plan for self evaluation reports in five areas was developed in May 1983 to accomplish accreditation. PECo submitted to INPO these reports in August 1984 for the following programs: Nonlicensed Operator, Reactor Operator, Senior Reactor Operator, Chemistry Technician, and Radiological Protection Technician. All five programs were accredited by the National Nuclear Accreditation Board in May 1985. Self-evaluation

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reports for five additional training programs: Shift Technical Advisor, I&C Technician, Electrical Maintenance, Mechanical Mainte-nance, and Technical Staff and Managers, were submitted in November 1985. These five programs were accredited by INPO in October 198 No operational performance changes due to INPO accreditation at Peach Bottom have been identified. However, the accreditation process has had some positive observable impacts on the training program such as:

o Better formation of training (course and class) goals and more detailed objectives, o Better Qualification Manuals, o Better overall planning and documentation of training activitie The INP0 accreditation process also appears to be the impetus for improved communications on training among the utilities. PECo is a member of the Mid-Atlantic Nuclear Training Group (MANTG).

Within the scope of this review, no unacceptable conditions were note .6 Quality Assurance The inspector reviewed QA/QC activities during the report perio The inspector attended a meeting on January 15, 1987. with site and corporate representatives from Nuclear Operations QA and QC, and Engineering and Research (E&R) QA and Q (See detail 1.2.)

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The inspector reviewed Control Room QA/QC activities (see detail

! 3.8), the QA/QC checks of the surveillance testing program (see detail 7.1.3), and the QA/QC reviews of on-site and off-site review i committees. The inspector reviewed a 1986 Joint Utility Management l Audit (JUMA) Report of the PECo Nuclear Review Board (NRB) dated l December 1, 1986. No unacceptable findings were documented in the JUMA report. Nuclear Operations QA performed a 1986 audit of the Plant Operations Review Committee (PORC) resulting in no significant

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findings. The inspector was informed that QC is planning to monitor PORC activities and that QA is planning to review ISEG activities.

i QC is also performing independent verification activities for I&C surveillance testin E&R QC activities include reviews of construction division perform-ance of major modification The inspector was informed of the upcoming Unit 2 E&R QC coverage schedule. E&R QA started on-site activities at Peach Bottom in April 1986. E&R QA performs audits and surveillances of major modification activities, audits of vendors, welding surveil-lances, and procurement document review E&R QA and QC activities

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are currently being planned for the upcoming Unit 3 pipe replacement outag E&R QC is currently performing receipt inspection and storage surveillance for the Unit 3 replacement pip Nuclear Operations QA and QC activities are currently planned for the Unit 2 refueling outage scheduled to begin March 14, 1987. Activ-ities scheduled to be reviewed include: control rod drive exchange, LPRM replacement, snubber surveillance and maintenance, ILRT, vessel hydrostatic test, core offload and reload, fuel inspections, and maintenance and modification Within the scope of the review of QA/QC activities, no unacceptable conditions were note . System Engineers 5.1 Program Description The licensee has recently revised and upgraded the Peach Bottom

" System Engineer" concept. A system engineer is a degreed engineer who has responsibility of maintaining expertise on one or more desig-nated plant systems. System engineer duties, responsibilities, and qualifications are delineated in Peach Bottom Atomic Power Station

" Guide for System Engineers", Revision 2, dated September 198 Duties and responsibilities of system engineers include the following:

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perform Plant Performance Monitoring Program (PPMP) functions

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evaluate surveillance testing and preventive maintenance results

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provide technical support for corrective maintenance and modifications

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track performance history

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assist in the preparation of operating and maintenance proce-dures, and training information

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perform periodic system walkdowns and assessments

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maintain system data books

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The Plant Performance Monitoring Program (PPMP), dated September 1986, is designed to ensure that equipment that could have a signifi-cant effect on plant performance is adequately monitored and timely corrective action is taken to maintain reliable operation. The PPMP is implemented at a system and plant level, and includes safety related systems. The PPMP takes full advantage of existing programs

