Text

Insp Rept 50-443/93-16 on 930727-0828.No Violations Noted. Major Areas Inspected:Operations,Maint,Engineering & Plant Support
	ML20057C258
Person / Time
Site:	Seabrook
Issue date:	09/10/1993
From:	Rogge J; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:	;
Shared Package
ML20057C254	List: IR 05000443/1993016; ML20057C253;
References
	50-443-93-16, NUDOCS 9309280137
	Download: ML20057C258 (50)
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U. S. NUCLEAR REGULATORY COMMISSION

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REGION I

Report No:

93-16 Docket No.:

50-443 License No.:

NPF-86 Licensee:

North Atlantic Energy Service Corporation Post Office Box 300 Seabrook, New Hampshire 03874 Facility:

Seabrook Station Dates:

July 27 - August 28,1993

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Inspectors:

Noel Dudley, Senior Resident Inspector

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Richard Laura, Resident Inspector Robert DeLaEspriella Reactor Engineer VM 9'//OM3 Approved By:

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hfi F. Rogge, Chief VV

bate v/${cactor Projects Section 4B, DRP i

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Inspection Summary: This inspection report documents the safety inspections conducted i

during day shift and back shift hours. The inspections assessed station performance in the l

areas of operations, maintenance, engineering, and plant support.

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Results: North Atlantic operated the facility safely. No violations were identified. See the

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executive summary for the assessment oflicensee performance.

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EXECUTIVE SUMMARY SEABROOK STATION NRC INSPECTION REPORT NO. 50-443/93-16

.Qperations: Operators responded correctly to a reactor trip. The post trip review was thorough and operators completed the necessary corrective actions before restart. The trip may have been avoided if the surveillance procedure had been consistent with the vendor manual. Changes to the tagging procedure provided additional guidance for using check valves as work boundaries. Attention is needed in the area of procedural reviews, based on the potential for enhancing pmcedure quality and on the difficulty in meeting self-imposed due dates. Staffing initiatives demonstrated an outstanding safety perspective. Plant

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management developed a thorough strike contingency plan and effectively carried out the initial phases of the plan.

Maintenance: Troubleshooting activities to identify the cause of the reactor trip were successful. I&C technicians performed well and used good procedural adherence. However,

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inappropriate use of a surveillance procedure caused an inadvertent feedwater isolation.

Maintenance was well planned and completed by knowledgeable technicians with direct involvement by technical support engineers. Surveillance tests were performed properly with good coordination between departments.

Encineering: The technical support department's additional trending and evaluation effectively addressed the safety significance of containment temperature increasing above the

alert limit. The revised corrective action program provided an improved process for identifying potential unreviewed safety questions.

Station management was aware of the need to reduce the number of plant trips and are j

developing long term programs to reduce single component failures and surveillances that

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could cause plant trips. However, limited program guidance existed for operators and maintenance supervisors on how to manage trip avoidance procedures.

Plant Support: The plant staff maintained the plant in good condition. A chemist, who sampled the reactor coolant system, was well trained and professional. The security department continued to upgrade equipment and to conduct training. The emergency

- preparedness procedure revisions made in response to lessons learned from hurricane Andrew reflected a proper safety perspective. The employee allegation resolution program provided detailed and thorough reviews of all concerns, and has been effective in resolving the concerns of employees and in answering the concerns of others.

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TABLE OT'

NTENTS

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EXECUTIVE SUMMARY......................................ii

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TABLE OF CONTENTS.......................................iii

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1.0 OPERATIONS (71707, 92700, 92701, 93702)...................... 1 1.1 Plant Activities..................................... 1 1.2 Routine Plant Operations............................... I 1.3 Automatic Reactor Trip

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1.4 Staffing

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1.5 Strike Preparation

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1.6 Check Valves Used as Boundary Isolation: Unresolved Item URI

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93-08-01 (Closed)

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1.7 Procedural Weaknesses: Unresolved Item URI 92-80-05 (Open)

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2.0 MAINTENANCE (61726, 62703,92701)........

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2.1 M ain tenan ce....................................... 5 2.2 S u rveillan ce....................................... 7 3.0 ENGINEERING (71707,92702)

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3.1 Containment Temperature

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3.2 Reactor Trip Rate................................... 8

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3.3 Tornado Doors: Violation VIO 93-05-01 (Closed)................ 9

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4.0 PLANT SUPPORT (71707)....

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4.1 Radiological Controls................................

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4.2 Emergency Preparedness..............................

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4.3 Sec u ri ty........................................

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4.4 C hem i stry.......................................

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4.5 Housekeeping.....................................

5.0 EMPLOYEE CONCERNS PROGRAM: TI2500-028 (2500/028)..........

6.0 M EETI N G S (30702).....................................

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DETAILS 1.0 OPERATIONS (71707, 92700, 92701, 93702)

1.1 Plant Activities At the beginning of the period, the reactor was at 100% power. On July 27, the reactor automatically tripped due to spurious actuation signals while testing the reactor protective system. The electrical leads attached to the back of a test push button, shorted the test circuitry to ground and caused the spurious trip actuation signals. The operators brought the i

reactor critical on July 30, and reached full power on August 1.

l 1.2 Routine Plant Operations The inspector ceducted daily control room tours, observed shift turnovers, attended the morning station maneger's meeting, and monitored plan +f-the-day meetings. The inspector j

reviewed plant staffing, safety system valve lineups, and compliance with technical i

specification requirements. The inspector verified the adequacy of tagging orders and l

verified the integrity of the containment and the containment enclosure building. The

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inspector conducted tours of the primary auxiliary building, the emergency 4.esel generator rooms, the residual heat removal vaults, the turbine building, the condennte storage tank building, and the service water pump house. During the tours and atteniauce at various

meetings, the inspector noted good performance by the operations staff.

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Operators responded to the malfunction of vital inverter IF. The inverter spuriously l

swapped from its normal power supply to its maintenance back-up power supply. Operators j

declared the inverter inoperable, and entered a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> shutdown action statement listed in

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Technical Specification 3.8.3.1, "Onsite Povcer Distribution." Electricians identified and I

replaced a faulty driver logic card. The operators identified and corrected an error on the posted operator aids for restoring the inverter to the normal power supply. The operators

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properly restored inverter IF to service and exited the technical specification action

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statement. The inspector noted that the main control room unit journal contained a good narrative of the event. The inspector assessed that the plant staff demonstrated good l

teamwork in assessing and resolving the failure mode of inverter IF.

While filling demineralized water storage tank TK-109, the operators overflowed the tank t

spilling a few hundred gallons of demineralized water on the ground. The tank high 1cvel

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alarm did not actuate. Operators contacted health physics personnel who verified the water

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was not radioactive. The inspector observed the operating crew discussion of the event. The crew thoroughly analyzed how the event may have been avoided. The operators initially

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trended the tank water level, but later removed the trend graph from the video screen.

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Rather than focusing on the failure of the high level alarm, the crew identified potential areas for improvement. The inspector assessed that the operating crew objectively evaluated the i

event and were self-critical.

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1.3 Automatic Reactor Trip During the conduct of a solid state riotection system (SSPS) Surveillance Test IX1680.921, l

"SSPS Train A Actuation Logic Testin( on July 27,1993, an automatic reactor trip occurred. The first-out anmmaator indcated that a steam line low pressure safety injection

caused the reactor trip. The operators followed the emergency operating procedures, I

determined that a safety injection had not occurred, and stabilized plant conditions. The

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l primary plant equipment responded as designed to the reactor trip. Operators made the appropriate NRC notification. North Atlantic made a 10 CFR 50.72 notification reporting two inadvertent feedwater isolation actuations. Later, North Atlantic retracted the i

notification indicating that the actuations were invalid and not reportable. The inspector verified that North Atlantic's interpretation of the reporting criteria was proper.

