IR 05000387/1993022

Insp Repts 50-387/93-22 & 50-388/93-22 on 931116-1231. No Violations Noted.Major Areas Inspected:Plant Operations, Radiation Protection,Surveillance & Maintenance,Engineering & Technical Support,& Safety/Quality Verification

ML17158A110
Person / Time
Site:	Susquehanna
Issue date:	01/25/1994
From:	Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML17158A109	List: IR 05000387/1993022 ML17158A108
References
50-387-93-22, 50-388-93-22, NUDOCS 9402040046
Download: ML17158A110 (18)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION I

Inspection Report Nos.

50-387/93-22; 50-388/93-22 License Nos.

NPF-14; NPF-22 Licensee:

Pennsylvania Power and Light Company 2 North Ninth Street Allentown, Pennsylvania 18101 Facility Name:

Inspection At:

Inspection Conducted:

Susquehanna Steam Electric Station Salem Township, Pennsylvania November 16, 1993 - December 31, 1993 Inspectors:

G. S. Barber, Senior Resident Inspector, SSES D. J. Mannai, Resident Inspector, SSES Approved By:

J. White, Chief Reactor Projects Section No. 2A, t>>Q$ >> ff Date Tdd d

p d

p d

d d

d d

p (during day and backshift hours) of station activities, including: plant operations; radiation protection; surveillance and maintenance; engineering and technical support; and safety assessment/quality verification.

Three non-cited violations were identified during review of Licensee Event Reports (LERs).

Findings and conclusions are summarized in the Executive Summary.

Details are provided in the full inspection report.

9402040046 940125

'DR ADOCK 05000387

PM

EXECUTIVESUMMARY Susquehanna Inspection Reports 50-387/93-22; 50-388/93-22 November 16, 1993 - December 31, 1993 Operations (30702, 71707, 71710)

The licensee identified excessive Unit 2 drywell leakage which necessitated a controlled shutdown.

The leak was from a reactor building closed cooling water (RBCCW) reactor return line for the 2A reactor recirculation pump.

A qualified weld repair was successful at stopping the leak, Section 2.2.1 pertains.

The inspector performed an Engineered Safety Feature (ESF) walkdown of the Unit 1 Automatic Depressurization System (ADS). The inspector found the system properly aligned for the given plant configuration.

Some minor deficiencies were identified.

The licensee took or planned corrective action for the identified deficiencies, Section 2.2.2 pertains.

The inspector observed fuel handling activities following the AIT inspection.

The inspector concluded the refueling operations were conducted in a safe manner in accordance with the new procedure.

The inspector found management and supervisory oversight was strong.

Support personnel were readily available on the refueling floor during fuel movement.

Section 2.2.3 pertains.

Maintenance/Surveillance (61726, 62703)

During the period, the licensee replaced the Jet Pump Hold Down Beams on Unit 1.

The licensee performed this replacement due to the failure of the beams at Grand Gulf Nuclear Station.

Since the Susquehanna beams were of identical design, PPEcL replaced the beams.

The inspector found the licensee's.actions were prompt and focused on safety.

The inspector observed portions of the Jet Pump Hold Down Beam replacement.

The evolution was performed in a controlled manner.

Management and supervisory oversight was apparent.

Section 3.4.1 pertains.

Safety Assessment/Assurance of Quality (40500, 90712, 92700, 92701)

The inspector reviewed seven Licensee Event Reports (LERs) during the period.

Three non-cited violations were identified.

Section 6.1 pertain TABLEOF CONTENTS EXECUTIVE SUMMARY.................. ~... ~......,...,,...

ii SUMMARYOF OPERATIONS...

1.1 Inspection Activities......

1.2 Susquehanna Unit 1 Summary 1.3 Susquehanna Unit 2 Summary

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

1

1 2.

OPERATIONS 2.1 Inspection Activities..................

2.2 Inspection Findings and Review of Events 2.2.1 Excessive Drywell Leakage - Unit 2 2.2.2 Unit 1 Automatic Depressurization System Walkdown 2.2.3 Fuel Handling Activities........,...

~

~

~

~

~

~

~

~

~

~

(ADS) ESF

~

~

~

~

~

~

~

~

~

~

~

~

l

2

~.

3

3.

