IR 05000443/1993013

Insp Rept 50-443/93-13 on 930615-0726.No Violations Noted. Major Areas Inspected:Operations,Maint,Engineering,Plant Support & Safety Assessment

ML20056H232
Person / Time
Site:	Seabrook
Issue date:	08/17/1993
From:	Rogge J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20056H224	List: IR 05000443/1993013 ML20056H223 ML20056H226
References
50-443-93-13, NUDOCS 9309090026
Download: ML20056H232 (24)

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U. S. NUCLEAR REGULATORY COMMISSION ,

REGION 1 i

Report Number: 93-13 Docket No.: 50-443  ;

License No.: NPF-86 Licensee: North Atlantic Energy Service Corporation Post Office Box 300

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Seabrook, New Hampshire 03874 Facility: Seabrook Station .

Dates: June 15 - July 26,1993 l Inspectors: Noel Dudley, Senior Resident Inspector Richard Laura, Resident Inspector .

Robert DeLaEspriella, Reactor Engirwer  ;

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Albert DeAgazio, NRR Project Manager Approved By: / d#d/7;ry;3 '

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Jo F. Rogge, Chief [/l/ 9 Date .

eactor Projects Section 4B, DRP ,

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Inspection Summary: This inspection report documents the safety inspections conducted during day shift and back shift hours. The inspections assessed station performance in the  !

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areas of operations, maintenance, engineering, plant support, and safety assessmen ,

Results: North Atlantic opemted the facility safely. The inspector identified one violation, i which involves two instances where plant workers failed to follow procedural instruction I See the executive summary for assessment of performanc .l

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EXECUTIVE SUMMARY l i

SEABROOK STATION NRC INSPECTION REPORT NO. 50-443/93-13 ,

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Operations: Operators performed routine activities well. The operators were sensitive to the effects of increased outside ambient temperatures on plant equipment, the replacement of an electrohydraulic pump, the de-energization of IRTU-7, and a reactor coolant pump second stage high seal flow alarm. A failed generator stator cooling pump surveillance test resulted from an ,

operator error that occurred during the restoration from preventative maintenance. The operator l failed to perform a step in the breaker operating procedure. The lack of a 10 CFR 50.59 safety j evaluation for a spent fuel pool purification system procedure change indicated a minor weaknes .

Mnintennnee: The failure of instrument and control (I&C) personnel to obtain a scope change  !

resulted, in part, in an inadvertent closure of a containment isolation valve. The corrective actions l taken to address inadequate safety related maintenance performed on a main steam isolation valve  ;

during the last refueling outage did not fully address the personnel performance issues. The  !

maintenance workers did not perform a procedural step and did not obtain a procedure chang ;

The inappropriate use of a formal procedure change vice a pen-and-ink procedure change during a reactor protection system sur, ;illance test increased the amount of time that a spurious trip signal  ;

could cause a reactor tri Plant Sunnort: North Atlantic has adequate controls in place to cope with the impact of hurricanes. The use of a contractor to perform a complete evaluation of the projected lifetime and reliability of the security computer exhibited a strong management commitment to plant securit Fire protection personnel properly tracked and monitored two newly identified unsealed fire l penetrations. General plant equipment condition appeared good. Inconsistent implementation of ,

the supervisory walkdown program indicated the need for increased management attentio [

Iingineerina: Technical support personnel aggressively pursued the evaluation of a long term emergency diesel generator vibration reliability issue, which exhibited a proper safety perspectiv The technical support and engineering staffs properly dispositioned some ultrasonic test data, which indicated possible wall thinning on the 'B' train diesel generator heat exchanger service water  !

piping. North Atlantic was slow in developing alternate methods for verifying emergency feed  !

water pump flow when the flow detector is inoperabl l Safety Assessment Personnel errors that result in challenges to plant equipment continued during this period. Plant management has not implemented meaningful corrective actions to improve performance. North Atlantic did not measure the effectiveness of numerous action items that were implemented over the last few years as a result of the inattention-to-detail, configuration control, and the auxiliary operator task forces. The failure of plant workers to follow procedures in two unrelated instances resulted in a violatio A review of the independent safety engineering group (ISEG) determined that ISEG performed wel ii

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f TABLE OF CONTENTS i Page !

EXECUTIVE SUMM ARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii  !

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

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1.0 OPERATIONS (71707, 93702) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Plant Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 l Routine Plant Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I

' Spent Fuel Pool Purification System Operation . . . . . . . . . . . . . . . . . 3 2.0 M AINTENANCE (61726, 62703, 42700, 92701) ................... 4 -

Routine Maintenance Observations . . . . . . . . . . . . . . . . . . . . . . . .

' .2 Inadequate Safety Related Maintenance on MSIV-88 ............. 7 : Surveillance Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 ,

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I 3.0 PLANT SUPPORT (71707, 92701, 92700) ....................... I1 Radiological Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I1 , Emergency Preparedness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 , S ecu ri ty . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 ' Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 H o u sekeepi ng . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 ,

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j 4.0 ENGINEERING / TECHNICAL SUPPORT (37828, 71707, 37702) . . . . . . . . . 15  ; Emergency Diesel Generator Reliability Initiative . . . . . . . . . . . . . . . 15 l Ultrasonic Testing of Service Water Piping . . . . . . . . . . . . . . . . . . . 16 Emergency Feedwater Pump Recirculation Flow Gauge ........... 16

. 5.0 SAFETY ASSESSMENT (40500, 71707) . . . . . . . . . . . . . . . . . . . . . . . . 17 i Personnel Errors / Management Effectiveness .................. 17 : Procedural Adherence ............................ .. 18 l Independent Safety Engineering Group . . . . . . . . . . . . . . . . . . . . . . 19 ,

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i 6.0 M EETI N G S (30702) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 i i

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DETAILS OPERATIONS (71707,93702)

i Plant Activities The plant operated at 100% powe ; Routine Plant Operations The inspector conducted daily control room tours, observed shift turnovers, attended the morning station manager's meeting, and monitored plan-of-the-day meetings. The inspector reviewed plant staffing, safety system valve lineups, and compliance with technical specification requirements. The inspector verified the adequacy of two tagging orders and verified the integrity of the containment and the containment enclosure building. The inspector conducted tours of the primary auxiliary building, the emergency diesel generator rooms, the residual heat removal vaults, the turbine building, the condensate storage tank building, and the service water pump house. During the tours and attendance at the various meetings, the inspector noted good performance by the operations staf ,

