IR 05000277/1993024

Insp Repts 50-277/93-24 & 50-278/93-24 on 930914-1030. Violation Noted.Major Areas Inspected:Operations,Refueling Maint,Surveillance,Engineering & Technical Support

ML20058D466
Person / Time
Site:	Peach Bottom
Issue date:	11/22/1993
From:	Anderson C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20058D388	List: IR 05000277/1993024 ML20058D382 ML20058D421
References
50-277-93-24, 50-278-93-24, NUDOCS 9312030161
Download: ML20058D466 (24)

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U. S. NUCLEAR REGULATORY COMMISSION i

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REGION I

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Docket / Report No.

50-277/93-24 License Nos. DPR-44 j

50-278/93-24 DPR-56

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Philadelphia Electric Company l

Licensee:

Peach Bottom Atomic Power Station

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P. O. Box 195 l

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Wayne, PA 19087-0195 l

l Facility Name:

Peach Bottom Atomic Power Station Units 2 and 3 i

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Dates:

September 14 - October 30,1993

.j Inspectors:

W. L. Schmidt, Senior Resident Inspector F. P. Bonnett, Resident Ir:spector

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R. K. Lorson, Resident Inspector R. R. Temps, Project Engineer i

R. A. Fernandes, Reactor Engineer

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Approved By:

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f C. J. Anderson, Chief //

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Date

N Reactor Projects Sectiod 2B

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}4 Division of Reactor Projects l

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9312030161 931122 i

PDR ADDCK 05000277

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EXECUTIVE SUMMARY j

Peach Bottom Atomic Power Station i

Inspection Report 93-24 -

Plant Ooerations

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PECo continued to conduct operational and shutdown activities safely. Operators performed j

well during routine activities. However, several instances of poor operator performance in the '

.i failure to return the control room ventilation system to a fully operable condition (Section 2.3),

I and failure to evaluate a condition that led to a fuel bundle being stuck partially inserted in a spent fuel rack (Section 2.2), indicated a need for increased individtal care and management supernsion.

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In one instance a poor technical review of a temporary change to a test resulted m ventmg a

small amount of radioactive steam to the Unit 3 reactor building and minor personnel clothing

.j contamination (Section 2.4). This appeared to be a result of a violation of the plant procedures for technical review (VIO 93-24-02).

i Maintenance and Surveillance l

l Routine activities observed were well conducted. PECo conducted activities well during the

Unit 3 refueling outage including planning and management (Section 5.1). Two of the four j

high pressure service water pumps at Unit 2 experienced coupling failures within a month.

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PECo attributed these failures to intergranular stress corrosion cracking. In one case a missing l

bushing caused the stress and in the other case a non-symmetrical load due to a crack in the l

pump housing caused the stress. These failures were significant due to the inservice testing not

identifying execssive vibration of these deep draft pumps in advance of the coupling failures

,l (Section 5.4)(URI 93-24-05).

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During activities on the Unit 2 refueling floor, an empty radioactive material shipping cask

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liner, which had been suspended within the fuel pool cask area, dropped approximately twenty,

l feet to the floor of the pool. This was caused by the holding mechanism slipping off the rigging -

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hook, because a safety latch was not used and because the crane operators did not account for the effect of the drag force of the water while lowering the liner in the pool (Section 5.2).

f PECo conducted a loss of offsite power test well (Section 4.1). Surveillance and post-mainte-

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nance testing of emergency diesel generators (EDGs) identified that two EDGs, although not j

required, would not have been operable for service at Unit 3 due to breaker and undervoltage j

relay problems. In another instance, the E-2 EDG was declared inoperable dne to high fuel oil i

filter differential pressures (Section 4.2).

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Review of the secondary containment integrity testing and the control of barrier breaches, raised l

several questions. Specifically, the inspector questioned; the testing of the containment with the

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design airlock doors closed and not performing retests of barrier breaches following resealing l

(Section 4.3)(URI 93-24-04).

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I Engineering and Technical Sunnort

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PECo performed well with respect to identification and analysis of cracking identified in the

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Unit 3 core shroud. In addition, PECo took the conservative action of shutting down Unit 2, following identification of cracking on Walworth valve yokes at both units (Section 3.3)(URI

93-24-03).

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i Assurance of Ouality i

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PECo performed well with respect to identification and evaluation of plant problems such as the

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Unit 3 shroud cracking, the Walworth valve yoke cracking and the failure of the Unit 2 high pressure service water pumps. The plant operations review committee (PORC) performed well

during their review of these issues (Section 3.1,3.3).

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i The inspectors found the independent safety engineering group (ISEG) was performing well at

identifying and tracking issues (Section 3.2)

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SUMMARY OF FACILITY ACTIVITIES *

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1.1 Philadelphia Electric Company Activities The Philadelphia Electric Company (PECo) conducted normal operating and shutdown activities at Peach Bottom Atomic Power Station (PBAPS) Unit 2 (Unit 2) and Unit 3 (Unit 3) safely over j

the period.

i Unit 2 operated at 100% power at the beginning of the inspection period. PECo reduced power to about 60% on September 21, to perform flux tilt testing (Section 2.1).

The unit was l

shutdown on October 1 to allow inspection for and repair of cracks on safety-related motor

operated valve (MOV) yokes (Section 3.3). Operators restarted and placed Unit 2 on the grid

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on October 10. Power ascension was delayed through the week while the E-2 emergency diesel

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generator (EDG) was returned to service (Section 4.2.2). Unit 2 operated at essentially 100%

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I power for the remainder of the period.

i Unit 3 began the inspection period operating at about 88% power in a fu. coastdown mode.

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Tripping of the 3A reactor feed pump (RFP) and the resuldng intermittcc. recirculation pump

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runback caused a reactor power reduction to about 60% on September 14. The 3A RFP had

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experienced speed and flow oscillations that were caused by a problem in the mechanical-

linkage of the RFP's governor control. Operators returned reactor power to 88% power using

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the remaining two RFPs on September 15. PECo shutdown Unit 3 on Saturday, September 18,

to begin the ninth refueling outage (Section 5.1). During the outage PECo conducted a recom-

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mended inspection of the core shroud, which identified cracking. PECo completed a structural

j analysis and a 10 CFR 50.59 safety evaluation, determining that the shroud was capable of

performing its function throughout the next operating cycle (Section 3.1).

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1.2 NRC Activities

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I The resident and regional based inspectors conducted routine and reactive inspection activities j

concerning operations (Section 2.0), refueling (Section 5.1), maintenance (Section 5.0),

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surveillance (Section 4.0), engineering and technical support (Section 3.0), and plant support

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(Section 6.0). These activities were conducted during normal PECo work hour and during off-

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normal (backshift) hours. There was a total of 63 and 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> of backshift and deep-backshift

inspection hours, respectively.