MAINTENANCE/SURVEILLANCE 3.1 Maintenance Inspection Activity 3.2 Maintenance Observations

'3.3 Surveillance Observations 3.4 Inspection Findings 3.4.1 Jet Pump Hold Down Beam Replacement

~

~

~

~

~

~,

~

~

~

~

~

~

~

~

4

5

6

ENGINEERING/TECHNICALSUPPORT 4.1 Inspection Activity.........,.........

~

8

5.

PLANT SUPPORT............

5.1 Radiological Controls......

5.2 Emergency Preparedness....

5.3 Secur1ty

.

r

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

8

8 6.

SAFETY ASSESSMENT/QUALITY VERIFICATION 6.1 Licensee Event Reports.... ~......,...

~

~

~

~

~

~

9 7.

MANAGEMENTAND EXIT MEETINGS.......

7.1 Resident Exit and Periodic Meetings.......

~

~

~

~

~

~

~

~

~

~

~

\\

~

~

~

~

111

Details, 1.

SUlVMARYOF OPERATIONS 1.1 Inspection Activities The purpose of this inspection was to assess licensee activities at Susquehanna Steam Electric Station (SSES) as they related to reactor safety and worker radiation protection.

Within each inspection area, the inspectors documented the specific purpose of the area under review, the scope of inspection activities and findings, along with appropriate conclusions.

This assessment is based on actual observation of licensee activities, interviews with license'e personnel, independent calculation, and selective review of applicable documents.

'.2 Susquehanna Unit 1 Summary At the start of the inspection, Unit 1 was in the midst of an extended refueling outage.

Following the Augmented Inspection Team (AIT) activities relative to fuel handling deficiencies, fuel handling activities resumed on November 22.

The licensee offloaded the 54 fuel bundles that were loaded prior to the AlT to facilitate emergent jet pump hold down beam replacement.

Section 2.2.1 pertains.

After successful completion of the jet pump hold down beam replacement, the core was successfully reloaded.

Vessel reassembly was in progress at the conclusion of the inspection period.

1.3 Susquehanna Unit 2 Summary Unit 2 began the inspection period at 100% power.

On December 10, the plant was manually shutdown due to unidentified drywell leakage exceeding Technical Specification Limits. The licensee determined the leak was from the 'A'eactor recirculation pump reactor building closed cooling water (RBCCW) outlet line. While the unit was shutdown for repairs, the licensee performed the reactor water level backfill modification to comply with NRC Bulletin 93-03.

Also, test equipment was installed to allow torsional testing of the Unit 2 main turbine assembly.

The unit was started up on December 26.

Main Turbine Torsional Vibration Testing was performed on December 29 and December 30.

Testing results indicated no modifications to detune the rotor were necessary.

At the conclusion of the inspection period, power was being increased to 100%.

2.

OPERATIONS 2.1 Inspection Activities The inspectors verified that the facility was operated safely and in conformance with regulatory requirements.

Pennsylvania Power and Light (PP&L) Company management control was evaluated by direct observation of activities, tours of the facility, interviews and discussions with personnel, independent verification of safety system status and Limiting Conditions for Operation, and review of facility records.

These inspection activities were conducted in accordance with NRC inspection procedure 7170 The inspectors performed 13.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> of deep backshift inspections during the period.

These deep backshift inspections covered licensee activities during between 10:00 p.m. and 6:00 a.m. on weekdays, and weekends and holidays.

2.2 Inspection Findings and Review of Events 2.2.1 Excessive Drywell Leakage - Unit 2 On December 10, at 5:30 p.m., the licensee identified a step increase in drywell (DW) floor drain sump pump rate.

An investigation was initiated to determine the cause of the increased input to the sump.

A potential leak was identified in the reactor building closed cooling water (RBCCW) supply to the 2A Reactor Recirculation (recirc) pump upper seal cooler.

The return line from the pump indicated a below average temperature which was indicative of a leak. At 7:00 p.m., Technical Specification (TS) 3.4.3.2.e.

was entered when unidentified DW leakage was determined to have increased by more than two gpm in a four-hour period.

At 7:20, unidentified DW leakage exceeded the 5 gpm TS 3.4.3.2.b. limit which required the initiation of a shutdown iffurther efforts were incapable of reducing leakage.

The licensee confirmed the leak as RBCCW since the RBCCW head tank required constant makeup at the time of the shutdown.

The licensee had been monitoring a small amount of additional DW leakage since July 1993 and believed it was due to RBCCW because of the increased head tank makeup.

A shutdown was initiated, and subsequently completed at 2:17 a.m., December 11.

