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EXECUTIVE SUMMARY

Arkansas Nuclear One, Units 1 and 2

NRC Inspection Report 50-313/97-02,50-368/97-02

This routine announced inspection included aspects of licensee operations, engineering,

maintenance, and plant support. The report covers a 6-week period of resident inspection;

in addition, it includes the results of an announced inspection by a regional project

inspector.

Operations

Operators demonstrated good attention to detail and diagnostic skills in identifying

and analyzing a small change in stearn generator levels caused by a malfunction in

the Main Feed Pump B controller circuitry (Section 01.2).

The Unit 2 high pressure safety injection system was properly aligned and in good

material condition. The system engineer demonstrated proper oversight and

ownership of the system (Section 01.3).

The loading of the third dry spent fuel storage cask was performed very well and

with appropriate management's oversight. Radiological controls were very good

during the activity (Section 014).

Maintenance

Maintenance activities were performed well and in accordance with

procedures. Personnel were knowledgeable and generally demonstrated

effective communications, self checking, and peer checking. When

conducted, prejob briefs were comprehensive. The licensee effectively

addressed difficulties encountered during maintenance associated with

Service Water Pump P4A. Unit 2 instrumentation and control technicians

displayed a good questioning attitude when procedural and technical

problems were encountered during the performance of a core protection

calculator surveillance. Appropriate management attention was provided te

address problems and the corrective action process was properly utilized to

address generic concerns. Inspectors found an isolated occurrence in which

documentation of a maintenance activity was inadvertently discarded

(Section M1).

The licensee's failure to perform periodic testing of backup air accumulators

associated with outside air dampers in the control room emergency ventilation

system and the failure to identify a condition adverse to qua!ity was determined to

be a violation. The inspectors found that corrective actions for similar discrepancies

identified by the NRC in 1990, which resulted in a Severity Level 111 violation, were

not fully implemented (Section M8.1).

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The failure to have administrative controls to ensure that fuel from the Units 1 or 2

cores was not off loaded to the spent fuel pool with service water temperatures in

excess of 85 F was determined to be a noncited violation (Section E8.1).

Plant Support

Locked high radiation areas were properly locked, areas were properly posted, and

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personnel demonstrated proper radiological work practices (Sections 01.4

and R1.1).

Chemistry technicians had a strong familiarity with assigned tasks, demonstrated

good knowledge in their areas of assigned duties, and were performing tasks for

which they were qualified (Section R5.1).

The licensee implemented proper physical security measures associated with the

integrity of protected area barriers, personnel and package access, and personnel

searches (Section S1.1).

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Report Details

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Summary of Plant Status

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Unit 1 began the inspection period at 86 percent power. Power was further reduced to

76 percent on March 16 at the request of the load dispatcher. Following the completion of

repairs to offsite transmission lines damaged as a result of tornados, Unit 1 raised power

and achieved 100 percent power on March 18,1997. Power was reduced to 85 percent

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on April 18 for turbine testing and returned to 100 percent on April 19, where it remained

through the end of the inspection period.

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Unit 2 began the inspection perioo a 97 percent power. On March 18, operators reduced

power to 73 percent to repair a malfunction of the Main Feed Pump B controller. On

March 20, during restoration of Main Feed Pump 8 and escalation to 100 percent power,

an unrelated malfunction in the Main Feed Pump A circuitry resulted in operators

maintaining the power at approximately 84 percent until the deficiency was corrected. On

March 21, power was restored to 97 percent and remained there through the end of the

reporting period.

1. Operations

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Conduct of Operations

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01.1

General Comments (71707)

The inspectors observed various aspects of plant operations, including compliance

with Technical Specifications; conformance with plant procedures and the safety

analysis report; shift manning; communications; management oversight; proper

system configuration and configuration control; housekeeping; and operator

performance during routine plant operations, the conduct of surveillances, and plant

power changes.

The conduct of operations was professional and safety co'iscious. Emlutions such

as surveillances and plant power changes were well controlled, deliberate, and

performed in accordance with procedures. Shift turnover briefs were

comprehensive and were typically ettended by a chemistry technician, a health

physics technician, and a representative from system engineering. Housekeeping

was generally good and discrepancies were promptly corrected. Safety systems

were found to be properly aligned. Specific events and noteworthy observations

are detailed below.

01.2 Unit 2 - Main Feed Pomo Speed Oscillation

a.

Inspection Scope (71707)

On March 1'7,1997, a malfunction in the Main Feed Pump B controller circuitry was

identified. Operators reduced reactor power to 73 percent to secure Main Feed

Pump B for repairs. The inspectors reviewed the event, logs, trends, and corrective

actions performed by the operations department.

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b.

Observations and Findinas

On May 17 at 12:10 p.m., a control room operator noticed a small perturbation in

Steam Generators A and B level on the computer display. Subsequent investigation

by operations indicated that the Main Feed Pump B speed had decreased by

approximately 240 rpm. Main Feed Pump A automatically compensated to correct

the error in steam generator level. Reactor power was subsequently reduced to

73 percent by the operators and Main Feed Pump B was removed from service to

repair the controller circuitry. The power reduction and transfer to Main Feed

Pump A was accomplished without incident.

The inspectors reviewed the observed indications and associated graphs. The

duration of the transient was less than 3 minutes and steam generator levels

changed by less than 2 percent. Due to the relatively small magnitude and duration

of the event, the event could have gone unnoticed until the next regularly scheduled

logs on the affected equipment.

c.

Conclusions

Operators demonstrated good attention to detail and diagnostic skills in identifying

and analyzing a sma!! change in steam generator levels caused by a malfunction in

the Main Feed Pump B controller circuitry.

01.3 Unit 2 - Hiah Pressure Safety Iniection System Walkdown

a.

Insoection Scone (71707)

The inspectors performed a detailed walkdown of the Unit 2 high pressure safety

injection system. Valve and electricallineups, Safety Analysis Report requirements,

Technical Specifications, system drawings, and associated procedures were

revTew ed.

b.

Observations and Findinas

Valve and electricallineups were consistent with prints and procedures. Breaker

enclosures were clean and free of debris. The inspectors identified a minor

discrepancy on Drawing M-2232, Revision 103, Sheet 1. A test connection on the

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drawing identified as Pressure Indicator 2PI-5094 should have been identified as

Pressure Indicator 2PP-5094.

c.

Conclusions

The inspectors concluded that the Unit 2 high pressure safety injaction system was

properly aligned and in good material condition. The system engineer demonstrated

proper oversight and ownership of the system.

c.

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01.4 - . Unit 2 - Loadina of Drv Fuel Soent Fuel Storaae Cas_k

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a.

Insoection Scope (71707, 71750, 60855)

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Between March 23 and April 2,.1997, the licensee loaded their third dry spent fuel

storage cask and placed it on the storage pad. rhis was the.first cask to be loaded

-with spent fuel from the Unit 2 spent fuel pool. The inspectors observed various

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portions of the cask loading evolution.

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Observations and Findinas

The inspectors found that the loading of the dry spent fuel storage cask was

performed in accordance with procedures and that the licensee complied with the

requirements of the Certificate of Compliance. Radiological controls implemented

during this activity were good. The inspectors observed that the licensee

successfully reduced the amount of time it took to vacuum dry the cask, compared

to the previous two casks, through the use of more effective drying equipment. On

March 26, during the performance of a dye penetrant test following completion of

-the shield lid root pass weld, the licensee discovered a small crack on the

multi-assembly sealed basket wall just above the weld. This issue was the subject

of an NRC specialinspection, the resuits of which are documented in NRC

Inspection Report 50-313/97-12;50-368/97-12,

c.

Conclusions

The loading of the third dry spent fuel storage cask was performed very well and

with appropriate management's oversight. Radiological controls were very good

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during the activity.

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Miscellaneous Observations

The inspectors observed other minor incidental problems with components in the

area of the work activities, which the licensee took correct.ive action on.

Specifically, the licensee took actions to correct a missing jam nut on a steam

generator blowdown line and placed covers around some intake structure electrical

heaters.

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08.1- (Closed) Licensee Event Reoort (LEJ) 50-313/06-004, " Excessive Load Moved Over

Eur! Store'in Soent Fuel Pool"

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This event was discussed in NRC Inspection Report 50-313/96-03;50 368/96-03

and was the subject of a noncited violation. No new issues were revealed by the

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11. Maintenance

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Conduct of Maintenance

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M 1.1 General Comments

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Lq. oection Scooe (62707)

a.

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The inspectors observed all or portions of the following maintenance activities:

Unit 1 - Job Order (JO) 00961368, "P-153 has Degraded Discharge Pressure

& Flow, investigate, Repair or Replace," performed on March 25,1997.

Unit 1 - JO 00960313, " Corrective Maintenance to Replace Worn Shaft

Sleeve," associated with Service Water Pump P4A, performed on March 31

through April 5.

Unit 1 - JO 00960389, " Preventive Maintenance on P4A Motor, " performed

on March 31 through April 5.

Unit 1 - JO 00923335, "I&C Support for Maintenance on P4A," performed -

on March 31 through April 5.

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Unit 2 - JO 00957988, " Corrective Maintenance to Adjust Local Position

Indicator on 2CV-1076 2," performed on April 15.

Unit 2 - JO 00957627, " Preventive Maintenance on 2CV-1076-2,"

performed on April 15.

Unit 2 - JO 00958413, " Preventive Maintenance on 2CV-1039-1,"

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performed on April 15.

b.

Observations and Findinos

The inspectors found the work performed in these activities to be professional and

thorough. All work was performed in accordance with procedures and the workers

were knowledgeable on their ass:gned tasks. When applicable, appropriate

radiological work permits were followod.

In addition, see the specific discussions of maintenance observed under

Sections M1.2 through M1.4, belovs.

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M 1.2 Unit 1 - Maintenance on Hydroaen-Oxvnen Analyzer

a.

trnpection Scope (62707)

On March 25,1997, the inspectors observed the licensee perform troubleshooting

activities associated with Hydrogen-Oxygen Analyzer C119A Sample Pump P-153.

The licensee believed that the pump had dagraded discharge pressure and flow and

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was determining whether or not the pump needed to be replaced.

b.

Observations and Findinas

On March 25, the inspectors observed the licensee troubleshoot and investigate the

need to replace the Train A hydrogen-oxygen analyzer sample pump. Technicians

found that the sample pump provided the proper discharge flow and pressure as

required by Procedure 1304.184, Revision 4, " Unit 1 Hydrogen / Oxygen Analyzer

Calibration, C119A." The technicians did not replace the pump and canceled the

JO.

The technicians had previously noticed that the suction pipe to this pump was

vibrating and they installed a pipe support which significantly reduced the vibration.

The technicians then performed the surveillance test on the system to verify

operability.

On April 7, the inspectors asked the licensee for the completed JO package. The

licensee discovered that when they discarded the original JO they also inadvertently

discarded the documentation for the work which had installed the pipe support.

The licensee then rewrote the description of the work performed during the

maintenance activity.

c.

Conclusions

The inspectors concluded that the licensee performed the maintenance activity on

the hydrogen-oxygen analyzer sample pump in accordance with the work

instructions. Inspectors found that documentation of the maintenance activity was

inadvertently discarded.

M1.3 . Unit 1 - Maintenance on Service Water Pumo P4A

a.

