IR 05000277/1990013

Insp Repts 50-277/90-13 & 50-278/90-13 on 900516-0702. Violations Noted.Major Areas Inspected:Operational Safety, Radiation Protection,Physical Security,Control Room Activities,Licensee Events & Maint

ML20056A506
Person / Time
Site:	Peach Bottom
Issue date:	07/30/1990
From:	Doerflein L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20056A502	List: IR 05000277/1990013 ML20056A501 ML20056A505
References
50-277-90-13, 50-278-90-13, NUDOCS 9008080065
Preceding documents:	ML20059M656 (22 September 1990)
Download: ML20056A506 (18)

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ENCLOSURE U. S. NUCLEAR REGULATORY COMMISSION

REGION I

Docket / Report No. 50-277/90-13 License Nos. DPR-44 50-278/90-13 DPR-56

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Licensee:

Philadelphia Electric Company i

Peach Bottom Atomic Power Station

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P. O. Box 195 Wayne, PA 19087-0195

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Facility Name:

Peach Bottom Atomic Power Station Units 2 and 3 Dates:

May 16 - July 2,1990 Insectors:

J. J. Lyash, Senior Resident inspector

R. J. Urban, Resident inspector L. E. Myers, Resident inspector e

Approved By:

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30b O L. T. Doerflein, Chic f Dat'e

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Reactor Projects Sect!on 28 Division of Reactor Projects

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Areas Inspected:

Routine, on site regular, backshift and deep backshift inspection of accessible portions of Units 2 and 3. The inspectors reviewed operational safety, radiation protection, physical security, control room activities, licensee events, surveillance testing, engineering and technical support activities, and maintenance.

9008080065 900730 PDR ADOCK 05000277 Cf FDC

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Executive Summary Peach Bottom Atomic Power Station Inspection Report 90-13 Plant Operations:

A licensee manager touring the plant identified an apparent "make shift bed." Appropriate investigation was performed by the licensee (Section 1.2).

During the period individuals expressed concerns to the inspectors regarding the adequacy of fire

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watch practices, inspector review indicated that portions of the concern were valid. The j

licensee has taken adequate action to address these concerns (Section 1.3).

The applicability of Techrual Specification 3.0.D concerning equipment operability and i

emergency power source availability isn't clear. The licensee has established an interpretation based on technical review. The NRC is also reviewing the issue. This item remains unresolved pending completion of the NRC review and subsequent evaluation of the licensee's position (UNR 90-13-01, Section 1.4).

Maintenance and Surveillance:

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The inspectors identified one violation of NRC requirements. Electrical splices specified by the maintenance planning section, and performed by the craft, on the E3 cmergency diesel generator air start solenoid pilot valves, weren't approved for use in Class IE applications, in addition, drawings used to support work performance weren't obtained from a controlled source and weren't the current revision (NC4 9013 02, Section 5.2).

During loading and lifting of a radioactive shipping cask liner, the liner was tipped to its side due to improper direction of the lifting operation. Contributing to the event were unqualified personnel involved in the operation, unclear division of responsibility and less than adequate

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I physical arrangement and protection (Section 2.1).

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Engineering and Technical Support:

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The inspector expressed concern regarding the removal of each emergency diesel generators l

(EDG), in series, for performance of annual inspections with both units at power. It doesn't

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appear that the assumed risk due to almost 4 weeks of EDG unavailability is offset by any significant benefit. The licensee has developed a TS change to alleviate this problem, but it hasn't been submitted (Section 1.2).

The licensee's approach to analysis of questions concerning the adequacy of DC fuse voltage I

ratings, and performance of confirmatory testing was well focused and effective (Section 3.0).

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TABLE OF CONTENTS

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1.0 Plant Operations Review (71707)

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1.1 Routine Observations

.................................I 1.2 Licensee Identification of a "Make-Shift Bed".................

1.3 Allegation of Inadequate Fire Watch Practices.................

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1.4 Review of Single Recirculation Loop Operations................

1.5 Licensee Interpretation of Technical Specification 3.0.D

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2.0 Follow up of Plant Events (93702)

............................4 2.1 Radioactive Material Shipping Cask Liner Fell on Unit 3

'tefuel Floor

.....................................4 2.2 RCWU Group !!A PCIS Isolations of Unit 2 and 3..............

2.3 Unit 3 Turbine Runback to Repair an Electro Hydraulic Control (EHC) Fluid System leak........................

3.0 Licensee Identification of Under Rated Fuses in the DC Electrical Distribution _ System (92702)................................

r 4.0 Surveillance Testing Activities (61726,71707).....................8 5.0 Maintenance Activities (62703,71707)........................,.