The licensee reported the event in accordance with 10 CFR 50.72.

After the shutdown was completed, the DW was opened, and a leak was confirmed on the 2A recirc pump.

A 270 degree crack was identified on a vendor weld internal to the pump housing for the 1 inch RBCCW stainless steel (SS) schedule 40 return pipe.

Investigation identified that this was the area of the highest pipe stress because of lack of pipe supports over a 16 foot piping span.

The calculated stress with existing hanger configuration was approximately 60% of the code allowable.

The inspector questioned the licensee on the susceptibility of the other three recirculation pumps to this problem.

The licensee stated that additional supports were included in their original design which lowered actual stresses to a small fraction of the code allowables (ANSI B-31.1).

The licensee was unable to explain why the 2A recirc pump did not have these additional supports.

Even though the piping was not designed to ASME specifications, the licensee used ASME section XI code case N-504, "Alternative Rules for Repair of Class 1, 2, and 3 Austenitic Stainless Steel Piping", to design a weld overlay repair for the failed pipe.

The licensee verified the acceptability of this repair in their safety evaluation for design change package (DCP) 93-9067.

In this DCP, the licensee described the code case weld repair method to be implemented with certain limited exceptions for actual configuration and clearances available to perform welding.

This DCP also critically examined the potential effects of the proposed weld repair on functions of RBCCW and the reactor recirculation systems and concluded that there would be no adverse effect on safety.

Thus, the weld repair was approved for us In DCP 93-9067, the licensee also noted the most likely causes of the cracked welds was either an original flaw in the vendor supplied weld and/or fatigue loading due to.recirculation pump vibration., The licensee took action to independently address both of these concerns.

The weld overlay repair was designed as a partial penetration weld to penetrate and fuse the crack and to provide additional reinforcement for heatup/cooldown and pressure stresses.

To lessen the potential for vibration induced fatigue, the licensee installed a two direction restraint to minimize unrestricted piping motion.

I Inspector Conclusion The inspector questioned the licensee on the weld repair method, safety evaluation and the training of the welders.

The inspector noted the use of an ASME Section XI code case as a good basis for the weld repair.

The inspector also noted the licensee performed the additional mock-up training as evidenced by inspection of a cross section of an actual specimen from the mock-up. The weld buildup was unusual since it was performed along the longitudinal direction of the pipe.

However, the use of a split backing ring provided a uniform surface to begin the repair.

The inspector noted that the licensee specimen's initiated saw cut cracks-were well fused and that a weld buildup of at least 0.133 inches (minimum) was present at all locations.

The specimen was penetrant tested and no cracks were identified.

The inspector concluded that the mock-up provided a necessary and appropriate training aid for the actual repair.

The licensee repaired the affected pipe on December 17.

The post-repair inspections were satisfactory.

Based on the above, the inspector had no further questions.

2.2.2 Unit 1 Automatic Depressurization System (ADS) ESF Walkdown During the period, the inspector performed an Engineered Safety Feature (ESF) Walkdown of the Unit 1 Automatic Depressurization System (ADS) to independently verify the status of the system.

The inspector verified the mechanical and electrical system checklist (CL)

outside containment.

Additionally, key components were verified on the mechanical CL inside containment.

The inspector compared as-built configuration to the as-built drawings.

The inspector identified some minor deficiencies, during the walkdown which were reported to the licensee.

They included an indication (gauge) on the ADS accumulator for the

'G'afety relief valve and some loose and missing valve handwheel retaining nuts.

Nuclear System Engineering initiated a nonconformance report (NCR) to document the indication on the ADS accumulator.

The inspector also discovered some industrial debris caused by the outage on various portions of the system inside containment.

The system CL contained some editorial errors pertaining to component description and location.

The licensee planned or took corrective action for the inspector identified deficiencie The inspector determined'hat the system was properly aligned.

The licensee maintained the system in goo'd physical condition.

Valve and component labeling was excellent.

The inspector found system supports and hangers were made up properly and aligned correctly.

The system operating procedure was adequate.

Although there were some deficiencies, they were not significant.

Due to delays in the outage, the unit remained in Condition 5, and thus, was not restored to an operable status.

The inspector had no further questions.

2.2.3 Fuel Handling Activities The inspector observed fuel handling activities following the Augmented Inspection Team (AIT) inspection.

The licensee performed the activities using the new temporary procedure OP-TY-81, Unit 1 Core Reload.