Operators properly responded to the 'C' reactor coolant pump (RCP) second stage high seal flow alarm by following the alarm response procedure. The operators observed that the RCP operating parameters remained normal and that the reactor coolant drain tank level remained constant. The operators contacted the maintenance staff who entered the containment and -

vented the RCP second stage high seal flow transmitter. The RCP second stage high seal flow alarm cleared. The inspector noted that the operators documented a good narrative of related events in the unit journal. The inspector assessed that the operators properly responded to and assessed the significance of the RCP high seal flow alar Operators closely monitored plant area temperatures during periods of elevated outside ambient temperatures of up to 100 degrecs Fahrenheit. Operators maintained the containment average air temperature less than technical specification limit of 120 degrecs Fahrenheit by reducing the bypass flow around the primary component cooling water heat exchange Operators monitored and implemented actions to prevent exceeding the temperature limits in the battery rooms and the pipe chases. The 'B' thermal barrier cooling loop pump and the

'2B' containment air handling fan spuriously tripped. Operators suspected the equipment tripped due to increased temperatures and generated work requests to evaluate the cause of the equipment trips. The inspector assessed that the operators were sensitive to the effects of i elevated outside ambient temperatures on plant equipment which reflected a proper safety {

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During a weekly surveillance test on July 6, the 'B' stator cooling water pump, GSC-P-60B, i

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failed to automatically start. The operators found that the pump breaker closing springs were not charged and that the charging spring motor disconnect toggle switch was in the off position. The operators placed the toggle switch to the on position which compressed the breaker closing springs. The operators successfully completed the surveillance test. The licensee initiated an operational information report (OIR) to identify the root cause and take corrective action The inspector discussed this configuration control problem with the control room operator !

The operators indicated that the pump was taken out of service on June 30 for an oil chang Tagging order 93-0939 required that the pump breaker be racked-out and danger tagge Procedure ON1046.08, Non Vital 480 Volt Operation, contains instructions on how to rack-out and rack-in service the pump breaker. Step 6.3.7 specifies that the toggle switch be  !

placed to the on position which charges the breaker closing springs. The auxiliary operator  !

(AO) failed to perform this step during restoration from the tagging order. The AO reviewed ,

the procedure but did not bring it with him into the plant. This activity is considered to be a routine evolution. The inspector determined that a plant transient could have occurred if a problem developed with the 'A' pump and the 'B' pump was not available in the standby mode for automatic star i l

The inspector questioned why the operators did not conduct a post maintenance test. MA3.5, l Post Maintenance Test, component testing guide No. 7 specifies that a pump should be demonstrated to be operable following an oil change. The system engineer and operations personnel did not require a post maintenance test because the pump was non-safety relate The inspector considered this to be a poor practice because a non-safety related pump usually I has less instrumentation than a safety related pump and the non-safety related pumps can also initiate a plant transient. The inspector assessed that the lack of a post maintenance test  ;

reDected a poor safety perspective. As part of the corrective action, the maintenance staff  :

will review the need to enhance non-safety related pump post maintenance test requirements.

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The operations manager discussed this event with the operating crews and the AO involved

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completed a stop-think-act-review (STAR) for The control room operators observed unexpected changes in various tank levels as read on the computer monitors. The operators contacted computer engineering personnel who identified -

the need to de-energize independent remote transmitting unit (IRTU) No. 7 for j troubleshooting. The operators used Attachment A in Procedure ON1251.01, Loss of the Plant Computer, to determine the computer programs which would be affected and identify i any compensatory measures. IRTU No.7 affects the safety parameter display system, the reactor coolant leak rate calculation, and the calorimetric program. Maintenance personnel

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replaced a faulty circuit card. The inspector assessed that the operators performed well by closely trending the changing tank levels and by properly identifying the plant impact of de-energizing IRTU No.7.

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The operators noted erratic operation of the 'B' electrohydraulic control (EHC) system pump j and contacted the system engineer for evaluation. The pump discharge pressure fluctuated ,

when started and then slowly drifted. Plant management decided to replace thc pump. The i'

plant staff classified the corrective maintenance as trip avoidance work. The operators were concerned that any boundary valve leakage during the work or entrapped air when returning  ;

the pump to service could result in a plant transient. The operators and maintenance

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personnel conducted a thorough pre-work conference which emphasized precautions and contingencies. Maintenance workers replaced the pump. Operators placed the new pump  !

into service with no problems. The inspector assessed that the operators carefully considered  !

the ramifications of replacing the 'B' EHC pum j With the exception of not properly returning the GSC-P-60B to service after maintenance, the inspector assessed that operators performed routine activities wel .3 Spent Fuel Pool Purification System Operation Operators implemented the annunciator response procedure for a high differential pressure  ;

alarm for the spent fuel (SF) pool cleanup system demineralizer. The alarm annunciated at i 10 psid. The operators turned off the skimmer pump which secured flow in the purification loop. The plant staff initiated a request for engineering services (RES) to determine whether ,

or not the alarm setpoint could be increased to 20 psi .

I The inspector reviewed the design basis of the system as described in Section 9.1.3 of the Updated Final Safety Analysis Report (UFSAR). The SF pool cooling and cleanup system is

divided into tv.o parts. The cooling loop is designated as safety related and utilizes two cooling water pumps and heat exchangers to maintain temperature of the water in the spent  ;

4 fuel pool. The purification loop is not safety related and uses a skimmer pump, a pre-filter,  !

a demineralizer, and a post filter which filters and purifies water in the spent fuel poo {

Through discussions with the system engineer and review of the applicable operating procedures, the inspector reviewed the operational performance of the purification loop.