Inspection Scope (62707)

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The inspectors observed portions of several JOs associated with maintenance on

Service Water Pump P4A, performed between March 31 and April 5. This activity

included the refurbishment of the pump motor due to increased vibrations observed

during previous surveillance tests.

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b.

Observations and Findings

The inspectors observed that the licensee experienced several difficulties during the

reassembly of the service water pump motor. Following a water flush of the motor

stator, the licensee had difficulty in drying out the motor sufficiently to achieve

desired electrical resistance values. The licensee decided to install a spare motor

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assembly. This was performed in accordance with Procedure 1402.061,

R9 vision 12, " Disassembly, inspection, and Reassemb!y of the Unit 1 Service Water

Pumps (P4A, B & C)." Following reassembly, the licensee ran the pump and found

that the motor vibrations remained high. The licensee disassembled the motor and

found that the upper collar on the bearing had an out-of-tolerance clearance on the

upper bearing sleeve. The licensee indicated that this problem was not revealed

when the rotor was balanced because the bearing war not loaded, as is the case

when the rotor is installed in the motor. The licensee had not checked this

clearance prior to installation and the vendor had not specified a tolerance for the

clearances on the upper bearing sleeve. Procedure changes were initiated to ensure

these clearances were checked during future activities.

The licensee reassembled the motor and found that vibra ^ ions were significantly

reduced.

c.

Conclusions

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The licensee effectively addressed difficulties encountered during maintenance

associated with Service Water Pump P4A.

M 1.4 General Comments on Surveillance Activities

a.

Inspection Scope (62707)

The inspectors observed all or portions of the following surveillance activities:

Unit 1 - Procedure 1304.14, " Unit 1 Hydrogen / Oxygen Analyzer

Calibration, C119A," on March 25,1997.

Unit 1 - Procedure 1109.009, Supplement 3, " Unit 1 Governor Valve Test,"

on April 18.

Unit 1 Procedure 1109.009, Supplement 2, " Unit 1 Turbine Valve Test," on

April 18.

Unit 2 - Calibration of Refueling Water Tank Level Transmitter 2LT-5636-1

performed in accordance with Procedure 2304.041, Revision 17, " Unit 2

Plant Protection System Channel A Field Calibration," Supp!ement 1,

" Calibrations Outside Containment," performed on April 25.

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Unit 2 - Calibration of Refueling Water Tank Leve! Transmitter 2LT-5637-2

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performed in accordance with Procedure 2304.042, Revision 17,

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" Unit 2 Plant Protection System Channel B Field Calibration," Supplement 1,

" Calibrations Outside Containment," performed on April 25.

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Unit 2 - Calibration of Refueling Water Tank Level Transmitter 2LT-5639-3

performed in accordance with Procedure 2304.043, Revision 18, " Unit 2

Plant Protection System Channel C Field Calibration," Supplement 1,

" Calibrations Outside Containment," performed on April 25.

Unit 2 - Calibration of Refueling Water Tank Level Transmitter 2LT-5640-4

purformed in accordance with Procedure 2304.044, Revision 18, " Unit 2

Plant Protection System Channel D Field Calibration," Supplement 1,

" Calibrations Outside Containment," performed on April 25.

b.

Observations and Findinas

The inspectors found that the surveillance activities were performed according to

the licensee's procedures by knowledgeable workers. When applicable, appropriate

radiological werk permits were followed.

M 1.5 Unit 2 - 18-Month Calibration of Core Protection Calculator

a.

Inscection Scope (61726)

On March 19, the inspectors observed instromant and control technicians perform

Procedure 2304.182, Revision 1, " Core Protection Calculator 'A' Reactor Coolant

Pump Speed input Loops Calibration." instrument and control technicians

performed a calibration of the pulse shaper modules that mouify the reactor coolant

pump speed input to the core protection calculator,

b.

Observations and Findinas

Due to the introduction of new test equipment, a function generator with a digital

output, the technicians appropriately questioned their supervisor about the readings

being recorded and methodologies utilized to obtain the reading. The function

generator duplicated indications to those found on the oscilloscope and the

technicians questioned which indication to utilize for the surveillance. The

supervisor was consulted and it was determined that the reading from the

oscilloscope was correct. A procedure change form was initiated to clarify the

procedure and a condition report was written to identify and correct procedures that

contained similar vulnerabilities with the use of multiple types of test equipment.

The technicians encountered difficulties integrating the restoration of Core

Protection Calculator A with the rerr. oval of Core Protection Calculator B. A

restoration step for the Core Protection Calculator A requires that the associated

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computer be restored to service, yet the subsequent procedure requires that the

same component be removed from service. The original intent of integrating the

procedures was to leave the computer out of service versus restoring it to service

between procedures. The technicians discussed the integration problem with their

supervisor who contacted the control room. A deviation from the procedure was

authorized in accordance with the guidance in Procedure 1000.006, Revision 45,

" Procedure Control." This allowed the computer to be left out of service and the

work to continue. A procedure farm was initiated to revise the procedure to better

integrate the testing of the core protection calculators.

c.

Conclusions

Instrument and control technicians performed the core protection calculator

surveillance per approved procedures. The technicians displayed a good

questioning attitude when procedural and technical problems were encountered.

Appropriate management attention was provided to address problems and the

corrective action process was properly utilized to address generic concerns.

M1.6 Conclusions on Conduct of Maintenance

Maintenance activities were performed well and in accordance with procedures.

Personnel were knowledgeable and generally demonstrated effective

communications, self checking, and peer checking. When conducted, prejob briefs

were comprehensive. The licensee effectively addressed difficulties encountered

during maintenance associated with Service Water Pump P4A. Unit 2

instrumentation and control technicians displayed a good questioning attitude when

procedural and technical problems were encountered during the performance of a

core protection calculator surveillance. Appropriate management attention was

provided to address problems and the corrective action process was properly

utilized to address generic concerns. Inspectors found an isolated occurrence in

which documentation of the installation of a pipe support on the hydrogen-oxygen

analyzer sample pump was inadvertently discarded.

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Miscellaneous Maintenance issues (92902)

M8.1 (Closed) Unresolved item (URI) 60-313/9701-03: 50-368/9701-03. " Failure to Test

Safetv Related Accumulators"

a.

Insnection Scoce (92902)

NRC Inspection Report 50-313/97-01; 50-368/97-01 documented the licensee's

discovery that they had not been performing a procedurally required 18-month test

of the control room emergency ventilation external air dampers to verify that backup

air bottles would maintain these dampers shut upon a loss of instrument air.

Subsequent testing revealed excessive leakage from one of the backup air supplies.

This issue remained unresolved pending further review of a similar finding in 1990

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and resolution of the basis for the test acceptance criteria for the backup air bottles.

The inspectors conducted additional inspection of this issue.

b.

Qbservations and Findinas

NRC Inspection Report 50 313/97-01;50-368/97-01 stated that, in 1990, the

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licensee wrote a condition report to document the fact that they were not

performing tests to verify that Dampers CV-7910 and 2PCD-8607B could be

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maintained closed upon a loss of instrument air. The condition report was written

in response to testing deficiencies identified during an operational safety team

inspection conducted by the NRC in September 1990 (NRC Inspection

Report 50-313/90-24;50-368/90 24). A subsequent followup inspection

conducted in October 1990 (NRC Inspection Report 50-313/90-38;50-368/90-38)

identified that the licensee failed to test certain safety-related instrument air check.

valves in the control room heating, ventilation, and air conditioning system and did

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not provide an accurate response to Generic Letter 88-14, " Instrument Air Supply

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System Problems Affecting Safety-Related Equipment." On December 17,1990,a

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Severity Level lli violation was issued to the licensee for providing inaccurate

information regarding the testing of air-operated, safety-related components and a

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failure to identify a significant condition adverse to quality.

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One of the condition report corrective actions was to provide a procedure for the

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periodic testing of the damper air consumption for Accumulators VRA-1 A

and 2VRA 1B to verify that system integrity was maintained. The periodicity was

specified to be a maximum of 18 months. Procedure 1304.175, "ANO-1 Damper

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Air Consumption Test of VRA-1 A and 2VRA-1B," was written and became effective

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'on October 15,1991. The procedure indicated that the test was to be performed

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at 18-month intervals. However, the procedure was not entered into the licensee's

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repetitive task prcgram and, therefore, was not scheduled to be performed on an

18 month interval, The licensee determined that the procedure was not entered

into the repetitive task program because actions contained in the condition report

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did not clearly define or assign a task to enter the procedure into the repetitive task

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program.

The inspectors found that the licensee failed to implement the corrective actions of

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the condition report in that Procedure 1304.175 had not been performed at

18-month intervals.

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10 CFR Part 50, Appendix B, Criterion XVI, " Corrective Action," requires, in part,

that measures shall be established to assure that conditions adverse to quality, such

as failures, malfunctions, and deficiencies are promptly identified and corrected.

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The licensee's failure to perform tests to verify that backup air accumulators would

maintain outside air dampers in the control room emergency ventilation system

closed upon a loss of instrument air, and the identification that the leakage from

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Accumulator 2VRA-1B was in excess of the acceptance criteria contained in

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Procedure 1304.175, Revision 0, " ANO-1 Damper Air Consumption Test of VRA-1 A

and 2VRA-1B," was determined to be a violation of 10 CFR Part 50, Appendix B,

Criterion XI and XVI" (50-313/9702-01; 50-368/9702-01).

NRC Inspection Report 50-313/97-01; 50-368/97-01 also described an apparent

discrepan y between the design basis of the backup air accumulators and the test

acceptance criteria contained in Procedure 1304.175. The inspectors noted that

Calculation 90 E-0072-02, " Calculation for ANO-1 Control Room Dampers CV 7910

and 2PCD-8607B Allowable Leakage Form High Pressure Accumulators," was used

as a reference in the development of Procedure 1304.175. An assumption made in

the leakage calculation was that the backup air accumulators would provide a

sufficient volume of air to maintain the dampers closed for 30 days on a

loss-of-instrument air. The calculation revealed that the allowable leakage rate to

maintain the damper closed for 30 days was 0.67 psig/hr. The calculation results

also included an acceptable pressure decay of 1.68 psig/ hour to maintain the

damper closed for 12 days. The inspectors noted that the acceptance criteria

contained in Procedure 1304.175,1.68 psig/hr, corresponded to the acceptable

pressure decay to maintain the damper closed for 12 days. However, it appeared to

the inspectors that the design basis for the backup bottles was to maintain the

dampers closed for 30 days. As a result, Procedure 1304.175 did not appear to

provide the correct acceptance criteria to ensure that the backup bottles satisfied

their design requirement,

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The licensee stated that the design basis for the backup air accumulators was to

ensure that an outside air damper can be closed even with the loss-of-instrument

air. The inspectors found that statements in the Safety Analysis Report supported

this design basis and did not include a duration for maintaining the dampers closed.

The licensee stated tl'.it 12 days was sufficient to identify and correct excessive

leakage from an accumulator. The licensee stated that Calculation 90-E-0072-02

was performed to develop appropriate test acceptance criteria in the development of

Procedure 1304.175. The 12-day acceptance criteria was selected for

incorporation into the procedure,

c.