5.1 Routine Obsuvations................................

5.2 Emergency Diesel Generator E3 Annual Inspection

..............9 6.0 Radiological Controls (71707)

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7.0 Physical Security (71707)................................. 11 8.0 Annual Radiological "nvironmental Monitoring Report Review (90712)..... 12 9.0 Management Meetings (30703)............................... 12

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DETAILS

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1.0 Plant Operations Review 1.1 Routine Observations Unit 2 began the inspection period at full power. The unit remained at full power except for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at 80% power when the administrative limit for copper concentration in the reactor

feedwater was exceeded. Reactor power was reduced to 80% for control rod pattern change and i

planned maintenance. The reactor returned to full power on July 2,1990.

Unit 3 began the inspection period at a reduced power of 85% due to condenser performance

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problems. Power was further reduced to 40% on June 3 to repair an oil leak in the reactor recirculation motor-generator set transformer. Power was increased on June 5 and full power

attained on June 11. On June 16 a condensate pump tripped due to line fault, causing a runback to 60% power. The fault was repaired, the pump returned to servlee and full power reached on June 19. On June 24, a leak in the electro-hydraulic control system resulted in a power reduction to 15% for repair. The unit returned to full power on June 28,1990 and remained at full power to the end of the inspection period.

A detailed chronology of plant events occurring during the inspection period is included in Attachment I.

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The inspector completed NRC Inspection Procedure 71707, " Operational Safety Verincation,"

by direct observation of activities and equipment, tours of the facility, interviews and discussions with licensee personnel, independent verification of safety system status and limiting conditions

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for operation, corrective actions, and review of facility records and logs.

1.2 Licensee Identineation of a "Make-Shift Bed" The licensee previously implemented an ongoing program of management plant tours during back shifts. During the inspection period a licensee manager performing one of these tours identified what appeared to be a make-shift bed in a ventilation fan room. The area is remote and receives little traffic. The manager immediately initiated actions to have it removed. When informed, licensee station management directed the security force and the operations Shift

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Managers to periodically monitor the area. This action was prudent, however removal of the material prior to a period of surveillance of the area would reduce the effectiveness of this action. The licensee performed an investigation, including review of security key card records, without success. The ambient temperatures in the area are very high. This, in combination with the negative key card audit results, indicates that the materials were not recently placed or used there. The licensee is continuing the program of management, Shift Manager and security force monitoring of suspect plant areas. The inspector had no further questions.

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1.3 Allegation of inadegate Fire Watch Practices The licensee's Fire Protection Program requires stationing a dedicated fire watch when work activities involve an ignition source (welding, grinding, cutting, etc.). Until recently a contract labor force was used to support this activity. To reduce onsite contractors and for ALARA purposes the licensee recently transferred a large percentage of the firewatch responsibility from the contractor to the craftsman involved with the work. One craftsman acts as the dedicated firewatch, while the second performs the task involving the ignition source. The inspector verifed that individuals called upon to act as fire watches were trained in accordance with the licensee's program requirements.

On June 13,1990, several individuals expressed concern to the inspectors that plant employees aren't properly implementing the fire watch procedure. The example given was that during work in the Unit 2 torus room, pipe support brackets were welded while one of the craftsman involved acted as the fire watch. The designated fire watch allegedly wasn't continuously observing the work activity, and a portable fire extinguisher wasn't within 15 feet as specified in the procedure, but was leated 50 or 60 feet away. The allegers stated that they had reported the condition to their supervision, but that the inadequate practice was continuing.

Subsequently, on June 14,1990 an anonymous individual telephoned the resident office and stated that grinding was being conducted in bay 12 of the torus room without a fire extinguisher

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present. The inspector made an entry into the torus room and observed ongoing work. The individuals working in bay 12 were grinding concrete. This doesn't constitute an ignition source and no fire extinguisher is required. Three other work crews were observed welding or grinding.

In each case the area was free of combustibles and the fire watch appeared attentive. Fire extinguishers were obtained and were present in the area. Interviews with the workers indicated

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a good appreciation of the circumstances requiring a fire watch. However, three problems were

observed:

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Only two extinguishers were available for the four crews, impacting their ability to work. The work areas were low dose (2-8 mr/hr), but this is still a poor i

ALARA practice.

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Two work crews shared an extinguisher, placing it between the locations (about

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20 to 30 feet from the activity). Licensee procedure A 12, " Ignition Source

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Control," indicates that each work activity involving an ignition source should be provided with an extinguisher and that it should be located within 15 feet, j

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One individual functioning as a fire watch wasn't in a position where he could see the entire area impacted by the ignition source.