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The inspector noted that the purification loop pre-filter has been bypassed during normal operation since approximately November of 1992. The pre-filter required frequent changing which generated radwaste and increased worker radiati on exposure. The licensee revised

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Operating Procedures OS1014.01, SF System Fill and Vent, and OS1014.02, Operation of SF Pool Cooling and Purification System. The procedure revisions authorized the bypassing -!

of the pre-filter during normal operation, and changed the valve line-up positions for the pre-- l

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filter isolation and bypass valves. The inspector identified that the operations staff should have performed a safety evaluation to determine whether or not the change involved an  ;

unreviewed safety question. UFSAR Section 9.1.3.2 describes that " Filtering is achieved j with pre- and post-ion exchange filters." Sheet 2 of Figure 9.1-2 depicts the pre-filter j isolation valves as normally open and the bypass valve as normally shu !

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The inspector discussed the need to perform a safety evaluation with the technical support and licensing managers. The licensee indicated that with the pre-filter bypassed, the resin in the ion exchanger would filter out any particulate matter. The chemistry department supervisor indicated that the SF system water met the chemistry specifications listed in UFSAR Section 9.1.3.2b.l. The inspector expressed concern that although there appears to be some merit in  ;

bypassing the pre-filter, a 10 CFR 50.59 safety evaluation should be performed. The managers responded to the inspector's concern by evaluating it in the safety evaluation being performed to increase the demineralizer high differential pressure alarm. The licensing

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manager indicated that a review of 10 CFR 50.59 screening criteria would be perfonned to identify any possible enhancements. The inspector assessed that the lack of a safety i evaluation during the procedure change process indicated a minor weaknes .0 M AINTENANCE (61726, 62703, 42700, 92701) -

Routine Maintenance Observations l The inspector attended some of the morning maintenance planning meetings, the plan-of-the-day meetings, and observed maintenance activities during routine plant tours. Maintenance observed by th, uenctor included the following

Correctidjainien;mee i on Valve SG-V4 Position Indication ,

i The inspector observed instrument and control (l&C) technicians perform corrective j maintenance on the position indication for the 'A' steam generator outboard isolation valve SibV9 per work request 93 WOOL 872. During maintenance troubleshooting ihe technicians found that two wires on the limit switch side of a Conax conduit entrance seal were shorted

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together. The technicians replaced the Conax seal and used Raychem splices on each Conax

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1 seal to field wire connection. The inspector verified that the technicians possessed the proper work qualifications. The inspector observed a quality control inspector and I&C supervisor present at the work site. The inspector determined that the technicians properly diagnosed the i j mot cause and repaired the position indication anomal When reviewing the work package, the inspector noticed that the technicians installed a  ;

jumper across the scal in contact in the safe;y-rclated blowdown isolation circuit for SG-V9 .

The jumper allowed the work to proceed while allowing the valve to remain open for steam

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generator blowdowns. The inspector verified that the jumper did not inhibit the isolation feature of the valve. The inspector reviewed the administrative controls that were used to modify the circuit. Maintenance and operations personnel decided to install the jumper using 4 M A 4.5, Configuration Control During Maintenance and Troubleshooting, instead of the a

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temporary modification procedure. MA4.5 allows the modification of in-service safety- .

related and balance-of-plant equipment for up to four days with the approval of the shift j superintendent. The inspector identified that MA 4.5 does not require a 10 CFR 50.59 !

evaluation to be performed nor specify that the configuration change be treated as a - !

temporary modification. The technical support manager agreed with the inspector's concern ;

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and indicated that MA4.5 would be revised. The manager indicated that the jumper should have been installed as a temporary modificatio !

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After completion of the work, an 1&C supervisor went to the control room and released the tagging order. Operations persennel began to develop the restoration sequence in the tagging order. Without direction from the control room operators, I&C personnel removed the ,

jumper before closing the slide links which de-energized the seal-in circuit. This caused ,

valve SB-V9 to inadvertently go shut. The inspector noted that the work package did not :

contain instructions to sequence the removal of the jumper or refer to the restoration section i of the tagging order. The maintenance personnel did not obtain a work request scope change !

to install and remove the jumper. This is a violation of MA3.1, " Work Request," l Section 4.1.2, which specifies thet when the scope of work changes after the work has been l released, the person making the change shall receive verbal concurrence from the system engineer, the quality control inspector, and the unit shift supervisor. Further, MA3.1 states j that the changes shall be documented on the work request. This violation is developed ,

further in Section 5.1 of this report. The I&C personnel indicated that having two different l processes, MA4.5 and the tagging order, in progress at the same time contributed to the l oversigh ,

North Atlantic initially reported this event to the NRC on June 18, 1993, as an inadvertent ;

enginected safeguards feature (ESF) actuation. North Atlantic subsequently retracted the l NRC notification on June 18, 1993, stating that the valve closure did not result from a valid !

containment isolation signal. The inspector assessed that the reportability change was appropriat The I&C technicians performed well by identifying the cause and repairing the SB-V9 .

position indication anomaly. The inspector considered that the I&C technicians were ;

innovative by identifying the need for and installing the jumper that maintained the valve !

open. A discussion between various work disciplines incorrectly decided to install the jumper l without the proper 10 CFR 50.59 review. Failure to obtain a scope change resulted in the !

valve to inadvertently close. The inspector assessed that this maintenance activity could have i been controlled bette l

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The inspector discussed with the I&C supervisor how the two Conax seal wires became i

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shorted together. The supervisor indicated that the solid copper leads are rigid and I

susceptible to breaking as they exit the Conax seal. There has been a few other similar conax seal failures. The supervisor had already discussed this concern with a technical support +

I department engineer. The engineer initiated a review of all Conax seal problems which included broken leads, wire length problems, and scuffed insulation. The engineer

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preliminarily identified 11 related work requests that documented these types of problem ;

The review will include the identification of the total population of these seals installed in the plant. The engineer indicated that a request for engineering services (RES) will be implemented requesting evaluation and possible corrective actions. The inspector assessed !'

that the maintenance and technical support personnel exhibited a questioning attitude by discussing the failure and initiating a RES for engineering evaluatio In summary, the I&C techmcians successfully identified and fixed the valve status light ['

indication problem. The I&C personnel worked with a technical support engineer to assess the implications of conax seal failures. This demonstrated good teamwork. The inspector considered it positive that the maintenance personnel id ,ntified the need to install the jumper !

during the work to continue steam generator blowdowas. However, the inspector considered  !

it a weakness that the jumper was installed under MA4.5 rather than as a temporary modification. The inspector determined that a contributing factor to this incorrect decision l was unclear wording in MA 4.5. Failure to perform a scope change resulted in the valve to l inadvertently clos .

