Text

Insp Repts 50-277/98-10 & 50-278/98-10 on 980922-1109. Violations Noted.Major Areas Inspected:Licensee Operations, Surveillances & Maint,Engineering & Technical Support & Plant Support
	ML20206N686
Person / Time
Site:	Peach Bottom
Issue date:	12/11/1998
From:	; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:	;
Shared Package
ML20206N679	List: IR 05000277/1998010; ML20206N677; ML20206N682;
References
	50-277-98-10, 50-278-98-10, NUDOCS 9812210163
	Download: ML20206N686 (43)
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U. S. NUCLEAR REGULATORY COMMISSION

REGION I

License Nos.

DPR-44 DPR-56 Report Nos.

98-10 98-10 Docket Nos.

50-277 50-278

. Licensee:

PECO Energy Company Correspondence Control Desk P.O. Box 195 Wayne, PA 19087-0195 Facility:

Peach Bottom Atomic Power Station Units 2 and 3 i

inspection Period:

September 22,1998 through November 9,1998 inspectors:

A. McMurtray, Senior Resident inspector M. Buckley, Resident inspector B. Welling, Resident inspector A. Burritt, Senior Resident inspector (Limerick)

P. Bonnett, Resident inspector (Limerick)

S. Dennis, Operations Engineer R. Nimitz, Senior Radiation Specialist J. Carrasco, Reactor Engineer Approved by:

Clifford J. Anderson, Chief Projects Branch 4

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Division of Reactor Projects

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l-l EXECUTIVE SUMMARY Peach Bottom Atomic Power Station NRC Inspection Report 50 277/98-10,50-278/98-10

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This inspection report included aspects of licensee operations; surveillances and maintenance; engineering and technical support; and plant support areas. The report covers a seven-week period of resident inspection and inspections by a regional radiation protection specialist and a regional engineering specialist.

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Operations:

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Very good performance by operations personnel was observed during the Unit 2 e

outage (2R12). However, some inadequacies with logkeeping practices were noted during the inspection period. (Section 01.1)

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< An incomplete, one-time use procedure and a poor turnover between operators

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e during system restoration caused four residual heat removal system vent valves to be left mispositioned. These mispositioned valves resulted in several hundred gallons of water from the 2B RHR subsystem spilling onto the Unit 2 torus room floor.This event was indicative of continued station challenges in the area of p!ar ystem status control. (Section O2.1)

e Ous.. ty assurance personnel performed substantial oversight of various activities

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ano trovided very good insights into the performance of all work groups involved

- with the 2R12 outage. (Section 07.1)

Maintenance:

e On August 10,1998, chemistry technicians were performing ST-C 095-878-2,

" Refuel Floor Vent Exhaust Rad Monitor Calibration and Functional Test for RIS-2-17-458A and C." During calibration of the 'C' detector, the technicians

inadvertently removed and dropped the 'D' detector. The technicians performing

- this work did not stop and notify the control room operations personnel or l-Chemistry Supervision that they had removed the 'D' detector and dropped it even though they were directed by ST-C-095 878-2to report any unexpected conditions. The behavior of the technicians to not tell details about the event for several days, and only when asked, was not acceptable. The licensee corrective actions were narrowly focused on the chemistry department and did not include the other departments at the station. Procedural non-adherence has been an

. issue at the station for the past year. This was considered a violation of the station Technical Specifications for not properly implementing procedures.

(Section M1.3)

e PECO operators performed the test of the alternate decay heat removal flowpath

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well. The reactor cavity and spent fuel pool water inventory, temperature, and clarity was maintained within the required limits. (Section M2.2)

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-Executive Summary (cont'd)

e PECO completed the. emergency core cooling system suction strainer replacement modification, from NRC Bulletin 96-03 commitments, during the 2R12 outage. The FME and work control activities were greatly improved from

the modification performed during the previous Unit 3 outage and were effective in ensuring that no foreign material was left in the ECCS systems. The modified j

systems were verified operable during post-maintenance testing. (Section M2.3)

e Operations staff were unnecessarily challenged during the performance of the E-22 and E-42 Loss of Offsite power / Loss of Coolant Accident functional tests, j

due to surveillance test procedure weaknesses. This issue was similar to others documented in NRC Inspection Report 50-277(278)/98-07,where inadequate

procedures resulted in unexpected plant equipment responses. (Section M3.1)

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- On October 25,1998, the Unit 3 E33 bus was inadvertently tripped during the performance of a surveillance procedure that functionally trip tested the E32 and E324 bus overcurrent relays. This resulted in an 'A' channel half scram, a full reactor water clean up isolation, loss of the 'C' standby gas treatment fan, an inboard primary containment isolation system group 3 isolation and subsequent loss of reactor building ventilation, and a half primary containment isolation system group 1 isolation that did not cause any valve motion. Control room personnel entered T-103, Revision 11, " Secondary Containment Control" due to high main steam line tunnel temperatures caused by the trip of the reactor

building ventilation. Procedure, T-103, was exited after the reactor building ventilation was restarted and the mainsteam line tunnel temperatures returned to normal. Since this event caused several automatic engineered safety feature (ESF) actuations, operations supervision made a four hour notification to the NRC per _10 CFR 50.72.

No violations of NRC requirements occurred due to this event. However, inadequate self-checking and peer checking by the instrument and control technicians performing the surveillance procedure were determined to be the root cause of this event. (Section M4.1)

e Contractor personnel performing modification work on the Unit 2 scram air header exhibited poor foreign material control practices, contrary to specific work order instructions. Weaknesses in contractor oversight were identified by these poor practices. In addition, PECO personnel did not enter the poor foreign material control practices into any of the station corrective action processes even though this issue appeared to meet the criteria for entry into the Performance Enhancement Program (PEP). (Section M4.3)

e Generally, core alterations during the 2R12 outage were conducted in a orderly and professional manner using precise communications and thorough shift turnover. However, three fuel movement errors occurred during the refueling activities on October 12 and 22,1998. These errors were caused by a failure to iii

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l Executive Summary (cont'd)

properly verify component location and orientation as required by procedure.

The Refueling Platform Operator failed to perform an adequate self-check and the Spotter failed perform an adequate peer-check during these fuel bundle moves.

These errors resulted in a violation of Technical Specification 5.4.1,

" Procedures." This non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy. (Section M4.4)

Enaineerina:

l PECO personnel identified that five Fire Areas in the plant, containing 25 rooms, e

did not contain automatic fire detection systems as required by 10 CFR 50 Appendix R, Section Ill.F. These areas were within the Turbine, Radwaste, Unit 2 and 3 Reactor, and Diesel Generator Buildings. PECO intends to submit an exemption request from the 10 CFR 50 Appendix R requirements for the

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identified Fire Areas. Interim compensatory actions, consisting of hourly fire i

watch patrols in accessible areas, were instituted on October 29,1998. The non-conformances constitute an apparent violation of 10 CFR 50 Appendix R.

This issue, which may represent a violation of NRC requirements, will remain open pending the submittal of the exemption request by PECO and the completion of the NRC review. (Section E2.1)

e Four examples of failures or degraded conditions on safety related motor operated valves were identified during the 2R12 outage. The operability.

- determinations for each valve were adequate and the valves were capable of performing their safety function when required. Although, the program and technical requirements for these valves were fulfilled, the failures and degraded conditions found during the outage indicated a negative trend in motor operated valve reliability. (Section E2.2)

- Plant Suooort:

o PECO established and implemented overall effective applied radiological controls and procedures for Unit 2 outage work activities. There were no significant unplanned external or internal exposures identified. Overall contamination controls were effective. Airborne radioactivity was minimized through use of decontamination and application of engineering controls. There was active l-oversight of implementation of controls by supervisors and managers. (Section R1.1)

e PECO implemented an overall effective ALARA program. ALARA measures were incorporated into work processes. Numerous exposure reduction initiatives were implemented including decontamination, shielding, remote monitoring, use of mock-ups, and work monitoring via closed-circuit television. (Section R1.2)

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Executive Summary (cont'd)

PECO provided appropriate training and qualification of contractor radiological e

. controls personnel and radiation workers involved in outage work activities reviewed. (Section R5)

There was active oversight of the radiological controls program and its j

e implementation. PECO quality assurance personnel performed ongoing performance-based surveillances of radiological controls activities. PECO radiological controls supervisors and managers provided oversight of program implementation and effectiveness. (Section R7)

A fire watch was found asleep in the cable spreading room by the inspectors.

e Based on subsequent observations during the 2R12 outage, this was an isolated occurrence involving a single individual. (Section F1.1)

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o TABLE OF CONTENTS EX EC UTIV E S U M M A RY.............................................. ii TAB LE O F CO NTENTS.............................................. vi Summ a ry of Pla nt Status............................................ 1

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1. Operations

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Conduct of Operations.................................... 1 01.1 G eneral Comme nts.................................. 1

Operational Status of Facilities and Equipment

...................2 O2.1 Residual Heat Removal System Configuration Control (Unit 2).... 2 O2.2 Unit 2 Drywell Close-out inspection...................... 4

Quality Assurance in Operations............................. 4 07.1 Outage Surveillance Performance by the Quality Assurance Org a nization (71707)................................ 4

Miscellaneous Operations issues............................. 5 08.1 (Closed) Inspector Followup item (IFI) 50-277(278)/97-07-01 Outage Overtime Usage and Approvals

...................5 08.2 (Closed) LER 50-277/2-98-005 Suppression Chamber-to-Drywell Vacuum Breaker Not Fully Seated....................... 5 i

ll. M ai nt e n a n c e................................................... 5 M1 Conduct of Maintenance................................... 5 M1.1 Generel O bservations................................ 5 M1.2 Observations of Reactor Core isolation Cooling Turbine Major inspection (U nit 2).................................. 6 M1.3 Incorrect Refuel Floor Vent Exhaust Radiation Detector Disconnected During Calibration........................ 7 M2 Maintenance and Material Condition of Facilities and Equipment....... 9 M2.1 Repeat Failures of 2D Residual Heat RemovalInstrumentation Pi p i n g........................................... 9 M2.2 Alternate Decay Heat Removal Test..................... 10 i

M2.3 Unit 2 Emergency Core Cooling System (ECCS) Suction Strainer Modificatio n P-3 50................................. 1 1 M2.4 Installation of End of Cycle-Recirculation Pump Trip Modification on Unit 2

.......................................12 M3 Maintenance Procedures and Documentation................... 13 M3.1 E-22/E-42 Loss of Coolant / Loss of Off-site Power Functional Tests..........................................13 M4 Maintenance Staff Knowledge and Performance................. 14 M4.1 Unit 3 E-33 Bus Trip Due to inadvertent Operation During a Unit 2 Surveillance Procedure.............................. 14 M4.2 Use of improperly Sized Jumper Leads to Unplanned Core Spray Loop inoperability and Extends Inoperability of Emergency Diesel Generators

......................................16 M4.3 Scram Air Header Replacement Modification (Unit 2).........