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The inspection procedure from NRC Manual Chapter 2515 that the inspectors used as guidance is

parenthetically listed for each report section.

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The following specialist inspections also occurred during the report period:

l Date Sub1ect Renort Ngt Insnector

9/13-17/93 Security 93-23 DeP 'Ratta

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i 9/20-10/8/93 Digital Modifications 93-21 Calvert 9/20-10/1/93 NRC-ISI 93-26 McBrearty i

9/27-10/1/93 Occupational Exposure 93-28 Eckert

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10/12-10/15/93 Maintenance (PIMS)

93-29 Florek 10/18-10/22/93 Effluents 93-30 Jang

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2.0 PLANT OPERATIONS REVIEW (71707, 70710, 60710, 93702)

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The inspectors independently found that operators conducted routine Unit 2 activities well i

including: implementation of extended core flow, which allowed the increase of core flow above i

100% and power maneuvering in support of flux tilt testing (Section 2.1). The Unit 3 outage

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operations staff managed activities well. The licensee established a dedicated team of licensed operators to coordinate operations outage support. This team provided excellent planning input, oversight, and helped to reduce control room distractions on the operating unit.

The operations crews made correct determinations of safety system operability and reportability of identified conditions. The entry into and exit from technical specification (TS) limiting

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conditions for operation (LCOs) were adequately tracked and controlled. The inspectors i

routinely verified the operability of safety systems required to support given plant conditions at both units. Controls over emergency core cooling systems required to support refueling activities at Unit 3 were good. Housekeeping at both units was good; however, minor house-

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keeping deficiencies, such as clothing left in a fire break zone, were identified to the operations

department and quickly corrected.

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l Four instances occurred where operators or licensed operators did not perform well. These included a poor safety review of a temporary change to a reactor core isolation cooling (RCIC)

test procedure (Section 2.4), failure to return the control room ventilation ystem to a fully operable condition following a planned activity (Section 2.3), and failure to evaluate a condition that led to a fuel bundle being stuck parthily inserted in a spent fuel rack (Section 2.2).

Further, while conducting demineralizer pre-coating on the non-safety related reactor water

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cleanup system an operator caused the overflow of the pre-coat tank and radioactive contamina-tion of sections of the Unit 3 reactor building.

l 2.1 Unit 2 Flux Tilt Testing PECo appropriately investigated and took actions to correct elevated off-gas system radioactive release levels at Unit 2. On September 21 power was reduced to about 60% to conduct flux tilt

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testing to identify suspected leaking fuel pins and prevent further possible fuel damage. The

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inspector reviewed the off-gas data obtained prior to the testing, observed portions of the

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testing, and reviewed the test results; concluding that PECo took good actions to address this l

issue.

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The inspector observed portions of the testing in the control room and at the sampling station.

The licensee used an improved multi-channel analyzer system to analyze off-gas composition,-

l which provided test personnel with timely information regarding fuel condition. The inspector

noted that the reactor engineers demanded a rod position report (OD-7) prior to moving control j

rods and after the rods were returned to their original positions to verify that no control rods

were mis-positioned. The inspector concluded that test personnel were knowledgeabic. The test

plan was appropriately modified to investigate suspected fuel leaks that were identified during j

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testing.

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The inspector reviewed the test data and discussed the test results with a PECo engineer. The -

test results identified fuel leaks from bundles 30-23 and 46-39. The control rods in these fuel I

cells were fully inserted to " shadow" the fuel which will minimize further degradation. This

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action stabilized off-gas levels. PECo was continuing to monitor fuel conditions. These actions

satisfied the inspector, who will continue to monitor PECo's response to this issue.

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2.2 Stuck Fuel Bundle in Spent Fuel Rack l

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During core offload a fuel bundle became stuck partially inserted in its storage rack in the Unit 3 fuel pool on September 24. This third cycle fuel bundle was partially landed in the storage

rack when the refueling bridge " Hoist Loaded" light went out. When the refueling bridge

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operators attempted to raise the bundle out of the rack, the " Hoist Jammed" interlock activated.

l The licensee suspended refueling activities to evaluate and correct the probicm.

The PECo reactor engineering staff evaluated the material condition of the fuel bundle, consid-ering its embrittlement due its exposure history. They calculated that an allowable lifting load

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limit of 2,000 pounds force could be applied to the bail handle without any potential damage to j

the bundle. The fuel vendor agreed with the PECo calculation.

i The licensee initiated a Troubleshooting, Minor Maintenance and Testing (TMT) procedure to i

increase the upper limit of the load cell to 2,000 pounds force and control the lifting of the fuel l

bundle. Performance of the TMT freed the stuck fuel bundle. The inspector reviewed the-

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TMT, attended the pre-task briefing, and observed the evolution from the refueling floor. The

pre-task brief was very thorough, with the Task Director clearly communicating the need for

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caution and conservatism during the evolution. The TMT _was well written and the evolution j

was conducted in an orderly, well planned manner. Health Physics technicians evacuated all l

unnecessary personnel from the refuel floor as a safety precaution in the event of a fuel bundle j

integrity breach.

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4 PECo found a five-foot piece of a local power range monitor (LPRM) string obstructing the fuel storage rack cell. The refueling bridge operators (RBOs) performed a visual inspection of the fuel bundle, which revealed no structural damage to the bundle. While the TMT was being prepared, the RBOs performed a visual inspection of the spent fuel storage cells surrounding the stuck bundle using a close-circuit camera. Two sections of LPRMs about two-feet long were found in two other empty cells. As a result, PECo performed a full inspection with the camera of all remaining empty storage cells prior to recommencing fuel movement. No further obstructions or debris was found.

Through review of the Senior Reactor Operator Limited to Fuel Handling (LSRO) log, the

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inspector noted that a similar incident occurred the previous evening, except that the bundle did not become stuck. The Core Component Transfer Authorization Sheet (CCTAS) was revised to locate the fuel bundle to a different cell and an action request (AR) was initiated to look for

obstructions in the cell following the outage. The inspector followed-up as to why an inspection

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of the cell was not performed at that time. In discussions with the LSROs, the inspector

learned that fuel bundle swelling had caused prior experiences with tight fitting storage cells.

Because the bundle was not lodged in the cell, the LSROs believed that swelling was the cause

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of the problem. PECo realized the cause of these two incidents were related to a fuel pool clean-up in June '93 when LPRM debris was found during the inspection of the adjacent fuel

rack locations.