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These issues were discussed with the licensee managers responsible for the work activity and with l

the site Fire Protection Engineer. The licensee stated that steps would be taken to ensure that each work crew is supplied with a fire extinguisher if appropriate, and that the requirements for l

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placement of the extinguisher, and location and duties of the fire watch would be discussed with all members of the work force during a series of "all hands" meetings.

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In addition, the licensee subsequently approved a major revision to procedure A 12 clarifying

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fire watch requirements.

The inspector observed four additional work activities involving ignition sources during the remainder of the inspection period. In each case the provisions of the licensee's fire watch procedure were effectively impicmented. Licensee corrective actions were appropriate. This

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allegation is considered to be closed. The inspectors will continue to evaluated this area during future routine plant tours.

1.4 Review of Single Recirculation Loop Operations Several months ago the licensee identified that the transformer which supplies power to the "B'

reactor recirculation pump motor generator set had developed a slow oil leak. The leak was monitored closely and its status discussed frequently at daily plann!ng meetings. Attempts were made to mitigate the leak and were partially effective. However, on June 3,1990 the leak rate increased, the 3B recirculation pump MG set was removed from service, and the transformer deenergized for repairs. While the repairs were being performed the licensee continued in single loop operation (SLO). The inspector reviewed the power reduction and transition to SLO, Technical Specifications (TS), operating procedures and surveillance procedures associated with SLO. The power reduction and transition were well handled, avoiding the areas of potential thermal hydraulic instability identified on the power to flow map. Licensee operating procedures for removal and return to service of the recirculation pump appeared adequate and were effectively implemented by the staff.

The inspector observed performance and reviewed completed samples of surveillance tests (ST)

9.21-3, " Jet Pump Operability - Single Loop," and ST 3.3.2A, " Calibration of the APRM System and Thermal Limit Check for Single Loop Operations." Tests observed were completed in accordance with the procedure, and in the time frame and at the frequency required by TS.

One concern was identified. TS 4.6.E.3 states that the baseline data required to evaluate jet pump operability will be obtained each operating cycle. The inspector noted that while the data for both dual and single recirculation loop operations had been obtained, surveillance procedures hadn't been revised to reflect the changes. The licensee reviewed the data and subsequently revised the procedures. Although some acceptance limits changed, the licensee's ability to detect jet pump failure using the original procedures wasn't substantially affected.

Additional administrative controls were put in place to ensure that future procedure revision would occur in a more timely manner. The inspector had no further questions.

l 1.5 Licensee Interoretation of Technical Specification 3.0.D

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Technical Specification (TS) 3.0.D allows the licensee to consider as operable those systems l

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whose emergency (or normal) power sources are inoperable, provided that the provisions

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specified in 3.0.D are met. One of these provisions requires that the redundant systems be

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i operable. If these provisions aren't met the specification states that the unit shall be placed in i

hot shutdown within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and cold shutdown within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The language of TS 3.0.D doesn't appear to limit its scope of applicability.

As a result of recent enforcement action initiated by Region I at the Peach Bottom facility, the licensee has reevaluated the approach historically taken to interpretation of TS 3.0.D. It appears that previously, application of 3.0 D was viewed by the licensee as discretionary; solely as added flexibility to allow a component or system to be considered operable with its associated normal or emergency power source inoperable if desired. If a choice not to rely upon 3.0.D was made, the associated system would be declared inoperable and its individual TS would be consulted.

Recent licensee review identified that as written, applicability of TS 3.0.D isn't limited in scope i

and doesn't clearly allow implementation on an discretionary basis. The licensee has identified the potential for unwarranted plant shutdowns as a result of implementation of the specification in this manner. The action required by 3.0.D seems appropriate for some combinations of equipment inoperability which represent a significant cumulative degradation, but not for all combinations potentially meeting the 3.0.D test.

The NRC Office of Nuclear Reactor Regulation (NRR) is performing a near-term review of Peach Bottom TS with the goal of j

providing guidance regarding the appropriate interpretation and enforcement of the specification.

This review will consider both the degradation in plant capabilities due to an inoperable emer-

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gency power source and the safety impact of the prompt plant shutdown potentially resulting from its enforcement.