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Table of Contents (cont'd)

M4.4 Refueling Platform Activities..........................

M8 Miscellaneous Maintenance Activities

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M8.1 (Closed) IFl 50-277/97-08-02 Unit 2 Circulating Water System

Pro ble m s........................................ 21 l

111. E n g i n e e ri n g.................................................. 21 El Conduct of Engineering................................... 21

E1.1 Pile Testing for the Rock Run Creek Bridge................ 21 l

E2 Engineering Support of Facilities and Equipment

.................23 E2.1 Fire Detection System Non-Conformances (Units 2 and 3)..... 23 i

E2.2 Motor Operated Valve Failures During the Unit 2 Refueling Outage.........................................25 E8 Miscellaneous Engineering issues.

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I E8.1 (Closed) IFl 50-277(278)/97-07-06lmplementation of a Revised Recirculation Flow versus Hours Strategy................. 27

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IV. Plant Support

................................................27 R1 Radiological Protection and Chemistry (RP&C) Controls............ 27 R1.1 Unit 2 Refueling Outage Radiological Controls.............. 27 R1.2 ALARA Program and Unit 2 Refueling Outage.............. 29 l

R5 RP&C Staff Training and Qualification in RP&C.................. 30 R7 Quality Assurance in Radiological Protection and Chemistry Activities.. 31 R8 Miscellaneous issues.................................... 32 R8.1 (Closed) VIO 50-277:278/98-02-04 Failure to Properly implement Radiation Area Procedures

...................32 F1 Control of Fire Protection Activities.......................... 32

F1.1 Fire Watch inattentive to Duties

.......................32 V. Management Meetings..........................................33 X1 Exit M ee ting Sum m ary................................... 3 3 ATTACHMENTS Attachment 1 - List of Acronyms Used

- Inspection Procedures Used-Items Opened, Closed, and Discussed

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Report Details i

Summary of Plant Status PECO operated both units safely over the period of this report.

Unit 2 began this inspection period at 60% power, in end-of-cycle coastdown. The plant was taken offline on September 30,1998, to commence refueling outage 2R12. During j

the outage, a number of maintenance and surveillance activities were conducted and

several major modifications were installed. Modifications performed included the following:

Replacement of the emergency core cooling system suction strainers per Bulletin

96-03 Replacement of the scram air headers i

Installation of wide range nucleai instruments to replace the source and

intermediate range nuclear instruments Installation of an end-of-cycle recirculation pump trip system

in addition, reactor vessel welds were inspected and noble metal chemical addition was.

performed to inhibit future intergranular stress corrosion cracking. The unit went critical on

' November 1,1998 and reached 100% power on November 9.

Unit 3 operated at 100% power throughout this inspection period.

I. Operations

Conduct of Operations 01.1 General Comments a.

Inspection Scope (71707)

The inspectors observed the performance of operations personnel throughout the 2R12 outage. Activities in the control room during the shutdown and startup of Unit 2, were focus areas for this inspection.

b.

Observations and Findinas The inspectors observed very good command and control in the control room during the outage. Very good three part communications, pre-job briefs, alarm response, and alarm response cards (ARCS) usage were also observed. Operators maintained

' Topical headings such as 01. M8, etc., are used in accordance with the NRC standardized reactor inspection report outline. Individual reports are not expected to address all outline topic,_

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good control of access and activities in the control room. The inspectors noted that

operations personnel remained aware of activities that were taking place in the plant. Procedurea were actively used by operations personnel during plant maneuverir.g and testing. Operations personnel routinely used self checking and peer checking when required to manipulate plant equipment. Good reactivity management was noted during the outage. Station and Operations management provided oversight and monitoring of control room activities throughout the outage.

Contrary to the positive performance observations noted above, the inspectors noted several examples of inadequate logkeeping by operations personnel during the inspection period. Most notable were entries in the station log that indicated that both subsystems of main control room emergency ventilation (MCREV) were inoperable at the same time. This condition would have resulted in Unit 3 being in Technical Specification Limiting Condition for Operation (LCO) 3.0.3 which required shutting the unit down within eight hours. The inspectors verified that one subsystem of MCREV had been made operable prior to the other subsystem being removed from service, contrary to the station log entry, c.

Conclusions Very good performance by operations personnel was observed during the Unit 2 outage (2R12). However, some inadequacies with logkeeping practices were noted during the inspection period.

O2 Operational Status of Facilities and Equipment O2.1 Residual Heat Removal System Confiauration Control (Unit 2)

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Insoection Scooe (62707 & 71707)

The inspectors reviewed an occurrence in which operators inadvertently left the 28 residual heat removal (RHR) header vent valves open during restoration of the system.

b.

Observations and Findinas On October 14,1998, during the restoration of the 2B RHR subsystem, operations personnel discovered several hundred gallons of water on the Unit 2 torus room floor. After further investigation, operators discovered that four RHR header vent valves had been left open during the performance of a system fill and vent evolution. The evolution was performed using a temporary, single-use procedure drafted under the Troubleshooting, Rework, and Testing (TRT) process.

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PECO's initial investigation of this event revealed:

The TRT procedure was drafted by an operator just before its intended use.

The operator was a member of operations restoration group, which planned and executed the restoration of systems following outage maintenance activities.

i The four RHR vent valves were omitted from the procedure by the drafter

because he believed that he would be operating the vent valves by a clearance and tagging process after completing the evolution described in the TRT.

The evolution continued past the operations turnover time, and the positions

of the RHR vent valves were not turned over to the relieving crew.

Operations shift supervisors and shift management did not have adequate

time to thoroughly review the TRT.

NRC review of this event indicated:

i The operations restoration group was established only as the outage was

beginning. Members of this group stated that the group should have been established earlier to provide for more thorough planning and supervisory review. Plant management indicated that this fact was identified as a lessons-learned item for the outage.

This issue was very similar to a configuration control issue described in NRC

inspection report 50-277(278)/98-08,in which poor turnover of system status between shift crews led to valves being mispositioned in the reactor water cleanup system.

Use of the one time TRT procedures created challenges for operators earlier

this year.

The inspectors determined that this event was indicative of on-going challenges at the station in the area of system status and configuration control. Similar issues were cited in Notices of Violation in NRC Inspection Reports 50-277(278)/98-08 and 98-01. The inspectors concluded that PECO did not have sufficient time to fully implement corrective e.ctions for these previous issues. Therefore, this event war not subject to formal enforcement action.

Plant management stated that they have begun a major initiative to improve configuration control and to reduce the number of system status control events.

This effort involved operations, maintenance and engineering personnel.

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Conclusions l

An incomplete, one-time use procedure and a poor turnover between operators during system restoration caused four residual heat removal system vent valves to be left mispositioned. These mispositioned valves resulted in several hundred gallons of water from the 2B RHR subsystem spilling onto the Unit 2 torus room

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floor. This event was indicative of continued station challenges in the area of plant / system status control.

02.2 Unit 2 Drvwell Close-out inspection a.

Inspection Scope (71707)

On October 30,1998,the inspectors performed a close-out inspection of the Unit 2 drywell at the end of 2R12 to verify that material used during the outage had been removed end that the drywell was ready to facilitate plant start-up, b.

Observations and Findinas The inspectors observed that housekeeping was required in the outboard main steam isolation valve room, to remove a hose fitting and maintenance related debris and to prcperly installlagging. These housekeeping activities were all completed prior to startup.

The inspectors also observed that the drywell was very clean. The inspectors had no concerns with the condition of the drywell for startup.

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Conclusions The Unit 2 drywell was found to be very clean and ready for restart at the end of the 2R12 outage.

Quality Assurance in Operations 07.1 Outaae Surveillance Performance by the Quality Assurance Oraanization (71707)

The inspectors noted that quality assurance personnel performed numerous surveillances during the 2R12 outage. Survoillances covered the activities of operations, maintenance, contractor personnel, engineering, health physics, chemistry, and security. Several minor issues were identified during these surveillances, including administrative weaknesces with procedures and foreign material exclusion controls. More significant issues were also identified by quality assurance personnelincluding work performed outside of the scope of a testing and centrol procedure for a 600 volt molded case circuit breaker and the 'dentification of

plant squioment that was mispositioned during a testing evolution. The inspectors l

concluded that quality assurance personnel performed substantial oversight of various activities and provided very good insights into the performance of all work

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groups involved with the 2R12 outage.

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08 Miscellaneous Operations issues 08.1 [Qlpsed) Inspector Followuo item (IFI) 50-277(278)/97-07-010utaae Overtime Usaae and Acorovals NRC Inspection Report 50-277(278)/97-07 documented concerns with overtime approval controls for work on safety-related activities. Specifically, the inspectors noted that project managers involved with the emergency core cooling system (ECCS) suction strainer modification were given blanket overtirne approvals and worked excessive hours for multiple weeks with no hourly limits specified.

During the 2R12 refueling outage, the inspectors reviewed overtime approval records for several work groups. The inspectors also made spot checks of overtime usage, particulaily for personnel involved with the ECCS suction strainer modification and for operators, and discussed the management of overtime work with a number of personnel. The inspectors determined that overtime approvals were well-controlled, and had adequate justification. The inspectors concluded that plant management had taken effective corrective actions for this matter.

08.2 (Closed) LER 50-277/2-98-OO5Sucoression Chamber-to-Drvwell Vacuum Breaker Not Fuily Seated NRC Inspection Report 50-277(278)/98-08 documented a non-cited violation (NCV)

in which operators did not verify that a torus to-drywell vacuum breaker was closed within 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months of the discovery of an unreliable indication, as required by technical specifications. The event was caused by the failure to adhere to equipment operator rounds and log review practices by operations p.srsonnel.

The inspectors performed an on-site review of the LER, which documented this event, and concluded that no new issues were identified.

ii. Maintenance M1 Conduct of Maintenance M 1.1 General Observations NRC Inspection Procedures 62707 and 61726 were used in the inspection of plant maintenance and surveillance activities. The inspectors observed and reviewed selected portions of the maintenance and surveillance test activities listed in Attachment 2.

l The work and testing performed during these activities was professional and I

generally thorough. Technicians were experienced and knowledgeable of their assigned tasks. The work and testing procedures were normally present at the job site and actively used by the technicians and operators for activities observed.