Conclusions

The licensee's failure to perform periodic testing of backup air accumulators

associated with outside air dampers in the control room emergency ventilation

system and the failure to identify a condition adverse to quality were determined to

be a violation. The inspectors found that corrective actions for similar discrepancies

identified by the NRC in 1990, which resulted in a Severity Level 111 violation, were

not fully implemented.

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M8.2' (Closed) Violation 50-368/9508-01, " Operation With inocerable Main Steam Line

Safetv Valves"

(Closed) LER 50-368/95-005, " Main Steam Safety Valve Lift Pressures Not Within

Technical Specification Tolerance Durina Operation Due to a Failure to Adeauatelv

Specifv Environmental Conditions for Use in Vendor P;ocedures for Testina and

Sotooint Adiustment"

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These two items concerned the same issue and the licensee wrote

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LER 50-368/95-005 for this violation of Technical Specifications. The inspectors

verified the corrective actions described in the licensee's response letter, dated

December 15,1995, to be reasonable and complete.

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M8.3 (Closed) Violation 50-313/9601-03, " Failure to Conduct Preventive Maintenance on

Emeraencv Feedwater Initiation and Control Heat Tracina"

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The inspectors verified the corrective actions described in the licensee's response

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letter, dated May 8,1996, to be reasonable and complete. No similar problems

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Miscellaneous Engineering issues (92903)

E8.1

(Closed) URI 50-313/9602-04: 50-368/9602-04, " Review of UFSAR Commitments"

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a.

Inspection Scope

NRC Inspection Report 50-313/96-02;50-368/96-02 documented an apparent

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discrepancy in the licensee's Updated Final Safety Analysis Repart regarding the

design basis of the Units 1 and 2 spent fuel pools and the lack of administrative

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controls to ensure the design basis was not exceeded. Further inspection of the

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unresolved item was conducted during this inspection period.

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b.

Observations and Findinas

The Units 1 and 2 Safety Analysis Reports stated that the spent fuel and spent fuel

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pool cooling system are designed to keep the pool water temperature below 120 F

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for normal refueling operations and 150 F for fut, core discharge situations. This

design basis assumed a service water temperature of 85 F. However, lake

temperatums have routine' exceeded 85 F during the summer months of

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operation. Since the plant began operating, lake temperatures in excess of 90 F,

but less than 95 F, have been recorded. Lake temperatures in excess of 85 F

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could cause the spent fuel pool water to exceed the design basis temperatures

stated in the Safety Analysis Reports. NRC Inspection Report 50-313/96-02;

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50-368/96-02 indicated that, if the service water temperature was assumed to be

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95 F and the cores were fully off loaded, the maximum spent fuel pool temperature

would be 168 F on Unit 1 and 162 F on Unit .2.

These maximum' values were well

below the temperature at which boiling of the water in the. spent fuel pool would

occur. However, the inspectors found that the licensee did not have administrative

controls to ensure a core discharge did not occur when service water temperatures

exceeded 85 F.

The inspectors found that the licensee had never off-loaded fuel from either plant

when service water temperatures exceeded 85'F and had never exceeded spent fuel

pool temperatures assumed in the current licensing basis.

To ensure that the maximum licensing basis spent fuel pool temperatures are not

exceeded in the spent fuel pools in the future, the licensee revised the refueling

procedures for both units. As a prerequisite to refueling, procedures require the

licensee to verify that required cocling system components are available and that

the Lake Dardanelle temperature is in a range that would provide sufficient cooling

to maintain spent fuel pool temperatures within design limp.s during the course of

the proposed refueling. Procedure 1502.004, " Control of Unit 1 Refueling," and

Unit 2 Procedure 2502.001, " Refueling Shuffle," were reviewed to verify that the

appropriate precautions were added. The added precautions could preclude the

licensee from performing refuelings during summer months when Lake Dardanelle

temperatures are elevated.

10 CFR Part 50, Appendix B, Criterion Ill, " Design Control," states, in part, that

". . . measures shall be established to assure that applicable regulatory requirements

and the design basis . . . for those structures, systems, and components to which

this appendix applies are correctly translated into specifications, drawings,

procedures, and instructions." The failure to have administrative controls to ensure

a core discharge did not occur with service water temperatures in excess of 85 F

was determined to be a violation. This failure constitutes a violation of minor

significance and is being treated as a noncited violation, consistent with Section IV

of the NRC Enforcement Policy (50-313/9702-02; 50-368/9702-02).

c.

Conclusions

The failure to have administrative controls to ensure fuel from the Units 1 or 2 cores

was not off loaded to the spent fuel pool with service water temperatures in excess

of 85 F was determined to be a noncited violation.

i

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_ ~ . ~ . - . . -_~.-.. - .-.-. -

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-13-

IV Plant SilDDort

,

P

R1

Radiological Protection and Chemistry Controls

R1.1 General Comments'(71750)

During routine tours of the plant and observations of plant activities, the inspectors

-

_

found that access' doors to locked high radiation areas were properly locked, areas

i

were properly posted, and personnel demonstrated proper radiological work

practices.

R5

Staff Training and Qualification

RS.1 Chemistry Technician Qualification (71750)

The inspectors reviewed the training and qualifications of chemistry technicians.

-Technicians. interviewed had a strong familiarity with assigned tasks and

demonstrated good knowledge in their ureas of assigned duties. The chemistry task

to training matrix was reviewed and a sampling of procedures indicated that

technicians were performing tasks for which they were qualified.

S1

Conduct of Security and Safeguards Activities

S 1.1 General Comments (71750_1

During this inspection period, the inspectors observed the licensee implement proper

physical security measures associated with the integrity of protected area barriers,

personnel and package access, and personnel searches.

s

t

.5

...-%

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-

..

. .

.... _ .-

. . - .

_ - . . - . . _ - -

..

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..

.

pg-

!i

,

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'

e

ATTACHMENT

SUPPLEMENTAL INFORMATION

PARTIAL LIST OF PERSONS CONTACTED

Licensee

B. Allen, Maintenance Manager, ui.,

.

-

C. Anderson, Plant Manager, Unit '

G. Ashley, Licensing Supervisor

B. Bement, Radiation Protection and Chemistry Manager

M. Chisum, instrumentation and Control Superintendent, Unit 2

A. Clinkirgbeard, Operations Shift Superintendent, Unit 1

~ M.- Cooper, Licensing

D. Denton, Director, Support

P. Dietrich, Maintenance Manager, Unit 1

R. Edington, General Manager, Plant Operations

C. Eubanks, Mechanical Superintendent, Unit 2

C. Fite, in-House Events Supervisor

R. Hutchinson, Vice President, Operations

J.~ Kowalewski, Manager, Unit 1 System Engineering

J. McWilliams, Modifications Manager

D. Mims, Director, Licensing

T. Mitchell, Manager, Unit 2 System Engineering

T. Russell, Operations Manager, Unit 2

M. Smith, Engirwering Programs Manager

' A_ . South, Licensing

J. Vandergrift, Director, Quality

H. Williams, Jr., Superintendent, Plant Security

C. Zimmerman, Plant Manager, Unit 1

I

INSPECTION PROCEDURES USED

IP 30855:

Plant Operations

IP 61726:

Surveillance Observations

IP 62707:

Maintenance Observations

IP 71707:

Plant Operations

IP 71750:

Plant Support Activities

IP 92902:

Followup - Maintenance

IP 92903:

Folicwup Engineering

)

. .

.

..

-

. -

.

-

<

' 's

.

2-

ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

50 313:368/9702-01

Failure to Test Safety Related Accumulators

(Section M8.1)

Opened and Closed

50-313:368/9702-02

Failure to Translate Design Basis of Spent Fuel Pool

into Procedures (Section E8.1)

. Closed

50-368/9505-00

LE9

Main Stearn Safety Valve Lift Pressures Not Within

Technical Specification Tolerance During Operation Due

to a Failure to Adequately Specify Environmental

Conditions For Use in Vendor Procedures for Testing

and Setpoint Adjustment (Section M8.2)

50-368/9508-01

Operation With Inoperable Main Steam Line Safety

Valves (Section M8.2)

50-313/96-004

LER

Excessive Load Moved Over Fuel Store in Spent Fuel

Pool" (Section 08.1)

50-313/9601-03

Failure to Conduct Preventive Maintenance on

{

Emergency Feedwater initiation and Control Heat

Tracing (Section M8.3)

50-313:368/9602-04

URI

Review of UFSAR Commitments (Section E8.1)

50-313:368/9701-03

URI

Failure to Test Safety-Related Accumulators

(Section M8.1)

,

. --

-.

.

._.

.

.. .-

.

..

.

-.

. .

__

__ _

.

'

PLANT IPE CORE DAMAGE FREQUENCY lNFORMATION

7

ceo

ree

neye- % a

p.e i.ec=eo ee.r,e ,.n.,perme.w.=ca e-

Innic0F

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7-

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som

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seO

ams

1-W=e

toca

som

98tOca w nee 4

Plant IPE

General Electric BWR S

teSees if2

4.7E-05

3.82E-05

1.87E47

7.30E-08

2.83E-08

-

neghgee

3 39E-06

81 %

0%

16%

0%

-

7%

Nme fMe Point 2

3.1E-05

5.50E-06

1.10E-06

2.31E-05

7.40E-07

-

2.50E-08

1.50E-06

18%

4%

75%

2%

-

0%

5%

WNP 2

1.8E-05

1.10E-05

6.25E-07

2.63E-06

5.10E-07

-

neghe &e

2.52E 06

63%

4%

15%

3%

-

0%

14 %

,

General Electric BWR 6

C1nton

2.7E-05

100E-05

1.40E-07

1.40E-05

1.10E-06

-

neghgMe

1.60E-06

38%

1%

53%

4%

-

0%

8%

Grand Gull 1

1.7E-05

7 46E-06

5.56E-08

9.35E-06

5.18E-07

-

neghgMe

JT07

43%

0%

54%

3%

-

0%

1%

Perry 1

1.3E-05

2 25E-06

4.70E-06

4.30E-06

4.50E-07

-

neghgde

1.50E 46

17%

36 %

33%

3%

-

0%

12%

fbver Bond

1.6E-05

1 35E-05 neghge.

2.05E-06 neghg de

-

neghgMe

1.80E-08

87%

0%

13%

0%

-

0%

Babcock and Wilcox PWR 2-loop

ANO 1

4.7E-05

158E-05

9.93'E-07

1.48E-05

1.57E-05

9.20E-08

6.90E-08

9.34E-0)

34 %

2%

32%

34 %

0%

2%

Cryst.1 Phver 3

1.5E-05

3.28E M negwg&e

9.45E47

9.00E-06

6.70E-07 noghgcle

1.25E-06

21 %

0%

6%

59%

4%

0%

8%

Davis Besse

6.6E-05

3.54E-07

5.71E-05

5.286-06

4.60E-07

8 80E-07

2.00E-06

1%

86 %

8%

1%

3%

i

Oconee 1,2,3

2.3E-05

2.57E-06

1.00E-07

5.33E-06

9.701-06

2.10E-07

4.50E-10

5.50E-06

11%

0%

23%

42%

1%

0%

24 %

!