The inspector observed refueling platform operators and the refueling floor senior reactor

. operators (SRO) perform the fuel movements in accordance with the new procedure.

Movements were performed in a slow, controlled, deliberate manner.

The operators turned over in accordance with the procedure using the checklist.

Good support was provided by system engineering, reactor engineering, and mechanical and electrical maintenance personnel.

The inspector witnessed Nuclear Quality Assurance (NQA), Nuclear Safety Assessment Group (NSAG), operations management and the refueling floor manager present at various times during core reload.

The inspector concluded the fuel movements were performed in a safe and controlled manner.

The operators were well versed in the new procedure and new method of controlling fuel movements.

Operator turnover was thorough and complete.

Excellent communications were maintained on the refueling platform and with the control room.

Operators understood the chain of command with regard to refueling operations.

Management and supervisory oversight was strong.

The inspector noted support organizations were present throughout the refueling operations.

The inspector had no further questions.

3.

MAINTENANCE/SURVEILLANCE

.3.1 Maintenance Inspection Activity On a sampling basis, the inspector observed and reviewed selected maintenance activities to ensure that specific programmatic elements described below were being met.

Details of this review are documented in the following sections.

3.2 Maintenance Observations The inspector observed and/or reviewed selected maintenance activities to determine that the work was conducted in accordance with approved procedures, regulatory guides, Technical Specifications, and industry codes or standards.

The following items were considered, as

applicable, during this review: Limiting Conditions for Operation were met while components or systems were removed from service; required administrative approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and quality control hold points were established where required; functional testing was performed prior to declaring the involved component(s) operable; activities were accomplished by qualified personnel; radiological controls were implemented; fire protection controls were implemented; and the equipment was verified to be properly returned to service.

These observations and/or reviews included:

WA 34850, Refueling Platform Mechanical Inspection, dated November 22.

WA 34103, Provide Mechanical Support for Jet Pump Hold Beam Replacement, dated December 7, WA 36043, Backfill Reference Leg for ISLI for Mod Installation, dated December 18.

WA 30547, Provide Electrical Test Support. for Unit 2 Turbine Torsional Test TP-293-021, dated December 29.

WA 35239, HCV 42-15 Scram Inlet Valve Body to Bonnet Leak Repair, dated

,December 30.

3.3 Surveillance Observations The inspector observed and/or reviewed the following surveillance tests to determine that the following criteria, ifapplicable to the specific test, were met:

the test conformed to Technical Specification requirements; administrative approvals and tagouts were obtained before initiating the surveillance; testing was accomplished by qualified personnel in accordance with an approved procedure; test instrumentation was calibrated; Limiting Conditions for Operations were met; test data was accurate and complete; removal and.

restoration of the affected components was properly accomplished; test results met Technical Specification and procedural requirements; deficiencies noted were reviewed and appropriately resolved; and the surveillance was completed at the required frequency.

These observations and/or reviews included:

SO-259-002, Monthly Operability Check of Suppression Chamber Vac Breakers, dated December 20.

SO-030-001A, Monthly CREOASS Operability Test, dated December 22.

I

SO-070-001, Monthly Operability Check Standby Gas Treatment Train B, dated December 29.

SO-178-210, Refuel Outage Weekly Functional Test of Average Power Range Monitor, dated December 30.

II 3.4 Inspection Findings The inspector reviewed the listed maintenance activities.

The review noted that work was properly released before its commencement; that systems and components were properly tested before being returned to service and that maintenance activities were conducted properly by qualified personnel.

Where questionable issues arose, the inspector verified that the licensee took the appropriate action before system/component operability was declared.

3.4.1 Jet Pump Hold Down Beam Replacement Background

.

On November 19, the licensee was informed by a General Electric (GE) advisory that current ultrasonic examination methods may be ineffective at detecting cracking at the jet pump hold down beam ends.

A previous Services Information Letter (SIL) identified periodic inspection requirements for jet pump hold down beams (SIL 330).

This inadequacy was derived by GE after metallographic examinations were completed on the September 13, 1993 ¹10 jet pump failure at the Grand Gulf Nuclear Station.