PECo had a contractor remove old LPRM strings and other spent reactor components from the fuel pool in June 1993. During that clean-up, the contractor reported debris in the area of the storage racks to the Rad Waste management. As a result, the licensee required the contractor to perform a detailed inspection of an enlarged area of storage cells to ensure the removal of all debris. During this inspection the contractor found more debris in the storage racks than

originally reported. The contractor intended to perform a final inspection using an underwater camera, however, the July outage for Unit 3 prevented the inspection from being performed.

At the beginning of the refueling outage in September, the licensee was confident with the condition of the fuel pool based the results of the contractors findings. As stated above, PECo performed a visual inspection with a camera of all empty cells in the fuel pool prior to resuming fuel movement.

The inspector determined that PECo took adequate corrective actions. No further incidents involving the fuel pool occurred for the remainder of the outage. However, PECo's staff involved with this incident displayed less than adequate attention to detail by assuming that the

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first fuel bundle problem was due to swelling and not investigating to determine the actual cause. PECo raised the sensitivity of the operators concerning issues in which senior manage-

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ment needs to be advised. The inspector had no further questions.

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2.3 Mis-alignment of the Control Room Emergency Ventilation System On October 6 a Nuclear Plant Operator (NPO) found the control switches for the control room emergency ventilation (CREV) system fans in the "off" position. These switches are normally maintained in the " auto" position to ensure that the CREV system will automatically start if the main control room ventilation (MCRV) system tripped on a high radiation condition. Shift management suspended core alterations and directed the NPO to align the control switches.

Both units were shutdown at the time of the incident; however, PECo determined that the CREV should have been operable for about 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> because of core alterations activities at Unit 3. The licensee notified the NRC via the Emergency Notification System (ENS).

The MCRV had tripped and CREV automatically started the previous day as part of a planned evolution. The licensee transported high radioactive materials through the area near the MCRV system radiation monitors. During the recovery of the MCRV system, the NPO was directed to realign the MCRV system. He needed to perform System Operating (SO) procedures SO-40D.7. A, " Restoration of Control Room Ventilation Following a High Radiation Trip," which referenced two other procedures S0-40.1. A, "Startup of Control Room Ventilation." and SO-40D.1.B " Setup of CREV for Automatic Operation". PECo found that procedure S0-40D.7.A, was not followed correctly, because SO-40D.I.B, was not performed. This was due to the less than adequate step in the restoration procedure (SO-40D.7.A) that directed the performance of more than one task. Further, the procedural step used cascading procedures to ensure that all required actions were accomplished.

Short term corrective actions implemented by Operations Management included discussion with the operators of the need to properly coordinate the execution of procedures to ensure all procedural requirements are completed. In addition, all Shift Managers were informed that p2-job briefings should be conducted prior to planned MCRV trips. PECo will revise the step in the procedure to direct one task.

The inspector reviewed the procedures and PECo's corrective actions, and agreed with the licensce's conclusions. The inspector also determined that the safety significance of this incident was low.. The potential consequences were minimal because the core alterations on Unit 3 were not continuous during the 10 hour1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> period. Because secondary containment and the standby gas treatment system (SBGT) were operable on Unit 3, no signiBcant amount of radioactive material could have entered the main control room. Also, the Alarm Response Card associated with the CREV system would have immediately alerted the operators to the mis-aligned fans if the control room normal ventilation isolated on a high radiation signal.

Technical Specification 6.8.1 requires that operators shall adhere to procedures. The inspector concluded that the licensee's failure to fully implement the step in S0-40D.7.A was of minor safety significance and that the licensee had taken appropriate corrective action to prevent recurrence. The violation for failure to strictly adhere to the SO is not being cited because the criteria specified in Section V. A. of the NRC Enforcement Policy were satisfie.

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2.4 RCIC Overspeed Test On October 19, steam was inadvertently vented into the reactor core isolation cooling (RCIC)

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room during restoration from a turbine overspeed test. The steam was vented through a removed section of the system that normally returns the condensed RCIC turbine steam to the main condenser. Three PECo employees were in the vicinity of the steam flow. None of the employees were injured; however, one individual received a small amount of contamination on

his pants which resulted in a Personnel Contamination Report (PCR). PECo initiated an

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Occupational Accident Report and a Performance Enhancement Program (PEP) investigation of this incident.

PECo was performing a routine test (RT)-X-013-210-3, "RCIC Overspeed Trip Test," to verify the proper operation and setpoint of the RCIC turbine's mechanical overspeed trip. The RT aligned auxiliary steam through a removable spool piece to the turbine. While verifying the

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initial system line-up in the RCIC Room, the NPO noticed that a 12 foot section of the RCIC i

steam drain line was missing. The System Manager (SM) recognized that the missing section would provide a leak path for steam during the test. The SM initiated a temporary change (TC)

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to the RT to fail closed two air operated valves (AOVs) in order to isolate the removed section.

Two outage Shift Supervisors (SSVs) reviewed and approved the TC. After completion of the

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overspeed portion of the RT, the NPO re-aligned the air supply to the two AOVs, which caused

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the AOVs to re-open, which vented the residual steam pressure into the RCIC Room.

l The inspector reviewed this event and noted that a maintenance crew had removed the section i

of the drain pipe under a work order prior to this event. A blocking sub-clearance which utilizcd existing blocking points was applied to the RCIC system Master blocking clearance to l

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cover the job. The sub-clearance was signed onto the Master clearance form after the RCIC SM had reviewed the Master clearance and determined that the system conditions were adequate to perform the RT. The inspector reviewed the Clearance and Tagging (CT) Manual to

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determine if the criteria for a clearance suspension were satisfied. The clearance suspension i

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changes an active clearance if it interferes with system operation or testing. For this RT, a clearance suspension was not necessary and the inspector noted that the CT program does not have a mechanism to stop work or " freeze" a clearance that does not meet the suspension

criteria. This resulted in the RCIC master clearance not identifying that testing was in progress.

The sub-clearance being applied to and performed on the RCIC system degraded the system to a condition that was adverse to running the test. This item will remain unresolved pending I

further review of the CT program (URI 93-24-01).

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The inspector reviewed the TC which failed to close the two steam drain line isolation AOVs i

and noted that the RT was revised to isolate the boundary in lieu of using a blocking tag. The l

TC did not consider the effects of residual steam pressure during system restoration. The

inspector determined that the technical review of this TC was inadequate.

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The inspector discussed the incident with the SM, SSV, and Station Qualified Reviewer (SQR).

The SSV and SQR were both licensed Senior Reactor Operators and familiar with the safe operation of the RCIC system. Each individual performed an independent review of the TC package. The RCIC SM had informed the SSV and the SQR that the system was breached, but

the TC would isolate this section of the system. The SQR and SSV indicated that control of the RCIC system had been turned over to the Nuclear Maintenance Department (NMD) to complete

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outage work and indicated that they would not have operated the system in its current condition.