TMt 1

4.5E-05

1.57E-06 neghg&e

2.36E-05

1.57E-05

8.94E-07

1.80E-07

3.00E-06

3%

0%

52%

35%

2%

0%

7%

Combustion Engineering PWR 2-Loop

ANO 2

3.4E-05

1.23E-06

1.02E-06

2.67E-05

4.804-06

9.53E-08

3.36E-07 neghese

4%

3%

79%

14%

0%

1%

0%

2.40E-05

1.30E-04

6.65E-05

4.49E-06

1.90E-06

1.55E.05

10%

54 %

28%

2%

1%

6%

Calvert Chffs 112

2.4E 04

2.89E-0 7

8.93E 06

1.07E u6

7.67E-07

6.74E-C7

1.87E-06

2%

66%

8%

6%

5%

14%

Fort Calhour 1

1.4E-05

St tucie 1

2.3E-05

2 65E 06

4.13E-07

5.36506

1.22E-05

8.18E-07

1.74E-06

5.00E-07

12%

%

23%

53%

4%

8%

2%

Sttucie 2

2.6E-05

2.64E-06

1.76E-06

5.31E-06

1.29E-05

8.99E-07

2.72E-06

5.00E-07

10%

7%

20 %

49%

3%

10%

2%

._

Minstone 2

3.4E-05

4.3E 07

1.5E-06

2.5E-06

8.01E-08

5.22E-07

8.60E-08

2.00E-07

1%

4i

74 %

10%

2%

0%

1%

P.hsedes

5.1E-05

9 02E-06

4.00E-06

2.00E-05

1.57E-05

2.54E-06

3E-07

3E 07

18%

8%

39 %

31 %

5%

0%

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PLANT IPE CORE DAMAGE FREQUENCY lNFORMATION

.

Iner. CDF

Core Damage Fueguen~y Por accident CImes

Percent of Care Demeys Fregeancy Pee AW Onee

Plant IPE

so

a1*s

vrer

toCa

sain

istoCa

ii nsed

seo

arws

reer.oinnie

toca

sein

istoCa

b.i nsed

IIsoes en CDF values:

* For Dans Besse. Calvert Chffs. & Fort Calhoun. seperate 580 CDF was unewedeble. so Transesni

For Turkey Poent, the CDF hsted in the avec summery of the submrttel. which

CDF and % CDF includes SBO contribution

corresponds to *all toyers of recovery," was used

The database values for Oyster Creek do not appear to anchsde the CDF for intemet floods; the

'For Salem 1 & 2. the revesed flood and plant CDFs bsted in the sahenittet letter for the IP1

vetues Ested here include the CDF for intemet Wood

were used

(2)The Surry internet flood CDF is from page 9 of 4/21/92 NMR letter which Ests a revised value

from 19126191 Surry seensiysis submittet

For Watts Bar. the CDFs from the revesed subtruttet were used

Deferred means that hcensee included Interriet flood enelyses in thes IPEEE

.

t

,

4

FILE: IPE-CDF.T8t

i

.

PLANT tPE CONTAINMENT FAILURE FREQUENCY INFORMATION

Coes Demoge Freesency Dy Centeinment Fasiste Mede

Percent of Core C.cc. p i

up Por Containment Fenisre r-2

Plant

Plant tPE

CDF

Bypese

EF

LF

NCF

Bypese

EF

LF

NCF

Generet Electric - Large Dry

l

5.4E-05l

7.56E-07l

2.32E-06l

neghgesel

5 09E-05l

1%l

4%l.

0%l

94 %

BIO ROCK POINT

General Electric - Merit i

BROWNS FERRY 2

4.8E-05

4.45E 07

2.18E-05

1.25E-05

1.33E-05

1%

45%

26%

28%

BRUNSWICK 1&2

2.7E 05

611E 08

2.38E-06

1.63E-05

8.33E-06

1%

9%

60 %

31 %

COOPER

8 OE-05

neghgtte

1.29E 05

b.7 7E-05

913E-06

0%

16%

72%

11 %

ORESDEN 2&3

1.9E-05

noghgele

5.55E-07

1.59E-05

2.04 E-06

0%

3%

86%

11%

DUANE ARNOLD

7.8E-06

neghgele

3.67E-06

2.49E-06

1.68E-06

0%

47%

32 %

21%

FERMI 2

5.7E 06

2.OOE 07

1.71E-06

2.22E-06

1.57E-06

4%

30 %

39%

28%

FITZPATRICK

1 9E-06

neghg@e

1.20E-06

4.16E-07

3 03E 07

0%

63%

22%

16 %

HATCH 1

2.2E 05

1.85E-07

5.47E 06

5.70E-06

1.10E-05

1%

25%

26%

49%

HATCH 2

2.4E-05

1.94E 07

5 OCE 06

5 91E.06

1.25E-05

1%

21 %

25%

53%

HOPE CREEK

4.6E-05

.neghg &

2.87E-05

1.20E 05

5.56E-06

C%

62%

26%

12%

M RSTONE1

1.1E-05

1.25E-07

3.74E-06

3.2 7E-06

3.87E-06

1%

34 %

3016

35 %

MONTICELLO

2.6E-05

5.20E 09

4.15E-06

6.24E OG

1.56E-05

1%

18%

24%

60 %

NINE MILE POINT 1

5.5E-06

7.48E-08

1.31E-06

3.40E-06

7.12E-07

1%

24 %

62%

13%

OYSTER CREEK

3.7E-06

2.70E-07

5.87E-07

9 69E-07

1.86E 06

7%

16%

26%

61%

PEACH BOTTOM 2&3

5 5E-06

6 64E-09

1.55E-06

1.40E-06

2.5 7E-06

1%

28%

25 %

46%

PtLGRIM 1

5.8E-05

2.32E-07

1.25E-05

3 54E.05

9.86E-06

1%

22%

61%

17%

OUAD CITIES 1&2

1.2E-06

6.OOE-10

2.84E-07

6.62E-07

2.53E-07

1%

24%

55%

21 %

VERMONT YANKEE

4.3E-06

4.30E-08

2.11E-06

9 89E 07

1.16E-06

1%

49%

23%

27%

IPE-CFF.T8L

September 30,1996

-

.

- . -

.

m.

..__ .. . _ _ .

. . . , . . . . . _ , , . . . . ._ . , , ,_

_., _

!

i

1

!

.

Pt ANT IPE CONTAINMENT FAR.URE FREQUENCY WeFORMATION

!

Case Desusage Fseepsency By Centehunent Fe8mre Mode

Percent et Case Dennage Psegsopey Per - FeAsse Mode

%

Plant IPE

CDF

9 ,pese

EF .

LE

feCF

Dypees

EF

LF

90CF

I

,

General Electric - Mark N

!

LA SALLE 1&2- 5305

4.7E-05

neghgede

1.66E-05

2.42E-05

8.64E-06

0%

~ 35 %

51%

14%

LIMERICK 1&2

4.3E-06

noghgede

3.96E-07

1.16E-06

2.75E-06

0%

9%

27%

64 %

.

N!NE MILE POINT 2

3.1E-05

2 79E-08

2.32E46

2.04E-05

8.30E-06

1%

7%

66%

27%

WNP 2

1.8E 05

2.98E-08

5.34E 06

5.30E-06

6.83EM

1%

31 %

30 %

39 %

,

Generet Electric - Meet M

.

CLINTON

2.6E-05

neghedde

8.27E-07

4 84E47

2.4 7E-05

0%

3%

2%

35 %

GRAND GULF 1

1.7E 05

neghgede

8 05E 06

5 66E 06

3 51E-06

0%

47%

33%

20 %

PERRY 1

1.3E-05

neghgede

3.14E-06

4.76E-06

5.30E-06

0%

24 %

36 %

40 %

'

RIVER SEND

1.6E-05

neghgede

4.30E 06

2.14E-06

8 98E 06

0%

28 %

14 %

58%

PWR -Ice Condesiser

CATAWBA 1&2

4.3E-05

7.71E-09

2.31E-07

2.02E-05

2.2 ?E-05

1%

47%

53%

~[

D.C. COOK 1&2

6.3E-05

7.11E-06

9.26E-07

1.13E 06

5.40E-05

11 %

.1%

2%

86 %

[

MCGutRE 1&2

4.0E45

9.60E-07

9.50E-07

1.64E-05

2.20E-05

2%

40%

54 %

SEOUOYAH 1&2

1.7E-04

7.99E-06

2 81E-06

S.32E-05

7.60E-05

5%

2%

49%

46%

i

t

WATTS BAR 1&2

9.0E-05

- 5.95Em

4.03EM

1.72E-05

5.27E-05

7%

5%

22 %

66 %

!

PWR - Subetsnospheetc

t

SEAVER VALLEY 1

2.1E-04

1.02E-05

4.73E-05

9.15E-05

6.17E-05

5%

- 23%

44 %

29%

SEAVER VALLEY 2

1.9E-04

9.84E-06

4.74E-05

8 54E 05

4.69E-05

5%

25%

45%

25 %

,

!

NORTH ANNA 1&2

6.8E-05

8 98E-06

1.05E-06

7.68E G

5.03E-05

13%

2%

11 %

74 %

SURRY 1&2

'

MILLSTONE 3

5.9E-05

3.90E47

2.24E-00

1.10E-05

4.47E-05

1%

8%

20 %

g0%

f

L

I

h

IPE CFF.TOL

e. at.n.e , vt te9A

[

.

-

--

-

. -

-

.

- -

-

- -

-

2

++L.h

1

_44-ca.

.

_..--A

E,

a

4.

L

_

-L

4.

N

e

.4

wi.

-

+.

4

3.

.D.

6-.E

r

&

-

.

Ft ANT IPE CONTAINMENT FAE.URE FREOUENCY INFORMATION

Core Deenage Frogsency 9y Contabwnent Feeure Mode

Percent et Case Dag Psogneney Per Centehuneset Fe8ese Stede

%

Plant tPE

CDF

Sypees

EF

LF

NCF

Bypees

EF

LF

NCF

s

p

PWR - Large Dry

ARKANSAS P.1.lCLEAR O*iE 1

4.9E-05

2.08E-07

3.03EM

5.95EM

3.96E-05

1%

6%

12%

81 %

t

ARKANSAS NUCLEAR ONE 2

3.7E-05

4.07E-07

4 51E-06

5.14E-06

2.69E C5

1%

12 %

14 %

73%

.