North Atlantic initiated an event evaluation that included a post trip review. The inspector attended several event evaluation team meetings; interviewed operators; and reviewed the human performance evaluation system review, root cause analysis review, and the event evaluation team report. The maintenance staff determined that the reactor trip resulted from

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a faulty lamp test push button. The maintenance troubleshooting activities are discussed in further detail in Section 2.1 of this report.~ The event evaluation team identified six wrrective actions required before plant restart and eleven long term corrective actions. The inspector determined that North Atlantic completed a thorough post trip review.

The SSPS test panel lamp checks were performed before the trip bypass breaker was closed.

If the bypass breaker had been closed, the reactor trip may not have occurred. The SSPS vendor manual has the bypass breaker sequenced to be closed before performance of the lamp checks. North Atlantic indicated that the lamp checks had not been viewed as a trip hazard activity and had been perfoimed before the bypass breaker was shut to minimize the time the bypass breaker was shut. Technical specifications allow the bypass breaker to be shut for up to two hours for SSPS testing. North Atlantic revised Procedure IX 1680.921 to conform with the vendor manual.

North Atlantic completed a thorough post trip review and completed the necessary corrective actions before restart. The reactor trip occurred due to an equipment failure. The inspector assessed that the operators placed the plant in a safe condition by properly using the emergency operating procedures. The inspector noted that the reactor trip may have been avoided if the surveillance test procedure had been consistent with the vendor manua.

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1.4 Starring l

The inspector reviewed operating shift composition and staffing initiatives. Each operating l

shift consists of five licensed operators. Three of the operating shifts have three senior

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reactor operators (SROs) while the other three shifts have four SROs. North Atlantic has four reactor operators in an upgrade program with the intent to staff on all shifts with four SROs. Technical specifications require two SROs per shift. Each shift also has full time i

fire protection and maintenance personnel assigned. North Atlantic has recently sponsored l

three SROs to get college degrees. The additional SROs on each shift greatly reduce the l

burden of paperwork and other distractions from the operators at the controls. The inspector j

concluded that these staffing initiatives demonstrate an outstanding safety perspective.

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l.5 Strike Preparation

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Approximately 225 plant workers voted to ?..n a union in September 1992. N)rth Atlantic

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management and members of the utility workers Union of America began negotiating a contract in January 1993. Union officials threatened to strike unless a written contract was ratified by August 6,1993. Station management had developed a strike contingency plan and

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began parallel watch standing for operations maintenance, chemistry, and health physics personnel on August 4 and 5.

The inspector and a regional operations specialist reviewed the strike contingency plan. The inspector observed that plant workers and managers exhibited a professional demeanor during i

I the parallel watches. Plant management presented union officials with a written contract.

On August 6, union workers ratified the contract and station management ended the parallel watches.

The inspector assessed that plant management developed a thorough strike contingency plan and effectively implemented the initial phases of the plan.

1.6 Check Valves Used as Work Boundaries: Unresolved Item URI 93-08-01 (Closed)

During the conduct of maintenance on condensate storage tank fill valve DM-517, the inspector expressed concern regarding the use of check valves as work boundary isolation i

valves. Maintenance Procedure MA 4.2, " Equipment Tagging and Isolation," Section 4.2.1,

" Danger Tags," Item 11 specified that check valves shall not be used as boundary isolation valves. However, Step 3.0 in MA 4.2 allowed deviation from any procedural requirement with shift superintendent approval. The shift superintendent approved the use of check valves on the tagging order for DM-517.

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i The inspector discussed the issue with several operators and the operations department manager. The manager indicated the use of check valves as boundary isolation valves is rare and is only used when there is no alternative. The inspector reviewed pertinent regulatory

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and industry guidance documents, which indicated that use of check valves as boundary isolation valves is discouraged but not prohibited.

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North Atlantic revised MA 4.2 to provide more guidance on the use of check valves.

Item 11 was changed to state " Check valves should not be used as boundary isolation alves

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unless it is the only viable method of effecting the isolation. A tell-tale drain and a vent inside the isolation boundaries should be open. Shift superintendent's permission and

signature must be obtained on the tagging order when check valves are used. If an external gagging mechanism is available on the check valve, it should be used as part of the isolation." The statement in Step 3.0, which allowed deviation from any procedural requirement with shift superintendent's permission, was deleted. The inspector assessed that

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the procedure change provided increased guidance concerning the use of check valves. This

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unresolved item is closed.

1.7 Procedural Weaknesses: Unresolved Itea URI 92-80-05 (Open)

An NRC team inspection conducted between July 20 a.nd August 21,1992, identified several procedural weaknesses and deficiencies after reviewing & small sample of operating and alarm response procedures. The team documented the wednesses in NRC Inspection Report No. 50-443/92-80 as an unresolved item. The inspector interviewed operations personnel, procedure writers and managers, reviewed applicable instructions and procedures, and conducted walkdowns of systems.

One aspect of the unresolved item involved weaknesses in opmting procedures that did not provide adequate guidance for the loss of a train of primary component cooling water (PCCW) or residual heat removal (RHR) during shutdown conditions. The completion of the procedural enhancements is tracking under ICTS action #RE03969G. The plant management has extended the action item completion date twice. Therefore, the procedure weaknesses in Operating Procedures OS1212.01, OS1213.01, and OS1213.02 remain unresolved.

The inspector determined that although weaknesses exist in the operational procedures,

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management, the probability risk assessment organization, and the training department have adequately conveyed the importance ofloss of decay heat removal during shutdown conditions. The licensee continued to pursue the resolution of these procedure weaknesses, with corrective actions scheduled for completion before the next refueling outage.

Another aspect of the unresolved item involved several discrepancies and procedure weaknesses in alarm response guidelines for the video alarm system (VAS) and the hardwired annunciator system. These issues were listed in Attachment 1 of NRC Inspection Report No.

50-443/92-80. The inspector reviewed licensee corrective actions for each issue, and determined that licensee responses were adequate. The licensee is in the first of a three year I

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intemal review of VAS alarm procedures. The operations procedure writer reviewed all of

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the approximately 2500 VAS alarms and identified 200 procedures that involve safety systems used during refueling. The operations support staff plans to review the 200 procedure before January 1994. This aspect of the unresolved item is closed During reviews of procedures of Station Operating Procedures OS1000.12, OS1001.05, OS1090.05, ON1090.06, and ONICO.07, the inspector found examples of notes and

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cautions that required action by the implementor. Procedure SM 6.2, " Station Operating Procedures," Section 4.1.3.6 specifies that "a note or caution shall not contain a statement that requires an action." Steps important to the safe operation of the plant may be hidden in I

a note or a caution, and overlooked by the implementor. The inspector discussed the finding with operations management and procedure writers. Since 1989, procedure writers have been screening plant procedures during the periodic reviews. However, Procedures OS1090.05 and OS1001.05, which have been reviewed, still contained notes that required

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actions.

The findings identified in this report and in previous inspection reports, indicate possible

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generic enhancements that can be made to Seabrook procedures. The inspector believes that although individually the procedure deficiencies may not pose a challenge to the safe

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operation of the plant, improvements can be made in the quality of the operating procedures.

l The enhancements to procedures for shutdown / fueling conditions are not needed for power operations, but the due dates for revising the procedures were postponed twice. The inspector concluded that attention is needed in the area of procedure reviews based on the potential for enhancing procedure quality and on the difficulty in meeting self-imposed due

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dates.