Good pre-job briefs were observed prior to the performance of the surveillances l

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l observed. Applicable procedures were present in the control room and at the job l

sites during surveillance testing and were appropriately used.

l Early in the 2R12 outage, the inspectors identified that a scaffold erected in the l

vicinity of a 2 'C' core spray (CS) discharge check valve inhibited the full travel of the actuator arm for the valve. The licensee immediately relocated a scaffold brace, initiated a PEP and evaluated the as found configuration. The licensee concluded that the check valve travel was 50 degrees and the as found configuration would allow 49 degrees of travel based on measurements taken from design drawings and from the as found photographs. The lic;nsee concluded that the valve remained operable since system flow would not be significantly affected unless valve travel was inhibited by more than 10 degrees. Subsequent corrective actions included walk downs of other scaffolds in the vicinity of safety related equipment and a revision to the scaffold specification checklist to ensure that scaffolds did not interfere with equipment operation such as check valves.

Later in the outage, Quality Assurance personnel identified that scaffolding was erected at the east end of the Unit 2 reactor recirculation motor-generator sets.

This scaffolding cnclosed the sample transport cask for the Unit 2 and 3 post-accident sampling system (PASS) thus rendering it unavailable for timely transport of PASS samples in case of an accident on Unit 3. Contractor personnel immediately rebuilt this scaffolding, to allow use of the PASS sample transport cask, after this issue was identified.

Both of these examples represented instances where scaffolding was not adequately inspected by contractor personnel during construction to ensure that it did not interfere with plant equipment.

M1.2 Observations of Reactor Core isolation Coolina Turbine Maior inspection (Unit 2)

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Insoection Scoce (62707)

The inspectors observed portions of a major inspection / overhaul performed on the reactor core isolation cooling (RCIC) turbine during the 2R12 outage, b.

Observations and Findinas During mid-October 1998, the inspectors observed Nuclear Maintenance Division (NMD) technicians performing planned maintenance on the RCIC system per procedure M-C 750-001,"RCIC Turbine Major inspection." The inspectors saw that the technicians were actively using the work procedure and were making sign-offs as appropriate. The technicians were knowledgeable of their assigned tasks.

l On October 14,1998, the inspectors identified that a temporary spool piece on the

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RCIC turbine steam supply piping was not torqued per the guidance in M-C-750-001. The procedure noted that the spool piece should be torqued using information in procedure MAG-CG-301, which referred to a third document, PECO Energy

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Specification N-004. Although the technicians appropriately requested assistance l

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'from NMD technical staff, the guidance provided by the technical' staff was l

incorrect. As a result, the spool piece flanges were under-torqued by approximately 20%. The inspectors brought this to the attention of plant engineering and NMD personnel, who reviewed the documentation and corrected the condition before

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j steam was introduced to th'e system.

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NMD supervision discussed this finding with maintenance and technical staff

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members and reviewed the apparent causes. They concluded that some steps in l

the M-C-750-OO1 procedure should be revised to provide technicians with specific

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torque values, rather than expecting them to research two additional documents to determine a torque value. Corresponding steps for the M-C-750-OO1 common procedure used at Limerick provided specific torque values.

The inspectors verified that a procedure change request was initiated for procedure M-C-750-OO1. The inspectors considered the corrective actions to be adequate, c.

Conclusions Reactor Core Isolation Cooling (RCIC) system turbine maintenance activities were

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performed according to procedures. However, a procedural weakness and inaccurate direction by NMD technical staff led to the improper torquing of a system spool piece, which was identified by the inspectors.

M1.3 incorrect Refuel Floor Vent Exhaust Radiation Detector Disconnected Durina Calibration a.

Inspection Scooe (62707)

The inspectors reviewed documentation and discussed with chemistry personnel, the inadvertent removal of the refuel floor vent exhaust radiation monitor, RIS-2-17-458D, and subsequent dropping and damage to this detector, b.

Observations and Findinas

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On August 10,1998, chemistry technicians were performing ST-C-095-878-2,

" Refuel Floor Vent Exhaust Rad Monitor Calibration and Functional Test for RIS-2-17-458A and C." During calibration of the 'C' detector, the technicians in the field inadvertently removed and dropped the 'D' detector, RIS-2-17-458D. The peer check technician in the control room noted that the downscale light was on the 'D'

detector and questioned the technicians in the field. The technicians in the field indicated to the technicians in the control room that the 'D' detector was disconnected and had been dropped. The technicians in the field reconnected the

'D' detector and continued on with the calibration of the 'C' detector. None of the

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i technicians notified any control room operations personnel or Chemistry Supervision of the dropped detector prior to resuming the calibration of the 'C' detector.

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During the calibration of the 'C' detector, the peer check technician in the control room noted that the 'D' detector downscale light again came on. The lead chemistry technician notified operations personnel and wrote an Action Request (ARi for the detector. The technicians did not document on the AR that they had inadvertently removed the 'D' detector and dropped it. The General Procedure (GP)-25, Appendix 8 was appropriately entered and the Group lli, Channel B trip was properly inserted for the inoperabh; RIS-2-17-458D as required by Technical

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l Specifications.

On August 11,1998 instrument and control personnel determined that detector l

RIS-2-17-458Dwas not working correctly because it had been damaged and l

installed a new detector. On August 12,1998, the Chemistry Manager started an l-investigation of the damaged 'D' detector. The investigation included interviews

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with the chemistry technicians who performed the calibration. It was during the interviews that Chemistry Supervision became aware that the 'D' detector was I

inadvertently removed and dropped. The issue was documented in PEP 10008822.

The inspectors reviewed the PEP 10008822 and ST-C 095-878-2and discussed this issue with chemistry personnel. The licensee's invectigation noted that Step 4.4.3 j

of ST-C-095-878 2was not implemented when the 'D' detector was inadvertently

pulled and dropped. Step 4.4.3 required the technicians to stop the test and notify i

operations personnel in the control room and Chemistry Supervision and request permission to continue to the next applicable step when any procedure step i

produced an unexpected response. In addition, the licensee investigation noted that

,

the actions of the chemistry technicians to wait for days to tell details about the

'

event, and only when asked, was not acceptable behavior. The licensee expected i

openness, integrity,'and accountability to self idertify errors made during I

perforrnance of the procedure.

l PECO rnanagement has addressed the behavior issue with the individual technicians involved in the event. The corrective action for PEP 10008822 included communicating this event to all chemistry personnel including expectations of proper behavior involving procedural compliance and was completed by the end of the inspection period. However, the inspectors were concerned that the corrective actions in the PEP only focused on the chemistry department and did not include the other departments at the station. Procedural non-adherence has been an issue i

at the station for the past year and was stressed in the Peach Bottom "Back to l

Basics" plan.

'

Technical Specification 5.4.1 requires that written procedures be established, implemented, and maintained covering activities as recommended in Regulatory Guide 1.33, Appendix A, November 1972. These activities include surveillance tests for process radiation monitoring calibrations, i

Contrary to the above, on August 12,1998, the licensee failed to properly l.

implement Step 4.4.3 of the process radiation monitor calibration test, ST-C-095-

!

878-2, when the 'D' refuel floor vent exhaust radiation detector was dropped.

l Specifically, chemistry technicians failed to stop the test and notify the reactor t

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operator or Shift Managemerit and Chemistry Supervision and request permission to continue to the next applicable step when they dropped the detector. Normally this issue would have resulted in a non-cited violation, but since more than one chemistry technician was involved and corrective actions were narrowly focused, a violation will be issued in accordance with our Enforcement Policy. (VIO 50-277/98-10-01)

c.

Conclusions On August 10,1998, chemistry technicians were performing ST-C-095-878-2,

" Refuel Floor Vent Exhaust Rad Monitor Calibration and Functional Test for RIS-2-17-458A and C." During calibration of the 'C' detector, the technicians

,

inadvertently removed and dropped the 'D' detector. The technicians performing l

this work did not stop and notify the control room operations personnel or

'

Chemistry Supervision that they had removed the 'D' detector and dropped it even i

though they were directed by ST-C-095-878-2to report any unexpected conditions.

The behavior of the technicians to not tell details about the event for several days, and only when asked, was not acceptable. The licensee corrective actions were

'

narrowly focused on the chemistry department and did not include the other

)

departments at the station. Procedural non-adherence has been an issue at the station for the past year. This was considered a violation of the station Technical Specifications for not properly implementing procedures.

]

M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Repeat Failures of 2D Residual Heat RemovalInstrumentation Pioina a.

inspection ,coce (62707)

'The inspectors reviewed actions taken for two minor through-wallleaks at the same location on the 2 'D' residual heat removal (RHR) loop instrumentation piping, b.

Observations and Findinas On October 16,1998, during a routine tour of the reactor building, the inspectors identified a minor leak on the 2 'D' RHR loop. The leak was a through-wall piping leak at a weld on a 3/4-inch instrumentation piping tee, downstream of the 2D RHR pump. Operators had placed the 2 'D' RHR loop in service for shutdown cooling approximately two hours before the discovery. Operators appropriately declared the 2 'D' RHR shutdown cooling subsystem inoperable based on operations manual guidance, and they requested engineering assistance.

Maintenance personnel completed repairs on the leaking instrumentation piping on October 18,1998. They performed an in-shop weld and then replaced the tee and adjacent sections of piping / tubing. All welds passed visualinspection and dye penetrant testing. Following installation, the piping passed a post-maintenance pressure test at normal operating pressur._

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l On October 22,1998, a health physics technician observed another leak at the i

same weld location that had been repaired. Maintenance personnel determined that I

the shop weld performed four days earlier had failed. Subsequent repairs to this weld were successful.

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At the conclusion of the inspection penod, maintenance and engineering personnel

,

were continuing to investigate the potential causes of the initial weld failure and subsequent failure of the shop weld. The investigation was being tracked in the Performance Enhancement Program (PEP) corrective action process.

c.

Conclusions A minor through-wallleak at a weld on the 2D residual heat removal (RHR) loop instrumentation piping was repaired, but a shop weld failed four days later.

Maintenance and engineering personnel were continuing to investigate the potential causes of this subsequent failure.

M2.2 Alternate Decav Heat Removal Test a.

Inspection Scope (61726)

On October 6,1998, the inspectors observed the performance of abnormal operating procedure AO 10.4-2, Residual Heat Removal (RHR) System Shutdown Cooling Mode - Fuel Pool to Reactor Mode. The inspectors reviewed the procedure and the technical specifications, and discussed the procedures impact on system operability with the system manager and persons of the operations staff, b.

Observations and Findinos The intent of procedure AO 10.4-2 was to verify an alternate decay heat removal (ADHR) flowpath in the event the normal shutdown cooling flowpath becomes unavailable. The procedure can only be utilized in Mode 5, Refueling, with the fuel pool gates to reactor cavity removed. The procedure aligned the 2A RHR pump suction to the spent fuel pool skimmer surge tank and discharged through the

- normal path to the recirculation loop.