6

BRAIDWOOD 1&2

2.7E 05

1.10E-08

5.48E-08

2.54E-06

2.48E-05

1%

9%

90%

.

r

SYRON 1&2

3.1E 45

1.24E-08

2.13E-07

2.50E-06

2.82E-05

1%

8%

91 %

j

CALLAWAY

5.8E-05

1.17E-06

1.17E-07

3.09E-05

2 fi3E-05

2%

1%

53%

45%

.

t

CALVERT CLIFFS 1&2

2.4E-04

7.44EM

2.11E-05

9.53E-05

1.1SE-04

3%

9%

40%

48%

j

COMANCHE PEAK 1&2

5.7E-05

4.67E M

6.75E-07

2.93E-05

2.26E.05

8%

1%

51 %

39%

j

CRYSTAL RIVER 3

1.5E-05

7.39E-C7

5.53E-07

9.56E-06

4.42E-06

5%

4%

63%

29 %

OAVIS-8 ESSE

6.6E-05

.1.725-06

4.16E-06

4 95E-C6

5.52E-05

3%

8%

84 %

DIABLO CANYON 1&2

8 SE-05

1.63E-06

1.01E-05

3 98E-05

3 65E-05

2%

11 %

45%

41%

i

FARLEY 1&2

1.2E-04

4.4 7E-07

7.19E-08

3.90E-06

1.20E-04

1%

3%

96 %

FORT CALHOUN 1

1.4E-05

1.44E-06

2.23E-07

3.80E-06

8.13E-06

11%

2%

28%

60 %

GINNA

8.7E-05

3.71E-05

2.67E-06

1.27E-05

3.50E-05

42%

3%

15 %

40%

H.S. ROBINSON 2

3 2E 04

6.37E-06

4.19E-05

3.20E-05

2.40E-04

2%

13%

10%

75%

HADOAM NECK

1.8E-04

1.16E-05

1.21E-06

9.70E-05

7.01E-05

6%

1%

54 %

39 %

INDIAN POSIT 2

3.1E-05

1.94E-06

5.615-08

2.82EM

2.65E-05

6%

1%

9%

85%

INotAN POINT 3

4.4E-05

2.44E-06

3.12E-07

1.07E-05

3.05E-05

6%

1%

24 %

89%

,

KEWAUNEE

6.6E-05

5.28E-08

1.48E-08

3.22E-05

2.88E-05

8%

1%

49%

43%

>

MAINE YANKEE

7.4E-05

1.21E-06

5.79E-06

3.54E-05

3.18E-05

2%

.8%

,

48%

42%

MILLSTONE 2

3.4E-05

7.66E-07

3.22E-06

1.11E-05

1.91E-05

2%

9%

32%

56 %

OCONEE 1,2.&3

2.3E-05

4.60E-10

2.SIE-07

1.71E-05

5.61E-06

0%

1%

74 %

24%

PALISADES

5.1E-05

2.89E-06

1.67E-06

7.66E-06

2.35E-05

6%

-33%

15 %

48%

PALO VERDE 1.2.&3

9.0E-05

3.20E-06

9.41E-06

1.21E-06

6.53E-05

4%

10%

13%

-

73%

POINT BEACH 1&2

1.0E-04

8.32E-08

3.24E 08

1.81E-06

7.97E-06

8%

1%

17%

77%

,

PRAIRIE 1SL AN01&2

4.9E-05

2.19E 05

4.15E-07

1.11E-05

1.56E 05

44%

1%

22 %

31 %

,

i

'

IPE-CFF.T8L

Sentamher10 1996

,

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_ _ _ ._ __

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_ . _ _ _ _ _ - . . _ _ _ _ _ . _ . _ .

. . _ . . _ _ . _

i

l

,

1

!-

Pre-Decisional

'

i

Semiannual P1 ant Performance Assessment

i

St. Lucie 1 and 2

i

-

Current SALP Assessment Period: 1/7/96 through 6/97

l

Last SALP Rating

Previous SALP Rating

i

1/2/94 - 1/6/96

5/3/92 - 1/1/94

,

Operations

2

1

Maintenance

2-

1

.

Engineering

1

Plant Support

1

4

l

I.

Performance Overview

'

Since July 1995, there have been a series of events that led to

,

l

questioning the plant's overall performance. These have included:

i

A Unit 1 turbine trip due to procedural weaknesses,

u

poor operator performance, and weak supervisory

'

oversight.

]

l

The' attempt to restage an RCP seal using inadequate and

inappropriate procedural guidance. The evolution was' compounded

4

i

by failing to follow aspects of the guidance that did exist, which

i

led to the failure of the second and third stage seals.

i

A main steam isolation signal due to an operator failing to block

F

the MSIS signal during a cooldown when an annunciator. indicated

i

that the block was enabled. This failure occurred despite the

fact that the operator's attention was directed to the annunciator

!

.

j'

on at least two different occasions,

i

Both pressurizer power operated relief valves being found

inoperable due to incorrect assembly during a refueling outage.

l

The conditions had existed for approximately 10 months (SL3,CP).

.

[

An loss of RCS inventory (4000 gallons) due to a shutdown cooling

i

relief valve which lifted and then failed to resent due to

'

incorrect setpoint margins (a generic problem involving several

l.

valves). The licensee had sufficient evidence that this generic

condition existed, but had failed to act promptly to evaluate the

conditions (SL4).

l

The spraydown of containment due to an inadequate procedure and

oparator error coupled with an existing operator-work-around.

'

The significant operator inattentiveness which resulted in the

overdilution event on January 22, 1996, highlighted the recent

j

large number of personnel errors and lack of command and control

in the control room.

I

These and several other recent deficiencies involving weak procedures, a

l

.

!

.-

. . - ,

,

. . -

,

---

.

_

_ _ _ _ _ _

_._ __.

_ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _

.

~

general. lack of procedural compliance, equipment failures, and personnel

errors clearly. indicated that the plant's past high level of performance

had declined. An NRC root cause effort determined that, in addition to

,

procedural adherence / adequacy weaknesses, the licensee suffered from

.

weaknesses in both interfaces across o ganizational lines and corrective

.

{

actions.

II.

Functional Area Assessment - Operations

!

A.

Assessment

i

.

A SALP board convened on January 18, 1996. The board coricluded

a

!

that the licensee's performance in the areas of Operations had

i

declined from an excellent level of performance to good. The

.

,

decline in Operations' performance particularly occurred in the

-

F

final six months of the assessment period. The licensee undertook

<

a number of efforts to reverse declinit;g performance following the

j

onset of the operational events descreed above. Verbatim

procedural compliance was established as the norm for the site,

which resulted in the need for literally hundreds of procedural

'!

-

changes and around-the-clock on-site review committee meetings.

An increased emphasis on the initiation of corrective action

documentation resulted in an increase in the number of documents

initiated, but has also resulted in increases in backlogs.

B.

Basis

As basis, the board noted an increase in the. number of operational

events attributable to:

Weaknesses in operator performance

1

Acceptance of long-standing equipment deficiencies

j

Management expectations were not effectively communicated to

personnel and enforced

,

. Weaknesses in procedural adequacy and adherence

Implementation and adequacy of corrective actions

C.

Future Inspections

Increase staffing at St Lucie to N + 1 and focus greater

inspection effort in the areas of: routine operator performance -

professionalism in CR; procedural compliance and enhancements;

operator problem identification and corrective action; management

communication of expectations; interdepartmental interface;

'

resolving impact of operator work arounds; and operation

contribution-to adequacy of safety evaluations.

i

--

'

.

-

. _

. _ .

. _ . _ . _ _ _ _ . _ . - . _ _ _

_ _ _ . _ ._ ..

._.. _ __ _ . _ _ _ __ _.__.._

_.

i

'

i

!

?

)

L

III.

Functional Area Assessment - Maintenance

A.

Assessment'

,

!

Adverse trends were noted in maintenanc' and the board concluded

e

i-

that the licensee's performance in the area of Maintenance had

declined from an excellent level. of performance to good. The EDG

i

problems indicate a weakness in EDG Maintenance. The number of

!'

problems related to personnel errors and procedure problems may

j.

. indicate possibly attitude problems. Also, Safety Equipment

performance has failed to meet the industry average on all safety

+

system. Maintenance performance has declined.

'

B.

Basis

,

i

1.

Adverse trends were noted on the Site Integration Matrix.

i

!

Recent Equipment Failures:

q

01/23/96 - Elect. arc during maint. caused loss of 25% of control

J

room annunciators

i

12/20/95 - Pitting of reactor flange o' ring groove

!

.1/06/95 - Failure of EDG 2A relay sockets

j

l

10/05/95 - EDG 1B fuel oil leak at threaded connection

4

09/20/95 - - EDG 1A/1B governor control problems resulted in load

L

oscillations

u

l

Recent Personnel Errors-

'

4

j.

01/01/96

ICI wiring error during Rx head installation

j

08/31/95 - Damaged cy. head on IB EDG due to loose-lash

!

adjustment

j.

08/09/95 - Inoperable Unit 1 PORV due to maintenance

error / testing inadequacy

4

)

!-

Recent Procedure Problems:

l

12/09/95 - 2A2 RCP seal destaged due to inadequate or weak

procedure-

-

09/15/95 - Failure to have clearance for work on cond. water box

,

08/25/95 - Failure to sign off procedure steps as work completed

j.

2.

Safety Equipment Performance (Availability %) has been below

-

industry a average.

,

i

Actual

Industry Averages

i

Unit 1.

Unit 2

,

1

AFW

99.5

97.0

99.6 - 99.1

!

HPSI

96.0

98.6

99.7 - 99.2

l

EDGs

95.6

99.8

99.1 - 98.6

,

'

l

- AFW wiring error on 2B AFW

- 2C AFW steam admission valve did not open and mechanical

'

j

trip linkage problem

- HPIC 2B Breaker Failure

t

i

e

"

.

-

. ___ .

-_.__ _ _ _ _ _ _ _ _ _ _ . _ _ .

_.

_ _ _,_ ___._._

f

j

\\

.

3.

Numerous equipment failures have Caused power reductions

'!

4'

-

during the last 6 months.

!

l

- 10/95 Unit 1 Heater Level Control

- 10/95 Unit 1 IB Heater Drain Pump

- 11/95 Unit 1 FW Reg. Viv. Contro'

,

- 11/95 Unit 1 1A Main Transformer

j

- 01/96 Unit 1 FW Viv. LSV-24-A2

- 08/95 Unit 2 Heater Drain Valve

3[

- 08/95 Unit 2 Heater Drain Pump

3

- 08/95 Unit 2 Circ. Water Valve-

1

- 08/95 Unit 2 Htr. Drn. Pop. PCM

' 01/96 Unit 2 Hydrogen Sys. Prob.

j

-

- 01/96 Unit 2 MFW Pump

'

.

!

C.

Future Inspections: Assist the Resident inspector with the

j-

routine Resident Maintenance / Surveillance Inspections program.

i

Conduct Regional Initiative inspection, focus on outage activities

l

BOP and EDG maintenance, procedure adequacy and safety system

i

performance.

Perform maintenance rule inspection in September

i

.!-

1996. Conduct the.ISI inspection.

I

1

l

IV.

Functional Area Assessment - Engineering

A.

Assessment

,

Engineering performance at St. Lucie remained superior during the

i

SALP period ending January 6, 1996, and has not changed since

then.

Continue with core inspections in the engineering area.

i

B.

Basis

The basis for the above assessment was the SALP report issued on

February 8,1996, and a continued low number of engineering

issues. A recent inspection.identifled weakness in engineering-

safety evaluations.

C.

Future Inspection

Conduct the following core inspections:

engineering core

inspection which focus on operability,10 CFR 50.59 evaluations,

engineering support to maintenance and FSAR review; employee

'

concern program due to increased number of allegations in the last

year; and corrective action plan implementation.

V.

Functional Area Assessment - Plant Support

A.

Assessment

Host of the assessment information in the past six months has been

captured in the most recent SALP report 95-99 dated February 8,

1996. There were no specific inspections of the Radiation

Protection (RP) program during the past 6 months. However,

Resident Inspectors observed RP activities throughout the

_ _ .

.

.. _

_ . - - - _

__ ..

.

_

.

. _ _ _ _

_

_ _ _ _ _ _ _

l

'

assassment period and performance was satisfactory. The RP

i

program continues to adequately maintain external and internal

radiation exposures within regulatory limits. The plant programs

]

for plant chemistry, radiochemical analysis, radiological effluent.

and environmental monitoring, and radioactive waste shipping

'

continued to be effective although some issues were identified.