Neither the SSV nor the SQR verified actual system condition prior to approving theTC.

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The inspector reviewed Administrative Procedure A-4.2, " Station Qualified Reviewer Program,"

and determined that a less than adequate review of the TC package was performed by the SQR.

i The SQR should have reviewed the package for technical accuracy and adherence to quality l

program requirements. Further, the inspector reviewed the Nuclear Quality Assurance Plan (NQAP), section governing the conduct of surveillance testing. The inspector determined that

the SQR and SSV maintained less than adequate overall control of the tests affecting plant l

operations, in that they did not assure that the test did not adversely affect the safe operation of

the plant.

The inspector concluded that the Operations Shift Management did not perform an adequate i

technical review of a RCIC system RT, in that steam was applied to the system while it was breached. This resulted in an inadvertent release of radioactive contamination to the Unit 3 reactor building. This is a violation of the requirements stated in Administrative Procedure A-4.2 and the NQAP both of which are required by TS 6.8. (NOV 93-24-02)

2.5 Engineered Safeguards Feature Walkdown The inspector performed a detail walkdown of the Unit 3 Residual Heat Removal (RHR)

i system, to independently verify its operability. The walkdown included verification or review

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of: system equipment condition; check-off list and plant drawing accuracy; valve, breaker,

instrument and switch alignment; pump in-service test (IST) data and the system as-built

configuration. The inspector concluded that the system was capable of performing its intended safety function. The inspector noted that general housekeeping in the RHR pump rooms was

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good, The inspector found the system to be lined-up correctly and breakers properly positioned.

l The motor control center (MCC) breaker cubicle for MO-3-10-034B was visually inspected for loose leads; signs of overheating; loose wires; and debris. The material condition of the breaker cubicle was good and all the leads appeared to be tight with no signs of insulation

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breakdown. However, several deficiencies in component support structures were noted.

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While performing review of the systems material condition several concerns with valves and valve supports were noted by the inspector and listed below.

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MO-3-10-89A power supply cable was supported by several plastic tie-wraps; i

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MO-3-10-89C vertical hangar support clevis had an undersize link pin and the limitorque cover to the valve was missing two bolts;

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MO-3-10-15C, RHR Shutdown Cooling Valve, spring hangar had several wedges lodged behind the spring mechanism preventing it from moving freely.

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The inspector discussed these observations with the system manager for the RHR system.

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PECO has initiated non-conformance reports, work action request, and corrective maintenance

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action request to resolve the above concerns. The licensee additionally stated that they would

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walkdown the remaining systems to determine if other hangers were gagged. These concerns do not make the system inoperable, but the inspector did note that component loading during a l

seismic event may have a detrimental effect on the valves. Based on the observed physical

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condition of the RHR system the inspector concluded that the system was maintained in an acceptable condition.

The inspector reviewed a vendor int vction report for the 3C RHR pump motor which had been

removed for inspection and rework The report indicated several minor items that required -

correction. The report also stated that these items did not threaten the motor and could not

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have been detected using predictive technology. The inspector reviewed the 3C RHR pump IST data from 1987 until present and determined that the data did not indicate any degradation in l

pump performance. The inspector also reviewed test data not included in the IST program

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(motor current) and noted that this data did not identify any degradation in motor performance.

The inspector concluded that available test data indicated that the 3C RHR pump motor ap-peared to be in good condition prior to being removed for inspection.

l 2.6 Licensee Event Report Update i

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During the report period, the inspectors evaluated licensee staff and management response to plant events that occurred, as discussed in Section 2.0 of the report. In addition, the inspectors

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reviewed Licensee Event Reports (LERs) submitted by the licensee during the period for events i

that were of lower safety significance, and did not warrant immediate review and evaluation by

the inspector at the time of the event. The inspector reviewed the following LER and found

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that the licensee had identified the root causes, implemented appropriate corrective actions, and

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LER No.

LER Date LER Title i

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2-93-13 9/16/93 Inoperable Primary Containment Isolation ' Valve not

Logged or Isolated.

3-93-07 9/16/93 Suppression Chamber-Reactor Building Vacuum Breaker -

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Surveillance Requirement was not performed.

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3.0 ENGINEERING AND TECHNICAL SUPPORT ACTIVITIES (37700)

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l 3.1 Unit 3 Shroud Inspection l

PECo conducted a well managed and technically sound inspection that disclosed cracks in the

heat affected zone (HAZ) of core shroud welds at Unit 3. This inspection was conducted as a

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result of GE rapid service information letter (RICSIL) No. 54, dated October 3,1990 and GE

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service information letter (SIL) 572, dated October 1,1993, and its revision. These GE documents recommended inspection of the core shroud welds following identification of l

l-cracking at a foreign reactor and Carolina Power and Light's (CP&L) Brunswick Nuclear j

Station. The inspectors observed portions of the visual examination process and found that it

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produced adequate results and documentation through an underwater invessel camera and video j

tape. Initial video pictures were of poor quality, but the quality increased as PECo understood j

i the affects that the radiation from the reactor fuel left in the vessel was having on the camera

tube. The camera tube was replaced at frequent intervals to assure adequate picture quality.

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Initially, PECo began by planning to clean and visually inspect weld H3 and H4 in eight locations where peripheral fuel bundles were removed. Based on finding cracks in these areas,

PECo expanded the scope to include 100% of the H3 and H4 welds. The visual inspections

l identified cracking in the lower HAZ of weld H3, located below the core guide support ring and l

to a lesser extent in the-H4 weld located in the middle of the core shroud barrel. Following

completion of the full internal visual inspection for welds H3 and H4, PECo visually inspected portions of the external surfaces of these welds and identified no instances of cracking. As l

discussed in the SIL, PECo and GE analyzed the cracking and GE prepared a final structural l

report on the cracking. GE determined an allowable through wall shroud crack length and

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criteria for determining what the length of the crack would be following the next operating cycle following the application of several conservative assumptions. These assumptions included: use of the ASME section XI safety factors and crack proximity assumptions even though the shroud is not a pressure boundary and conservative crack growth, based on conservative assumptions of nuclear fluence in the cracked area. PECo also assumed that any identified cracks were

through wall. Based on this, PECo determined that the total assumed crack length following the

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next outage would be 247 inches, below the GE structural limit of 430 inches.

The inspectors attended several plant operations review committee (PORC) meetings where the shroud cracking was discussed and found that the issue was well understood and appropriate questions asked and answered. Overall, PECo did a good job identifying and evaluating the I

cracks in the Unit 3 core shroud.