Component Cooline Water Valve CC-V-986 Solenoid Replacement r

Two instrument and control (I&C) technicians replaced an ASCO solenoid on valve CC-V-  !

j 986 using RTS 93RIO907201. Valve CC-V-986 is a one inch diaphragm actuated plug valve i that supplies loop 'B' component cooling water (CCW) to radiation monitor 651 ;

Maintenance personnel performed this work as a preventative maintenance activity because the solenoid was approaching the end of its nine year equipment qualification life. The inspector reviewed the work package which contained the appropriate work instructions. The .

i inspector verified that tagging order 93-1022 provided proper isolation for the work. The  !

control room operators notified chemistry personnel to take grab samples every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to j analyze for radioactivit !

l The I&C technicians determinated the solenoid wiring and properly documented the lifted I leads on a MA 4.5 configuration control sheet. The technicians used a heat shrinkable polymeric splice kit made by Raychem Corporation to seal the new solenoid wiring connections. The technicians carefully adhered to the detailed splice kit installation instructions. The inspector verified that the technicians possessed the proper qualifications to l perform this work. The technicians finished installing the new solenoid and performed a j satisfactory post maintenance tes '

The inspector assessed that the technicians were very experienced and utilized good procedural adherence. Replacing the solenoid is an example of North Atlantic being sensitive of equipment qualification requirement l l

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Service Water Pump SW-P-41D Maintenance Mechanical maintenance technicians added packing to the 'D' service water pump, SW-P-41D per work request 93 WOO 76. Mechanical maintenance initiated this work request because the packing could not be adjusted any further during the Ir.st adjustment made using Procedure 93RM2372661. The inspector verified the adequacy of tagging order 93102 The technicians removed the packing gland and installed an additional ring of packing. The inspector verified that the packing was procured as safety related. The technicians re-installed the packing gland and tightened the two packing nuts hand tight. Operations personnel cleared the tagging order and started the pump. The technicians allowed the packing to run-in and then adjusted torque of the packing nuts. The inspector reviewed the work package which contained ihe appropriate procedural controls. The service water system engineer observed the adjustment of the new packing. The inspector assessed that the maintenance technicians successfully completed the wor .2 Inadequate Safety Related Maintenance on MSIV-88 l

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l The in+ator reviewed operational information report (OIR)93-041 which evaluated the root i cause w developed corrective actions for inadequate maintenance that caused MSIV-88 to le declared inoperable on May 20,1993. The inspector documented the preliminary information in Secti on 3.1 of NRC Inspection Report 50-443/93-10. Maintenance personnel identified that a limit switch lever pipe plug had never been tightened during maintenance performed during the second refueling outage. During this period the inspector attended several of the interviews of the maintenance personnel involved and discussed the issues with the plant staf North Atlantic's review of the maintenance history of MSIV-88 revealed that the limit switch I had been replaced during the second refueling outage. Procedure LS0564.19, NAMCO Limit Switch Maintenance, Step 8.14 2 states that the pipe plug be installed finger tight, assemble the operating lever on the shaft, check switch operation and trip angle, and then increase the torque on the pipe plug until the lever is tight. The procedure required a signature and verification signature that Step 8.14.2 had been completed. This step had been previously marked as not applicable (N/A). The technicians installed the operating lever onto the new limit switch in the I&C shop, the pipe plug was left fm' ger tight. Subsequently, the maintenance workers installed the limit switch with the lever affixed onto MSIV-88. The maintenance workers could not stoke MSIV-88 to check the limit switch operation and thus 3 did not tighten the pipe plu l

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During a paperwork review an acting I&C supervisor identified that Step 8.14.2 had been inadvertently marked as N/A. The supervisor noted that the pipe plug had not been tightened but thought that the plug would be tightened later during the post maintenance test. The

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supervisor notified the maintenance workers to line through the N/As and initial that the step had been completed. The maintenance workers initialed Step 8.14.2 when the pipe plug had l

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never been tightened. This failure to follow procedure is a violation and is further developed .

in Section 5.1 of this report. The inspector notes that the supervisor and workers should ;

have obtained a procedure change to authorize not tightening the pipe plug until a later tim Subsequently, the maintenance staff performed the post maintenance test which did not require torquing the pipe plug after verifying satisfactory limit switch operatio ;

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The North Atlantic review identified six causes that were listed in the OIR. The technicians

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signed the steps based on the general sign off description rather than reviewing the actual i detailed step which included tightening the pipe plug. The work procedures did not reflect ;

the sequence of steps needed to complete the job. Involvement of many workers including

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contract workers led to no job continuity. The multiple procedures did not cleanly transition from one to another and back again. The step was incorrectly marked as N/A before the work began. Inadequate procedural instructions for the switch replacement led to several .

I problems. North Atlantic identined five corrective actions. All other MSIV limit switch lever pipe plugs were checked and tightened as necessary. Three corrective actions involved procedural enhancements. The last corrective action specified that the event be discussed ;

with I&C personnel at the next continuing training meeting and had a duc date of j October 31,199 ;

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The inspector determined that the corrective actions did not completely address the vanous !

personnel performance issues. The failure of the acting I&C supemsor to obtain a procedure change to allow tightening the pipe plug later contributed to the event. The acting supervisor

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instructed a contractor and North Atlantic worker tojust sign the step. The workers signed the step without tightening the plug as specified by the procedure. Several workers recalled that there was some schedule pressure to complete the work. During the interviews some

. problems with contractor personnel were noted which concerned the use of procedures and the oversight of contractors. These issues are not addressed by the corrective Mions i

, developed by North Atlantic. The inspector noted that plant management did not require a !

formal root cause analysis per Procedure OE4.3 or a human performance enhancement system ;

(HPES) revie ,

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e The inspector assessed that the corrective actions taken in response to this event did not fully address the personnel performance issues. The maintenance worker interviews revealed l important information that did not get adequately documented or evaluated. This reflectea l poorly on the effectiveness of the implementation of the Nonh Atlantir corrective action ;

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! Surveillance Activities t i

The inspector observed portions of the following test activitie I t

Emergency Bus 6 Monthly Loss of Power Tests  ;

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The inspector observed electrical department relay technicians perform the emergency bus 6 [

loss-of-power trip actuating device monthly surveillance test. The technicians used ,

Procedures MX0513.06, "5 kV Loss of Voltage Protection Surveillance," and MX0513.07, !