The licensee is implementing a series of emergency diesel generator outages, as discussed in Section 5.2 of this report. The licensee has provided guidance to the operating staff on the implementation of 3.0.D during this period of emergency power source unavailability. The technical staff reviewed the loads supplied from the diesel to be removed from service, and developed a position regarding the action to be taken if that system or component was found to be inoperable. This guidance was reviewed and approved by plant management. The inspector reviewed portions of the guidance and noted that it appeared to be based on a sound technical and safety perspective. Final review of the acceptability of this position, however, will be performed following completion of the ongoing NRC:NRR evaluation. Pending completion of this effort this item will remain unresolved (UNR 90-13 01).

2.0 Follow-up of Plant Events The inspector evaluated licensee response to plant events to ensure that prompt analysis was performed, reasonable root causes were identified, and appropriate corrective actions were implemented. In each case, the inspector reviewed applicable administrative and technical j

procedures, interviewed personnel and examined the affected systems and equipment.

I 2.1 Radioactive Material Shipping Cask Liner Fell on Unit 3 Refuel Floor On May 22,1990, a radioactive waste material shipping cask liner located on the Unit 3 refuel floor and partially filled with radioactive waste material, fell over on its side during the

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installation of the liner cover. The liner is 33 inches in diameter and 9 feet high with 2-inch angle iron supports on the bottom, raising it off the floor. The tipping over of the liner didn't result in any radioactive contamination or increase in exposure levels in the area. The incident was initially reported to the NRC under 10 CFR 20.403.

The liner was located adjacent to the spent fuel pcxal inside of a specially prepared containment enclosure. The enclosure was such that the overhead crane operator couldn't see within the enclosure. An individual outside of the enclosure transmitted hand signals to the crane operator from an individual inside the enclosure.

The liner was being loaded with radioactive shroud head bolt (SHB) pieces and local power range

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monitors (LPRM) pieces. The cover was removed and placed beside the liner. At shift change the maintenance workers supporting the activity left. The maintenance foreman informed the Maintenance Support Engineer (MSE) overseeing the activity and the two supporting Health Physics technicians (HP) that workers were scheduled on the next snift to load the liner. The i

HPs were concerned about maintaining temporary high radiation areas for longer than they perceived necessary. The MSE and HPs made a decision to load the liner themselves. There was a crane operator available to lift the SHBs into the liner. The crane operator was unaware that there were no qualified maintenance craftsmen available. The MSE and one HP entered the enclosure and loaded the SHBs into the liner. One of the individuals inside the enclosure gave hand signals to another located outside the enclosure, who in turn transmitted the signals to the crane operator. When installing the liner cover the crane hook was not centered over the cover.

When lifted, the cover moved under the bottom of the liner, lifting it upwards and tipping it over. No radioactive material spilled out of the liner. After the fall appropriate surveys and air samples were completed indicating no contamination or increase in radiation levels. The MSE

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and HPs then informed the maintenance foreman and shift management of the incident.

The licensee initiated Radiological Occurrence Report 90-0058, held a critique on May 24, and prepared Event Investigation Report No. 3-90-014. As a result of the investigations the licensee determined:

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The MSB and HP technicians were actively involved with activities rather than

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providing oversight and support; l

The MSE and HP technicians performed functions normally performed by a

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l qualified craftsman; There wasn't a clear division of responsibility between the MSE and maintenance

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foreman; The enclosure wasn't properly constructed to provide visibility for the crane

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operator;

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The liner should have been provided with a support structure to stabilize the high

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aspcCf ratio.

As immediate corrective actions a liner support structure was installed, and the enclosure was i

modified so that the crane operator could see in. The HPs involved in the activity were l

counselled and all HPs were instructed on the event, with emphasis not to become involved in

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the work while providing support. The MSE was also counselled to provide oversight and refrain from performing functions requiring qualified craftsmen.

The inspector found the licensee's immediate corrective actions adequate.

However, the inspector noted that following the incident the licensee's Maintenance and Support Services Superintendents agreed that HP technicians could be used in the future to direct crane operations

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under certain conditions. The inspector questioned if the technicians would receive training i

similar to that received by the craftsman as part of their qualification program prior to directing l

lifting activitics. Additionally, the inspector pointed out that Special Procedure 1130, addressing the cask loading evolution, hadn't been revised to incorporate the cask support structure and enclosure construction corrective actions taken by the licensee, This would ensure their use

during future activities. The licensee stated that these questions would be reviewed and

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appropriate action taken.

2.2 RWCU Groun 11 PCIS Isolations of Unit 2 and 3 On June 20,1990 two priii.ary containment isolation system (PCIS) group II isolations occurred on reactor water cleanup (RWCU) system high flow, while the system was being returned to service.

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in the first case repairs had been completed on the Unit 2 RWCU outboard inlet isolation valve.