'l 2.0 M AINTENANCE (61726, 62703, 92701)

2.1 Maintenance The inspector attended morning planning meeting held by the different maintenance i

departments, and reviewed the following work request packages or observed the maintenance activities:

93WR2425 Replacement of diaphragms in containment atmosphere radiation monitoring sample pumps

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93WR2414 Scobie line outage RM1739602 Five year preventive maintenance on the motor driven emergency feedwater i

pump ampere meters

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93WR2324 Troubleshoot cause of reactor trip t

Troubleshooting and repair of the service water loop 'A' flow indicator to the diesel generator heat exchange, SW-FIS-615 Post maintenance stroke testing of the 'C' atmospheric steam dump valve The inspector reviewed the twelve pages of guidance provided in 93WR2324 and assessed i

that the system engineer provided high quality guidance to the I&C technicians. I&C technicians controlled configuration changes according to Maintenance Procedure MA4.5,

" Configuration Control." During the conduct of work, the system engineer made four work

request scope changes.

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Two inadvertent feedwater (FW) isolations occurred when operators closed the reactor trip l

breakers to support the troubleshooting. The first FW isolation occurred due to a procedural

inadequacy. Procedure IX1680.921 did not provide instructions for verifying whether active solid state protection system (SSPS) trips existed before closing the trip breakers. Since the

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power range negative rate trip bistables were not reset a FW actuation signal was generated i

when the operators shut the reactor trip breakers. The operators missed an opportunity to

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clear the negative rate trip signal before shutting the trip breakers. The second FW isolation

resulted from an equipment deficiency. Maintenance technicians identified that bounce of the _

auxiliary contact located within the 'B' trip breaker caused the isolation.

North Atlantic determined that a faulty lamp test push button caused the reactor trip. A short in the push button overloaded a test circuit driver card transistor. The failed transistor j

caused the 48 VDC power supply to the 'A' trip breaker under-voltage coil to drop out, which opened the reactor trip breaker. The I&C technicians replaced the lamp test push button and the test circuit driver card. The techphians verified proper operation of the trip

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breakers and the 48 VDC power supplies. The technicians also replaced the auxiliary contact on the 'B' trip breaker. The system engineer and I&C supervisor provided oversight at the

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work site. The inspector determined that the I&C technicians performed well and used good procedural adherence. The inspector assessed that North Atlantic successfully identified the most probable cause of the reactor trip and implemented appropriate corrective actions.

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On August 3, the Scobie offsite electrical line tripped due to a short on the 'C' phase of the i

electrical line between the ring bus and the transmission yard. The electricians traced the short to a failed bushing in the SF. but duct and identified damage to the associated flash arrester. During repairs, the electricians noted that the end caps on the nine SF. ducts, that contained the flash arresters for the three offsite electrical lines, were secured by either bolts or welds. No procedure existed for disassembling the end caps. The electricians initiated an

operational information report to resolve the issue.

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System engineers noted that a high generator temperature condition existed before the line failure and initiated a request for engineering services to investigate the possible cause and effect relationship.

The inspector noted no other problems with the performance or documentation of maintenance activities. The inspector concluded that maintenance was well planned and completed by knowledgeable technicians with direct support of technical support engineers.

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2.2 Surveillance The inspector observed portions of the following surveillance or special tests.

LX0556.04 Station Battery Service Test (18-month load test)

OX1456.48 Train B ESFAS Slave Relay K610 Quarterly Go Test OS1426.12 DG A and B weekly surveillance IX1660.718 R-6526 Containment Atmosphere Radiation Monitor Calibration

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IX1680.921 Solid State Protection System (SSPS) Train A Actuation Logic Test

The inspector noted good coordination between departments and concluded the surveillances were properly performed.

3.0 ENGINEERING (71707,92702)

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3.1 Containment Temperature

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Containment temperature has been above the plant computer warning limit of 115 F since the end of the refueling outage. Operators reduced the containment temperature in June to

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about 116 F. The inspector reviewed technical specification shift logs beginning in 1990, plotted containment temperatures, and studied the updated final safety report and system

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descriptions. The inspector held discussions with technical support and operations engineers.

f Containment temperature is a single point calculated by the computer. The calculated

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temperature is the average of temperatures from four levels of the containment. The temperature at cach level is an average of from three to five temperature detectors. The

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containment is cooled by the non-safety related containment structure cooling subsystem.

The subsystem is comprised of six fan coolers, only five of which are normally operating.

Three of the six fans have 2 speed motor 3, designed to operate at one-half normal speed during special testing. The component cooling water (PCCW) flow to the fan coolers is constant. Containment temperature can be varied by changing the temperature of the PCCW system. The 'A' train PCCW system temperature is set at 85"F to prevent overcooling of the reactor coolant in the chemical volume control system, which affects core reactivity. The

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'B' train PCCW system temperature is set at 75 F. Workers recently verified the cleanliness i

of the cooling coils of the fan coolers, because the filter had been removed from the units.

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Chemists monitor the PCCW water for the concentration of hydrazine, which is used to j

inhibit corrosion.

Technical Specification 3.6.1.5, " Primary Containment Air Temperature," requires

containment temperature be maintaimd below 120 F, and worse case design calculations indicate that containment temperate should remain below 118 F during normal operations.

The inspector graphed containmem i.emperatures over the last three years and determined that containment temperature appears to have increased about one degree per year. On

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June 27,1992, the containment temperature reached 118.2 F. Technical support engineers i

trend containment temperatures, but have not seen an increasing trend.

The technical support engineers explained that the containment temperature data must be

normalized to PCCW temperature before it is plotted. When normalized, the containment

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temperature data did not show an increasing trend. The inspector questioned whether or not l

the 115 F computer warning setpoint should be increased since containment temperature is

normally between 115 F and 120*F. The technical support engineers began an evaluation to i

review changing the setpoint. The inspector determined that the technical specification containment temperature limit of 120 F had not been exceeded. The inspector assessed that i

the technical support staff had been trending containment temperature and were sensitive to

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not exceeding the technical specification limit.

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3.2 Reactor Trip Rate

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The inspector reviewed the seven reactor trips that occurred during the last year to identify

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any common causes. Three reactor trips occurred during the conduct of surveillance testing.

Two trips resulted from operator errors made when operating the feed water system. The causes of two reactor trips appeared to be random in nature. The plant has averaged one l

manual or automatic reactor trip every two months over the last year.

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The inspector met with members of the technical support staff to discuss the reactor trip rate.

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On August 10, 1993, the technical support staff reviewed the fourteen reactor trips that i

occurred since June of 1990. Nine of the trips were related to single component failure or

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performance of a trip avoidance activity. The remaining five reactor trips were random in l

nature. In May 1993, the technical support staffissued a charter for the development of a l

plant performance realization program. The program included gross electrical megawatt i

optimization management, a plant reliability maximization program (PRMP), and life cycle

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management. One goal of the program is to increase plant reliability by identifying and

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minimizing, where possible, single component failures. The system suppmt manager

indicated the PRMP is a long term program and should be fully implemented by

January 1997. The inspector assessed that although the development and implementation of i

the PRMP is a positive initiative to improve plant performance, the effects of the program may not be sensed for several years.