"4.16 kV Bus Degraded Voltage Protection Surveillance," which meet the requirements }

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specified in technical specifications (TS) Section 4.3.2.1, Table 4.3-2 (9a) and (9b). The performance of these two tests were properly classified as trip avoidanc *

During the tests the inspector observed that the various relays met the acceptance criteria contained in the surveillance procedures. The two technicians used good procedural adherence. The technicians properly installed jumpers specified in the procedures so that in ;

the event an actual bus undervoltage or degraded voltage condition the breaker would still _

trip. The technicians worked well with the control room operators and kept them informed ;

of the status of the test. The inspector observed an electrical department supervisor monitoring the performance of the tests at the designated supervisor hold point The inspector discussed the intent of precaution 5.4 contained in both procedures concerning '

the ambient temperature affect on Agastat relay repeatable test results. The technicians ;

indicated that the required and recommended temperature ranges applied only when a relay adjustment is made and was not intended to apply when just testing the relays. The inspector noted that the precaution could have been clearer. The inspector discussed this with the cognizant electrical department procedure writer. The procedure writer indicated that the ;

technicians properly interpreted the precaution and that during the next periodic review, the ;

precaution would be reviewed for any needed clarificatio :

3 In summary, the inspector assessed that the electrical technicians performed were experienced and interacted effectively with the control room operators. The inspector observed effective supervisory oversight of these trip avoidance testing activide Gntrol Rod Surveillance The inspector observed the performance of surveillance procedure OX1410.02, " Monthly Rod Operability Check." For each control and shutdown rod bank, the operator withdrew the bank to 231 steps, inserted the bank to 219 steps, and withdrew the bank to 226 steps. The

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inspector verified that there was no outward rod motion when the operator inserted the rod banks. Through discussions with the operators, technical support engineers, and the nuclear quality group inspector that observed the surveillance test, the inspector determined that the station staff was aware of recent industry problems with incorrect control rod motio l l

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Reactor Protection Surveillance l

The inspector observed portions of IX1640.317, " Protection Cabinet A Steam Generator  !

Steam Line Pressure," an analog channel operational test conducted by Instrumentation and Control (I&C) technicians. The inspector reviewed the surveillance procedure, observed the

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performance of the surveillance, inspected the test equipment used, and interviewed the I&C specialist J The inspector raised several concerns during the observation of the surveillance. A note in Section 5.0, " Precautions," states in part; " Precautions 5.1, 5.2, and 5.3 are applicable only >

. . . at the discretion of the Unit Shift Supervisor." Discussion with the I&C specialists i revealed that related surveillances contain similar notes. The inspector expressed concern that although the analog channel operational tests are stamped " Trip Avoidance," the first three

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precautions to prevent unit trips may be waived. The licensee regarded the procedure steps to be adequate, and to contain the necessary flexibility to allow them to operate the plant in :

an efficient manner. The inspector also noted that although there is a procedure describing ,

what activities should be stamped " Trip Avoidance," there is no procedure that describes how such an activity should be conducted to minimize the risks of causing a reactor trip.

i The inspector reviewed recent changes to the surveillance procedure, noting that the change :

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added a hyphen between two words. Through questioning of the I&C specialists, the inspector learned that under strict management guidelines for procedural adherence, a formal procedure change was required for this minor change. During tra time required to process the change, approximately 15 to 20 minutes, one of four channels required for a reactor trip l

was in the trip condition, and only one additional channel reaching its setpoint would be

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required to trip the reactor. The inspector assessed that the workers used an inappropriate l procedure change process. The previous week, a similar change took one hour to proces In late 1992, a reactor trip actually occurred during a similar surveillance, due to a signal i spike in one of the remaining channels not in the trip condition. The inspector discussed this observation with plant management. Plant management provided new guidance to station personnel for conducting procedure changes, to minimize time spent in trip avoidance  ;

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Section 4.5.7.5 of MA 2.1 requires supervisors to insert hold points at critical points for all

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tasks designated " Trip Avoidance." The inspector noted that Procedure Step 4.5.7.4 allows the supervisor to waive the hold point, without providing any criteria describing when the ;

hold point could be waived. Additionally, the procedure does not provide a definition for s

" critical tasks." The inspector discussed trip avoidance procedures with I&C personnel and ;

maintenance supervisors. The licensee considered this practice acceptable, referring to a )

similar practice of waiving Quality Control hold point ;

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The inspector determined that the surveillance was conducted in a satisfactory manner. The i

experience and professionalism of the I&C specialists performing the surveillance was a '

notable strength. Delays in the completion of this and past " Trip Avoidance" surveillances due to minor procedural changes was regarded as a potential area for improvement by the inspector, was corrected expeditiously by the hcense j s

The inspector found examples of procedure steps that seem to provide the implementor with !

certain flexibility, which may be applied in a non-conservative manner. Examples include  !'

the flexibility to waive certain prerequisites and hold points for critical steps of trip avoidance procedures. Additionally, requirements for performing trip avoidance procedures are not .