The system was out of service for approximately 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> and depressurized. The Reactor Operator (RO) was implementing procedure SO 12.1.A-2, " Reactor Water Cleanup System Start Up for Normal Operations or Reactor Vessel Level Control," to place the system in service.

.i The procedure requires that the outboard inlet isolation valve be slowly " bumped" open until

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pressure equalizes in the volume between the inlet and outlet valves. The differential pressure instrumentation for high flow is located between the inboard and outboard inlet isolation valves.

The RO bumped the valve several times and cleared the alarm for " Clean up Recirculation Pump Suction Instrument Line Break," which indicates that pressure had exceeded 100 psig. The Shift Supervisor concluded that since the alarm had cleared, sufficient time had passed to repressurize and the valve could be fully opened. When the valve was stroked open the system isolated.

In the second case, a similar RWCU high flow primary containment isolation system (PCIS)

group II isolation occurred on Unit 3.

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approximately two hours to inspect a packing leak on the outboard inlet isolation valve, he system had depressurized to about 300 psig during the inspection. The RO implementing procedure SO 12.1.A 3, bumped open the inboard inlet isolation valve then bumped open the outboard inlet isolation valve when the actuation occurred. The operator had monitored system l

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pressure while bumping the valve open and stopped the valve motion when pressure slightly increased.

The licensee reviewed the events and concluded that procedure revisions should be implemented to 1) clarify or add appropriate caution statements and 2) add direction for hold times between

valve opening bumps. The licensee is also performing a study to evaluate the need for a time delay circuit to prevent spurious high Dow signals. The inspector concluded that the licensee's response was adequate.

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2.3 Unit 3 Turbine Runback to Repair An Electro-Hydraulie Control (EHC) Fluid System Ira);

r On June 25,1990, reactor power was being reduced in order to repair an EHC leak from the #3 turbine control valve. While reducing power, a generator load runback occurred unexpectedly from about 315 MWe, In addition, the runback did not stop at 7726 amps (about 250 MWe) as designed, but continued to 50 MWe. Eight and one half bypass valves opened during the runback. After systems stabilized, the operator raised the load set to close the bypass valves.

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The runback we.s caused by stator cooling water inlet low pressure to the main generator. The operating pressure was already low, and when a system temperature control valve opened pressure dropped low enough to actuate two of the three pressure switches necessary to complete

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the runback logie. Also, a relay that stops the.tmback at 7726 amps didn't function properly.

All three pressure switches were checked and found within calibration. The stator water cooling system flow indicating controller was reading 25 GpM high. It was adjusted, thereby raising system pressure so that the margin to the low pressure runback was increased. The temperature control valve was cycled several times and the system operated satisfactorily. The relay was removed and inspected; it was dirty and contained metal filings. The malfunctioning relay was cleaned, refurbished and tested satisfactorily. Another similar relay in the runback logic * as also inspected and no abnormalities were found. Both relays for Unit 2 were also found satisfactory.

The relays weren't part of the preventive maintenance program and were subsequently added.

The inspector had no further questions.

3.0 Licensee Identification of Under Rated Fuses in the DC Electrical Distribution System The licensee conducted an internal Safety System Functional Inspection (SSFI) in January,1990, focusing on the 125 and 250 VDC electrical distribution system. The SSFI team raised questions regarding the adequacy of voltage rating and interrupting capability of DC distribution fuses installed in both the 125 and 250 VDC systems. The licensee operates the nominal 125 V system at a Boat voltage of 130 V and an equalizing voltage of 135 V. The nominal 250 V system operates at a float voltage of 260 V and an equalizing voltage of 270 v. The voltage rating of the installed fuses are 125 and 250 VDC, no allowance was made during the qualification test program for use in systems operated at higher voltages, in response to this concern the licensee initiated a supplemental qualification test program

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conducted at the Gould Shamut High Power Test Laboratory. The testing was performed at voltages in excess of the maximum float voltages observed in the plant. The methodology and acceptance criteria used were in agreement with UL Standard 198L, "DC Fuses for Industrial

Use," with only minor exceptions.

Bussman Type FRN R and Gould Shawmut Type TR-R,

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Class RK 5 fuses w*th ratings ranging between 30A and 200A were tested.

Overload, interrupting ability and maximum energy tests were performed. All 125 V fuses passed all tests.

The 35,40,50,60, and 100 ampere Gould Shawmut fuses used in the 250 V system didn't pass the 200% and 400% overload tests. They did function to interrupt the current, but circuit i

voltage was sufficient to arc over the fuse gap and re-establish the circuit. However, these fuses did pass the maximum energy and interrupting capability tests.