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The systems support manager indicated that any short term actions in the trip avoidance area would be implemented as soon as possible. This included developing guidance for trip i

avoidance activities, performing a review of reactor trips that occurred at similar vintage Westinghouse plants, and installing placards or boundaries around equipment bump hazards.

Longer term actions included the reduction in frequency of trip avoidance surveillance tests, the use of less intrusive SSPS testing equipment, and the modification of equipment.

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number of plant trips and are developing long term programs to reduce single component failures and surveillances that could cause plant trips. However, the inspector noted that limited guidance existed for operators and maintenance supervisors on how to manage trip avoidance procedures.

3.3 Tornado Doors: Violation VIO 93-05-01 (Closed)

North Atlantic operated for over sixteen months with an internally approved change to the updated final safety analysis report (UFSAR) without completing a 10 CFR 50.59 review to identify any potential unreviewed safety questions. North Atlantic's failure to document and

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report the change in the design basis tornado described in the UFSAR was a violation of 10 CFR 50.59. North Atlantic responded to the violation in a letter (NYN93076) to the -

NRC, dated May 24,1993.

The inspector reviewed North Atlantic's response to the violation and the completed corrective actions. North. Atlantic determined that a safety evaluation was not timely, in part, due to the manager of engineering's confidence that an unreviewed safety question did not exist. His confidence was founded on the engineering department's informal evaluations,

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which utilized existing industry guidance. The manager of engineering postponed completing

the safety evaluation and updating the UFSAR until the design basis document was completed. However, completion of the design basis document was not timely.

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Additional factors included the failure to implement the corrective action program and an i

inadequate engineering department screening procedure. The engineering department revised Engineering Procedure 30070, " Engineering Self-Assessment Reports," and conducted training on the new procedure. The inspector assessed the new procedure and training sessions in NRC Inspection Report No. 50-443/93-08. North Atlantic reported the design

problems with the tornado doors, completed the engineering evaluations, and revised the UFSAR. The inspector assessed the short term corrective actions in NRC Inspection Report No. 50-443/93-05.

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After updating the UFSAR with the site specific design basis tornado, two doors did not meet-the reduced design basis for differential pressure. The inspector verified that North Atlantic

installed design changes that strengthened the two doors to withstand the design differential pressure. North Atlantic developed a revised corrective action program procedure and initiated the program on June 30,1993. The inspector assessed the conclusions and recommendations of the task force that developed the revised procedure in NRC Inspection Report No. 50-443/93-10.

The inspector reviewed the report of a regulatory compliance team meeting that was issued on August 19, 1993. A team reviewed a large random sample of engineering activities and identified fourteen documents that contained evaluations or designs changes of plant components that describe plant conditions that may be reportable. The regulatory compliance group plans to review the fourteen documents for reportability in accordance with the North

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Atlantic reporting manual. The team also identified two engineering evaluations that indicated potential programmatic problems.

Engineering evaluated the results of the nuclear safety audit review ' committee's engineering / licensing subcomm3ttee's reviews of unreviewed safety questions to determine if any specific trends existed. Engineering identified in a letter to the Executive Director of Engineering and Licensing the following areas that require follow-up by engineering management:

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ensure the engineering organization is providing the necessary details to support 10 CFR 50.59 evaluations

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ensure design issues are addressed or reported in a timely and effective way

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review the use of engineering judgements in 10 CFR 50.59 evaluations review the UFSAR change process for possible weaknesses The inspector concluded that the corrective action program changes provided an improved process fer identifying potential unreviewed safety questions and that the engineering department's sensitivity to assessing the need for 10 CFR 50.59 reviews of engineering documents was heightened. This violation is closed.

4.0 PLANT SUPPORT (71707)

4.1 Radiological Controls During routine plant tours, the inspector verified postings of radiation and contaminated

areas, calibration of radiological monitoring equipment, locked high radiation area doors, and i

radiation work permits. The inspector observed the removal and decontamination of the 1:tdown radiation monitor flow switch that initially read 30 millisievents (mSv) [3000 mrem]

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i on contact. A health physics (HP) technician surveyed the area initially and closely

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monitored the worker and work area during removal of the flow switch. Radioactive waste l

utility workers wore double anti-contamination clothing and respirators while decontaminating the flow switch in a sealed tent. The flow switch radiation levels read 7 j

mSv [700 mrem] after decontamination. The inspector concluded that HP technicians

carefully evaluated, planned, and monitored the removal and decontamination of the flow i

switch.

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4.2 Emergency Preparedness

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The inspector reviewed Revision 2 to Procedure SS92100, " Post Event Reviews and Evaluations," that was issued in July 1993. The revision added Figure 1, which provided

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guidance for assessing the ability to impicment the radiological emergency response plan

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following a man-made or natural disaster. Figure 2 provided information for assessing

personnel resources, facilities, communications, accident assessment, protective measures,

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and public information. The revision also added a figure, which provided guidance for assessing the capability of the State of New Hampshire and the Commonwealth of Massachusetts to protect the health and safety of the public living in the emergency planning zone following a man-made or natural disaster. The inspector concluded that Revision 2 provided detailed guidance for assessing the ability to implement the emergency response

plan following a disaster and to protect the public.

The inspector held a discussion'with the emergency preparedness (EP) manager concerning the lessons learned by Turkey Point in dealing with hurricane Andrew. The EP manager

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indicated that the EP staff has a review in progress to review the EP aspects of the lessons learned. In a rnemo, dated April 5,1993, the EP staff identified several areas that warranted

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further study. North Atlantic revised Procedure 11800, " Hazardous Condition Response Plan," to provide guidance for capturing the event on video, considering the use of the

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Department of Energy communications equipment, securing any radioactive sources, and considering employee concerns.

In summary, the EP staff made changes, as appropriate, to enhance the guidance for dealing with natural and man-made disasters. The inspector assessed that the procedure revision reflected a proper safety perspective.

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4.3 Security

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The inspector toured the protected area, observed security guards on patrol, and monitored activities in the control alarm station (CAS). The CAS operators now prepare their operating logs on a computer instead of a typewriter. Hard informational copies of logs are no longer retained in the CAS since the logs are on computer disks. The inspector observed a security

.

i

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i

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l shift supervisor conducting unannounced response drills. During a walkdown of the fence i

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line at night, the inspector determined that station lighting was good. The inspector concluded that the security department continued to upgrade equipment and to conduct training.

4.4 Chemistry The inspector observed a chemist collect a reactor coolant system primary sample at the sample sink, and discussed the procedure with the chemist. The chemist was knowledgeable of the effects of the various sampling valve lineups and the expected response of the flow gage. The chemist followed proper radiological checks and contamination control techniques while handing the primary coolant samples. The inspector concluded that the chemist was well trained and professional.

4.5 IIousekeeping

,

The inspector observed that the plant staff maintained the plant in a good condition. The j

inspector identified that primary component cooling water relief valve CC-V-42 was leaking-by. Although the valve discharge flange had a clear poly bag taped around it, no

,

maintenance deficiency tag was hanging. The inspector informed a regulatory compliance engineer that valve CC-V-42 had not been entered in the work control program.

5.0 EMPLOYEE CONCERNS PROGRAM: TI2500-028 (2500/028)

The inspector reviewed the characteristics of North Atlantic's employee allegation referral (EAR) program by having the EAR program manager complete a questionnaire, which is provided as Attachment 1. The inspector discussed the completed questionnaire with the EAR program manager.