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PECo evaluated the possibility for shroud cracking at Unit 2. The conclusion was that Unit 2 cracking, if present, should not be worse than the cracking observed at Unit 3. This was based

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on Unit 2 having better reactor water chemistry through its operating life. Since the cracking

phenomenon was based on intergranular stress corrosion cracking (IGSCC), the water chemistry I

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plays an important role in the cracking. Further, Unit 3 had more IGSCC flaws identified in reactor coolant pressure boundary piping, presumably due to its poor water chemistry early in plant life.

A meeting between the NRC staff and PECo was held on November 3,1993, to further discuss the shroud inspection findings and analysis of the safety evaluation. The results of the meeting and the discussions between the NRC staff and PECo will be documented in an NRR report detailing the meeting minutes.

3.2 Independent Safety Engineering Group Review The Independent Safety Engineering Group (ISEG) was established to provide an independent assessment of plant activities. ISEG is independent of the site QA organization and reports off-site to the Director, Nuclear Quality Assurance. The inspector reviewed ISEG's composition, interviewed ISEG members, and reviewed ISEG's findings in order to evaluate their effective-ness at overseeing plant activities. The ISEG staffis composed of five full-time engineers. The l

group's members have diverse backgrounds in nuclear operations with experience levels ranging

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from eight to over twenty years.

The inspector reviewed selected ISEG reports and concluded ISEG's reviews were critical and focused on the appropriate issues. ISEG's recommendations are tracked using the AR system l

and ISEG controls closecut of the AR. The inspector noted that ISEG's findings have enhanced -

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plant operations in the areas of shutdown risk and in the safety evaluation for a special proce-

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dure developed to backfill the reactor vessel reference legs while at power. ' The inspector concluded that ISEG is fulfilling its TS requirements and providing effective oversight of plant operations.

3.3 Walworth Valve Yoke Cracking Problem PECo took conservative and timely actions to address potential operability issues resulting from the identification of cracks on the yokes of several safety-related Walworth pressure seal valves at Unit 3. An operator observed the cracks while conducting a surveillance test on a core spray system isolation valve MOV-3-14-11B. The cracks were found to be in the area where the valve yoke struts blend into the valve operator mounting flange, at the high stress points at the edges of the struts. This normal open valve is cycled as part of the inservice testing program and does not receive a containment isolation signal. PECo inspected the same valve on Unit 2 and found a similar cracking situation. In both of these cases, weld repairs were conducted.

Based on finding these cracks, PECo developed a list of the similar valves at Unit 3 and began an engineering analysis of the flaws. As inspections were ongoing at Unit 3, engineering deter-mined that a potential cause could be that the bolting of the Limitorque to the valve voke had not been properly torqued, allowing the yoke and operator flanges to separate and allow flexing of the yoke flange. The NRC staff reviewed the engineering analysis and accompanied mechan-ics checking the torque of valve to operator bolting. On October 1 PECo decided to shutdown Unit 2 to allow a complete inspection of the suspect valve group.

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.A list of all potential valves was developed for both units. The final outcome was that nine

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valves were cracked (5 at Unit 2 and 4 at Unit 3). Weld repairs were conducted in all cases.

Engineering also evaluated the known thrust on these valves and determined that the torque

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values for several needed to be increased, this was done. PECo was able to get samples of the cracking in two cases, which indicted that the cracks started at existing flaws in the cast yokes.

i The safety significance of the valves which were found cracked were minimal, since all were

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either open or required to be open during an accident and thus. Any cracks would be put in compression. At the close of the period, PECo was completing the engineering analysis of the failures and applicability review for a 10 CFR 21 report.

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3.4 Plant Modifications l

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The inspectors reviewed the plant modification (MOD) process and concluded that the process j

provided adequate control of MOD activities. The inspectors examined selected MOD packag-l es, interviewed personnel, and observed field activities and determined that the MODS werc

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implemented in accordance with procedural and TS requirements.

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The MOD process is comprised of three basic steps, proposal initiation / approval, installation, and acceptance / closure. The inspectors found that the first two areas, including the licensce's j

10 CFR 50.59 reviews, were adequate. However, the number of different procedures and

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groups involved in the modification process made the MOD closecut process difficult to follow.

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Recent personnel changes resulting from the Nuclear Effectiveness and Efficiency Design Study

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(NEEDS) contributed to this difficulty. The inspectors noted that the licensee recently approved procedural enhancements to simplify the closecut process for future modifications.

The inspectors reviewcd the MOD packages for MOD 5236, " Torus Hardened Vent" and MOD

5383 "RHR Equalizing Line Block Valve" The inspectors noted that the packages were

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comprehensive and contained appropriate guidance including the MOD scope and installation i

plan, MOD acceptance test (MAT) requirements and the 10 CFR 50.59 review.

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The inspectors observed the installation activities for several MODS including MOD 5347,

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"ESW Flow Monitoring Equipment", MOD 5247, " CAD Analyzer", and MOD 5169, "125 l

VDC Battery Charger" and noted that these activities were well controlled and that installation

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personnel were knowledgeable.

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l The inspectors noted that the plant drawings are not required to be updated prior to performing l

the M AT. The inspectors were concerned that this could result in a loss of configuration-

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control and challenge the operators. The inspector noted that a new procedure, MOD-C-5,

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" MOD Process Acceptance Testing" will require drawings to be revised prior to removal of l

installation clearance. The inspector was satisfied with response to the issues noted above.

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3.5 Root Cause Analysis for Component Failures Leading to the JULY 4,1992 Reactor Scrarn (Closed) Unresolved Items 92-14-01 and 92-14-02: These items deal with NRC review of PECo root cause analysis of a non-safety related switchyard transformer and safety-related switch failure which led to the July 4,1992, Unit 3 reactor scram and emergency plan Alert.

The B phase of the #1 transformer failed. This transformer, located in the North Switchyard allows the Unit 3 generator output to supply the Muddy Run station and the #3 startup trans-former. The transformer failure caused an electrical grid transient which caused the supply breaker to the #3 startup transformer to open effecting a loss of power to the #3 startup source.

Three of the four emergency buses normally supplied from this source automatically transferred to their alternate supply from the #2 source on the sensed loss of voltage. The Unit 3 E-13 bus deenergized because the switchgear breaker control switch for the #3 startup supply to the bus had not spring returned to its normal after shut position when the breaker was closed. This prevented switch contacts from making up, which caused the fast transfer and emergency diesel start logic not to function.