,

The EP program continued to provide an adequate level of readiness

j

i

to respond to events. Overall, site security has been adequate.

i

Implementation of the fire protection program continued to be

!

satisfactory.

Potential problem exists with " Speak Out" employee

j

concerns program (ECP).

t

B.

Basis

Near the end of the assessment period the licenseer missed

i

some RCS boron surveillances.

The surveillance was missed

4

in October and a NCV 95-18-06 was identified. However the

licensee's corrective actions were not sufficient to prevent

,

{.

a recurrence in November and a VIO 95-21-03 was issued.

'

'

Unit I was suspected of having some leaking fuel that was

not evident prior to this assessment period.

.

No Exercise Weaknesses were identified in the Feb 1996 Full

Participation Exercise.

Site Management expressed concern

that two practice drills were necessary before the NRC

j.

graded exercise to assure no NRC findings.

4

i.

The licensee reported a training and qualification error in

l

which security personnel were qualified using only half the

required rounds, a failure to compensate within 10 minutes

4

and problems with protectoid area barriers.

Fire protection inspections, conducted by resident

-

inspectors, identified overall good performance but-

4

.

l

weaknesses in fire fighting techniques and respirator

qualification program.

4

.

A large number of allegations have been received.

No

4

pattern to organization but some against " Speak Out" program

i

'

C.

Future Inspections

Conduct the following core inspections in the areas of:

occupational exposure to observe RP practices; security - to

review audits, corrective action, plans, management support,

review PA equipment, vital access and alarms; and employee

concerns program implementation due to large number of allegations

dealing with adequacy of employee concern program.

VI.

Attachments

A.

Inspection Schedule

B.

Power Profile (last six months)

C.

Site Integration Natrix

_-_._._ _ , . _ _ . _ . _ _ . _ _ . . _ _ . . . _ _ . _ _ _ _ . . _ _ _ _ _ _ _ _ _ _ . _ . _ . _ . . . _ . _ _ _ _ . _ . . . _ . . . . . . . _ . . _ . - . - . . - . . . _ _ _ . . . _ . _ _ . -

i

ST. LUCIE - INSPECTION PLAN

}

.

INSPECTION

NUMER OF

PLAMED

PROCEDURE /

TITLE / PROGRAM AREA

INSPECTORS

INSPECTION

TYPE OF INSPECTION -

i

TEMPORARY

DATES

COMENTS

INSTRUCTION

j

INITIAL OPERATOR EXAMINATION

1

3/11/96

PREPARATION

l

INITIAL OPERATOR EXAMINATON

2

3/25/96

ADMINISTRATION OF EXAM

j

I

71001

LICENSED OPERATOR REQUALIFICATION

1

3/25/96

REQUALIFICATION PROGRAM

PROGRAM EVALUATION

INSPECTION

61726

MAINTENANCE OBSERVATIONS

1

3/25/96

CORE INSPECTION

l

62703

SURVEILLANCE OBSERVATIONS

,

81700

PHYSICAL SECURITY PROGRAM FOR

1

4/1/96

CORE - SAFEGUARDS

POWER REACTORS

.

4XXXX

EMPLOYEE CONCERNS PROGRAM

2

4/29/96

REGIONAL INITIATIVE

i

62700

MAINTENANCE IMPLEMENTATION

2

5/6/96

REGIONAL INITIATIVE -

MAINTENANCE - OUTAGE

i

,

i

'

ACTIVITIES; PROCEDURES

37550

ENGINEERING

1

5/13/96

CORE 50.59 FOCUS

j

73753

INSERVICE INSPECTION

1

5/13/96

CORE - MINTENANCE

i

40500

EFFECTIVENESS OF LICENSEE

3

6/24/96

INSPECT STATUS OF

t

CONTROLS IN IDENTIFYING

PERFORMANCE IMPROVEMENT

RESOLVING,*AND PREVENTING

PROGRAM;

e

!

92720

PROBLEMS; CORRECTIVE ACTION

DILUTION EVENT FOLLOW-UP

l

REVIEW

61726

MAINTENANCE OBSERVATION

1

6/24/96

-

CORE MAINTENANCE AND

62703

SURVEILLANCE OBSERVATION

SURVEILLANCE _

i

37500

ENGINEERING

1

7/22/96

FSAR CORRECTIVE ACTIONS

i

,

!

'

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llllI!

.

_ .

__

. . _ _

ST. LUCIE

UNIT

1

Operational

Period

Sep te rn b er

1995

th rough

March

15,

1996

L OO -

-

On November 19,1995

80-

Z

End of outage following

a manual reactor trip was

Hurricane E in

initialed to perform MFRV

maintenance.

2

60 -

H

Zy

40 -

On February 24,1996,

.

Z

a manual trip was initiated

p1

cL

wiiile going to a TS required

20-

shuldown

0 ~rrrrri v i t

i i i

i i rr r i i i i

iiiiiiiirrrrriiiiiiiiiiiiiisiii

iiiiiii

S

O

N

D

J

F

M

PERIOD

OF OPERATIdN

Graph

does not include power reductions

for routine

re p airs , waterbox cleaning,

or required repairs.

-

.

- - -

-

- -

.

,-

- ---

-

. . .

.

, _ -

_ _

,T

LUCIE

I

Operational Period August

1,

-

Tlirough September

12,

1995

1

2

3

4:

.

-

100 -:

-

--

.I

..

(1 0 -

x

1.

On October 26, 1994, the unit tripped from 100 percent power due to a

M

loss of electrical load. This was the result of arc-over la a potential

"5**' '" *** 5"'**hd d"' ** 5 6=d P-

Th' ""' ***"

at'"d * =a' t r *i 'ai *=t'9' "h'ch **d 6"a 5ch'd=d 6a '

O

6 0 --

days later. The unit was returned to service on flovember 29.

CL

2.

On February 21, 1995, the unit was removed from service for the

b

replacement of pressurizer code safety valves which had been leaking by

.the seat since shortly after startup in Movember, 1994. The unit was

Z

returned to service on March 8.

m

.-1 0 -

U

On July 8, 1995, the unit tripped during turbine valve survelliance

3.

testing. It returned to power on July 12.

M

On August I, 1995, the unit was shutdown as a result of Hurricane Erin.

4.

s

4

Due to a se.les of e

nt problems and personnel performance issues,

.y n

the unit is presenti

utdown.

%U-

0

nniuu,nn u nni,n uo........-,,,

,,,,,,,,,,,,, .n n ninnn,n o,u,u u,uin,n o u,1,o,ou,n,,no,,o,o, nooo,n un,nn,n,oona

-

A

S

O

N

D

J

F

M

A

M

J

A

S

l

.

,

PERIOD OF OPERATION

Graph does not include power reductions

for routine repaifs, wat erbox cle;aning,

or required repairs.

.

,

.

.-

-

ST. LUCIE

UNIT

2

O pera ti o n al

Period

S e p te rn b er

1995

through

March

27,

1. 9 9 6

100

=

,

On October 9,1995, the

,

80-

unit was shut down for

a

m

.'

$

scheduled refueling outage.

,

k

60-

s

$

On January 5,1996, the

40-

'

d

unit was manually tripped

]

E

due to high generator

{

20-

-

hydrogen gas temperature. '

,

O

vivitivtrriviiviivivitivtrr*T-

iiiiiiiiii

S

O

N

D

J

F

M

'

~

PERIOD

OF OPERATION

,

Graph

does

not include power reductions

for routine repairs, waterbox cleaning,

'

or . required

repairs.

.

. -

.-

.

-.

.-

..

.

-

.

-

.

ST

.lTIE 2

.

Operational Peritul August

1,

Through Sepleinber

12,

1995

1

2

.

100

, , _ .

,,

..

II

.

k

80 -

m

N

' = -

.

t

[

60-

,

1.

On February 21, 1995, the unit tripped as a result of low steam

p

generator water level. The condition was the result of a feedwater

Z

regulating valve closure after a steam generator water level centrol

level transmitter failed high. The transmitter was replaced and the

y

40-

. nit was returned to service on rehr arr 25.

W

2.

On August I,1995, the unit was shutdown as a result of ifurricane

M

Erin. It was restarted on August 4,1995 but.

cL

20-

1

0

imi,mi,,,mmimi,mi,mmimimmm,mmmm,mm,,,,m,,,m,m,m,,m,m,,mmmm,,,,mm,,m,,,m.m. ,.,,mm,,,,,,,,,,,,,,,,,m,,,,,,

A

S

0

N

D

J

F

M

A

-M

J

A

S

>

PERIOD OF OPERATION

Graph does not include power reduelions

for roittine repairs,' waterbox clearting,

.

- -

-..-....:..-i........:..

- - -

- --- -

-

- -

.

.--..--.

..

-

. - . . _ . .

. .

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. _ . _ _ _ < ._

._

.. . . _ . - . . _ _ - .

.

. _ _ . _.

_

__.

-

__.. _ __

..

s

SITE INTEGRATION MATRIX BY DATE

,

~

St. Lucie

I

SFA

-

sEc

APPARENT CAUSE I COMMENTS

DATE

, TYPE

, SOURCE

ID

, PRIM

, ITEM

3/15/96

LER

IR 96-04

L

PS

Fish kilt identified in intake (great'er than 25 fish

Excessive levels of sitt in waterdue

(pending)

and greater than 100 lbs). NRC notification

to recent rough seas.

required per TS and EPP.

3/14/96

OTHER

1R 96-04

L

PS

Management change. A. Desoiza (human

(pending)

resources manager) replaced by Lynn Morgan

(from TP)

3/13/96

WEAK

IR 96-04

S

M

O

' Unplanned start of 2C AFW Pump. Pump was

Weakness in troubleshooting

(pending)

out-of-service for maintenance and

control. Operations was unaware

troubleshcoting due to the failure of 1 of 2 steam

of the efforts in progress.

!

'

admission valves to open on demand.

Troubleshooting resulted in valve openning and

-

pump starting.

,

3/12/96

OTHER

IR 96-04

S

O

M

Unit 2 standby charging pumps started / stopped

Undetermined.

(pending)

for no reason. Troubleshooting underway for

standby pumps * start controllers.

3/10/96

OTHER

1R 96-04

L

O

. Unit I downpowered to 97.5% due to hot leg

Hot leg stratification.

(pending)

stratification and flow swirl which resulted in

-

higher than actual indicated reactor power.

3/1/96

OTHER

1R 96-04

L

O

Management Changes - T. Plunkett succeeds G.

Goldberg, C. Wood replaces L Rogers as ~

manager of SCE, C. Marple replaces C. Wood

as Ops Supeivisor.

.

,

FROM: 1/1/90 TO: 3/18/96

Page 1 of 11

18-Mar-96

- - .

.

-

.-

. .

-

- . . - - -

-

.

-

.

m . . . . . _ . _ . _ . _ _ _ - . _

.. .. _

_ . . .

. _ . ,

-

.

_

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. _ _ _ _ _

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-

-i

i

!

'

I

'

SFA

DATE

TYPE

SOURCE

10

PRIM

sEc

ITEM

, APPARENT CAUSE I COMMENTS

(

t

,

2/27/96

WEAK

1R 96-04

S

M

inadvertent start of 1 A EDG occurred when l&C

Poorwork planning. Personnel

(pending)

personnelinstalling a modification in an

were not aware of the proximity of

electrical cabinet bumped the EDG's actuation

the subject relay and EDG was not

relay. No load shedding was required, nor did it

declared out-of-service and isolated

occur.

electrically prior to the

commencement of work.