The EAR program has provided an alternate path for employees and concerned citizens to raise safety and non-safety concerns outside normal line management channels. The EAR program is run by the EAR program manager and his assistant. The EAR program manager assigns technical or management personnel to respond to employee concerns. In personnel matters, the EAR program manager functions as an arbitrator. After the first union contract was ratified on August 6,1993, union grievances were handled by a separate labor relations

'

program. The EAR program manager planned to continue to respond to personnel concerns.

Most employee safety concerns have been resolved by the EAR program. Individuals were encouraged to bring concerns to the NRC if they were not satisfied with the response by the EAR program. The inspector noted that the number of employee concerns has remained constant, while the number of concerns raised by contract workers and concerned citizens has fallen since the plant operating license was issued. Management fully supports the EAR

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program.

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The inspector concluded that the EAR program provided detailed and thorough reviews of all (

concerns, and has been effective in resolving the concerns of employees and in answering the i

concerns of others.

6.0 MEETINGS (30702)

,

Two resident inspectors were assigned to Seabrook Station throughout the period. The inspectors conducted backshift inspections on August 6 and 11, and deep backshift inspections on July 31, August 17, and 22.

Throughout the inspection, the inspecto s met with station management to discuss inspection

findings. At the conclusion of the inspection, the inspector met with the station manager and his staff to discuss the inspection findings and observations. The technical support manager

noted that containment temperature had been watched closely since the fan cooler filters were

removed and that the evaluation of normalizing containment temperatures to primary component cooling temperatures was in progress. The system support manager asked for clarification between trip avoidance and trip reduction assessments. No proprietary information was covered within the scope of the inspection. No written material regarding a

the inspection findings was given to the licensee.

i During the week of July 26, the deputy director for the Division of Radiation Safety i

Safeguards, the Division of Reactor Safety (DRS) operations branch chief, and the Division

of Reactor Projects (DRP) section chief responsible for Seabrook toured the site and attended inspection exit meetings.

On August 19, Commissioner Forrest Remick toured the site and met with North Atlantic managers and staff. Slides used by North Atlantic during the meeting are provided as i

Attachment 2.

-

On August 20, North Atlantic's senior vice president and chief nuclear officer and members of his staff met with the Regional Administrator and members of his staff at the Region 1

office in King of Prussia, Pennsylvania. North Atlantic discussed ti:e company's strategic

!

planning and cost competitiveness program, and plans for addressing personnel error and procedure adherence issues. Slides and handouts used by North Atlantic during the meeting are provided as Attachment 3.

On August 27, the division directors for DRP and DRS toured the plant and held discussions r

with North Atlantic managers.

Region based inspectors conducted the following exit meetings during this inspection period.

DATE SUBJECT REPORT NO.

INSPECTOR

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7-28 Operator Licensing 93-12 J. Prell 7-30 Security 93-15 R. Albert

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ATTACHMENT 1 EMPLOYEE CONCERNS PROGRAM

)

A.

PROGRAM:

1.

Does the licensee have an employee concerns program? Yes i

2.

Has NRC inspected the program?

Yes, NUREG 1425, Appendix 9, Section 18 B.

SCOPE:

1.

Is it for:

a.

Technical?

Yes b.

Administrative? Yes c.

Personnel issues? Yes 2.

Does it cover safety as well as non-safety issues? Yes 3.

Is it designed for:

a.

Nuclear safety? Yes b.

Personal safety? Yes c.

Personnel issues - including union grievances?

Comment: Any Seabrook Station employee, contracted service employee or member of the general public can walk in or call the Concerns Program office and discuss Seabrook Station concerns with the Concerns Program Manager. Resolution of union grievances is the responsibility of NAESCO management and Local 555 of the UWUA.

4.

Does the program apply to all licensee employees? Yes 5.

Contractors? Yes 6.

Does the licensee require its contractors and their subs to have a similar program?

No

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Attachment 1

7.

Does the licensee conduct an exit interview upon terminating employees asking if they have any safety concerns?

Yes. Since 1985 the employee concerns program initiated 10,930 face-to-face interviews and mailed out 8,032 forms to workers who terminated on off-shift or week. ends.

C.

INDEPENDENCE:

1.

What is the title of the person in charge?

Concerns Resolution Program Manager 2.

Who do they report to?

Director of Quality Programs 3.

Are they independent of line management? Yes 4.

Does the ECP use third party consultants? Yes 5.

IIow is a concern about a manager or vice president followed up?

'

.

As required to adequately resolve and document closure for the concern.

D.

RESOURCES:

1.

What is the size of the staff devoted to this program?

,

2 full-time employees, the Concerns Program Resolution Manager and an assistant 2.

What are ECP staff qualifications (technical training, interviewing

,

training, investigator training, other)?

<

The job description for the Concerns Resolution Program Manager requires a

,

minimum of:

'

Bachelor's Degree in engineering or equivalent education and/or experience.

i Eight to ten years of related or project management experience. Experience in i

an employee relations environment and/or department involved in nuclear l

safety is helpful.

l

.

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_

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j Attachment 1

-

E.

REFERRALS:

1.

Who has followup on concerns (ECP staff, line management, other)?

Concerns (allegations) that are substantiated and require corrective action become the responsibility of line management. Concerns then may be tracked through implementation (in accordance with North Atlantic Management

"

Manual Procedure 12700, " Corrective Action System.")

'

The Concerns Resolution Program Manager may conduct routine follow-up inquiries of program participants (submittees of concerns) to assess program short and long term effectiveness.

<

F.

CONFIDENTIALITY:

1.

Are the reports confidential?

Yes. All individuals submitting a concern will be afforded every opportunity to ensure confidentiality from individuals or organizations extemal to the Concerns Program. This confidentiality is intended to protect the identity of the persons whether or not confidentiality was requested.

2.

Who is the identity of the alleger made known to (senior management, ECP staff, line management, other)?

ECP staff and limited senior management with a need to know 3.

Can employees be:

a.

Anonymous?

Yes b.

Report by phone? Yes ( from anywhere in the USA by 800 line)

G.

FEEDIIACK:

i 1.

Is feedback given to the alleger upon completion of the followup?

!

Yes through a Concern Disposition Report (CDR)

2.

Does program reward good ideas?

All ideas are forwarded to responsible department heads.

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Attachment 1

3.

W at what level, makes the final decision of resolution?

The Loncerns Program Manager. The resolution to a concern could require

-

concurrence from the Director of Quality Programs or the Senior Vice

-

President and Chief Nuclear Officer.

,

4.

Are the resolutions of anonymous concerns disseminated?

A concern of significance was disseminated through the use of a periodic l

company publication.

l

'

5.

Are resolutions of valid concerns publicized (newsletter, bulletin board, all hands meeting, other)?

Not as a rule, but selectively. The concernee is sent a written Concern Disposition Report (CDR) that closes the concern. At this time, the individual may make a decision, such as: a) disagree with resolution and take other action such as going to the NRC and/or news media, b) agree with resolution, j

be pleased and end concern, or c) agree with resolution and decide to show the

!

CDR to fellow employees, possibly seeking recognition.

>

The Concerns Program continues to use all methods available to protect the f

concernee's identity. Wide distribution (publicizing) of concern resolutions

could affect the decision by other concerned individuals to come to the Concerns Program. The Concerns Program believes that most individuals will come forward only if they believe their identities will be protected from public disclosure.

.

II.

EFFECTIVENESS:

.

1.

Ilow does the licensee measure the effectiveness of the program?

!

Employee feedback obtained from:

- Exit Interviews

- Feedback during General Employee Training

- NRC (Concerns Program has never received a negative comment from the NRC related to effectiveness of the program)

- Followup information from users (during random surveys / interviews)

- Independent Review Team Review (1985)

- Employee Concerns Task Force Input (1991)

I

-

.-

Attachment 1

2.