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and functions which mor.itor plant performance. The PPMP utilizes existing data collection activities (e.g., surveillance test data, in-service inspection data, and preventive maintenance data). The PPMP supplements these activities with data from those areas not currently monitored which have a significant impact on plant power output and equipment reliabilit The PPMP is implemented for each plant system as part of the system engineer's normal duties. Implementation includes the determination of components and performance indicators to be monitored, the identi-fication of instrument requirements, data analysis, and follow-up action on identified problem In addition to individual system performance parameters, top level performance parameters (plant heat rate, plant availability, capacity factor, and the reliability of major components) are tracked by the assigned PPMP Engineer to ensure any abnormal trends are adequately addresse A monthly management report is prepared and issued by the PPMP Coordinator. The report summarizes the overall performance of Peach Bottom Units 2 and 3, including a discussion of major incidents of degraded unit performance. A central file of the individual system PPMP data is also maintained by the PPMP Coordinato .2 NRC Review and Conclusion The inspector reviewed the following documents:

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Guide for Systems Engineers, Rev. 2, Plant Performance Monitoring Program Description, Rev. Peach Bottom Systems Responsibility Lis Selected systems' data books and deficiency log Selected monthly PPMP management report The inspector discussed the system engineer program and PPMP imple-mentation with the Technical Engineer, the PPMP Coordinator and selected system engineers. The inspector accompanied selected system engineers on periodic plant tour The inspector concluded that the system engineer program is func-tioning adequately System engineers were determined to be knowledgeable of their assigned systems. The PPMP is essentially

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in the development stages; however, progress appears to be goo The inspector will continue to follow program implementatio No violations were noted.

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14 Review of Licensee Event Reports (LERs)

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

LER N LER Date Event Date Subject

• 2-86-24 Unit 2 oxygen analyzer PCIS actuation January 5,1987 December 9, 1986 2-86-25 Failure to establish fire watch

January 16, 1987 December 16, 1986 6.2 LER On-Site Followup 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 opera-tion of the facility was conducted in accordance with Technical Specifications and did not constitute an unreviewed safety question as defined in 10 CFR 50.59. Report accuracy, compliance with current reporting requirements and applicability to other site systems and components were also reviewe . LER 2-86-24 concerns a Unit 2 oxygen analyzer primary contain-ment isolation system actuation on December 9, 1986. The

, event was reviewed in NRC inspection 277/86-24. There were no

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inadequacies noted relative to this LE . Surveillance Testing 7.1 Surveillance Program 7.1.1 Background The NRC had previously identified weaknesses in the surveil-l lance test (ST) program during NRC Inspections 277/85-44; 1 278/85-44; and 277/86-12; 278/86-13. The programmatic weak-nesses included overdue or missed tests primarily caused by poor control and oversight by station mar.agement. The i

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improper focus of ST performance accountability and oversight resulted in missed tests including STs on ECCS and RPS function .1.2 Licensee Response Licensee response to these ST programmatic concerns was forwarded to the NRC in letters dated April 9, 1986, and October 1, 198 To ensure that STs are completed in a timely manner and to provide guidance for surveillance tests which cannot be com-pleted prior to expiration of their grace period, the licensee ,

revised administrative procedure A-43, Surveillance Testing !

System, Revision 18, July 8, 1986. Revised procedure A-43 includes the following additional controls:

-- The Surveillance Test Coordinator (STC) issues, three times a week, a " Grace Period Report" to each Cognizant Engineer, for their specific are The STC issues a weekly Overdue Test Report, a Grace period Test Report, and a Test Awaiting Official Verifi-cation Report to the following; each Senior Engineer for their specific area, each Superintendent for his specific area, and the Plant Manage The STC informs the app.opriate Cognizant Engineer when a test is three days from the expiration of its grace perio The licensee concluded that the revised ST program focuses management attention on tests which are in their grace period (i.e., prior to becoming overdue) so that appropriate steps can be taken to overcome the obstacles which are interfering with timely completion of the test . Licensee QA/QC Reviews The site Quality Assurance Division (QAD) QC group performs weekly monitoring of the ST system in accordance with Detailed Monitoring Checklist (DMC) 3.16. QC checks the status of STs that are in the grace period or are overdu The site QAD QA group performs audits on the ST progra Audit No. AP86-109 ST was completed on December 8, 198 The scope of this audit was to review the administrative controls governing the ST program and adherence to the technical speci-fication frequency requirements. In addition, the audit was conducted to comply with a commitment made in response to unresolved item 277/85-44-0 .