I

!

2/24/96

WEAK

IR 96-04

t.

PS

O

Unit 1 containment radiation monitor found out-

Failure 10 fcitow procedure on the

(pending)

of-service due to isolation valve which was

part of HP personnel, compounded

closed for a containment entry and not returned

by failure to identify condition by

to the open position.

operators during rounds (the low

-

flow condition of the detector was

,

2/24/96

WEAK

IR 96-04

N

M

Maintenance practices for Steam Bypass and

Poor preventive maintenance and

(pending)

Control System and Feedwater Regulating

work instructions

i

valves found weak in inspection following

2/22/96 Unit 1 trip. Additional weakness found

in the acceptance criteria specified for CEDM

coil resistances.

.

2/22/96

EMERG

IR 96-04

s

O

Dropped CEA (due to SCR failure) leads to TS-

Equipment Failure

T1"W

required shutdown and declaration of NOUE.

. ,

Failure of air supply to FRV leads to operators

tripping reactor from 26%. Good operator

'

performance throughout.

!

I

2/17/96

OTHER

1R 96-01

N

M

PS

Work on 1 A ECCS suction header through-wall

Personnel Work Practices

leak revealed strong FME, but poor HP work

practices observed regarding contamination

,

control.

2/17/96

NEG

IR96-01

N

M

Freeze seal procedure lacked objective criteria

Procedural Weakness

defining when a freeze seat existed.

!

,

.

c o n u.1siton T o- 3118/96

Page 2 of 11

18-Mar-96

- -

-

.

!

,

!

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_

. = . . .-.

. .

, .

.

- .-

-_

,

-

. ..

_

,

6

'

I

1

SFA

APPARENT CAUSE I COMMENTS

DATE

TYPE

SOURCE

ID

PRIM

sEc

ITEM

,

1/7/96

N

O

SALP CYCLE 12 BEGINS

t15/96

NEG

IR 95-22

N

O

Several procedural deficiencies and

inadequate Procedure Review and

calculational errors identified in reload physics

Execution

test procedure.

!

I/5/96

IR 95-22 -

N

O

PS

Several deficiencies in prodecure change

Failure to Properly implement

NCV 95-22-

process implementation identified. Expired or

Procedures

01

cancelled TCs found in control rooms and hol

shutdown panel.

i

t15/96

WEAK

IR 95-22

L

O

M

U2 manual RX trip on high generator H2 temp

Temp Control Valve Failure

'

due to failure of temp control valve. Operator

I

awareness of RPS status post-trip poor.

inspection of post-trip review (for current trip as

,

well as past trips) indicated weaknesses in the

rigor of post-trip reviews

r

12/27/95

NEG

IR 95-22

S

O

E

FRG meeting suffered / items deferred due to

Lack of Attendance at FRG

lack of OPS /Eng*g attendance at meeting.

Majorissues at meeting affected OPS /Eng'g.

-

12/20/95

OTHER

IR 95-22

S

M

RX vessel flange inner O-ring groove pitting

Pitting - Localized Corrosion

resulted in cooldown and head removal for

repair.-

-

.

'

12/9/95

OTHER

1R 95-22

L

M

2A2 RCP seal pkg lower seat destaged da i1

Filling RCS Before Coupling RCP

reverse pressure a:ross seat.

,

r

FROM: 1/1/90 TO: 3/18/96

Page 4 of 11

18-Mar-96

_- _

_

'

I

'

SFA

, ITEM

, APPARENT CAUSE / COMMENTS

DATE

TYPE

SOURCE

ID

PRIM

sEc

12/5/95

WEAK

IR 95-22

N

O

M

ESFAS cabinet doors found unlocked following

Poor Logkeeping/Atta to Detail

maintenance work - l&C error. lod entries

associated with work were not complete.

12/1/95

NEG

IR 95-21

N

O

Operators unable to effectively obtain I&C

Inadequate Operator Training

setpoints from computer after hard copies were

removed from control room.

12/1/95

NEG

IR 95-21

N

PS

Rad survey results unavailable for B hot leg

Failure to Document RAD Survey

work. Surveys performed but not documented.

12/1/95

NEG

IR 95-21

N

O

Unit 2 procedures and valve deviation log used

valve Position Administrative

to cycle Unit 1 cross connect valves.

Controls

12/1/95

WEAK

1R 95-21

N

O

SDC procedure contained conflicting values for

Procedural Weakness / Inadequate

RX cavity level requirements. Procedure had

Review

been approved since emphasis on accuracy

stressed.

12/1/95

WEAK

IR 95-21

N

O

CCW sample valve showed dualindication

FTF Procedure

without corrective action documentation initiated.

12/1/95

WEAK

IR 95-21

N

O

Clearance in place to isola *e N2 from CST to

Poor Corrective Actions

facilitate pressure switch rr placement for nine

days without work order bring written.

-

18-Mar-96

FROM: 1/1/90 TO: 3/18/96

Page 5 of 11

- - - .

-

.

. . .

.

._. ~....- .-

.

_

.

'

SFA

APPARENT CAUSE I COMMENTS

DATE

TYPE

SOURCE

ID

PRIM

sEc

ITEM-

,

12!1/95

NEG

IR 95-21

N

O

Recurrent non-valid alarms when starting fire

FTF Procedure

pumps were not documented as operator

workarounds. Voltage dips associated with such

starts were contributors to a trip previously.

t 2/1/95

WEAK

1R 95-21

N

O

Followup to previous inspection findings

Corrective Actions

indicated a weakness in followthrough in

addressing deficiencies.

!

t 2/1/95

NEG

IR 95-21

N

O

SDC Procedure required natural circ-relatect

Procedural Inadequacy

surveillance prior to estabhshing RCS pressure

boundary Natural circ not possible without

pressurization.

11/27/95

IR 95-21 -

L

O

Missed RCS Boron sample surveillance -

Personnel Error

,

VIO 95-21-03

Repeat from IR 95-18.

.

11/21/95

IR 95-21 -

L

O

Failure to maintain Penetration Log.

FTF Procedure

NCV 95-21-

04

i

11/21/95

Oli:ER

IR 95-21

s

O

Light socket failure during lamp replacement

Equipment Failure

,

results in loss cooling to 1 A Main Transformer.

Unit downpower to ~60%.

11/20/95

IR 95-21 -

N

O

Valve discovered Closed vice Locked Closed as

FTF Procedure

VIO 95-21-01

specified on Equipment clearance Order.

-

FROM: 1/1/90 TO: 3/18/96

Page 6 of 11

18-Mar-96

_

.

. . .

.

. . .

-

!

SFA

DATE-

TYPE

SOURCE

ID

PRIM

sEC

ITEM

APPARENT CAUSE I COMMENTS

,

11/16/95

OTHER

IR 95-21

S

O

M

Unit 1 manually tripped when 18 MFRV locked

Long-Standing Equipment Problem

in 50% position. Root cause - degraded power

supply, compounded by voltage dip on starting

both station fire pumps.

11/11/95'

IR 95-21 -

N

O

Tech. Spec. equipmer.1 not specified for IV on

FTF Procedure

VIO 95-21-02

Equipment Clearance Order.

11/6/95

OTHER

1R 95-21

s

M

Fa: lure of EDG 2A relay sockets Potential

Equipment Failure

common mode failure

11/1/95

1R 95-18 -

S

M

ICI wiring error during RX head installation last

Personnel Error

NCV 95-18-

RFO.

,

05

.

10/19/95

IR 95-18 -

3

O

Missed shift CEA position indication surveillance. Personnel Error

l

NCV 95-18-

06

.

10/18/95

IR 95-18 -

L

O

Missed RCS Boron sample surveillance.

Personnel Error

'

NCV 95-18-

07

,

!

.

10/17/95

WEAK

IR 95-18

S

O

Lack of attention to task resulted in overfalling .

Personnel Error

RCS lower cavity during flood up.

L

,

FROM: 1/1/90 TO: 3/18/96

Page 7 of 11

18-Mar-96

- - -

- - .

.

. - - .

.

_ . .

-. .

. .--

-

..

_.

.

- - . - . . -

.-

.

-

I

SFA

DATE

TYPE

SOURCE

ID

PRIM

sEc

ITEM

APPARENT CAUSE f COMMENTS

,

10/12/95

IR 95-18 -

S

E

inserting CIAS signal during safeguards test

Design Error

VIO 95-18-04

shifted EDG 2A to isochronous mode while EDG

paralleled with offsite power.

10/9/95

LER

LER 95-S02

L

PS

Potential route for unauthorized access to

Personnel Error

protected area CWwater piping.

10/7/95

IR 95-18 -

N

O

Did not enter bypass key position in deviation

Failure to Follow Procedures

VIO 95-18-01

log

10/5/95

OTHER

1R 95-18

S

M

DG 18 developed FO leak at threaded

Equipment Failure

connection during surveillance run.

9/30/95

IR 95-18 -

N

O

Did not enter bypass key position in deviation

Failure to Follow Procedures

VIO 95-18-02

log.

9/28/95

OTHER

IR 95-18

s

E

Leaking PZR SVs extended forced outage -

Equipment. Failure

problems with lailpipe alignment.

9/20/95

OTHER

1R 95-18

S

M

EDG 1 A/1B govemor control problems resulted

Equipment Failure

in load oscillations.

.

9/15/95

IR 95-18 -

S

O

M

MaintOps did not provide clearance for work on

Failure to Follow Procedures

VIO 95-18-03

condenserwaterbox cover. When cover pulled

closed, severed worker's finger.

FROM: 1/1/90 TO: 3/18/96

Page 8 of 11

18-Mar-96

5

.

-

- -

-

--

- - - ---

-

- --.

!

'

SFA

APPARENT CAUSE / COMMENTS

DATE

TYPE

SOURCE

ID

PRIM

sEc

ITEM

9/14/95

WEAK

LER U1/U2

L

pS

Security failed to take correct compensatory

Failure to Follow Procedure

95-S01

action on computer failure

9/10/95

VEAK

IR 95-18

S

O

SG blowdown sent to incorrect system on RAB

Failure to Use Correct Procedrue

roof. Operator used wrong procedure. When

identified did not back out of procedine correctly.

9/9/95

WEAK

IR 95-15

S

M

Leak on SV 1201 flange extended outage,

Weakness in Work Screening and

identified one month earlier but not worked.

Planning

9/7/95

WEAK

IR 95-15

L

O

Unit 2 Main Generator overpressurized while

Personnel Error / Inoperable

filling with H2. Inattention by operators.

Equipment /OWA

'

9/2/95

IR 95-15 -

N

O

Weaknesses identified in logs relating to

Personnel Enor

VIO 95-15-03

abnormal equipment conditions and out of

service equipment not logged (mulitple

' examples).

"

8/31/95

OTHER

1R 95-15

S

M

Damaged cylinder and head on iB EDG due to

Personnel Error

loose lash adjustment.

8/30/95

WEAK

IR 95-15

N

PS

Containment closure walkdowns by

Management and QC Weaknesses

>

management were inadequate and depended

heavity on OC involvement to identify

.

deficiencies.