Are concerns:

a.

Trended? Yes b.

Used?

,

i

.

Yes. This information is part of the written reports sent to the Director of Quality Programs and the Senior Vice President and Chief Nuclear Officer.

l l

3.

In the last three years how many concerns were raised?

i At Seabrook Station, Nuclear Quality or Safety concerns that could affect the safe operation of the plant (technical), are separated from employee issues of a personal or administrative nature (personnel).

l Technical Concerns: 40 received in the last three years.

Personnel Issues: 116 formal issues representing 262 individuals, since some

'

issues were submitted with multiple signatures.

l Of the concerns raised, how many were closed?

l

!

37 technical concerns were closed (1 is open to accommodate NRC followup l

and the other 2 require a written report to file to close).

{

There is one open personnel issue from the 3 years 90,91, and 92. The issue,

,

from 12 employees, relates to wages and job description. Closure delay was i

due to management limitation (by law) during union contract negotiations.

What percentage were substantiated?

I 17.5% of the technical concerns were substantiated.

7 concerns were substantiated of the 40 (1 of the 7 was categorized as safety-i related/ quality).

4.

Ilow are followup techniques used to measure effectiveness (random survey, interviews, other)?

See H, number a

.

Attachment 1

5.

Ilow frequently are internal audits of the ECP conducted and by whom?

Last audit was by the independent Review Team in 1985.

I.

ADMINISTRATION / TRAINING:

1.

Is ECP prescribed by a procedure? Yes Procedure #16421 - Employee Concerns Program (formally the Employee Allegation Resolution Program (EAR)). This procedure is supported by an

'

internal operating procedure that has been provided to the Resident NRC Inspector.

Procedure #16420 - Employee Issues Program 2.

Ilow are employees, as well as contractors, made aware of this program (training, newsletter, bulletin board, other)?

- New employee training (orientation)

- General Employee Training, including Yearly Requalification

- Employee Handbook

- Outage Handbook, used by Contractors

- Signs at key location (high traffic locations)

- Official site and office bulletin boards

- Te.rminating employees, including contractors, are given an exit interview

- Newsletter i

ADDITIONAL COMMENTS:

The Concerns Program and the issues Program are fully supported by North Atlantic executive management and line managers.

In addition to the concerns raised through the formal employee concerns program, presented in the answer to question 3, the following concerns were also addressed.

255 concerns were addressed in Enclosure 3 to NYN-90020, " Response to Employee

Legal Project's Allegations."

12 concerns were addressed in Enclosure 1 to NYN-90020, " Control Room Radio Communications Allegation."

3 concerns were addressed in Enclosure 2 to NYN-90020, " Control Room Radio i

Communications: Additional Allegation."

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f

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Attachment 1

The Employee Concerns Program Manager is eligible to be tasked with allegations

related project management responsibilities. For example, he coordinated Seabrook Station activities related to the NRC documentation requests initiated by Congress such as process sheets, radiographic reports, weld repair orders, and non-conformance reports. This resulted in the search and review of thousands of

.

documents and their duplication, which were then provided to the NRC.

He supported the NRC Senior Resident Inspection - Construction regarding weld

allegation issues. This support consisted of research, coordination, being a point of contact on hundreds of requests for supporting documentation, by the NRC, as a result of congressional inquiry.

As an organization NAESCO promotes the Employee Concerns Program as a place

where employees may choose to informally express their concerns. These undocumented employee concerns are addressed privately. The resolution to these issues / concerns may be a simple referral to the Employee Assistance Program (EAP), Security, Employee Relations and/or the employee's supervisor. The employees are also encouraged to use the program as a sounding board. Many times they do not want the program to take any action at all. They just want the program to be there to listen and express an interest in their problems.

NAME:

William J. Gagnon TITLE:

Concerns Program Manager PHONE #:

(603) 474-9521, Ext. 2458 DATE COMPLETED:

August 13, 1993 i

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SEABROOK JOI N T OWN ERS

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North Atlantic Energy Corporation 35.6 %

creat Bay

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12.1 %

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Massachusetts

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liluminat.ing Connecticut Power Co.

17.5%

Light & Power o

4.0%

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f NORTH ATLANTIC ENERGY SERVICE CORPORATION EXECUTIVE VICE PRESIDENT

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ENGINEERi~NG/

SUPPORT kERVICES PRODUCTION LICENSING

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G. R. Gram B. L. Drawbridge

R. l. DeLoach Emergency station Operations

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Seabrook Station CAPACITY FACTOR SUMMARY DATA

L

Cycle 1 through 7/25/91 84.8 %

Cycle 2 through 9/7/92 97.1 %

Cycle 3 through 7/19/93 91.3 %

8/19/90- 7/19/93 Lifetime *

78.0 %

Lifetime excluding refueling outage (through 7/19/93)

91.0% -

Initiated regular full power operation 8/19/90 l

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ATIAQfENT 3

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MEETING BETWEEN U.S. NUCLEAR REGULATORY COMMISSION

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REGION I-KING OF PRUSSIA, PA AND

NORTH ATLANTIC ENERGY SERVICE CORPORATION August 20,1993

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t SEABROOK BACKGROUND

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1150 MW WESTINGHOUSE PWR

=

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3rd CYCLE OF OPERATION

.

REFUELING OUTAGE #3 SCHEDULED SPRING 1994

.

CAPACITY FACTORS:

CYCLE 91.0 %

.

-

.j 1993 (YTD) -- 93.6 %

LIFETIME 78.3%

--

MERGED WITH NU - JUNE 1992 I

.

i FIRST UNION CONTRACT RATIFIED - AUGUST 1993 (225 PEOPLE)

.

EMERGENCY PREPAREDNESS NORMALIZATION - DECEMBER 1992

.

,

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1993 O&M BUDGET - $126 MILLION (NON-REFUELING YEAR)

.

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1993 CAPITAL IMPROVEMENT BUDGET: $19,217,000 i

.

.f STAFFING:

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943 - NORTH ATLANTIC

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99 - GREEN MOUNTAIN SECURITY 19 - OTHER CONTRACTORS (FILLING APPROVED POSITIONS).

1061 - TOTAL ON SITE

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MISSION o sa e y genera:e e ec~:rici:y at a cost aer

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North Atlantic

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VISION

\\ lor:1 A:arricis recognizec as a eacing 3erbraerin our indus:ry, a sa ~e anc relia a e g enera:or com ae:i'ive

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Our Vision is aclieved using our Va ues br Exce ence aliosoaly, anc :le 'ounca: ion o~ a we co is mu:ua

rus: anc 3 rice in wla: we accom]is, as a ~:eam.

North Atlantic

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SUCCESS FACTOR: MANAGE NORTH ATLANTIC TO SUPPORT HIGH PLANT PERFORMANCE, EXCELLENT LONG-TERM RELIABILITY AND COST-EFFECTIVENESS IN ORDER TO MAKE SEABROOK STATION POWER COSTS COMPETITIVE WITH OTHER GENERATORS OF ELECTRICITY.

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Objective 1:

Plant Performanca

'

(see note below)

!

'

To ensure that all work and support activities are planned and done to maximize plant performance and sustain a lifetime capacity factor of at least 92% (not including refueling).

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Objective 2:

Outaoe Performance

!

(see note below)

-

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To minimize refueling outage length, increasing it above the required minimum duration target only to reflect work with important value-added

-

significance that will support this, and other, Critical Success Factors.

l (Outage minimum target for ORO3 is 56 days or less.)