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proceduralized. The inspector discussed the apparent weaknesses in the use and adequacy of l

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procedures with North Atlantic management. North Atlantic indicated that they had recognized a procedural adherence weakness in the maintenance area and were developing a l

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training pla .0 PLANT SUPPORT (71707, 92701,92700)

The plant support area is comprised of radiological controls, emergency preparedness, security, fire protection, and housekeepin .1 Radiological Controls

3.1.1 Routine Tours ,

t During routine tours of the plant, the inspector observed proper radiological controls implemented by personnel entering, exiting, and working in the radiological controlled area, i The inspector verified proper posting of radiation and contaminated areas, calibration of l radiological monitoring equipment, and locking of hi;;h radiation area doors. The inspector determined that health physics personnel conducted routine activities wel ,

i 3.1.2 IIcalth Physics Coverage During Maintenance Activity The inspector observed an instrument and control (I&C) technician perform corrective f

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maintenance on the reactor coolant system letdown gross activity radiation monitor, RM 6520, which is located in the primary auxiliary building. The work consisted of removing and decontaminating the liquid sample stream tube. The general area around RM 6520 was  !

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contaminated. Health physics (HP) technicians established a radiological boundary around RM 6520 to prevent the spread of contamination. A HP technician provided coverage during j the work as specified by radiation work permit (RWP) 93-R-10 ;

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technician assisted the technic'an in removing the tubing which contained radioactive wate ;

The HP technician carefully collected the water into a plastic bag as it drained from the i tubing. Once removed from the RM, the workers properly bagged, installed a radioactive  :

material identification tag, and transported the tube to the decontamination shop in the ,

radwaste buildin The inspector noticed that prior to entering the work area, the I&C technician reached over [

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the boundary rope and performed some preliminary work. The I&C technician had rubber  !

gloves on, but was not fully dressed out per the RWP instructions. Also, the inspector observed that the HP technician reached across the radiological boundary rope many times during the work to assist the worker without fully dressing up per the RWP. The HP  :

technician did have a pair of rubber gloves on. The inspector discussed these observations l with the HP supervisor who indicated that Procedure RP 9.1, Section 4.1 specifies that  :

supporting work activities be performed under the discretion of the HP technician at the work ,

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During performance of the work, the inspector observed thy the I&C technician had to straddle the step off pad in order to gain access to the tubing. The inspector discussed this !

with the HP technician who indicated that the step off pad could have been installed in a  ;

better location to facilitate increased access to tubing. The HP technician surveyed the step ,

off pad which was found free of contamination. Subsequently, the inspector discussed this I

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with a HP supervisor who indicated that proper placement of step off pads would be discussed with all technician !

The inspector assessed that the station workers minimized the spread of contamination by  :

adhering to the RWP requirements. The inspector noted excellent communications and

teamwork between the I&C and HP technicians. The inspector considered the poor placement of the step off pad to be a minor weaknes ;

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1 Dnergency Preparedness i The Commonwealth of Massachusetts completed its final reviews of the turnover of the emergency response responsibility from North Atlantic which occurred on l December 30,1992. North Atlantic deactivated its off-site response organization (ORO)

which remained available until all remaining items were resolved. The inspector determined i

that the completion of the turnover of responsibilities indicated effective management oversigh :

In light of the lessons learned by Turkey Point nuclear power station in coping with hurricane Andrew, the inspector held a discussion with plant management to review the hurricane controls at Seabrook. The licensee indicated that a formal review of the lessons learned has t not been performed and is not scheduled to be. Procedures OS1200.03, entitled " Severe  ;

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Weather Conditions," NAMMll800, entitled " Hazardous Condition Response Plan," and the j

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Emergency Plan provide for a graded response and mobilization of resources to combat a hurricane. Plant operators are required to decide whether or not to shutdown the plant when ;

winds are expected to exceed 73 miles / hour within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. The licensee pointed -

out that this graded approach worked well during past severe weather fronts. The inspector i noted that these past weather fronts were not close to the order of magnitude of Hurricane Andrew. The inspector assessed that adequate controls existed to prepare for the effects of a ,

hurrican . Security l

3.3.1 Routine Security Observations +

The inspector toured the protected area, observed security guards on patrol, and monitored i activities in the common and secondary alarm stations. The security force properly

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monitored people, packages, and vehicles entering and exiting the protected area. The security staff and plant management properly followed up on a fitness-for-duty alcohol test i failure of an individual who performed safety related activities. The inspector assessed that the security force performed routine activities wel .3.2 Security Self Assessment Activity l

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The inspector held a meeting with the security manager to discuss an on-going North Atlantic ;

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security initiative. North Atlantic hired a contractor to perform a performance based check of the security computer. The security manager indicated that the purpose of the review was i to measure response times and to predict the remaining life and reliability of the existing ;

security computer. The inspector assessed that this North Atlantic initiative reflected an .

excellent safety perspectiv > Fire Protection ,

The inspector performed a review of a random sample ofinoperable fire rated assemblies and ,

fire detection instrumentation to verify the proper implementation of the actions contained in ;

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technical requirements 11 and 12. The inspector checked that fire fighters implemented proper compensatory actions for work being performed on control building fire panel No. 377 and for two recently identified fire barriers that were found missing their fire rated penetration seals. North Atlantic initiated a station information report to evaluate the cause

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of, and develop corrective actions for the two unsealed conduit penetrations located between the essential switchgear rooms. A status board in the fire fighters office and a computer data base effectively tracked the necessary continuous and roving watches. The inspector observed portions of the installation of a new computerized plant fire detection system. In

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summary, the inspector determined that North Atlantic remained sensitive towards fire i fightmg activities.

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i llousekeeping  :

l 3.5.1 Routine llousekeeping Observations During tours of the plant, the inspector observed effective housekeeping practices based on i the good material condition of the plant. The inspector observed a few valve and piping leaks that the licensee already knew about. The amount of contaminated areas seemed smal l Tools and other equipment were properly stored. There were no fire hazards and ventilation ,

was considered good in most areas, and adequate in all cases. The inspector observed a few burned out light bulbs. The inspector considered that the installation of extra lagging on high ,

energy steam lines to be a strength. In summary, the general housekeeping practices maintained the plant in good conditio .5.2 Supervisory Walkdown Program ,

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The inspector reviewed the implementation of the supervisory walkdown program established by Procedure SM 7.3. The program is designed to ensure supervisory and management ,

presence in the field and to assess the material condition of the plant. The inspector held a ,

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discussion with the supervisory walkdown program coordinator and reviewed the last six months of monthly reports issued by each of the participating supervisors and managers.