In this case, the reactor scrammed from 100%,

power on high reactor water level and high pressure core spray (HPCS) initiated due to pressure perturbations stemming from the ¹10 jet pump failure. After vessel disassembly, the ¹10 jet pump inlet-mixer assembly was found wedged between the ¹8 and ¹9 jet pumps and the vessel wall. In vessel inspections also showed that the ¹10 jet pump inlet-mixer assembly struck the low pressure coolant injection (LPCI) piping, the reactor vessel wall, several steam separator stand pipes, and a steam separator hold down bolt.

When the jet pump hold down beam was eventually located it was missing a 2-inch end piece that normally fits into the beam pocket on the riser transition piece, and the other end had a crack across the top face.

Grand Gulf forwarded the damaged hold down beam to GE for further evaluation.

The results of this evaluation were summarized in their November 19 advisory.

In a November 20, 1993 correspondence to PP&L, GE noted that the hold down beams used by Grand Gulf and Susquehanna were of the same design, material, heat treatment, and were installed with the same preload torque specifications.

The beams were fabricated of Inconel X-750.

The. failure mechanism determined through metallographic examination foi the Grand Gulf failure was inter-granular stress corrosion cracking (IGSCC).

Approximately 80% of the crack cross section indicated IGSCC with the remaining 20% indicating ductile failure from gross overload conditions (fatigue failure). To address this concern, GE is preparing a Rapid Information Communication Services Information Letter (RICSIL).

PPEcL confirmed there is no pre-failure operability test which would detect beam end cracking prior to failure. In addition, PPScL noted that Grand Gulf ran their daily jet pump surveillance two hours prior to the 9/13 event without receiving any anomalous indications.

The visual (VT) inspections that were performed prior to the Grand Gulf failure did not identify any beam cracking.

The ability of ultrasonic testing (UT) to detect cracking was also questioned for the beam ends since current methods do not address this location.

GE also identified that the beams used in all BWR-4,5,6's are manufactured at a single facility in Wilmington, NC.

The planned RICSIL should provide conservative short term recommendations aimed at avoiding mid-cycle failures with a high degree of confidence (wanting to entirely avoid forced outages and reactor internals damage experienced at Grand Gulf). RICSIL recommendations willaddress beam replacement as soon as practical for BWR 4,5, & 6 reactors with original design (heat treatment) beams.

It will be applicable for those reactors with accumulated service approaching that of Grand Gulf at the time of failure (minus one fuel cycle), or about eight years.

Inspector Conclusion The inspector reviewed the licensee's actions in responding to the November 19 GE advisory and found them to be prompt,'comprehensive, and focused on safety.

The'licensee independently contacted GE on November 20 and discussed their potential susceptibility to the failures.

Based on these discussions and additional internal reviews, the engineering organization recommended jet pump hold down beam replacement prior to startup of Unit 1.

Station management agreed with the evaluation and began efforts to replace the affected hold down beams.

The inspector questioned the licensee on the susceptibility of Unit 2 of these failures.

The licensee stated that Unit 2 has one less operating cycle than Unit 1 and that reactor water chemistry has been better on Unit 2.

Thus, a short delay until the March 1994 refueling was justified.

The inspector observed Jet Pump Hold Beam replacement activities.

The inspector observed inlet mixer section in-vessel installation, and hold down beam installation.

The inspector determined the activity was performed satisfactorily.

Personnel were focused on the evolution, communications were excellent, and the work was being performed in accordance with the procedure.

Active management and supervisory oversight was witnessed by the inspector.

The licensee documented the problems encountered during the evolution.

The licensee willincorporate lessons learned for the Unit 2 Jet Pump Hold Down Beam replacement planned for the March 1994 refueling outage.

The inspector had no further question.

ENGINEERING/TECHMCALSUPPORT 4.1 Inspection Activity The inspector periodically reviewed engineering and technical support activities during this inspection period.

The on-site Nuclear Systems Engineering (NSE) organization, along with Nuclear Technology in Allentown, provided engineering resolution for problems during the inspection period.

NSE generally addressed the short term resolution of engineering problems; and interfaced with the Nuclear Modifications organization to schedule modifications and design changes, as appropriate, to provide long term corrective action.

The inspector verified that problem resolutions were thorough and directed at preventing recurrence.

In addition, the inspector reviewed short term actions to ensure that they, provided reasonable assurance that safe operation could be maintained.

Licensee actions were acceptable.

5.

PLANT SUPPORT 5.1 Radiological Controls PP&L's compliance with the radiological protection program was verified on a periodic basis.

These inspection activities were conducted in accordance with NRC inspection procedure 71707.