The system manager and unit supervisor controlled the test well. Individuals assigned to operate various valves in the plant attended a pre-task briefing in the main control room and understood the purpose of their functions. The isolation of the normal shutdown cooling suction flowpath did not render the shutdown cooling mode of operation inoperable per Technical Specification 3.9.7. However, PECO did suspend all core alterations, maintained the secondary containment and the standby gas treatment systems operable, and implemented GP-12, " Core Cooling Procedure" during the test.

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Conclusigna PECO operators performed the test of the alternate decay heat removal flowpath well. The reactor cavity and spent fuel pool water inventory, temperature, and clarity was maintained within the required limits.

M2.3 Unit 2 Emeraency Core Coolina System (ECCS) Suction Strainer Modification P-350 l

a.

Insoection Scope (62707)

i The inspectors monitored the foreign material exclusion (FME) controls and work activities for the modification to the ECCS suction strainers. Particular attention was directed toward activities involving material and personnel access control to the strainer elements and the torus.

i b.

Observations and Findinas d

To permanently increase the net positive suction head of the ECCS pumps in

!

accordance with NRC Bulletin 96-03, PECO performed a major modification of the suction strainers for core spray (CS) and residual heat removal (RHR) systems

'

during 2R12. This modification consisted of the replacement of the existing, eight,

ECCS suction strainers, with larger, modular assemblies supported from the torus ring girders. This modification was completed on Unit 3 during the last refueling outage. Foreign material was introduced into the CS system when this modification was performed during the previous Unit 3 outage, which resulted in the 3 'A' CS pump becoming inoperable.

The inspectors noted that PECO reviewed and revised the FME plan, emergency plan and required FME training for the Unit 2 modification as part of the correctlye actions from the event involving the foreign materialin the 3 'A' CS pump. The revised FME training sessions were good, providing the essential elements of the FME plan and stressed the safety reasons for following the plan and procedures.

Quality Assurance (QA) assessors performed several surveillance activities during i

the' ECCS suction strainer modification. The surveillances consisted of reviews and observations of various work activities involving installation of the strainer assemblies. Minor discrepancies in FME controls and work planning for the ECCS suction strainer modification were documented by QA.

'

Each access to the torus had an FME attendant to control and maintain a log of the FME material accountability. The inspectors reviewed the logs and interviewed the attendant and found that the attendants understood their responsibilities. The logs were properly maintained. The attendants were rotated often to ensure alertness.

The inspectors toured the torus during a test of the 'B' CS system and no abnormal conditions were noted while the test was being performed. The inspectors conducted random tours, attended pre-shift briefs, observed work activities in the i

torus via cameras, and the inspected access points during the strainer replacement l

modification work. The inspectors observed that work practices for the control of l

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FME, movement of strainer elements, and access control to the torus were greatly improved when compared with the modification performed during the previous Unit 3 outage. Health Physics personnel were wellintegrated into the work processes l

and provided continual coverage during modification activities. The inspectors did l

identify a riggers glove in an FME exclusion area and some minor discrepancies with l

FME material accountability log keeping and the FME dropped log.

l The inspectors observed and performed selected reviews of the CS and RHR pump testing data from post strainer modification testing and independently determined that the ECCS pumps would be capable of performing their safety function. The-l inspectors also verified that the station engineering staff had ensured that there was

!

no degraded performance with any CS or RHR pump after the modification.

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c.

Conclusions PECO completed the ECCS suction strainer replacement modification, from NRC Bulletin 96-03 commitments, during the during the 2R12 outage. The FME and I

work control activities were greatly improved from the modification performed during the previous Unit 3 outage and were effective in ensuring that no foreign

,

'

material was left in the ECCS systems. The modified sys+ ems were verified operable during post-maintenance testing.

M2.4 Installation of End of Cvele Recirculation Pumo Trio Modification on Unit 2 a.

Inspection Scoce (62707)

During the 2R12 outage, PECO installed a modification on both of the Unit 2 recirculation pump motors. This end of cycle-recirculation pump trip modification initiates a pump trip to reduce the peak reactor pressure and power resulting from

turbine trip or generator load transients and to minimize the decrease in core Minimum Critical Power Ratio (MCPR) during these transients. The inspectors observed portions of the mcdification installation and discussed the modification with electrical maintenance contractors and site engineering personnel. The inspectors also reviewed several modification work packages, post-maintenance test results, and surveillance reports detailing observations and findings by Quality Assurance personnel.

l b.

Observations and Findinas Modification work observed by the inspectors was performed in a professional manner and in accordance with procedures. Work procedures were present at the job site and were actively used. Maintenance personnel were knowledgeable of their assigned tasks.

The inspectors reviewed the Acceptance Test Plan for this modification and identified no concerns. Results obtained during testing met acceptance criteria.

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The inspectors determined that installation and testing activities for the end of

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cycle-recirculation pump trip modification were well performed and met procedural j

requirements, i

c.

Conclusions During the 2R12 outage, PECO installed a modification on both of the Unit 2 recirculation pump motors. This end of cycle-recirculation pump trip modification initiates a pump trip to reduce the peak reactor pressure and power resulting from (

turbine trip or generator load transients and to minimize the decrease in core Minimum Critical Power Ratio (MCPR) during these transients. Overall, installation and testing activities for the end of cycle-recirculation pump trip modification were well performed and met procedural requirements.

M3 Maintenance Procedures and Documentation M 3.1 E-22/E-42 Loss of Coolant / Loss of Off-site Power Functional Tests a.

Inspection Scope The inspectors observed portions of ST-O-054-752-2,"E-22 4kV Bus Undervoltage Relay and LOCA LOOP Functional Test and E-22 and E-224 Alternate Shutdown Control Functional Test;" and ST-O-054-754-2,"E-42 4kV Bus Undervoltage Relay and LOCA LOOP Functional Test and E-42 and E-424 Alternate Shutdown Control Functional Test."

b.

Observations and Findinas These surveillances functionally tested the operation of the undervoltage relays and the sequentialloading for the E-22 and E-42 4kV emergency busses. Due to suppression pool strainer replacement, PECO conducted these tests with the major emergency bus load breakers in the test pori ion so that the RHR or CS system t

pumps would not start. The automatic system actuation portions of the tests were performed later in the outage.

Overall, the operators performed the functional tests well. However, the MCREV automatically initiated during the performance of the E-42 test on October 7,1998..

This occurred because power to the motor control center (MCC) feeding the high radiation signal to the MCREV was de-energized during the test. The procedure, ST-O-054-754-2,did not warn or caution the operators that this emergency safeguard function actuation would occur. This event was similar to others during the past year involving unexpected plant equipment responses.

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Another potential challenge was identified prior to the E-22 test. The test director discovered, just before starting the test, that the Unit 2 secondary containment blue light system would be disabled for over ten minutes during the test. The blue light

)

was providing access controlinto the secondary containment while the test was

'

run. Again, the procedure did not warn or caution the operators about this condition.

PECO's corrective actions included submitting procedure changes to revise the -

-!

tests. These changes included warnings and cautions of equipment status changes.

The procedure, ST-O-054-752-2,was changed prior to starting the E-22 test.

The inspectora noted that the automatic initiation of the MCREV was not reportable because the initiation of the system was not due to a valid signal. However, both tests were delayed and operations personnel were forced to respond to these unexpected challenges, i

c.

Conclusions

.

Operations staff were unnecessarily challenged during the performance of the E 22 and E-42 Loss of Offsite power / Loss of Coolant Accident functional tests, due to surveillance test procedure weaknesses. This issue was similar to others documented in NRC Inspection Report 50-277(278)/98-07,where inadequate procedures resulted in unexpected plant equipment responses.

M4 Maintenance Staff Knowledge and Performance M4.1 Unit 3 E-33 Bus Trio Due to inadvertent Operation Durino a Unit 2 Surveillance Procedure a.

Inspection Scope (61726 & 62707)

On October 25,1998, the Unit 3 E33 bus was inadvertently tripped during the performance of a surveillance procedure that functionally trip tested the E32 and E324 bus overcurrent relays. The inspectors reviewed the surveillance procedure and discussed this event with operations and instrument and control (l&C)

personnel, b.

Observations and Findinas -

During performance of Sl2M-54-E32-XXF4, Revision 2, " Functional Trip Test of E32

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and E324 Bus Overcurrent Relays," an l&C technician inadvertently actuated the 'A'

phase differential relay on the E33 bus causing the bus to trip and lockout. This resulted in an 'A' channel half scram, a full reactor water clean up isolation, loss of the 'C' standby gas treatment fani an inboard primary containment isolation system group 3 isolation and subsequent loss of reactor building ventilation, and a half primary containment isolation system group 1 isolation that did not cause any valve motion. Control room personnel entered T-103, Revision 11, " Secondary

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Containment Control" due to high main steam line tunnel temperatures caused by

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the trip of the reactor building ventilation. Procedure, T-103, was exited after the reactor building ventilation was restarted and the mainsteam line tunnel temperatures returned to normal. Since this event caused several automatic engineered safety feature (ESF) actuations, operations supervision made a four hour notification to the NRC per 10 CFR 50.72.

Relays for the E32 and E33 are located side by side on the same panel and were identical. Instrument and control technicians had initially verified that they were on the correct relay. When they asked permission from the control room operator to perform the next step in Sl2M-54-E32-XXF4 which actuated the E32 differential relay, the operator requested that they hold for a few minutes. During this time, their attention was diverted from the relay. When the technicians returned to the relay, they verified that they were still on the 'A' phase relay but they failed to re-verify that they were on the correct bus. As a result, the l&C technician inadvertently pushed the 'A' phase differential relay trip test button on the Unit 3 E33 bus instead of the Unit 2 E32 bus.

After this action occurred the technicians recognized their mistake and informed the control room operators. The test was stopped and operations personnel took actions to mitigate the Unit 3 response to the loss of the E33 bus. Instrument and control personnel placed yellow stickers on the E33 bus relays after this event until Sl2M-54-E32-XXF4 was completed. The test procedure was completed satisfactorily without any edditional events. Failure by the I&C technicians to adequately verify that they were on the correct relay was documented as the root cause of this event in PEP 10009105.

The inspectors performed a walkdown of the panel containing the E32 and E33 'A'

phase differential relays. The inspectors also reviewed S12M 54-E32-XXF4 and discussed this event with l&C and operations personnel. The inspectors did not identify any inadequacies with the instructions in Sl2M-54-E32-XXF4.

The inspectors identified no violations of NRC requirements due to this event.

However, the inspectors determined that inadequate self-checking and peer checking by the l&C technicians performing Sl2M-54-E32-XXF4 caused the de-energization of the Unit 3 E33 bus and subsequent automatic ESF actuations.

c.