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The licensee reviewed the 250 VDC system design to evaluate the potential impact of this

performance deficiency, it was determined that a component failure resulting in the r,ubject overload condition could occur. In this case the fuse may fail resulting in the loss of DC bus.

However, all components powered from the affected Division 11 bus are safety-related, and are

associated with the high pressure core cooling system (HPCI). This type of failure wouldn't be more severe than other analyzed single failures resulting in loss of the HPCI system. The affected Division I bus powers only reactor core isolation cooling (RCIC) components but two

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of the loads are nonsafety related. The licensee immediately placed the control switches for these loads, the barometric condenser vacuum pump and condensate pump, in pull to-lock. RCIC was not declared inoperable based on previously performed engineering analyses demonstrating RCIC operability without this support equipment. Additional analysis by the licensee of the as built configuration and resultant maximum credible locked rotor current values for these two motors indicated that the installed fuses, although not meeting all UL test criteria, would perform satisfactorily in this specific application.

The licensee also evaluated the distribution system coordination as it relates to the 10 CFR 50, Appendix R, analysis. No concerns were identified. The licensee developed and approved a Justification For Continued Operation (JCO) to support the acceptability of power operation pending permanent fuse replacement with fuses having a higher voltage rating.

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The inspector reviewed the licensee's JCO, design analysis, vendor testing specification and engineering calculations related to this problem. The licensee acted in a deliberate manner, and with a sound engineering basis in approaching resolution of this issue. The inspector discussed the licensee's analysis extensively with NRC Region I and headquarters technical specialists. No concerns were identified.

4.0 Surveillance Testing The inspectors observed surveillance tests to verify that testing had been properly scheduled, approved by shift supervision, control room operators were knowledgeable regarding testing in progress, approved procedures were being used, redundant systems or components were available for service as required, test instrumentation was calibrated, work was performed by qualified personnel, and test acceptance criteria were met. Daily surveillances including instrument

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channel checks, jet pump operability, and control rod operability were verified to be adequately performed. Surveillance tests observed or reviewed are listed in Attachment 11.

5.0 Maintenance Activities 5.1 Routine Observations The inspectors reviewed administrative controls and associated documentation, and observed portions of ongoing work. Administrat!ve controls checked included blocking permits, fire watches and ignition source controls, QA/QC involvement, radiological controls, plant conditions, Technical Specification LCOs, equipment alignment and turnover information, post-i maintenance testing and reportability. Documents reviewed included maintenance procedures

(M), maintenance request forms (MRF), item handling reports, radiation work permits (RWP),

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material certifications, and receipt inspections. Maintenance activities reviewed are listed in

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Attachment Ill.

5.2 Emergency Diesel Generator E3 Annual Inspection 5.2.1 Inspection Requirements During the period the inspector reviewed efforts associated with performance of the annual inspection of I of the 4 cmcrgency diesel generators (EDG), EDG E3, Technical Specifications (TS) require that the licensee perform annual EDG inspections in accordQce with the manufacturer's recommendations. The vendor recommended inspections are quite extensive, require significant disassembly and about a 6 day EDG outage. Review of the Fairbanks/ Morse EDG manual however, indicates that the specified frequency allows up to 18 months between inspec* ions. Discussions with licensee staff involved in pmvious inspection efforts indicated that no substantial wear or significant defects were identified during the last several inspections. The EDGs had accumulated only about 50 hours5.787037e-4 days <br />0.0139 hours <br />8.267196e-5 weeks <br />1.9025e-5 months <br /> of run time since the last inspection. A total of 4

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weeks of EDG unavailability with both units at power will result from performance of the inspections, in addition, removal of an EDG from service requires starting each of the remaining 3 EDGs daily to satisfy the TS action statement. The inspector expressed concern at the additional risk due to the increased EDG unavailability, and the EDG wear resulting om the daily testing, didn't appear to be balanced by any significant safety benefit derived from the

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inspection. The licensee agreed and stated that a major EDG TS change request was being

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developed which included extension of the frequency to 18 months. This change would allow performance of the inspection with I unit in an outage conditim The licensee also stated that consideration was being given to separating this portion of the %e request and submitting it in advance. The inspector discussed the concern with cognizant M C headquarters personnel to determine if any immediate safety concern existed, and if near-term relief from the requirement was warranted. Based on these discussions it appeared that no immediate safety concern existe _

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5.2.2 Caneral Observations Licensee planning activities associated with the E3 EDO outage appeared to be comprehensive.