Observations of radiological controls during maintenance activities and plant tours indicated that workers generally obeyed postings and Radiation Work Permit requirements.

No significant observations were made.

5.2 Emergency Preparedness The inspector reviewed licensee event notifications and reporting requirements for events that could have required entry into the emergency plan.

No events were identified that required emergency plan entry.

5.3 Security PP&L s implementation of the physical security program was verified on a periodic basis, including the adequacy of staffing, entry control, alarm stations, and physical boundaries.

These inspection activities were conducted in accordance with NRC inspection procedure 71707.

The inspector reviewed access and egress controls throughout the period.

No significant observations were mad.

SAFETY ASSESSMENT/QUALITY VERIFICATION 6.1 Licensee Event Reports The inspector reviewed LERs submitted to the NRC office to verify that details of the event were clearly reported, including the accuracy of the description of the cause and the adequacy of corrective action.

The inspector determined whether further information was required from the licensee, whether generic implications were involved, and whether the event warranted onsite follow up.

The following LERs were reviewed:

Unit 1 92-015-00 Fire Barriers Not SurveBled and Not Installed Per Specification On September 3, 1992, with both units in Condition 1, the NRC identified that Kaowool fire rated barriers were not inspected during performance of the inspection surveillance.

The licensee determined the cause of the failure to inspect the Kaowool barrier was procedural inadequacy and personnel error.

The licensee determined the condition to be reportable as an operation prohibited by Technical Specifications.

The required surveillances were not performed and required LCO action statement not entered.

The licensee planned a corn'prehensive corrective action plan to upgrade procedures, drawing and training; The inspector agreed with the licensee's reportability analysis.

NRC Inspection Report 92-23 documented this event.

The NRC issued a violation regarding the matter.

The NRC will assess the adequacy of corrective actions during violation closeout.

92-016-00 Voluntary Report - Spent Fuel Storage Pools On April 16, 1992, engineers were performing evaluations as part of the future uprated licensed power project (Power Uprate Project).

The engineers questioned the adequacy of existing analysis for the stations two Spent Fuel Storage Pools.

Additional concerns were documented with respect to the ability to re-establish Fuel Pool Cooling and Fuel Pool Makeup following postulated accident conditions.

The licensee determined the consequences of the loss of Fuel Pool Cooling were determined to be satisfactory for the design basis and, therefore, not reportable.

The NRC office of Nuclear Reactor Regulation (NRR) is currently involved with a comprehensive technical review of this issue.

I

93-005-00 Fire Barrier Not Installed on Conduit as Required On June 22, 1993, with unit at 100%, the licensee determined that a,conduit containing a cable required for safe shutdown did not have fire barrier wrapping as required by 10 CFR 50, Appendix R 'analysis.

The condition was discovered during a licensee fire protection program audit.

The conduit was routed through several fire zones and was wrapped in all but one of the zones.

The licensee determined the cause of the event was a drawing error by the architect/engineer in 1980.

The licensee reported the event as a condition prohibited by Technical Specifications.

At the time of discovery, compensatory fire watches were in place and fire detection operability confirmed.

The licensee performed a modification to wrap the subject conduit.

The licensee considered the drawing error to be isolated.

The inspector agreed with the licensee's reportability determination.

Corrective actions taken were adequate.

The failure to have the conduit containing the safe shutdown cable properly wrapped was a violation of Technical Specification 3.7.7.

This violation willnot be subject to enforcement action because the licensee's effort in identifying and correcting the violation met the criteria specified in Section VII.Bof 10 CFR Part 2, Appendix C.

93-006-00 Failure to Correct Instrument DriftCondition Within Technical Specification Required Action Time On May 26, 1993, an evaluation of a level instrument's location, function and tolerance, and a review of surveillance test documentation from December 19, 1991 through July 20, 1992 concluded that a noncompliance with the plant's Technical Specifications occurred.

A calibration check, which had been performed on July 20, 1992, using a corrective maintenance work authorization, determined that the level indicating instrument for the

'C'mergency Diesel Generator (EDG) fuel oil storage tank had drifted in a nonconservative direction.

The 'C'DG fuel oil storage tank low level alarm had annunciated on December 19, 1991 during performance of a monthly surveillance run on the 'C'DG.

Per the alarm response procedure, the operator observed the storage tank level indication to be 96.9%

level.

The low level alarm setpoint is 94.3% level. A work authorization identifying the annunciator as alarming, with an indicated level of 96.9% level, was initiated by operations personnel on December 23, 1991.