Conclusions On October 25,1998, the Unit 3 E33 bus was inadvertently tripped during tne performance of a surveillance procedure that functionally trip tested the E32 and E324 bus overcurrent relays. This resulted in an 'A' channel half scram, a full reactor water clean up isolation, loss of the 'C' standby gas treatment fan, an inboard primary ccntainment isolation system group 3 isolation and subsequent loss of reactor building ventilation, and a half primary containment isolation system group 1 isolation that did not cause any valve motion. Control room personnel entered T-103, Revision 11, " Secondary Containment Control" due to high main steam line tunnel temperatures caused by the trip of the reactor building ventilation.

Procedure, T-103, was exited after the reactor building ventilation was restarted

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and the mainsteam line tunnel temperatures returned to normal. Since this event caused several automatic engineered safety feature (ESF) actuations, operations supervision made a four hour notification to the NRC per 10 CFR 50.72.

No violations of NRC requirements occurred due to this event. However,

inadequate self-checking and peer checking by the instrument and control technicians performing the surveillance procedure were determined to be the root

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. cause of this event.

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M4.2 Use of Imoronerly Sized Jumper Leads to Unolanned Core Sorav Looo inoperability and Extends Inoperability of Emeroency Diesel Generators a.

Inspection Scope (61726)

The inspectors reviewed an event during the 2R12 outage where a blown fuse led to an unplanned inoperability of the 2 'B' CS system and extended the inoperability period for all four emergency diesel generators (EDGs).

b.

Observations and Findinos On October 28,1998,l&C technicians and operators conducted surveillance test ST-O-052-190-2," Simultaneous Start of All Emergency Diesel Generators." A step

,

' in the test procedure required the installation of an alligator clip jumper between I

two relay contacts. The technicians determined that a jurnper about 10" long was needed; however, they did not have one staged for the test. Instead, they connected two jumpers together that ended up significantly longer than 10". As the jumpers were being installed, one jumper began to slip from a terminal post due

,

to the weight of the jumpers. When the technician reached to make an adjustment, the other end of the jumper came in contact with a terminal post associated with

the 2 'B' CS loop. This caused a fuse to blow in the 2 'B' CS logic, rendering this loop inoperable for a period of about 40 minutes.

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The blown fuse caused delays in the EDG surveillance testing. These delays extended the amount of tirr.4 that all four EDGs were inoperable and exceeded a

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one-hour limit allowed by the surveillance test procedure. Operators entered appropriate technical specification action statements for both the 2 'B' CS system and all four EDGs. No technical specification violations occurred.

Instrument and Control supervisors stated that the technicians should have performed a more thorough job brief and walkdown. This would have allowed staging of a jumper of suitable length to appropriately perform the test procedure step. Instrument and Control supervisors also noted that the technicians should

.

have stopped the test to obtain the proper jumper.

The inspectors reviewed some of the follow-up activities for this issue and discussed them with l&C supervisors. The inspectors determined that this event revealed minor performance weaknesses among l&C technicians related to pre-job walkdowns and use of appropriate tcst equipment.

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c.

Conclusions A poor pre-Job walkdown and the use of an inappropriately sized jumper by

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Instrumentation and Controls technicians led to an unplanned 2 'B' core spray loop inoperability and an extended period of inoperability for all four emergency diesel generators.

L M4.3 Scram Air Header Reolacement Modification (Unit 2)

I a.'

Inspection Scope (62707)

l l

l-The inspectors observed portions of outage maintenance activities associated with the Unit 2 scram air header replacement modification. The work, performed by contractors, included replacement of copper tubing, installation of flexible hoses and isolation valves, and performance of post-maintenance testing.

b.

Observations and Findinas During walkdowns of the new scram air header tubing, the inspectors observed that the ends of several sections of tubing were left uncovered while workers were j

away from the work area. This was contrary to specific instructions in the work

'

order, C0180288," Plan and install New Air Header," which stated that "all tubing will have the ends covered when not being worked on." In addition, the inspectors

]

noted that Engineering Change Record 97-03241, included in the work package,

'

stated that " extreme caution shall be used during installation activitier to prevent any foreign materials of any kind from entering the control rod drive (CRD) air system."

The inspectors observed that other work groups were performing maintenance

!

activities in the vicinity of the scram air header, creating the possibility of foreign material entering the open ends of the tubing. Foreign materialin the scram air header tubing was a concern due to the potential to affect the performance of the scram solenoid pilot valtes (SSPVs). The inspectors notified the system manager of the open tubing ends, and Nuclear Maintenance Division (NMD) personnelinstalled suitable covers consistent with station administrative procedures for foreign material

,

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exclusion.

The inspectors noted that later steps in work order C0180288 provided for

~ blowdowns of the scram air header for removal of foreign material. These steps

!

significantly reduced the potential for foreign material remaining in the system j

following the completion of maintenance. The inspectors concluded that the non-l adhuence to the work order was a minor issue not subject tc formal enforcement action; however, it was indicative of poor foreign material controls practices by the contractor work group and weak oversight by PECO personnel.

l The inspectors noted that, following post-maintenance testing on the scram air

header, operations personnel were concerned about a number of minor leaks on the tubing connections between the scram air header and the SSPVs. Maintenance t

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. personnel generated an action request documenting over 30 air leaks. Rework procedures and work orders were subsequently drafted to address these leaks.

Maintenance personnel stated that many of the leaking joints were disturbed during the scram air header work.

During walkdowns following post-maintenance testing, NMD personnel also identified and replaced kinked tubing between the scram air header and the SSPVs on three hydraulic control units (HCUs). This tubing was supposed to have been inspected and replaced, as necessary, by the scram air header replacement work order, C0180288.

i The inspectors also noted that PECO did not enter the poor foreign material control practices or the re-work issues described above into any of the corrective action

processes. These issues appeared to meet the criteria for entry into the licensee's corrective action program (i.e. Performance Enhancement Program (PEP)).

c.

Conclusions Contractor personnel performing modification work on the Unit 2 scram cir header exhibited poor foreign material control practices, contrary to specific work order instructions. Weaknesses in contractor oversight were identified by these poor practices, in addition, PECO personnel did not enter the poor foreign material control practicos into any of the station corrective action processes even though this issue appeared to meet the criteria for entry into the Performance Enhancement

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Program (PEP)

M4.4 Refuelina Platform Activities a.

Insoection Scoce (60710 & 71707)

The inspectors observed portions of core alterations and Senior Licensed Operator Limited to Fuel Hardling (LSRO) shift turnovers from the refueling platform during 2R12. The inspectors reviewed documentation used during an incorrect movement of a fuel bundle and improper orientation of two other fuel

<

bundles. These issues were also discussed with Nuclear Maintenance Department personnel responsible for fuel movements.

b.

Observations and Findinas Generally, core alterations were conducted in a orderly and professional manner in accordance with procedure FH-6C, " Core Component Movement - Core Transfers."

The Senior Reactor Operator Limited to Fuel Handling (LSRO) directed all core alterations and was in constant communication with the reactor operator in the Unit 2 control room. Communicat;ons were precise and conducted prior to and after every significant step of the Core Component Transfer Authorization Sheet (CCTAS). The LSRO properly maintained the CCTAS after performing each step.

The shift turnover between LSRO's was found to be formal, orderly, and well documented.

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i The inspectors verified that the LSRO and RPO qualifications were current. The

inspectors also verified that secondary containment was in effect and that the standby gas treatment (SBGT) system was operable during fuel movements as required.

During the morning of October 22,1998, the refueling floor operators removed a fuel bundle at core location 23-50 (southwest orientation) rather than the specified i

23-52 (southeast orientation). The LSRO, noting the hole left by the removed fuel

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bundle, discovered that the wrong bundle had been fully removed from the core.

'

Following the discovery, core alterations were suspended and site management and

reactor engineering were notified. The fuel bundle was returned to the proper

location and a stand-down was held. The on-coming fuel handling crew reviewed and discussed the event as part of the shift turnover process.

The licensee determined that the primary cause of the wrong bundle movement was i

related to poor verification techniques. Fuel bundle location and orientation were

,

required to be double-verified in the resctor vessel and spent fuel pool by the i

Refueling Platform Operator (RPO) and the Spotter. They used the channel fastener location as viewed in the mast camera to determine the orientation and location of f

the bundle. After noting the channel fastener orientation in the mast camera monitor, the position of the platform operator was used to correlate the mast position with the location of the fuel bundle shown on the monitor image. In this case, the platform operator was standing 90 to the side (southeast) while holding o

the mast in the incorrect southwest orientation. The RPO failed to adequately self-check and the Spotter failed to adequately peer-check that the correct fuel bundle i

had been selected prior to moving the bundle.

,

.

During the afternoon of October 22,1998, fuel floor operators inserted a fuel bundle with an improper orientation. The bundle was inserted in the southwest orientation instead of the required southeast orientation. The LSRO discovered that j

the bundle was incorrectly oriented before it was ungrappled.

Following the discovery of this error, core alterations were again suspended and licensee management and reactor engineering were notified. A change was made

,

to the CCTAS and the fuel" as raised, re-oriented and properly inserted into the

core. A fact finding session was held with the crew involved in this second event.

The RPO and Spotter involved with this error stated that they had become misoriented on the bridge during the fuel bundle move. Again, the RPO failed to perform an adequate self-check and the Spotter failed perform an adequate peer-

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check during this fuel bundle move.

The licensee's corrective actions for this second event included:

installing supplemental coordinate markers on the bridge

increasing the exclusion zone around the General Electric Reactor Inspection

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System (GERIS) vessel weld inspection device

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reiterating management's expectations regarding LSRO responsibilities

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re-directing control room communications to the fuel coordinator instead of

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the LSRO The inspectors noted that this second error, while somewhat different than the first, involved a common element of inadequate verification of fuel bundle orientation.

This event occurred only about 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months after the first, even though corrective actions were implemented from the first error.

l l

On October 24,1998, core alterations were suspended for a third time due to a

mis-oriented fuel bundle in the spent fuel pool. Investigation by the licensee

!

determined that this mis-orientation happened on October 12,1998, but remained undetected until October 24. The licensee evaluated this error and determined that the corrective actions from the two other errors were adequate for the remainder of l

l the core alterations. Refueling personnel successfully completed core alterations l

following this third error. A full core verification was performed after completion of fuel movements.-

The inspectors learned during discussions with refueling personnel that the licensee had changed the setup for the mast camera prior to this outage. The new setup required more effort by the fuel handing crew to verify the orientation and location of fuel bundles.

The inspectors reviewed the PEP 10009087 and discussed all three of the core alteration errors with the Nuclear Maintenance Department manager. The inspectors reviewed SO 18.1.A-2, Revision 5," Operation of Refueling Platform."