PECo completed their full investigation of these failures in late 1992. Inspector review of PECo's transformer root cause evaluation showed that flashovers on 230 KV disconnects caused high B phase currents, internal insulation damage, turn-to-turn winding shorts, and locally high currents. These high currents caused the windings to heatup further damaging the insulation and causing internal mechanical damage. The breaker control switch (GE SMB) was found to have had internal wear which caused the spring not to be strong enough to return it to its normal position. PECo observed other such failures since the event. These switches have been replaced during the 1993 refueling outage at Unit 3. Further, operators have received training on the significance of these switches not being returned to their normal positions and that if they do not return, the switches can be moved by hand to the normal position. The inspector deter-mined that PECo took adequate corrective actions for these failures and adequately determined the root causes, these items were closed.

4.0 SURVEILLANCE TESTING OBSERVATIONS (61726, 71707)

The inspectors observed conduct of surveillance tests to determine if approved procedures were used, test instrumentation was calibrated, qualified personnel performed the tests, and test acceptance criteria were satisfied. The inspectors verified that the surveillance tests had been properly scheduled and approved by shift supervision prior to performance, control room operators were knowledgeable about testing in progress, and redundant systems or components were availabic for service, as required. The inspectors routinely verified adequate performance of daily surveillance tests including instrument channel checks, and jet pump and control rod operability tests. The inspectors found the licensee's activities to be generally acceptable.

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4.1 Unit 3 Loss of Offsite Power Test

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On October 25 PECo performed well during surveillance test ST-O-052-110-3, " Diesel Genera-tor Simulated Auto Actuation and Load Acceptance For Unit 3." The purpose of the test was l

to verify the EDGs ability to start automatically on a loss of offsite power (LOOP) condition coincident with a simulated loss of coolant accident (LOCA) signal; and to load emergency

equipment on the EDGs within the required time. During the test, all equipment functioned as

expected within the required times and the test was declared satisfactory.

l The inspectors reviewed the test procedure, attended the test pre-briefing, witnessed conduct of

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the test from the control room and the EDG building and reviewed the test results. The test pre-brief was very thorough, with the Shift Manager clearly communicating the need for caution and conservatism during the evolution. The procedure was well written and testing was conducted in an orderly, well planned manner. Communications by operators and technicians in the control room and in the plant were excellent.

4.2 Emergency Diesel Generator Problems

During this inspection period, three instances occurred where EDGs were found to be inopera-ble during post-maintenance and surveillance testing. In each case the operators took appropri-ate actions to declare the appropriate functions of the EDG inoperable and entered the appropri-

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ate TS LCO. Two of these events were related to a breaker and a relay contact problem affecting the ability of two EDGs to supply power to Unit 3. The other was related to fuel oil filter clogging which affected the ability of one EDG to supply power to both units.

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4.2.1 E-1 Breaker Failure to Close

On September 27, during a post-maintenance testing run of E-1, the output breaker to the E-13 cmergency switchgear bus would not close. PECo reviewed the situation and determined that this was because the E-13 breaker had not been fully racked into its slot. Because of this, contacts were not made up and the breaker would not close. After investigation, the breaker was re-racked into its slot and the test completed satisfactorily.

i 4.2.2 E-2 Fuel Filter Clogging

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On October 12, during its monthly operability run, EDG E-2 was secured before being loaded following the operator receiving a high fuel oil filter differential pressure alarm and secured the machine. The operator then swapped the duplex filter to the other element and restarted the EDG. The high differential pressure alarm came in again as the machine was being loaded.

The EDG was secured and declared inoperable. An AR was written to allow maintenance to change-out the filter elements. The elements were changed and the EDG restarted and tested satisfactorily.

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i The inspceter independently reviewed the EDG technical manual, the station operating proce-j dures, and the surveillance testing for reference to the fuel oil differential pressure setpoints and j

operational considerations. The inspector found that these documents adequately addressed the l

differential pressure setpoint and the operations response to the alarm. However, while it was j

conservative for the operator to secure the EDG before switching the fuel oil filter to the spare

element in this instance, the alarm response procedure does not specifically say to secure the l

EDG. Based on this concern the operations department manager was taking steps to ensure that

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operators would not secure the EDG if it was running loaded in an emergency.

PECo analyzed the removed filters and found carbon particles, which were assessed as not

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l being sized or loaded enough to have caused the high differential pressure indication. Further, fuel oil tanks were sampled with no indication of water or debris. Based on this PECo was not j

able to determine the actual cause of the event.

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4.2.3 E-4 Failure to Auto-Start

On October 14 the undervoltage (UV) relay (127-18) on vital bus E-43 failed to actuate while

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performing surveillance test ST-O-054-754-3, "E-43 4KV Bus Undervoltage Relays Functional

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Test." The failure resulted in the bus not being able to automatically transfer to the alternate

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l startup power source or to the EDG on a bus undervoltage condition. The SSV declared the E-

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43 Bus and E-4 EDG inoperable and entered LCOs for both components.

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PECo's I&C technicians performed troubleshooting activities on the HGA type UV relay to I

determine the cause of the problem. The troubleshooting identified that an unused set of

contacts on the relay were interfering with the normal operation of the UV relay, preventing the

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normal contacts from closing. The technicians adjusted the spare contacts out of the way,

.i recalibrated, and placed the UV relay back in-service. The ST was re-performed satisfactorily and the E-43 bus and E-4 EDG were declared operable. PECo also visually inspected the UV

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relays on all of the remaining Unit 2 and Unit 3 vital buses. No further problems were found.

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The inspectors completed a detailed review of the electrical system drawing and the ST finding that the functions of the circuitry were appropriately tested. This included testing to ensure that l

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the appropriate transfer functions and the EDG start fun:tions performed as designed. The test also met the intent of the TS functional testing requircment for these relays.

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4.3 Control of Secondary Containment Integrity l

l The inspectors reviewed PECo's program for maintaining secondary containment (SC) integrity

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and identified concerns regarding the containment capability test procedure, the restoration of

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breaches that did not render the secondary containment inoperable, and operation of the access j

doors in the reactor building airlock.

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i The inspectors reviewed procedure GP-16, "Bmaching and Establishing Secondary Contain-ment" and noted that the conditions specified for rendering the secondary containment inopera-ble satisfied TS 3.7.C. The inspectors also noted that GP-16 provided adequate guidance for re-

establishing SC integrity. The licensee rendered the Unit 3 SC inoperable on September 20 to

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facilitate replacement of the 3C RHR pump motor. The inspectors verified that PECo re-l

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established SC integrity on September 22 in accordance with GP-16.