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Objective 3:

Life-Cycle Manaaement i

'

To ensure that Seabrook Station's key components and systems are operated and maintained to permit Seabrook to operate for its fully-licensed

life.

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Objective 4:

Cost-Competitiveness To manage our resources and instill cost-consciousness throughout the

organization so that Seabrook Station stays competitive with all other

generators of electricity in our region -- targeting a continually-decreasing

,

total production cost that will reach 1.5 cents (in 1993 dollars) by the end of-t 1998.

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Note:

Achievement of Objectives 1 & 2 will result in a three-year average unit capacity factor of at least 80%.

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PLANT PERFORMANCE REALIZATION PROGRAM PARTI Gross Electrical Meaawatt Ootimization Manaaement Condenser Subcooling Minimization

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Waste Heat Reduction Efforts

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Condenser Termination Project

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P A R T 11 Plant Reliabilit" Maximization Procram Minimization of i'8 ant Trip Circumstances

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Control Philosophy Advancement to Preemptive

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Methods Analysis PART 111 Life Cycle Manaaement Steam Generators

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Main Plant Turbine / Generator

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Main Condenser

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Feedwater Heaters

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h BUSINESS FUNCTION REVIEW WORKSHEET

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REMEMBER...

NORTH ATLANTIC MISSION I

ORIGINATOR:

"TO SAFELY GENERATE ELECTRICITY AT A COST PER KILOWATT DATE:

THAT IS AS LOW AS REASONABLY ACHIEVABLE, WHILE WAINTAINING RELIABILITY THROUGHOUT THE LIFE OF THE PLANT" NOT DESCRIPTION:

YES NO ANALYlED IS FUNCTION THE LEAST COST ALTERNATIVE T lll START HERE IF NOT LEAST COST ALTERNATIVE. INDICATE TARGET DATE FOR ANALYSIS AND CORRECTIVE ACTIONS:

BUDGET CONTROL SERVICES NAESCOLABOR:Sl1OTHER:$L.ITOTAL$l

COST:

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CONFIRMATION:

IS BUSINESS FUNCTION NEEDED TO.

INIT./DATE CIRCLE YES OR MO PROTECT COWPLY ENSURE BE HEALTH &

WITH LAWS HIGH PLNT RECOGNIZE SOCIALLY PROWOTE ACTIVITY IS SCFETY OF NO AND NO WAINTAIN NO PERFORWANCE NO EWPLOYEES*

NO

& ENVIRON-NO A POSITIVE NO THE PUBLIC &

REGULATICNS PROFESSIONAL

/ RELIABILITY CONTRIBUTIONS WENTALLY R E L N SH IP. W/

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EMPLOYEEST AND OWNER RELATION-

& COST AS VITAL TO RESPONSIBLE NEIGNBORS &

DISCRETIONARY REQUIRE-SHIPS T EFFECTIV-OUR T

OFFICIALS WENTST ENESS SUCCESS T

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YES YES YES YES YES YES YES

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WHAT IS THE WORST BASED ON THIS, CIRCLE CATEGORY CREDIBLE

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CONSEOUENCE OF CHECK l PROBABILITY l NOT DOING THIS HERE:

ITEM T HIGH WED LOW ANSWER HERE:

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NEW CAPITAL PROJECT INITIATIVE CONDENSATE POLISHER 1994-1997

$30 MILLION

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MAIN PLANT COMPUTER CHANGEOUT 1992-1994

$13 MILLION CONFIG. CONTROUDRAWING UPGRADE 1992-1998

$ 8 MILLION INVENTORY COMPUTER SYSTEM UPGRADE 1993-1995

$ 3 MILLION STEAM GENERATOR WET LAYUP SYSTEM 1990-1994 51 MILLION

,

SECURITY SYSTEM COMPUTER REPLACEMENT 1996-1997

$ 7 MILLION RDMS COMPUTER REPLACEMENT 1996-1997 5 2 MILLION MSR REHEATER CHANGEOUT 1997-1998

$ 6 MILLION

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NORTH ATLANTIC - SEABROOK STATION

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t METHODOLOGY - EVENT REDUCTION EVALUATION 1.1 Event Characterization

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1.2 Station Information Report (SIR) Event Evaluation Team Formation 1.3 Root Cause Analysis

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1.4 Human Performance Enhancement System (HPES)

Investigation 1.5 Independent Review Team (IRT) Evaluations 1.6 Recommendations 1.7 Dates and Duration of Evaluation Activities 2.0 Event Reduction Evaluation 2.1 Evaluation Questions 2.2 Evaluation Summary 2.3 Tracking / Trending of Event Reduction Evaluation Information 2.4 Event Evaluation Report Page 1 Rev.O r

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.t 1.1 Event Characterization Prepare a matrix that lists items 1.1.1 through 1.1.11 and that indicates which of those items are either part of the SIR or accompany the SIR.

1.1.1 Past history relative to the event, including references to previous Station Information Reports (SIRS) for related events and to Operational Information Reports (OIRs) for the same or related events.

1.1.2 Event description including a " big-picture" write-up.

1.1.3 Initiating conditions.

1.1.4 Chronology.

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1.1.5 Summary of actions by Control Room Personnel.

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1.1.6 Equipment response and/or troubleshooting / recovery i

summary.

1.1.7 References to sources for data and information, including-the names of individuals interviewed.

i 1.1.8 Root cause analysis.

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1.1.9 Human Performance Enhancement. System (HPES)

investigation.

1.1.10 Names of individual (s) who conducted the evaluations.

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1.1.11 Conclusions.

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.i 1.2 SIR Event Evaluation Team Formation 1.2.1 Was an event evaluation team formed?

1.2.2 If a team was formed, list the team members and their duty areas or responsibilities.

1.3 Root Cause Analysis The event reduction evaluation will respond to this section if root cause analysis was performed for the SIR. For some events, evaluation may include separate root cause analyses by more than one investigating group or individual. For example, separate root cause analyses may be conducted by the HPES coordinator and by the event evaluation team. When separate root cause analyses are performed, the event reduction evaluation should include a review of this list for each of the root cause analyses.

1.3.1 List the name(s) and duty-area responsibilities for the individual (s) who performed the root cause analysis.

1.3.2 Did the individual (s) performing the root cause analysis have necessary training on formal root cause analytical techniques?

1.3.3 Prepare a matrix that lists the actions in formal root cause analysis stated in the checklist of Administrative Procedure OE 4.3, Root Cause Analysis, and that shows the actions completed for the SIR. Indicate in the matrix the actions included in the root cause analysis that exceeded the minimum requirements of Administrative Procedure OE 4.3. Indicate actions omitted from the analysis that prevented meeting the minimum requirements of Administrative Procedure OE 4.3.

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1.4 HPES Investigation The event reduction evaluation will consider the items of this section if a HPES investigation was performed for the event.

1.4.1 List the name(s) and duty-area responsibilities for the

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individual (s) who performed the HPES investigation.

1.4.2 Construct a matrix that lists the following -

techniques / analyses and indicates those included in the

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HPES investigation.

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Formal root cause analysis.

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Events / causal factors chart and time line.

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Human performance behavioral analysis and

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summary of factors that influenced the analysis.

Causal factors analysis explaining the reasons for

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inappropriate actions and relating the reasons to behavioral analysis.

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Situation analysis.

1.5 Independent Review Team (IRT) Evaluations

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The action specified for this part of the event reduction evaluation is to be applied to event evaluations performed by the IRT.