Section 4 of SO 18.1.A-2 specified that refueling platform operators were to position the refuel mast over the desired core component in accordance with the CCTAS and required a double verification by the LSRO, RPO or Spotter that fuel bundles were at the proper location and orientation. These steps were improperly performed on the three occasions described above.

i Technical Specification 5.4.1 requires that written procedures be established, implemented, and maintained covering activities as recommended in Regulatory Guide 1.33, Appendix A, November 1972. These activities include core alterations.

Contrary to the above, on October 12 and 22,1998, on three separate occasions, refueling personnel failed to properly implement Section 4 of SO 18.1.A 2. This resulted in a violation of Technical Specification 5.4.1, " Procedures." However, the inspectors noted that the errors were licensee identified as a result of observations made by refueling personnel. In addition, the inspectors concluded that station l

personnel eventually took adequate and reasonable corrective actions for the errors

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involving the three refueling bundles described above. This non-repetitive, licensee-

!

identified and corrected violation is being treated as a Non-Cited Violation (NCV),

consistent with Section Vll.B.1 of the NRC Enforcement Policy. (NCV) 50 277/98-10-02 I

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Conclusigr}

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Generally, core alterations during the 2R12 outage were conducted in a orderly and

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professional manner using precise communications and thorough shift turnover.

However, three fuel movement errors occurred during the refueling activities on October.12 and 22,1998. These errors were caused by a failure to properly verify

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component location and orientation as required by procedure. The Refueling Platform Operator failed to perform an adequate self-check and the Spotter failed i'

perform an adequate peer-check during these fuel bundle moves. These errors I

resulted in a violation of Technical Specification 5.4.1, " Procedures." This non.

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repetitive, licensee-identified and corrected violation is being treated as a Non-Cited

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Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy.

I M8 Miscellaneous Maintenance Activities

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M8.1 (Closed) IFl 50-277/97-08-02 Unit 2 Circulatina Water System Problems in January 1998, circulating water (CW) system problems resulted in operational transients on two different occasions. During the first event, the 2 'C' CW pump tripped unexpectedly, and an initial attempt to start the standby 2 'B' CW pump failed. The 2 'C' pump did not start during the second event due to a significant failure of the 2 'C' CW pump discharge valve.

Substantial work was performed on the CW system during the 2R12 outage. Work

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activities included replacing cable to all of the CW pump motors and performing

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maintenance on the 2 'C' CW discharge valve. In addition, the licensee recently

upgraded the synchronous motor exciter cabinets on Unit 2. This upgrade included

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installation GE/Multilin solid state circuits for old motor exciter relays. This modification provided improved controllogic for more reliable CW pump starts.

The inspectors reviewed the completed work orders and post-maintenance tests.

The inspectors determined that these maintenance activities and CW system upgrades would improve system reliability and performance. No additional concerns were identified.

111. Enaineerina E1 Conduct of Engineering E1.1 Pile Testina for the Rock Run Creek Bridae a.

Insoection Scooe (60851)

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This inspection reviewed independent spent fuel storage installation (ISFSI)

engineering and construction activities affecting the activities associated with the testing of a pile for the reinforced concrete bridge over Rock Run Creek. The bridge and its supports including abutments, wind loads, pile foundation, and bearing pads were designated as "important to Safety" per 10 CFR 72. The bridge is supported i

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on nine pile caps at 12' 0" (nominal) intervals between abutments. Each pile cap is supported by five vertical,14-inch (nominal) diameter reinforced concrete piles with a steel shell. In order to validate the accuracy of the pile capacity used in the

bridge design, a pile test was performed. The inspectors observed the pile testing during this inspection, b.

Observations and Findinas Assessment of the Test Procaration To apply the testing loads on the pile, the licensee installed four rock anchors around the test pile. Each of these anchors was constructed by auguring a hole into the bedrock and grouting the rods into the bedrock. The inspectors noted that the grout that was placed between the rods and the bedrock did not attain 4000 psi strength, within the 3-day curing time, as stated in the pile load test procedure.

The actual minimum grout strength obtained by the licensee's lab was 3200 psi.

The licensee reassessed the bond strength required for the testing of the pile and through a calculation demonstrated that 3200 psi was more than adequate for the pile load test.

The inspectors reviewed this calculation and found it acceptable.

Assessment of the Test i

The inspectors noted that the pile testing of the bridge was performed per Section 6.1.1 of the pile installation and load testing specification, NE-284, Rev. O.

Prior to the test, the licensee held a pre-job briefing with all the participants after all measuring instruments were in place. The inspectors noted that the precautions and details of the test were clearly communicated. The area was properly barricaded and the pertinent signs were visibly displayed. The inspectors also noted i

that the contractor performing the test was experienced and knowledgeable.

I Engineering personnel were directly involved with the details of the test.

The inspectors noted that the 200% load test (loading the pile up to 130 tons) was j

successfully performed. However, the test pile displaced at a inconsistent rate when the licensee attempted to load the test pile above 186.4 tons during the

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300% load test (loading the pile up to 195 tons). The load, above 186.4 tons, was

unable to be sustained due to continued pile displacement. The licensee terminated the test and unloaded the test pile in accordance with Section 6.4.3 of specification, NE-286, revision O.

The overall net displacement of the test pile was greater than 0.75". This exceeded the criteria established for the test.

Assessment of the Test Results The inspectors reviewed the test results and discussed these results with engineering personnel. Engineering decided to revise the ultimate pile capacity to 180 tons based on the test results. This new pile capacity was less than the 195 tons used in the design and installation of the Rock Run Creek bridge. The impact

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of the reduced pile capacity on the bridge pile design was evaluated by the licensee.

The results of this evaluation showed that the pile design margins were for all the loading cases, slightly above the minimum criteria. However, the inspectors noted that there was significant conservatism in the calculations including the following:

A factor of safety of 3 was maintained, which meant that the 180 tons

corresponded to testing the pile at 300% of the design load.

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The licensee selected the worst case location of test pile taken from the soil

core borings (all other piles have higher soil bearing capacity).

Worst location along the bridge and the worst load and load combinations

i were applied.

With these cons. vatisms built into the calculations, the inspectors determined that the bridge pile design was adequate and met all the design requirements established for the ISFSt.

c.

Conclusion For the independent spent fuel storage project, the licensee prepared an acceptable reassessment of the bond strength for the grouted anchors of the pile testing frame for the reinforced concrete bridge over Rock Run Creek. Prior to the pile test, the

licensee communicated test precautions and details in a clear manner. The area

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was properly barricaded and the pertinent signs were visibly displayed. Upon completion of the test, the revised calculations reflecting the new tested load capacities of the pile were prepared using a conservative approach and sound engineering judgement. PECO engineering performed effectively during interactions

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with Raytheon Engineering. In summary, the testing of the pile was conducted in an acceptable and conservative manner.

E2 Engineering Support of Facilities and Equipment

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E2.1 Fire Detection System Non-Conformances (Units 2 and 3)

a.

Insoection Scoce (37551. 71707 & 71750)

l The inspectors reviewed PECO actions following their discovery of a non-(

conforming condition involving fire detection systems for several areas of the station. Fire protection engineers identified that a number of fire areas did not l

contain automatic fire detection systems as required by 10 CFR 50 Appendix R, Section Ill.F, and as committed to in the Peach Bottom Updated Final Safety Analysis Report (UFSAR).

b.

Observations and Findinas in March 1998, during reviews of a proposed modification to the reactor protection system (RPS) for Unit 2, a fire protection engineer discovered that an area of the

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Turbine Building containing safety-related equipment was not protected by an automatic fire detection system. These systems were required be installed in all areas of the plant that contain or present an exposure fire hazard to safe shutdown or safety-related systems or components.

Engineering and fire protection personnel conducted additional, extent-of-condition reviews and identified five Fire Areas, containing 25 rooms, with safety-related or safe shutdown equipment that do not have automatic fire detection systems. These areas were within the Turbine, Radwaste, Unit 2 and 3 Reactor, and Diesel Generator Buildings. Engineering personnel documented these findings in a non-conformance report (NCR) and a Performance Enhancement Program (PEP) report (initiated on October 6,1998). They concluded that this condition was not reportable.

Further investigation into the history of this issue by engineering personnel revealed that an evaluation of this condition was performed in 1983. This evaluation -

incorrectly determined that these areas did not require fire detection systems because they were in Seismic Class ll areas. Therefore, PECO incorrectly concluded j

that this condition was acceptable and no NRC exemption was required.

PECO and NRC personnel conducted conference calls regarding the fire protection non-conformances and compensatory actions during the week of October 26,1998.

On November 5,1998, PECO submitted a letter to the NRC summarizing their plans and interim compensatory measures. PECO stated that they intended to submit an exemption request from the 10 CFR 50 Appendix R requirements for the identified I

fire areas on or about November 16,1998. In addition, they stated that on October 29,1998, they instituted, as an interim compensatory action, hourly fire watch patrols for each of the accessible rooms that lack the required fire detection capability.

NRC personnel will review the potential safety impact of the non-conformances as part of the technical review of the exemption request. The non-conformances constitute an apparent violation of 10 CFR 50 Appendix R. This issue, which may represent a violation of NRC requirements, will remain open pending the submittal of the exemption request by PECO and the completion of the NRC review. (eel 50-

'277(278)/98-10-03)

c.

Conclusions PECO personnel identified that five Fire Areas in the plant, containing 25 rooms, did not contain automatic fire detection systems as required by 10 CFR 50 Appendix R, Section Ill.F. These areas were within the Turbine, Radwaste, Unit 2 and 3 Reactor, and Diesel Generator Buildings. PECO intends to submit an exemption request from the 10 CFR 50 Appendix R requirements for the identified Fire Areas.

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l Interim compensatory actions, consisting of hourly fire watch patrols in accessible areas, were instituted on October 29,1998. The non-conformances constitute an

'pparent violation of 10 CFR 50 Appendix R. This issue, which may represent a

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violation of NRC requirements, will remain open pending the submittal of the i exemption request by PECO and the completion of the NRC review.

'E2.2 - Motor' Ooerated Valve Failures Durina the Unit'2 Refuelino Outaae

! a.-

. inspection Scone (37551,61726 & 62707) -

r The inspectors reviewed several motor operated valve failures that were identified

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during the 2R12 outage. The inspectors also evaluated the operability of these valves during previous power operation.

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. b.

. Observations and Findinag PECO experienced three failures of motor operated valves (MOVs) during 2R12.

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One other MOV was in a significantly degraded condition when inspected. All of these MOVs were safety-related. These MOVs were worked during the outage and

- returned to operable condition prior to startup.