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j Prior to re-establishing secondary containment integrity, PECo performed ST-O-009-200-3,

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" Secondary Containment Capability" to verify the capability of the standby gas treatment system (SBGT) to maintain -0.25 inches of water vacuum in the SC without exhaust flow exceeding j

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10,500 cubic feet per minute (CFM). The inspectors reviewed the test procedure, observed the l

test performance, and reviewed the test data calculations to determine if the testing satisfied TS j

requirements. The inspectors observed that the test was conducted in accordance with the procedure, ae test calculations were correct and that the measured values satisfied TS 4.7.C.1-

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requirements.

The inspectors noted that PECo secured access to and from the reactor building during the test.

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Access to the reactor building is through an airlock system which is maintained by a multiple i

door configuration. The TS specifies that secondary containment integrity is satisfied provided j

at least one door in the access opening is closed. The Updated Final Safety Analysis Report j

(UFSAR) states that reactor building access is through an airlock system which is designed to l

maintain the leaktightness of the reactor building during personnel access. The inspectors j

concluded that the airlock is relied upon to maintain secondary containment integrity during personnel access. The inspectors concluded that the leaktightness of the access system is not being tested due to the practice of securing reactor building access during secondary contain-

ment testing and questioned if TS 4.7.C is being satisfied.

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The secondary containment test procedure uses asterisks to alert the operator that unsatisfactory completion of that step could require action in accordance with a TS LCO. The inspectors noted that the portion of the test procedure which documents the capability of one standby gas

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fan to maintain adequate secondary containment vacuum is not highlighted with an asterisk.

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The UFSAR accident analysis assumes the failure of one EDG, which could result in only one

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SBGT fan being available during accident conditions. The inspectors questioned whether the l

step discussed above should be highlighted to aid the operators in making appropriate operability l

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decisions when one standby gas treatment fan is unable to maintain secondary containment.

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GP-16 also provides a method where the SC can be breached without rendering it inoperable.

l The method uses an engineering calculation to predict the amount ofin-leakage for a particular

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sized breach. The cumulative inventory of breaches is maintained in the barrier breach log l

which sums the cumulative leakage from the most recent containment capability test combined with~the sum of the temporary breach leakages. The SC is considered intact if the total leakage

is less than 9,000 CFM leakage, which is conservative when compared to the TS limit of -

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10,500 CFM. The inspectors noted that the GP-16 does not require retestipg of the breaches j

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following restoration. The inspector discussed this issue with PECo's engineers who indicated j

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that testing the barrier was not required because the penetration designs were vendor tested, and a controlled assembly process was used to restore the penetration to the design configuration.

The inspector identified one barrier permit that had been cleared without restoration of the

barrier penetration to an approved design configuration. The inspectors questioned whether this j

method of restoring breached barrier penetrations was adequate.

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The access doors to the reactor building are electronically supervised and alarm if door opera-l

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tion results in breaching of the secondary containment. The inspectors noted that on several l

occasions the alarm system actuated due to improper door operation. The inspectors questioned

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whether this condition satisfied TS requirements regarding secondary containment integrity.

l This inspectors consider the safety significance of this issue minimal due to the relatively short

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duration that the doors are improperly operated (less than 10 sec.). However, the TS do not specify an out-of-service-time for having both doors open at the same time.

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The licensee was reviewing these concerns and determining if a TS change was required. The

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inspectors are continuing to review the questions discussed above and these issues are unre-

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l solved (UNR 93-24-03).

l 4.4 Unit 2 Invessel-Inservice Inspection

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During the normal invessel inspection PECo identified cracking in the core spray piping at the

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welded slip fit connection in the annulus region of the vessel. Further, during inspection of the j

lower annulus baffle plate, PECo identified that one of the four "L" bolts used to fasten the p

manway cover to the baffle plate was mis-oriented. This mis-orientation appeared to have been j

caused by the bolt not being torqued. PECo was conducting analysis of these two issues, to be

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to make a submittal to NRC headquarters in accordance with NRC Bulletin 80-13, which j

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requires NRC approval of the situation prior to restan. The NRC's final review of this issue j

will he documented in a future NRC letter.

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j 5.6 MAINTENANCE ACTIVITY OBSERVATIONS (62703)

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The inspectors observed portions of v. going maintenance work to verify proper implementation l

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of maintenance procedures and controls. The inspectors verified that the licensee adequately Ia implemented administrative controls including blocking permits, fire watches, and ignition

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source and radiological controls. The inspectors reviewed maintenance procedures, action f

y requests (AR), work orders (WO), item handling reports, radiation work permits (RWP),

material certifications, and receipt inspections. During observation of maintenance work, the-f inspectors verified appropriate Quality Verification (QV) involvement, plant conditions,-TS

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LCOs, equipment alignment and turnover, post-maintenance testing and reportability review.

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The inspectors found the licensee's activities to be acceptable.

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i 5.1 Unit 3 Refueling Outage

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The ninth refueling outage for Unit 3 began September 18. Major modifications implemented

during the outage included the installation of a digital recirculation control system, a hard pipe vent path from the torus air space, replacement of the inboard main steam isolation valve (MSIV) poppets, and the reactor level instrumentation continuous backfill system. Major maintenance activities included replacement of the 3C RHR pump motor, both reactor recircula-

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tion pump seal packages, and inspection of the main tmbine rotor assembly. At the end of the period the outage was about 75% complete and was generally on schedule.

The inspectors frequently attended outage planning, status, and management meetings; finding them effective at coordinating and communicating outage efforts. The inspectors found ongoing

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modification and maintenance work activities well coordinated and controlled, and good t

radiation worker practices in use. The inspectors observed performance of activities on the refueling floor, including reactor disassembly, fuel movement, and the licensee's special

inspection of the reactor shroud (Section 3.1).

l The inspectors noted that PECo emphasized job pre-planning, pre-briefing of workers, and maintaining housekeeping controls in thejob area. These efforts were evidenced in the replace-ment of the 3C RHR pump motor activity, which involved breaching secondary containment to an area outside the power block and rigging out the pump mator, pump casing, impeller, and

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shaft. The maintenance crew demonstrated their knowledge of the task by the efficient manner in which they completed the task, with no PCRs.

Throughout the outage, PECo staff and management nave been well informed, emerging

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problems have been promptly raised and addressed, and coordination among working groups l

was excellent. Overall, the outage has been well planned, was handled professionally, and was

well managed.