.

!

FROM: 1/1/90 TO: 3/18/96

Page 9 of 11

18-Mar-96

- _ _ _ _ _ - _ _ _ _

.

. . . _ _ - -

-_

_

-__

- _ - _ - _ _ - - - _ - _ _ - - _ _ _ - - _ - _ _ __-_ _ _

- - _ . _ _ _ _ _ _ _ - - _ - _ _ _ - _ _ _ _ - _ _ _ _ _ _ - - _ _ . - - _ - _ _ _ _ _ - - _

I

SFA

DATE

TYPE

SOURCE

ID

PRIM

sEc

ITEM

APPARENT CAUSE / COMMENTS

B/30/95

WEAK

IR 95-15

N

M

Mainte..ance personnel not using procedures for

Supervisory Oversight and Worker

work in progress.

Altitude

8/29/95

IR 95-15 -

N

M

Maintenance joumeyman not signing off

Procedure Use

VIO 95-15-06

procedure steps as work completed (previously

identified as a weakness in May 1995).

8/29/95

IR 95-15 -

L

O

Started 1B LPSI pump with suction valve

Personnel Error

VIO 95-15-04

closed. (No damage 1o pump)

8/23/95

WEAK

IR 95-15

S

M

2A HDP trip due to relay failure. Eight HDP trips

Equipment Failure / inadequate

in past year. Engineering solution available but

Corrective Action

not implemented.

.

8/22/95

IR 95-15

g

PS

QA failed to document a deficiency on

Personnel Error

containment spray valve surveillance identified

in an audit

8/19/95

WEAK

IR 95-15

s

O

Overfill of PWT. Spilled approx.10K gellons on

Operator Error / Operator

ground inside RCA. Operator work around on

Workaround

level control system and inattention to filling

i

'

process by operator caused error.

8/18/95

WEAK

IR 95-15

N

M

Procedural weakness involving supervisory

Procedural Weakness

oversight and joumeyman qualification.

.

FROM: 1/1/90 TO: 3/18/96

Page 10 of 11

18-Mar-96

,

.

.-

..

SFA

APPARENT CAUSE / COMMENTS

DATE

TYPE

SOURCE

ID

PRIM

sEc

ITEM

8/97/95

LER U195-

3

O

Spraydown of Unit 1 containment. STAR

ProceduralInadequacy and

007 - VIO 95-

process did not assign accountability for

Weakness / Operator-Work-Around

15

corrective action. Valve surveillance prelube

!

not documented on STAR.

j

B/9/95

IR 95-16 -

L

M

inoperable Unit 1 PORVs due to maintenance

Maintenance / Testing Errors

LER U195-

error / testing inadequacies. (Valves assembled

'

005 - EA 95-

incorrectly) (Used acoustic data only)

180

t

6/6/95

LER U195-

S

E

Lifting of Unit 1 SDC thermal relief due to

Corrective Action / Procedural

006 - VIO 95-

procedural revision from presious corrective

Weakness

!

20-01

action. Inoperable equipment not logged.

l

8/2/95

LER U195-

t

O

1 A2 RCP seal failure due to " restaging" at high

Procedural Weakness / Failure to

004 - VIO 95-

temperature.

Follow Procedures

15-02

8/2/95

LER U195-

3

O

Operator failed to block MSIS actuation dunng

Operator Error _

04 - VIO 95-

cooldown.

15-01

.

SALP Functional Areas:

ID Code:

E

ENGINEERING

L

UCENSEE

M

MABITENANCE

N

NRC

O

OPERA 110NS

S.

SELF-REVEALED

PS

PLANT SUPPORT

sA

SAFETY ASSESSMENT & QV

!

18-Mar-96

conu- ission TO: 3/18/96

Page 11 of 11

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OPERATIONS

F-

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ST. LUCIE 1

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PI EVENTS FOR 95-1

j

.

SSA

02/16/95

LERs 33595001

50.728: 28400

PWR HIST: POWER OPERATIONS AT 1005

,

DESC

WNILE RESTORING A SAFETT BUS TO A MORMAL LINEUP FOLLOWING RELAT REPLACEMENT, THE BUS WAS

l

DEEMERG1 ZED. THE EMERGENCT DIESEL STARTED AND LCADED ONTO THE BUS.

i

1

PI EVENTS FOR 95-2

1

NONE

PI EVENTS FOR 95-3

'

SCRAM 07/0s/95

LERs 33595003

50.72#: 29039

PWR HIST: POWER OPERATIONS AT 1005

~

DESC

THE REACTOR TRIPPED ON MIGH PRE 55URIZER PRE 55URE WhEN THE MAIN TURBINE GOVERNOR Am INTRCEPT

,

VALVE 5 WENT CLOSED DURING TESTING. THIS EVENT WAS CAUSED ST AN OPERATOR OMITTING A TEST Mt0CIDURE

STEP.

,

SSF

Os/09/95 . LERs 33595005

50.72fs 29175

PWR HIST: COWITION EXISTED IN ALL MODES UP TC 100Y. POWER SINCE 1994

)

GROUP

SAFETT AND RELIEF VALVES GROUP

I

SYSTEM ' AEACTOR COOLANT ST5 TEM

CESC

a THE POWER OPERATED RELIEF VALVES WERE FOUND IN0PERA5LE DURING TESTING. THE MAIN DISC GUIDES WERE

INSTALLED INCORRECTLT DURING THE 1994 REFUELING OUTAGE.

,

SSF

os/10/95

LERs 33595006 50.72#:

'

PWR HIST EVUT CCCURRED IN COLD SHUTDOWN

<

GROUP : RESIDUAL HEAT REMOVAL ST5TEMS GROUP

1

STITEM , RESIDUAL HEAT REMOVAL SYSTEM

SOTN TRAINS OF RESIDUAL HEAT REMOVAL WERE RENDERED INOPERABLE AS A RESULT OF A FAILED GPEN SUCTION

CEsc

RELIEF VALVE. THE ROOT CAUSE WAS INADEOUATE DESIGN MARGIN SETWEEN THE RELIEF AND SLinEMnal SETPotNT

'

AS NORMAL SYSTEM OPERATING PRE 55URE.

'

PI EVENTS FOR 95-4

NONE

,

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_____ _ _ _ ___ _

_ _

_ _ _ _ _ _ _ . _ _ . . . _

,

L

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ST. LUCIE 2

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L.e.ne: s==cei sw-

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ST. LUCIE 2

.

PI EVENTS FOR 95-1

SCRAM c2/21/95

LER# 38995002 50.72#: 28416

PWR HIST POWER OPERAT!DNS AT 1001

DESC

A REACTOR TRIP RESULTED FROM A LOW STEAM GENERATOR LEVEL AFTER A STEAM GENERATOR LEVEL INSTR

FAILED HIGH, CAUSING THE FEED REGULATING VALVE TO CLOSE.

i

PI EVENTS FOR 95-2

NOME

PI EVENTS FOR 95-3

f

NONE

PI EVENTS FOR 95-4

SSF

11/20/95

LERs 3a995005 50.72#: 29626

PWR HIST: CmeITION EXISTED FOR AM INDETERMINATE PERICD OF TIME

Group

EDERGENCY AC/DC polar STSTEMS GRGJP

E7ERGENCY ONSITE PoiER SUPPLT SYSTEM

STSTEM : DEGRADED RELAT 5002T CONNECTIONS CAUSED THE FAILURE OF ONE EDG, AND THE POTENTIAL FAILURE OF THE

DESC

OTHER. VIBRAfl0N INDUCED F ATIGUE CAUSED THE SOCKET CONNECTION DELRADATION.

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.

ST LUCIE MAJOR ASSESSMENTS -

l

DATE

TYPE OF ASSESSMENT

l

i

JULY 1995

INPO ASSESSMENT - CATEGORY 1

AUGUST 1995

DR. CHOU ANALYSIS BY REGION II TO IDENTIFY ROOT CAUSES OF THE RECENT DECLINE IN

.

PERFORMANCE AND MULTIPLE EVENTS

,

i

The team concluded that the predominant root cause for the events observed at St Lucie

!

was insufficient detail and scope in site programs and procedures. This causal factor

was found to result in recent events which demonstrated deficiencies in the following

i

areas:

7

!

job skills, work practices, and decision making;

.

interface among organizations as evidenced by a lack of interface formality;.

.

organizational authority for program implementation as evidenced by instances

. .

,

!

of unclear responsibility and accountability.

l

AUGUST 1995

LICENSEE SELF-ASSESSMENT: A SPECIAL TEAM PERFORMED AN ASSESSMENT OF OPERATIONAL PROBLEMS

l

AND IDENTIFIED ROOT CAUSES: MANAGEMENT AND STAFF COMPLACENCY - POOR PERFORMANCE,

i

'

ACCEPTING LONGSTANDING EQUIPMENT PROBLEMS, AND NOT KEEPING UP WITH INDUSTRY IMPROVEMENTS.

-t

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- .

--

-

- -

-

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.- .

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-

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p2M4

UNITED STATES

NUCLEAR REGULATORY COMMISSION

l

$

REGloN 11

i

o

101 MARIETTA STREET. N.W., SUITE 2900

k _

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7.

ATLANTA. GEORGIA 3GI234199

l

March 27, 1996

%..

Florida Power and Light Company

ATTN: Mr. T. F. Plunkett

'

President - Nuclear Division

P. O. Box 14000

'

Juno Beach, FL 33408-0420

.

SUBJECT:

PLANT PERFORMANCE REVIEW (PPR) - ST. LUCIE 1 AND 2

Dear Mr. Plunkett:

On February 28, 1996, the regional staff completed the semiannual Plant

Performance Review (PPR) of St. Lucie Unit 1 and Unit 2.

The staff conducts

these reviews for all operating nuclear power plants to develop an integrated

understanding of safety performance. The results are used by regional

,

management to facilitate planning and allocation of inspection resources. The

PPR for St. Lucie involved the participation of all technical divisions in

evaluating inspection results and safety performance information for the

period September 1995 through February 1996.

PPRs provide regional management

with a current summary of licensee performance and serve as inputs to the NRC

Systematic Assessment of Licensee Performance (SALP) and senior management

meeting (SMM) reviews.

l

This letter advises you of otr planned inspection effort resulting from the

St. Lucie PPR review.

It is provided to minimize the resource impact on your

staff and to allow for' scheduling conflicts and personnel availability to be

i

resolved in advance of inspector arrival onsite.

The enclosure details our

inspection plan for the next six (6) months. The rationale or basis for each

inspection outside the core inspection program is provided so that you are

aware of the reasons for emphasis in these program areas.

Resident

inspections are not listed due to their ongoing and continuous nature.

During each NRC inspection planned during this period, specific attention will

be given to the verification of selected UFSAR commitments. Applicable

portion (s) of the UFSAR that relate to the inspection activities will be

reviewed and verification made that the UFSAR commitments have been properly

implemented into plant practices, procedures and/or parameters.

The goal is

to determine the accuracy of the UFSAR regarding existing plant practices and

conditions by providing specific attention to the UFSAR when performing

various reactor inspections.

Inspectors will not be judging the overall

completeness of the UFSAR; rather, the inspections will focus on identifying

differences between the UFSAR description and the plant.

,

.

A

9705190225 970512

FOIA

BINDER 96-485