During performance of a system operating procedure, the 'A' CS inboard discharge

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i valve, MO-2-14-012A, failed to open on demand due to a rolled key on the motor

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shaft. This condition rendered MO-2-14-012Ainoperable.- The valve had stroked open and closed successfully after Unit 2 was shutdown just prior to the performance of system operating procedure. This valve was not required by j

Technical Specifications to be operable while the plant was shutdown.

j PECO found that the MO-2-14-12A MOV had a key installed during maintenance activities in 1988 as part of the site's limitorque operator rebuild restart activities.

Since the MOV operated for 10 years without failure the licensee did not consider this a failure caused by maintenance practices.

During an inspection for motor shaft cracking on the RHR Loop 'A' Inboard Discharge Valve, MO-2-10-25A,the licensee found that the key which secures the motor pinion to the motor shaft had sheared. The key was found on the motor shaft, rotated about 90 degrees, but still secure on the shaft as indicated by successful valve operation prior to inspection. Further, the worn gear clutch had a detached lug. A hard worm shaft gear clutch was believed to be a contributing cause of the broken lug. A new soft clutch was installed during maintenance refurbishment.

The clutch was installed prior to 1988 and had lasted for greater than 10 years.

Based on the time in service, the licensee did not consider this to be a maintenance related failure.

During valve operation test and evaluation system (VOTES) testing, maintenance

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technicians determined that the High Pressure Coolant injection (HPCI) discharge isolation valve, MO-2-23-19, would not produce the specified thrust in the closing direction. The required thrust was based on a closing differential of 1152 psi.

Engineering personnel re-evaluated the closing thrust differential pressure and

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determined that only 49 psi was required. Although the MOV was degraded and would not produce the originally specified thrust based on a differential pressure of 1152 psi, it would have preformed its closing safety function during a design basis accident.

Following operator replacement and valve inspection, the inspectors reviewed the as-left VOTES testing graph and data and determine that the valve would provide the required thrust to meet its safety function under design conditions.

During restoration of shutdown cooling, RHR shutdown cooling suction outboard isolation valve, MO-2-10-17 failed to fully stroke open. The MOV torque switch tripped immediately after the valve moved off of the closed seat. The valve was declared inoperable and manually opened. The valve operated smoothly in the manual mode.

Subsequently, the valve operator was inspected and maintenance personnel identified that the stem was dry, indicating improper lubrication. Maintenance personnel also found the wrong stem nut installed. Engineering personnel concluded that the primary cause of the valve operational failure was inadequate stem lubrication and that the improper stem nut contributed to this failure.

Maintenance personnellubricated the stem and replaced the stem nut. The valve was declared operable following successful VOTES testing.

Based on reviews of the engineering operability determinations for these valves, the inspectors determined that each valve was operable and capable of performing its safety function, when required. The inspectors noted that the licensee was addressing the MOV issues individually instead of generically and questioned the licensee as to the potential for other MOVs to have similar conditions. The licensee generated PEP 10009188 to comprehensively capture the MOV deficiencies identified during the 2R12 outage. In addition, the licensee planned to have a periodic verification program in place, as defined by the owner group, by December 31,1998. Although, the program and technical requirements for these MOVs were fulfilled, the failure and degraded conditions found during the 2R12 outage indicate a negative trend in MOV reliability, a.

Conclusion Four examples of failures or degraded conditions on safety related motor operated valves were identified during the 2R12 outage. The operability determinations for each valve were adequate and the valves were capable of performing their safety function when required. Although, the program and technical requirements for these valves were fulfilled, the failures and degraded conditions found during the outage indicated a negative trend in motor operated valve reliabilit _

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E8 Miscellaneous Engineering issues l

l E8.1 (Closed) IFl 50-277(278)/97-07-06lmolementation of a Revised Recirculation Flow I

versus Hours Strateav l

l During the Unit 3 refueling outage (3R11), cracking was fcund on three of the ten recirculation system riser elbow welds. Following identification of this cracking, PECO developed an interim operating strategy that allowed the plant to restart from the refueling outage. This strategy restricted the number of hours of various recirculation drive flows up to and including flow at 100% power. Based on this operating strategy, PECO planned to conduct a mid-cycle outage in 1998 to effect a perrnanent repair to the riser weld cracks.

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In NRC Inspection Report 50-277(278)/97-08,the inspectors reviewed the interim operating strategy, safety evaluation, and flaw evaluation for the cracks. The inspectors had no concerns with the operating strategy or these evaluations.

In NRC Inspection Report 50-277(278)/98-02,the inspectors documented that PECO installed clamps on two of the jet pump riser elbows and inspected and adequately analyzed the third jet pump riser crack during an outage in March 1998.

The inspectors had no concerns with the clamp repair or analysis of the third crack.

This third crack will be inspected during future outages to verify that crack growth remained bounded by analysis.

The inspectors had no additional concerns with this issue.

IV Plant SuDDort R1 Radiological Protection and Chemistry (RP&C) Controls R1.1 Unit 2 Refuelina Outaae Radioloaical Controls a.

Insoection Scope (83750)

The inspectors selectively reviewed applied radiological controls for the Unit 2 outage incNding external and internal exposure controls and radioactive material and contamination controls. The inspectors selectively reviewed radiologically significant work activities including drywell work activities, diving operations within the torus, control rod drive removal activities, refueling work activities, and turbine work activities including main steam system work. The performance and documentation of appropriate radiatior, contamination, and airborne radioactivity surveys was also selectively reviewed.

The inspectors evaluated performance relative to requirements contained in (

10 CFR 20, Technical Specifications, applicable PECO procedures, and the Updated Final Safety Analysis Report.

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Obst.vations and Findinas PECO provided overall effective applied radiological controls for outage work activities. Radiological controls supervisors and manage ~rs were actively engaged in oversight of work activities and implementation of controls. Radiological controls technicians provided appropriate radiological briefings of workers and were

observed to perform appropriate radiation, contamination and airborne radioactivity surveys to support ongoing work activities.

Radiological controls provided for drywell work, turbine work, refueling work, and radiological diving activities were commensurate with potential radiological hazards present. PECO supplied and required use of appropriate personnel radiation exposure monitoring devices during work activities. The devices were properly worn and were supplemented with additional dosimetry for workers entering areas exhibiting dose rate gradients (e.g., under vessel work). Worker dosimetry records were updated and properly maintained.

PECO used real time, alarming electronic teledosimetry to monitor worker radiation exposures in high radiation areas. Workers were observed to be monitored with teledosimetry during selected work (e.g., drywell work, under vessel work, and diving activities). Radiological controls personnel maintained cognizance of worker radiation exposure accumulation and provided feedback to workers (via headsets),

as to their accumulated exposure and low-dose waiting areas. Dosimetry alarm setpoints were reasonable.

Radiological areas (e.g., high radiation areas, radiation areas) were properly posted and controlled. PECO used numerous remote television cameras to monitor activities in high radiation areas.

Airborne radioactivity sampling and analysis for ongoing work was commensurate with the radiological hazard present. No individual sustained any significant intake of airborne radioactivity as of the end of the inspection. PECO implemented use of close-capture engineering controls to reduce ambient and peak concentrations of airborne radioactivity. Individuals were observed to properly use respiratory protective equipment. Breathing air quality, for air supplied respirators, was properly evaluated in accordance with applicable standards.

PECO implemented effective area and personnel contamination controls. Work areas were decontaminated as appropriate to minimize unnecessary protective clothing, access controls, and the potential for personnel contamination. When personnel contamination was identified, appropriate dose calculations were made and evaluations and actions were initiated to prevent recurrence. No significant internal or external exposure of workers was identified as a result of personnel contamination.

Applicable radiological controls procedures were implemented. Workers were observed to properly sign-in on their assigned radiation work permits and follow prescribed radiological controls.

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l Efforts to limit airborne radioactivity were effective. Consequently, while air-

supplied respiratory protective equipment was used for certain tasks, the licensee

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did not routinely apply credit for the protection afforded by the equipment and did

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not routinely rely on respiratory protection equipment to limit intake of airborne radioactivity. Notwithstanding, observations of the use air supplied respiratory protective equipment revealed two instances in which workers did not properly don air supplied hoods prior to entry into the work area. Upon being informed of the condition, a radiation protection supervisor initiated immediate corrective action.

PECO subsequently reinstructed personnelin proper donning techniques and posted donning instructions at the location.

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Overall, PECO made and documented appropriate radiological surveys to support ongoing work activities. However, an instance of inattention to procedure detail was identified with respect to Procedure HP-C-321, Rev. O. A review of radiological surveys made to support initial diving activities identified that, contrary to the j

procedure, one survey (a torus Pre-Dive survey dated October 3,1998) was not

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annotated to identify which of two radiation survey meters was uscd to make the various survey measurements; and additional survey points had not been selected for underwater survey (when underwater dose rates greater than 100 mR/hr were encountered in the torus. PECO acknowledged these matters and took immediate

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action to: 1) update the survey to reflect the complete information, and 2) instruct personnel relative to proper survey documentation practices. PECO concluded that though additional survey points had not been identified, sufficient survey information and data was available to adequately characterize the radiological conditions in the affected areas. Consequently, adequate surveys were made to support diver entry into the areas. This violation was considered of minor significance and is not subject to formal enforcement action.

c.

Conclusions PECO established and implemented overall effective applied radiological controls and procedures for Unit 2 outage work activities. There were no significant unplanned external or internal exposures identified. Overall, contamination controls were effective. Airborne radioactivity was minimized through use of decontamination and application of engineering controls. There was active oversight of implementation of controls by supervisors and managers. No safety concerns were identified.

R1.2 ALARA Proaram and Unit 2 Refuelina Outaae a.

inspection Scoce (83750)

The inspectors reviewed implementation of the ALARA program for the Unit 2

refueling outage. The inspectors reviewed ongoing work activities and toured station areas to evaluate efforts to reduce occupational exposure to as low as is reasonably achievable (ALARA).

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Observations and Findinas PECO established and implemented reasonable exposure goals for the Unit 2

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outage. The development of the goals included implementation of effective work planning and physical controls to reduce occupational exposure. Shielding, remote reading teledosimetry, cameras, and mock-ups were used to reduce worker time and exposure in work areas. PECO also used lessons learned from its 1997 Unit 3 outage and its Limerick station to plan for the Unit 2 outage, including torus strainer work. PECO also contacted other reactor facilities to identify areas for exposure reduction. Accumulated exposure was evaluated daily and compared to established goals. ALARA efforts were integrated into the work process. Work process review were initiated for anomalous individual or aggregate exposure results. ALARA waiting areas were clearly posted and used by workers, i

The stations's ALARA committee was actively reviewing and evaluating the station's occupational exposure accumulation and dose reduction initiatives.

PECO was actively planning and reviewing exposure reduction initiatives for diving by personnel into the Unit 2 reactor vessel for core-spray T-box work. PECO initiated comprehensive radiological surveys to characterize the dive location dose rates and optimize exposure reduction efforts.

c.