Approximately 25 personnel participate in the program. The inspector reviewed the minutes i from the last meeting conducted in December 1992, where the station manager discussed the various observation l

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The inspector identified that most participants submitted their monthly report as specified in

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SM 7.3. Some participants had not submitted any reports in the last six months. The inspector discussed this with the appropriate department manager who indicated that the missed monthly reports were an oversight. The inspector noted that the quality of the monthly reports were generally good. Some of the participants consistently identified ;

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performance-based issues, while a few participants appeared strictly compliance-based. The participants identified various housekeeping and personnel issues. Typical findings included unnecessary erected scaffolding, various minor leaks, ladders not properly stored, and areas in need of a fresh coat of paint. Deficiencies were reported to the appropriate personnel and

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corrective actions taken. The inspector assessed that the supervisory walkdown program was ;

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15 ENGINEERING /TECIINICAL SUPPORT (37828, 71707, 37702)  ! Emergency Diesel Generator Reliability Initiative When the operators ran the 'B' emergency diesel generator (EDG) for a routine surveillance -

test, technical support personnel installed extra test equipment to closely monitor vibrations in the vicinity of the right turbocharger. The EDG met all acceptance criteria listed in the surveillance procedure. Subsequently, the inspector discussed with the system support department manager and the system engineer why the additional data was taken. The system engineer indicated that the right turbocharger area has experienced a vibration velocity of approximately 1 inch /second (acceleration of .47g) for the last few years. The EDG t manufacturer, Coltec industries, reviewed this condition on September 27,1991, and concluded that the vibration amplitude is more than expected but still is less than the !

allowable acceleration of the turbocharger of 1.0g on the casin Although not an operability concern, the technical support staff considered the high vibration to be a long term reliability issue. North Atlantic attempted several different solutions to identify the cause of and resolve the vibration. During a past refueling outage, workers pumped the EDG foundation solid with epoxy. An alignment between the engine and generator altered the vibration slightly. The maintenance staff replaced the exhaust manifold with a new design. During refueling outage inspections, the engine bearings were measured and found acceptabl I In May 1992, North Atlantic contracted ARC Associates to evaluate the dynamic characteristics of the turbochargers, intercoolers and the supporting brackets. This evaluation concluded that the right turbocharger area vibrations resulted from the excitation of a natural frequency by a second order dynamic force produced by the generator. The contractor recommended the modi 6 cation of the turbocharger support bracket. North Atlantic chose not to modify the support bracket since the vibration was just a symptom of the root caus North Atlantic hired another contractor to perform a dynamic loading analysis. North Atlantic performed the testing for this evaluation during this period. The contractor indicated that this type of vibration has been experienced on other Colt diesels. Preliminarily, the contractor assessed that the engine fuel system consistently delivered the fuel in an accurate manner. The engine cylinders loaded eveniy and Gred wel The technical support staff indicated that a process of climination would be used until the root cause of the abnormal vibration in the area of the right turbocharger was identified and remedied. The plant staff indicated that during the fourth refueling outage a EDG monitoring package modi 6 cation is scheduled to be installed. This will provide the licensee and the EDG vendor more precise diagnostic information. The technical support staff stated that plant management has provided the necessary support to identify the cause of the vibrations

, and take corrective actions. The inspector assessed that North Atlantic exhibited an excellent safety perspective by improving the long term reliability of the EDGs.

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. I 16 Ultrasonic Testing of Service Water Piping ,

During the second refueling outage, the station staff identified and repaired a through-wall leak in the diesel generator heat exchanger service water piping. The technical support department decided to perform ultrasonic testing (UT) on one train of affected service water ;

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piping every quarter. The latest UT testing performed on the 'B' train diesel generator heat exchanger service water piping indicated multiple areas of wall thinning around one of the ;

twelve welds examined. The areas of apparent wall thinning were pin points with readings ,

below the minimum wall thickness of 3.048 millimeters [0.120 inches].

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The inspector reviewed generic letter 90-05, " Guidance for Performing Temporary Non-Code Repairs of ASME Code Class 1,2, and 3 Piping." The inspector discussed North Atlantic's actions with technical support, licensing, and operations personnel. Following the guidance of GL 90-05, North Atlantic established a planned response consisting of flaw detect ion .;

I determination, potential reportability, and an operability determination if require ;

The initial UT readings around the weld were taken using hand-held probes. North Atlantic ;

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contracted EBASCO to conduct a flaw detection determination, over a weekend, using automated UT equipment. The inspector observed EBASCO technicians calibrating the automated UT equipment and discussed the different UT detectors with the North Atlantic lead special process analyst. The analyst is a non-destructive examination (NDE) level 111 i inspector. The hand-held UT probe is a precise instrument but only measures the wall {

thickness located directly under the probe. The automated UT equipment is less precise but uses various detection angles and a computer program to map the inside pipe diamete ;

The results of the automated UT showed uniform inside pipe diameters with no wall thinning below minimum wall thicknesses. The lead special process analyst concluded that the readings from the hand held UT probes indicated laminations formed during the fabrication ,

process. The inspector concluded that North Atlantic promptly responded to UT readings [

indicating possible pipe wall thinning and properly evaluated subsequent UT test indication !

3 Emergency Feedwater Pump Recirculation Flow Gauge -

Prior to the performance of procedure OX1436.02, " Turbine Driven Emergency Fcedwater !