1.5.1 List the name(s) and duty-area responsibilities for the individual (s) who performed the evaluation.

1.5.2 List the analytical techniques applied in the evaluation.

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1.6 Recommendations 1.6.1 Analyze all the recommendations resulting from the various evaluations performed for the event, such cs recommendations frorn the event evaluation team, root cause analysis, the HPES investigation, and evaluations by the IRT.

Answer the following questions in the analysis.

Are all the findings substantiated?

Does each finding have a corresponding

recommendation?

Does each recommendation relate to a finding?

Will completing all of the recommendations preclude

recurrence?

1.6.2 Determine whether the various sets of recommendations were appropriately consolidated into a single set of final recommendations and/or corrective actions.

1.6.3 Were the due dates and completion dates for the selected corrective actions entered into the Integrated Commitment Tracking System (ICTS)?

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.i 1.7 Dates and Duration of Evaluation Activities The following dates and durations are to be recorded in the event reduction evaluation. For each pair of dates requested, list the

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corresponding duration in weeks or months.

1.7.1 Dates for the event and Station Operation Review Committee (SORC) approval / assignment for the SIR action items.

1.7.2 Beginning and ending dates for the SIR evaluation by the cognizant group (or departmental) manager or by the event evaluation team.

1.7.3 Beginning and ending dates for IRT evaluation, if performed.

1.7.4 Due date and completion date for each SIR action item.

1.7.5 Number and length of postponements in the due date for SIR action items.

1.7.6 Beginning and ending dates for performing root cause analysis.

1.7.7 Beginning and ending dates for performing the HPES investigation.

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2.0 Event Reduction Evaluation 2.1 Evaluation Questions The event reduction evaluation must include responses relating to the following questions and discussion items.

2.1.1 Did the circumstances of the event warrant the formation of an event evaluation team?

2.1.2 Was the selection of the designated evaluator or the members of the event evaluation appropriate for the event?

2.1.3 Did the actions of the designated evaluator or the event evaluation team reflect a thorough, well organized approach using all available sources of relevant information and data?

2.1.4 To what degree was formal root cause analysis performed? Compare / contrast actions performed to those of the checklist of Administrative Procedure OE 4.3, Root Cause Analysis.

2.1.5 Was the root cause analysis conducted in an appropriate way?

2.1.6 Which, if any, omitted techniques of formal root cause analysis should have been applied?

2.1.7 If some form of root cause analysis was applied, was it performed by appropriate individuals?

2.1.8 Were all relevant sources of information and data used in the root cause analysis?

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2.1.9 Were human performance problems and inappropriate actions identified and discussed in an appropriate manner?

2.1.10 If the HPES process was used, was it applied in an effective way using the

hniques/ analyses of item 1.4.27 Which, if any, of the omitted HPES techniques / analyses should have been applied?

2.1.11 If the HPES investigation was made, did the investigators have necessary training on HPES methods?

2.1.12 If a HPES investigation was made, did the investigators use all relevant sources of information and data?

2.1.13 If IRT evaluations were performed, were they conducted in an effective manner, using appropriate analytical techniques / analyses? Discuss the evaluations.

2.1.14 Discuss / critique the mechanism used to select the final recommendations and corrective actions.

2.1.15 Were the final corrective action recommendations nonconflicting with one another?

2.1.16 Were the final recommendations and corrective actions

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consistent with the findings of the SIR evaluations?

2.1.17 Was the scope of the final recommendations and corrective actions commensurate with the scope of the findings?

2.1.18 Do the recommendations and analyses reflect the use of trending information for SIRS from previous root cause i

analyses under Administrative Procedure OE 4.3, Root Cause Analysis?

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2.2 Evaluation Summary 2.2.1 Prepare an event reduction evaluation summary for the event based on the responses to the questions of Section 2.1. Include a listing of the following inforrration.

event category, e.g. Engineered Safetv Features

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(ESF) actuation, reactor trip, or compc nent failure.

basic cause, e.g. people problems, toci problems,

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equipment problems.

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primary causal area / event subcategory, e.g.1)

failure to follow procedures /did not use existing procedure, 2) fabrication error / wrong rr aterial, or 3)

maintenance deficiency / tools not availa ale or inadequate.

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.i 2.3 Tracking / Trending of Event Reduction Evaluation Information 2.3.1 For each event evaluated, the information of Sections 1.1,1.2,1.3,1.4, 2.1, and 2.2 is to be recorded to the extent possible on appropriate matrices and standard forms.

2.3.2 When evaluating a group of SIR events, the results indicated by the matrices and forms for the individual events should be correlated and presented on charts and tables included with the event reduction evaluation for the group of SIRS. The evaluation for the group of SIRS

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is to contain discussion and conclusions relating to trends indicated by the charts and tables. Indicated trends should be compared with trends shown by charts and tables for previous SIR evaluations.

2.3.3 The tables developed for the evaluation of a group of SIR events must include a table which summarizes the root cause analysis process applied for each SIR. Attachment

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1 illustrates a possible form for the table. Trends in process characteristics should be noted in reports that evaluate a group of SIR events.

2.3.4 The organization responsible for implementing the methodology will maintain tables that show event category, basic cause, primary causal area, and event subcategory for SIR events. There will be one table for each of the basic causal areas of people, equipment, and tools as determined under Administrative Procedure OE 4.3, Root Cause Analysis. The tables are to be continuously maintained and used as a source of tracking / trending information to be reported in all evaluations of groups of SIRS.

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2.4 Event Evaluation Report 2.4.1 Periodically the organization implementing the methodology will issue a comprehensive written evaluation report covering a group of SIR events. The group report is to contain evaluation analyses, charts, and tables summarizing the results of applying the methodology to each event of the group. The report is to include discussion and analyses resulting from the tracking / trending activities specified in Section 2.3.

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ATTACHMENT 1 Summary of Root Cause Analvsis Process SIR NUMBER

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Root Cause Component Complies Some Components of Root Cause Root Cause Analysis as per Administrative with Root Analysis Procedure Used Not Applied Procedure OE 4.3, Root Cause Cause Analysis Analysis Procedure Initial Problem Description Data Collection Worksheet

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Evaluator Selects

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Appropriate Techniques (s) From items (1) Through (4)

Below:

(1) Events / Causal Factors Chart &

Time Line (2) Change Analysis (3) Barrier Analysis

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(4) Kepner-Tregoe Analysis

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Root & Secondary

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Cause Summary Recommended Solutions

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Root Cause Evaluation Worksheet

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v t e Inspection Report - Seabrook - 1993016
80 \| 81 \| 82 \| 83 \| 84 \| 85 \| 86 \| 87 \| 88 \| 89 \| 90 \| 91 \| 92 \| 93 \| 94 \| 95 \| 96 \| 97 \| 98 \| 99 00 \| 01 \| 02 \| 03 \| 04 \| 05 \| 06 \| 07 \| 08 \| 09 \| 10 \| 11 \| 12 \| 13 \| 14 \| 15 \| 16 \| 17 \| 18 \| 19 \| 20 \| 21 \| 22 \| 23 \| 24 \|
1993 Quarterly Integrated 1Q (0) 2Q (0) 3Q (0) 4Q (0) Assessments Mid Cycle End of Cycle 8(0) 9(0) 10(0) 11(0) 12(0) 13(0) 14(0) 15(0) 16(0) 17(0) 18(0) 19(0) 21(0) 80(0) Security Operator Exams Emergency Planning Other

IR 05000443/1993016

Text

REGION I

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