However, operations shift personnel did not assign any priority code to the work authorization.

A low (routine) priority code (i.e., during the next scheduled 'C'DG work window) was assigned by the work group (instrumentation and Controls).

Unknown at the time, the 'C'DG fuel oil storage tank level transmitter had drifted in a non-conservative direction. A calibration check performed on July 20, 1992 determined that the level indicating transmitter for the 'C'DG fuel oil storage tank had a zero shift of 3.7% high.

The resulting condition, indicated level higher than actual level, was a non-conservative condition.

The evaluation concluded that the 'C'DG fuel oil storage tank actual fuel oil volume may have been less than the required Technical Specification minimum volume (approximately 200 gallons low) several times during the

'eriod from December 19, 1991 to July 20, 199 'he licensee determined this condition was caused by instrument drift and lack of proceduralized (operating and surveillance procedures)

guidance for the EDG fuel oil storage tank instrumentation.

This event was determined reportable as a condition prohibited by the plant's Technical Specifications per 10 CFR 50.73(a)(2)(i)(B), in that the drifting of an instrument out of its acceptable range and failure to implement the ACTIONS of the Technical Specifications within the time required (1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />), resulted in an EDG fuel oil storage tank fuel oil volume being less than that required by the Technical Specifications (47,570 gallons; 93.6% level).

Licensee corrective actions included calibrating the level transmitter, training for operations shift personnel, operating and alarm response procedure revisions.

The inspector agreed with the reportability determination.

The licensee determined there was sufficient fuel to provide for the required seven day operation of the diesel with the full complement of Engineered Safety Feature loads applied.. Based on this, the inspector concluded that no safety consequence existed.

Since the 'C'DG fuel oil tanks actual fuel oil volume may have been less than required is a violation of Technical Specification.

This violation willnot be subject to enforcement action because the licensee's effort in identifying and correcting the violation met the criteria specified in Section VII.Bof 10 CFR Part 2, Appendix C.

93-008-00 Reactor Scram Following Turbine Trip on High Vibration At 4:35 p.m.'on July 12, 1993 with the unit at 100% power, a reactor scram resulted per design when the main turbine tripped. All major equipment operated per design during the transient.

The licensee determined an unplanned ESF actuation occurred when the reactor protection system (RPS) initiated an automatic reactor scram following turbine control valve fast closure with power greater than 24%.

NRC Inspection Report 93-11 documented this event.

93-009-00 Unplanned ESF Actuation - Primary Containment Isolation Valve Closure At 12:15 a.m. on August 25, 1993, with Unit 1 in Condition 4 at 0% power, a drywell vent primary containment isolation valve failed closed.

The licensee determined the cause of the event to be a failed circle seal solenoid operated valve (SOV). The licensee reported the event as an unplanned ESF actuation.

NRC Inspection Report 93-13 documented this event.

The licensee committed to submit an updated LER pro'viding details of their SOV failure history.

The licensee was also evaluating the need to report the condition per 10 CFR 21.

93-010-00 Loss of Fire Protection/Suppression On August 16, 1993, a severe lightning storm caused numerous spurious alarms in the Simplex Fire Protection System and disabled a transponder which rendered the fire suppression system in two areas inoperable.

%ith the thermo-lag fire barriers already

inoperable, continuous fire watches were required within one hour once the detection system became inoperable.

Sufficient manpower was not available for all affected areas within the required one hour.

The licensee determined the condition reportable as a condition prohibited by Technical Specifications.

Specifically, the required action of establishing a

.continuous firewatch was not accomplished within one hour as required.

Roving hourly firewatches were in place.

The failed transponder card was replaced and system operability was restored.

The inspector agreed with the licensee's reportability determination.

The failure to implement continuous firewatches within one hour was a violation of Technical Specification 3.7.7.

This violation willnot be subject to enforcement action because the licensee's effort in identifying and correcting the violation met the criteria specified in Section V.IIBof 10 CFR Part 2, Appendix C.

The inspector found the above LERs acceptable.

7.

MANAGEMENTAND EXIT MEETINGS 7.1 Resident Exit and Periodic Meetings The inspector discussed the findings of this inspection with station management throughout and at the conclusion of the inspection period.

Based on NRC Region I review of this report and discussions held with licensee representatives, it was determined that this report does not contain information subject to 10 CFR 2.790 restrictions.