Maintenance Request Forms (MRF) for discrete work activities were generated. Work permits and blocking requests were coordinated to avoid application of multiple tags to the same

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components.

Manpower, materials and procedures were available and in place prior to application of the blocking and release of the equipment by operrt ons. The licensee has estab-i lished a series of maintenance procedures (M 52) to be used in conducting EDO maintenance activities. The procedures were adequate for the task, with an acceptable level of detail MRFs and procedures were present at the job site, and were acceptably referenced by the craftsmen.

MRFs reviewed by the inspector are listed in Attachment 111.

L 5.2.3 Identified Concerns One of the activities observed was work performed under MRF 9061750. This MRP authorized removal, disassembly and reinstallation of the EDO air start valves and the associated solenoid operated pilot valves. Portions observed by the inspector involved the retermination of the electrical leads for the 3 solenoid operated pilot valves. During installation of the splices on June 27,1990 the inspector identified that the splice procedure specified by the maintenance planner and the alternate procedure performed by the craftsman weren't approved for use in Class IE systems, and that the drawings in use at the work site weren't the current revision.

Section 3 of the MRF directed use of maintenance procedure M521.202, " Procedure for Insulating and Environmentally Scaling 600 Volt Cable Splices on Nuclear Safety Related Systems, Class IE and Non-Class IE," for making the required electrical splices. The craftsman designated to perform the task felt that the splice called for by M521.202 couldn't be performed within the space available at the conduit. After discussion, the maintenance planner deleted the reference to M521.202 and replaced it with Design Specification 1317, " Wire & Cable Notes

& Details Power, Control & Instrumentation," Sheets 71 and 72. However, this splice is.

restricted for use in non-Class IE applications. No prior engineering approval for use of this -

type of splice in the IE application was obtained. After review of the newly designated splice detail the craftsman again returned to the planner to request a change, because the specified technique wasn't the method preferred by the craft. Inten>iews with lleensee personnel indicate that the craft suggested, and the maintenance planner agreed, to use the splice detail contained on E1317, Sheets 6E, Revision 52. Copies of this drawing were obtained by the craft from an uncontrolled source. The drawing had undergone a major revision and this splice detail was deleted April 3,1990.

The inspector discussed the following concerns with maintenance department management:

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The MRF was revised by the planning section to allow use of a non-Class IE splice design for a Class IE application without engineering review and approval;

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The involved craftsman obtained drawings to be used for performance of the work from an uncontrolled source. The drawings used weren't the current revision; 3)

Given items 1) and 2) does the potential exist that other improper splices were performed.

The licensee discussed the incident with the involved personnel and issued a letter reemphasizing the need to verify that all drawings are current prior to use. The licensee reviewed other MRFs completed on the E3 EDG during the outage and found 1 adclitional case where improper splices had been installed on the auxiliary lubricating oil pump. All 4 splices were reperformed using a Raychem procedure acceptable for Class IE applications.

i The inspector informed the licensee that the deficiencies discussed above constitute a violation of 10 CFR 50, Appendix B Criterion 111 and IX (NV4 9013 02). The inspector noted that a previous incident involving improper electrical splice installations on safety related equipment was identified and documented in Inspection Report 89 22. The inspector also reviewed the j

results of a recently completed maintenance self-assessment which indicated problems with use

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of out of date drawings. This may indicated that a more general process or training problem exists, i

6.0 Radiological Controls During the report period, the inspector examined work in progress in both units and included health physics procedures and controls, ALARA implementation, dosimetry and badging, I

protective clothing use, adherence to radiation work permit (RWP) requirements, radiation surveys, radiation protection instrument use, and handling of potentially contaminated equipment and materials.

The inspector observed individuals frisking in accordance with HP procedurts. A sampling of high radiation area doors was verified to be locked as required. Compliance with RWP

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requirements was verified during each tour. RWP line entries were reviewed tc, verify that l

personnel had provided the required information and people working in RWP areas were observed to be meeting the applicable requirements. No unacceptable conditions were identified.

7.0 Physical Security The inspector monitored security activities for compliance with the accepted Security Plan and associated implementing procedures, including: security staffing, operations of the CAS and

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SAS, checks of vehicles to verify proper control, observation of protected area access control and badging procedures on each shift, inspection of protected and vital area barriers, checks on control of vital area access, escort procedures, checks of detection and assessment aids, and compensatory measures. No inadequacies were identified.