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A recently completed DMC 3.16 did not identify any unacceptable findings. QA audit No. AP-86-109 ST concluded that the ST program is adequate and is being effectively implemente .1.4 NRC Review The inspector reviewed the following documentation:

-- licensee letters responding to ST concerns dated April 9, 1986, and July 8,198 revised administrative procedure A-4 QA audit No. AP86-109 S ,

-- completed QC checklists per DMC 3.1 completed " grace period ST review forms".

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-- PORC meeting minutes approving the " grace period ST review forms".

-- ST periodic reports including: grace period test report, overdue test report, and test awaiting official verifica-tion repor QA Plan Volume III, Section 3, Surveillance Testing (ST).

The inspector interviewed the following individuals with respect to the ST program:

-- Surveillance Test Coordinator

-- QC inspectors and supervisors

-- QA auditors and supervisor

-- Cognizant and Senior Engineers ( -- Licensed operators

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-- Plant managemen .1.5 Conclusion

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The inspector concluded that the surveillance testing program is functioning adequately to ensure that required tests are performed in a timely manner. Administrative controls are now i in place to improve management awareness of tests that could become overdue. Prior to any test becoming overdue, manage-ment and PORC approval is required including corrective or compensatory measures.

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Within the scope of the review of the surveillance testing program, no unacceptable conditions were note .2 Surveillance Test Observation The inspector observed surveillance tests to verify that testing had been properly scheduled, approved by shift supervision, control room operators were knowledgeable regarding testing in progress, approved procedures were being used, redundant systems or components were available for service as required, test instrumentation was calibrated, work was performed by qualified personnel, and test acceptance criteria were met. Parts of the following tests were observed:

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ST 7.6.6, Reactor Area Vent Exhaust Radiation Monitor Calibration, Rev. 6, observed for Unit 3 on January 16, 198 ST 8.1, Diesel Generator Full Load Test, observed for the E-4 DG on January 7 and 8, 198 No inadequacies were identifie . Maintenance 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 MRF #86-7706 Unit 3 high pressure turbine January 5, 1987 steam leak repair SP-973 E-4 DG troubleshooting due to January 7, 1987 engine low cylinder temperature MRF #87-0908 2A RFP maintenance January 30, 1987 Administrative controls checked included maintenance request forms (MRFs),

blocking permits, fire watches and ignition source controls, item handling reports, QC involvement, plant conditions, TS LCOs, equipment turnover information, and post maintenance testin Documents reviewed included maintenance procedures, material certifica-i tions, RWPs, MRFs, and receipt inspection No inadequacies were identifie .

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18 Radiation Protection During the report period, the inspector examined work in progress in both units, including health physics (HP) procedures and controls, dosimetry and badging, protective clothing use, adherence to radiation work permit (RWP) requirements, radiation surveys, radiation protection instruments use, and handling of potentially contaminated equipment and material The inspector observed individuals frisking in accordance with HP procedures. A sampling of high radiation doors was 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 pro-

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vided the required information and people working in RWP areas were observed to be meeting the applicable requirements. No unacceptable conditions were identifie . 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 proce-dures on each shift, inspection of physical barriers, checks on control of vital area access and escort procedures. No inadequacies were identifie . Management Meetings 11.1 Preliminary Inspection Findings A verbal summary of preliminary findings was provided to the Manager, Peach Bottom Station at the conclusion of the inspection. During the inspection, licensee management was periodically notified verbally of the preliminary findings by the resident inspectors. No written inspection material was provided to the licensee during the inspection. No proprietary information is included in this repor .2 Attendance at Management Meetings Conducted by Region Based Inspectors Inspection Reporting i Date Subject Report N Inspector l

' Jan 12- Chemistry 87-01/01 Zibulski 16, 1987 Jan 26- Chemistry 87-03/03 Bicehouse 30, 1987 ._ - _- . - - - . - . --__ -_- - -