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5.2 Unit 2 Dropped Shipping Liner I

On September 14 an empty irradiated component shipping liner suspended about seven feet l

below the surface of the spent fuel pool dropped approximately twenty feet into the cask storage

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area. The liner had been suspended in the spent fuel pool above the cask storage area to

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prepare the liner for shipment. Immediately following the event, PECo determined that the

spent fuel in the pool was not damaged, (no fuel is stored in the cask storage area), that there was no increase in background or airborne radiation levels, and that the fuel pool integrity was i

intact. Additionally, PECo initiated a PEP investigation and suspended fuel pool cleanup

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operations pending completion of the investigation. The inspector determined that the licensee's

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immediate response to this event was appropriate. The inspector reviewed this event and t

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I examined PECo's program for controlling the movement of items within the spent fuel pool.

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The inspector reviewed procedure M-018-001 " Spent Fuel Pool Inventory Control" which I

controls the movement of items within the spent fuel pool. The procedure requires that the

movement of loads weighing less than 1000 pounds (the empty liner weighs approximately 850 l

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pounds) over spent fuel be minimized. The inspector noted that the load path was not over any spent fuel in acccrdance with M-018-001. The inspector also noted that if the liner had tipped

over while descending, the design of the cask storage area would have prevented impact with

the spent fuel. The inspector concluded that the safety significance of this event was minimal.

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Following the event, all rigging components were inspected and found to be in good condition.

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The inspector inteniewed the job rigger who indicated that the liner had been suspended from

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the auxiliary hook of the reactor building crane via an adapter. The adapter hook was equipped

with a safety latch designed to prevent the load from slipping off the hook. The job rigger indicated that the safety latch had been taped back prior to being attached to the liner sling in order to facilitate removal of the hook from the liner sling. The rigger also indicated that the liner had been suspended for approximately 45 minutes and that several vertical adjustments of

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the liner's position had been performed prior to the drop. The inspector concluded that the liner slipped off the adapter hook; based on the good condition of the rigging components and

the defeated adapter hook safety latch. PECo was performing an evaluation to determine if the l

vertical drag forces which acted on the liner during the vertical repositioning contributed to this event.

I The inspector reviewed PECo's load handling procedures and noted that PECo does net have a specific procedure for handling light loads (less than 1000 pounds). PECo relies on a l

formalized training program to ensure safe load handling. The inspector reviewed the training

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records for the rigger and crane operator involved in this event and noted that both individuals

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had completed the required PECo training. The inspector reviewed PECo's rigger and crane operator training program and concluded that the program was generally good, however, the inspector noted that the program did not address vertical component drag when handling loads in a viscous fluid and also did not provide guidance on the need to implement appropriate precautions when use of a hook's safety latch is considered impractical. The inspector reviewed

industry guidance (ANSI /ASME B30.2-1983) regarding the use of safety latches and noted that defeating the safety latch is an accepted industry practice when the rigging application makes

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use of a latch impractical. The inspector concluded that weaknesses in rigger training and station policies regarding compensatory measures to be implemented when the safety latch is defeated contributed to this event. The inspector reviewed the PEP investiga-

tion report and noted that the investigation was thorough and identified appropriate corrective

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action recommendations. The inspector concluded PECo's follow-up actions were acceptable -

and had no further questions.

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5.3 Residual Heat Rernoval Heat Exchanger Leak - Unit 2

i PECo responded well to a suspected leak in the 2B RHR heat exchanger. - The chemistry l

department identified the potential for a leak through routine high pressure service water j

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(HPSW) sampling. The initial sample results identified that the leak could have been from either the 2B or 2D heat exchangers. The licensee determined that the leak was from the 2B

RHR heat exchanger and promptly isolated the heat exchanger to minimize effluent releases.

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After isolating the heat exchanger, the licensee performed further testing to identify the location

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of the leak. This testing revealed that the leak was from the tube bundle region. Presently, the

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licensee is maintaining the heat exchanger isolated and plans to repair the leak in November i

1993. The inspector concluded that the licensee aggressively pursued this issue and noted good.

l use of chemistry data to evaluate component performance.

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5.4 High Pressure Service Water Pump Failures - Unit 2 PECo determined through metallurgica' analysis that two recent HPSW pump shaft coupling

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failures were caused by intergranulu stress corrosion cracking. The two failures occurred

l within one month of each other. The two couplings failed in different ways; the C coupling j

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failed in a horizontal axis and the B failed in a vertical crack. PECo speculated that the stress necessary to cause the failures resulted from vibration due to an in line rubber bushing falling i

from its support for the C pump and a non-symmetrical load caused by water flow through a l

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crack in the pump casing for the B pump. The ultimate fix to this problem is to replace the

couplings with material that is not susceptible to IGSCC.

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Inservice testing data for these pumps showed no degradation in vibration. readings prior to

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failure. These reading are taken on the pump motor bearing, located some thirty feet above the i

deep draft pump. This arrangement is not conducive to identification of shaft vibration due to the dampening effects of the pump motor support. PECo has developed a method of taking-l

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vibration readings on the rotation pump shafts. This vibration method was used on the eight

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pumps after the B and C were returned to service. Data indicated that the 2A pump shaft was

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vibrating at an amplitude about twice that of the other pumps. Based on this PECo plans to

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remove the A pump and conduct an inspection, once a replacement pump can be put together.

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This disassembly should validate the use of this vibration technique.

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6.0 PLANT SUPPORT (.71707, 90712)

6.1 Radiological Controls The inspectors examined work in progress in both units to verify proper implementation of j

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health physics (HP) procedures and controls. The inspectors monitored the ALARA (As 1.ow As Reasonably Achievable) program implementation, dosimetry and badging, protective clothing J

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use, radiation surveys, radiation protection instrument use, handling of potentially contaminated equipment and materials, and compliance with RWP requirements. The inspectors observed

that personnel working in the radiologically controlled areas were meeting applicable require-

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ments and were frisking in accordance with HP procedures. During routine tours of the units,

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the inspectors verified a sampling of high radiation area doors to be locked, as required. All

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activities monitored by the inspectors were found to be acceptable.

j 6.2 Physical Security

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The inspectors monitored security activities for compliance with the accepted Security Plan and

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associated implementing procedures. The inspectors observed security staffing, operation of the

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Central and Secondary Access Systems, and licensee checks of vehicles, detection and assess-ment aids, and vital area access to verify proper control. On each shift, the inspectors observed protected area access control and badging procedures. In addition, the inspectors routinely

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inspected protected and vital area barriers, compensatory measures, and escort procedures. The inspectors found the licensee's activities to be acceptable.

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7.0 MANAGEMENT MEETINGS (71707,30702)

The Resident Inspectors provided a verbal summary of preliminary findings to the s'ation

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management at the conclusion of the inspection. During the inspection, the Resident Inspectors

verbally notified licensee management concerning preliminary findings. The inspectors did not

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provide any written inspection material to the licensee during the inspection. The licensee did

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not express any disagreement with the inspection findings. This report does not contain propri-etary information.

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