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8.0 Annual Radiological Environmenydjjpaitoring Reoort Review The Annual Radiological Environn. ental Operating Report, Number 47 covers the period from f

January 1 through December 31,1989. The report summarizes the radiological environmental mc.nitoring program. During this period the licensee performed 3,041 analyses on 2,245 samples which included samples from surface and drinking water, fish, sediment, air, fr. ilk vegetation, and soil in the vicinity of the plant. The report contained all required informr.tlon and no

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concerns were identified during the review.

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9.0 Manacement Meetings A verbal summary of preliminary fmdings was provided to the Peach Bottom Stailon Plant Manager at the conclusion of the inspection. During the inspection, licensee management was periodically notified verbally of the preliminary findings by the resident inspectors.

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proprietary information is included in this report.

During the inspection period the inspector provided the licensee a copy of a February 22,1990 memorandum from Thomas E. Murley to the five NRC Regional Administrators describing the current NRC process for review and issuance of Temporary Waivers of Compliance. The i

contents of the memorandum were discussed with the Plant Manager, Operttions Superintendent, and the Regulatory Engineer. No additional written material was provided to the licensee during

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the inspection.

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y; ATI ACHMENT 1

.i Facility and Unit Status o

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Unit 2 l

May 16 Unit at full power.

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June 20 Primary containment isolation system Group II A isolation, reactor water cleanup i

isolation on high suction flow.

June 22 -

Reactor power reduced to 80% when feedwater copper concentration exceeded administrative limit of 0.3 parts per billion (ppb) for 7 days.

June 23 Feedwater copper 0.294 ppb, Reactor power increasing to 100%.

June 24 Reactor returned to full power.

June 30 Reactor power reduced to 70% to repattern control rods and to do maintenance I

on "B" reactor feedwater pump and "C" condensate pump.

July 2

.Readar returned to full power.

Unit 3

May _16 Reactor power at 85%, limited due condenser tube flow reductions with "C"

. condensate pump out of service.

June 3 Power reduction to 40% and single 1-p operation to repair an oil leak in "A" motor generator set of recirculation pump.

June 6

Power ascension to full power, after condensate pump repair.

. June'l Reactor at full power.

l June 16 Runback to 60% power when condensate pump tripped on line fault.

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' June 19 Reactor at full power.

s June 24 Power reduction to 15% to repair electro-hydraulic control system leak.

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Generator runback occurred.

June 28 Reactor at full power. Remained at full power to end of period.

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ATTACHMENT 11 SURVEILLANCE TESTS Reviewed:

ST 8.3-3A, "3AD001 & 3CD001 Station Battery Quarterly Inspection," Revision 2, performed on 6/8/90 S13F-12-124-BIFM, " Functional Test of RWCU High Flow Instrument DPIS 3-12-124B,"

Revision 2 on 6/18/90 S'I9.21-2, " Jet Pump Operability," Revision 14, performed on 6/18/90 ST 13.25-3, "Ist Exercise of ESW Air Operated Valve-Unit 3," Revision 7, performed on-6/20/90 S13N 60B-RBM BIFM, " Rod Block Monitor "B" Functional Check," Revision 1, performed M

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6/20/90

.S13K 54 E33-XXFM, " Functional Test of E33 4160 V Transformer Undervoltage Relays,"

Revision 5, performed on 6/20/90 Sil2R 63 251-AICQ, " Electronic Calibration / Function Check of Main Steam Line Pad Monitor, i

RIS 2-17-251 A," Revision 3, performed on 7/2/90 ST 3.3.2, " Calibration'of the APRM System," Revision 16, performed on 7/2/90 Observed and reviewed:

ST 6.17, " Diesel Driven Fire Pump Operability Test," Revision 21, performed 5/8/90

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ST 6.8F-2, " Unit 2, " A" RHR Loop, Pump, Valve, Flow and Unit Cooler Functional Test,"

Revision 6, performed 5/22/90 ST 9.21-3, " Jet Pump Operability - Single Loop Operation," Revision 1, performed 6/4/90 and

- 6/5/90 ST 3.3.2A, " Calibration of the APRM System and Thermal Lidt Check for Single Loop

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Operations," Revision 7, performed 6/4/90

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l NITACHMENT Ill MAINTENANCE ACTIVITIES EnDEnl Equipment

MRF 9003027 Repair packing leak on "B" SLC pump MRF 9002620 Diesel driven fire pump exhaust line tail piece replacement

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MRF 9061705 Remove and inspect E3 emergency diesel generator air start solenoid valves MRF 8905184 Fabricate mounting plate and install ball valve'on EDG MRF 8905511 Repair penellex for EDG aux. lube oil pump l

MRF 9061615 Perform diesel annual inspection per M 52.1

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