Conclusions PECO implemented an overall effective ALARA program. ALARA measures were incorporated into work processes. Numerous exposure reduction initiatives were implemented including decontamination, shielding, remote monitoring, use of mock-ups, and work monitoring via closed-circuit television.

R5 RP&C Staff Training and Qualification in RP&C a.

Inscection Scooe (83750)

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The inspectors selectively reviewed the training and qualifications of radiological controls staff and radiation workers. The review was against criteria contained within licensee program procedures,10 CFR 19.12 and 10 CFR 50.120.

The inspectors selected contractor radiation protection technicians observed to be providing radiological controls for radiologically significant work activities and reviewed their training and qualification records. The inspectors also reviewed the status of training of selected radiation workers.

b.

- Observations and Findinas Radiation workers observed in the field exhibited a good understanding of their work area radiological conditions.

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Contractor radiological controls personnel were provided training and qualifications for their assigned duties in accordance with licensee program procedures.

Radiological controls personnel exhibited a very good understanding of their Y

responsibilities and procedure requirements.

Selected workers and radiological controls personnel involved in radiologically significant work activities were verified to have received applicable training.

PECO effectively used control points to instruct workers in expected radiological hazards and job control measures.

PECO established and implemented special procedures and training for torus work

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activities. These included a safety, heath and emergency plans and associated training. This latter program also included special training.

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PECO was also reviewing its hazardous materials training programs to consolidate programs and ensure all appropriate individuals were receiving applicable training, c.

Conclusions PECO provided appropriate training and qualification of contractor radiological controls personnel and radiation workers involved in outage work activities reviewed. No safety concerns or violations were identified.

R7 Quality Assurance in Radiological Protection and Chemistry Activities a.

Insoection Scope (83750)

The inspectors selectively reviewed audits, assessments, and surveillances of the radiological controls program.

b.

Observations and Findinas PECO quality assurance personnel performed ongoing performance-based surveillances of radiological controls activities. Surveillance reports were detailed and provided a clear description of areas reviewed and results obtained.

PECO radiological controls supervisors and managers routinely provided oversight of infield activities and implementation and effectiveness of applied radiological controls. In addition, PECO actively monitored outage performance and critical performance indicators during weekly senior management epdate meetings.

c.

Conclusions There was active oversight of the radiological controls program and its implementation. PECO quality assurance personnel performed ongoing performance-based surveillance: of radiological controls activities. PECO

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radiological controls supervisors and managers provided oversight of program implementation and effectiveness. No safety concerns were identified.

R8 Miscellaneous issues R8.1 (Closed) VIO 50-277:278/98-02-04 Failure to Properly implement Radiation Area Procedures PECO implemented the corrective and preventative actions outlined in its July.10,

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_1998, response to the violation. Tours of the station did not identify any posting

deficiencies.

F1 Control of Fire Protection Activities i

F1.1 Fire Watch inattentive to Duties

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JEAprtion Scone (71750)

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The inspectors observed fire watch personnel attentiveness and awareness

.following the observation of an individual, assigned as a continuous f:re watch,

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j asleep in the cable spreading room.

b.

Observations and Findinas

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On October 2,1998, during a backshift plant tour, the inspectors observed an

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individuaf asleep in the cable spreading room. This individual had been stationed as a continuous fire watch in the cable spreading room for maintenance work involving

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fire barrier penetration seals. No other personnel were in the room at the time. The c

inspectors notified the operations work control supervisor, who questioned the individual and began an investigation.

PECO personnel evaluated the working conditions and the shift rotations of fire L

Jwatch personnel and identified no significant concerns. Interviews of the individual f

indicated that he was drowsy,'but he did not ' bring this to the attention of a

supervisor or request relief. PECO determined that this event resulted from the i

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h failure of the individual to follow the guidance in the administrative procedures that

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implemented compensatory actions for inoperable fire barriers.

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The inspectors observed fire watch personnel attentiveness, as well as their awareness of their duties, throughout the 2R12 refueling outage. No other similar occurrences were identified. The inspectors considered the observation on

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October 2,1998, to be an isolated occurrence.

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Conclusions j

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inspectors identified a fire watch who was asleep in the cable spreading room, but V

concluded, based on observations during refueling outage 2R12, that this was an isolated occurrence involving a single individual.

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V. Manaaement Meetinas X1 Exit Meeting Summary The inspectors presente,d the results of the inspection to members of licensee management on November 16,1998. The licensee acknowledged the findings i

pressoted. No proprietary information was identified by toe licensee.

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ATTACHMENT 1 LIST OF ACRONYMS USED

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ALARA As Low As Reasonably Achavable ADHR alternate decay heat removal

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CRD control rod drive

'l CREV control room emergency ventilation

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CS core spray i

CW circulating water CCTAS core component transfer authorization sheet

{

ECCS emergency core cooling system EDG

. emergency. diesel generator eel escalated enforcement item ESF engineered safety feature i

FME foreign material exclusion FHD fuel handling director GERIS general electric reacter inspection system GP general procedure

.HCU hydraulic control unit IFl inspector followup item

'&C-instrumentation and control IFSFl inoependent spent fuel storage installation LCO limiting condition for operation LER licensee event report LOCA loss of coolant accident LSRO Senior Licensed Operator Limited to Fuel Handling MCC motor control center MCPR minimum critical power ratio MCREV main control room emergency ventilation MG motor generator MOV.

motor operated valve NCR non-conformance report NCV non-cited violation NOTICE notice of violation NMD nuclear maintenance division NPSH net positive suction head NRC Nuclear Regulatory Commission PAB protected area boundary

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PASS post-accident sampling system

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PECO Peco Energy PEP performance enhancement program PDR public document room

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QA Quality Assurance RCIC reactor core isolation cooling RHR residual heat removal RP&C radio!ogical protection & chemistry

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'.RPO refueling platform operator

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RPS reactor protection system RWCU reactor water cleanup

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Attachment 1

SBGT standby gas treatment SSPV.

scram solenoid pilot valve TRT

- troubleshooting, rework, and testing TS-technical specification UFSAR.

updated final safety analysis report VOTES valve operation test and evaluation system WRNM wide range nuclear monitors i

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Attachment l'

l INSPECTION PROCEDURES USED IP 37551 -

Onsite Engineering Observations

- IP 60710-Refueling Activities.

- IP 60851'

Design Control of IFSFl Components

. IP 60853 On-Site Fabrication of Components and Construction of an IFSFl

- IP 61726 Surveillance Observations -

IP 62707

Maintenance Observations IP 71707

Plant Operations IP 71750 Plant Support Observations IP 83750.

Occupational Radiation Exposure IP 92904~

Followup - Plant Support ITEMS OPENED, CLOSED,' AND DISCUSSED

' Opened / Closed 50-277/98-10-02

.NCV Incorrect Fuel Movement During 2R12 Refueling Activities Opened 50-277/98 10-01-VIO -. Incorrect Refuel Floor Vent Exhaust Radiation Detector L

Disconnected During Calibration 50-277/98-10-03 - eel-Fire Detection System Non-Conformances (Units 2 and 3)

50-278/98 10-03 eel Fire Detection System Non %nformances (Units 2 and 3)

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Closed

.50-277/98-02-04 VIO Failure to Properly implement Radiation Area Procedures

'50-278/98-02-04 VIO Failure to Properly implement Radiation Area Procedures

'50-277/2-98 005 LER Suppression Chamber-to-Drywell Vacuum Breaker Not Fully

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Seated t

50-277/97-07-01 IFl-Outage Overtime Usage and Approvals

.50-278/97-07-01 IFl Outtae Overtime Usage and Approvals 50-277/97-07-06 IFl implementation of A Revised Recirculation Flow Versus Hours j

Strategy

50-278/97-07-06. IFl Implementation of A Revised Recirculation flow Versus Hours p

Strategy l-50-277/97-08-02 IFl

' Unit 2 Circulating Water System Problems

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ATTACHMENT 2 l

. Maintenance Observations:

Observed On:

M-004-200 Reactor Pressure Vessel Disassembly October 1-6 RO563782 250 Volt DC Breaker Removal, October 5 Assembly inspection and Maintenance and Installation C0180835 PM 1 & 2 Main Overhaul of Hydraulic October 6 Control Unit Surveillance Observations:

Observed On:

ST-O-05 2-411 -2 E1 Diesel Generator Fast Start and September 22 Full Load Test G13A-2-MSL-81 FO Functional Test Main Steam Line September 27 High Flow instruments of RPS "D" Card File ST-O-052-413-2 E3 Diesel Generator Fast Start September 29 and Full Load Test ST-l-028-65 5-2 Reactor Level and Pressure Excess September 30 Flow Check Valve Operability ST O 003-635-2 Scram Discharge Volume Pressure September 30 Test inspection SP-2111 Alterex Excitiation System Stability Test September 30 RT-O-01 D-421 -2 Main Turbine Overspeed Trip Test September 30 RT-O-018-427-2 Main Turbine Backup Oversped Test SepteW 30 ST-0-60A-210-2 Average Power Range Monitor System September 30 Calibration During Two Loop Operation ST-O-080-500-2 Recording and Monitoring Reactor October 4 Vessel Temperature and Pressure

. Sl2L-2-101 -D 1 C2 Calibration Check of Reactor Low Level October 5 Loop Instrument LT/LIS 2-2-3101C i

Sl3M-60F-RPS-A2FW Function test of RPS Channel A Scram October 6 Test Switch

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v t e Letter Sequence Request
TAC:M98684, (Withdrawn, Closed) TAC:M98685, (Withdrawn, Closed)
Initiation Request Acceptance... Administration Meeting Questions 14 August 1997 Answers Results Withdrawal Other: ML20141A977
MONTHYEAR1997-09-12 [Table View]

v t e Inspection Report - Peach Bottom - 1998010
80 \| 81 \| 82 \| 83 \| 84 \| 85 \| 86 \| 87 \| 88 \| 89 \| 90 \| 91 \| 92 \| 93 \| 94 \| 95 \| 96 \| 97 \| 98 \| 99 00 \| 01 \| 02 \| 03 \| 04 \| 05 \| 06 \| 07 \| 08 \| 09 \| 10 \| 11 \| 12 \| 13 \| 14 \| 15 \| 16 \| 17 \| 18 \| 19 \| 20 \| 21 \| 22 \| 23 \| 24 \| 25 \|
1998 Quarterly Integrated 1Q (0) 2Q (0) 3Q (0) 4Q (0) Assessments Mid Cycle End of Cycle 7(0) 8(0) 9(0) 10(0) 11(0) 12(0) Security Operator Exams 301(0) Emergency Planning Other

IR 05000277/1998010

Text

REGION I

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