Pump Monthly, Quarterly, and 18 Month Surveillance Test," the inspector held a discussion ,

v;ith a technical support engineer. The technical support engineer planr.ej to monitor pump j discharge pressures while the flow detector was inoperable. The engineer had prepared an acceptable range of discharge pressures derived from the pump head curve to verify adequate l

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pump flow. The recirculation flow detector was inoperable for over half an hour while the instrumentation and control technicians vented the flow gaug ,

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I The inspector discussed the flow detector with the technical support system engineer. The system engineer had recogalzed over two years ago that air in the feedwater caused detector i inaccuracies and damaged the snubbers in the gauge lines. During the second refueling :

outage, mechanics installed a vent on the recirculation line based on engineering  :

recommendations. The use of the vent did not correct the problem. The system engmeer t

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then contacted the pump vendor, Ingersoll-Rand, to evaluate the pump seals as a possible source of air in-leakage. Until the flow detector problems are corrected, the system engineer i

intended to provide operations personnel with a range of acceptable discharge pressures to assure adequate flow when the flow detector was being vente ,

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Efforts by the technical support department to resolve the problem have been continuous but !

unsuccessful. North Atlantic issued an operational information report on May 24,1993, to ;

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address operational concerns associated with the loss of flow indication during pump operation Based on the piping configuration and testing procedures the inspector determined the l potential for damaging the emergency feedwater pumps was small. The inspector concluded i North Atlantic was slow in developing alternate methods for verifying pump flow when the !

flow detector was inoperabl ;

! SAFETY ASSESSMENT (40500,71707)

, Personnel Errors / Management Effectiveness

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The inspector performed a review of several personnel errors which occurred during the last ,

the last routine inspection period from May 11 to June 14,1993, and this routine inspection .

l period to determine whether or not in the aggregate they may represent a potentially more j

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significant problem. Each personnel error resulted in challenges to plant equipment. The errors were made by operations and maintenance personnel. The inspector reviewed five personnel errors listed belo !

• On May 20,1993, MSIV-88 failed its operability test due to inadequate safety related maintenance performed during the last refueling outage. The details of this event are !

discussed in Section 2.2 of this repor ,

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• On May 20,1993, inadequate communications between two licensed operators i resulted in the automatic initiation of the emergency feed water system. The details of ;

this event are discussed in Section 1.3 of NRC Inspection Report 50-443/93-1 ;

• On May 22,1993, during a plant start-up, a feedwater isolation occurred due to operator error when swapping from the feed bypass valves to the main feed regulating valves. The details of this event are discussed in Section 1.4 of NRC Inspection Report 50-443/93-1 :

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• On June 18, 1993, a containment isolation valve inadvertently closed due to the failure of maintenance workers to obtain a work request scope change. Also, plant workers installed a temporary jumper into a safety related circuit without classifying it as a temporary modification. The details of this event are discussed in Section 2.1 of this repor ;

• On July 6,1993, a generator stator cooling pump did not automatically start during i the performance of a routine surveillance due to operator error when restoring from ;

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a tagging order. The details of this event are discussed in Section 1.2 of this repor !

The inspector determined that the corrective actions taken in response to each event appeared to be adequate. The inspector considers that these personnel errors are symptoms of a larger problem regarding weak plant worker attention-to-detail. Approximately two years ago,  ;

North Atlantic established the attention-to-detail, configuration control, and auxiliary operator l

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task forces. The task forces identified approximately 120 action items aimed at improving j

performance. North Atlantic has implemented the majority of these action items and i disbanded the task forces. The licensee developed a procedures task force which is still ;

ongoing to improve procedure quality. The inspector considered it a weakness that North Atlantic did not perform a review to determine the effectiveness of the action item :

i The inspectors met with plant management to discuss the trend toward personnel errors that ;

challenged plant equipment. The management staff had already identified the need to i enhance procedural adherence but did had not recognized the increase in challenges of plant i equipment which directly resulted from errors made by operations and maintenance personnel. The plant manager tasked the training department to develop a training pla I When developing the training plan, the management staffidentified that neither they nor j plant workers had a consistent understanding of the procedural adherence policy. In i summary, plant management has not implemented effective corrective actions to improve [

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procedural adherence and reduce the number of personnel errors that challenge plant equipmen L i Procedural Adherence (VIO 93-13-01) l The inspector discussed two different personnel errors in Sections 2.1 and 2.2 of this report that resulted in challenges to plant equipment. These personnel errors resulted, in part, from i the failure to follow procedural instructions and are considered to be a violation of Technical i Specifications (TS) 6.7.1. TS 6.7.1 specifies that procedures listed in Appendix A of  ;

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Regulatory Guide 1.33 shall be established and implemented. A procedure for procedural adherence is listed in Appendix A. North Atlantic Procedure SSMM, Step 5.2 states that all !

personnel performing work shall comply with written instructions (VIO 93-13-01). l

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The inspector identified two other procedural adherence issues during this period which -

indicate that plant workers do not fully understand the procedural adherence policy set forth ,

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by management. Maintenance technicians used an inappropriate procedure change process during a reactor protection surveillance as discussed in Section 2.3 of this report. An operator did not properly restore a generator cooling pump to an automatic start line-up per procedure as discussed in Section 1.2 of this report. Collectively, these events indicate that ;

plant workers do not have a clear understanding of management expectations in the area of procedural adherenc ; Independent Safety Engineering Group  ;

The inspector examined the operations of the Independent Safety Engineering Group. The assessment included a review of the qualifications of ISEG engineers, organization, and ISEG .

documentation. Technical Specification 6.2.3 requires North Atlantic to have an Independent ;

Safety Engineering Group (ISEG). The group is composed of a minimum of five full time ;

engineers that examine operating experience to determine areas where safety can be improved. The activities of ISEG are conducted to provide independent verification that 6 i

l station activities are performed correctly and that human errors are reduced. Technical Specifications specifies the minimum qualifications for the members. The ISEG charter, ,

responsibilities, and requirements are described in North Atlantic Management Manual l (NAMM), Section 1127 ISEG is composed of five engineers, including an ISEG Supervisor. ISEG reports to the ;

Nuclear Safety and Assessment Department which reports to the Director of Quality ,

Programs. This organizational structure is completely independent of the production and 9 engineering activities thereby assuring the independence ofISEG. The inspector reviewed the qualifications of the individuals assigned to ISEG. The inspector concluded that the qualifications and professional experience of all ISEG members ISEG exceeded the minimu ,

NAMM 11270 identifies ISEG's principal responsibility to be the review of certain ;

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information sources to determine areas where there is opportunity to improve nuclear safet The specified sources provide information about operational events and experience i throughout the nuclear industry. ISEG reviews documentation such as reports available through the INPO Nuclear Network program (e.g., Significant Operating Experience Reports, Significant Event Reports), reports by others such as NRC Bulletins and .

Information Notices, and Licensee Event Reports for experience and events at other facilitie ISEG also reviews internally generated reports relating specifically to the Seabrook Statio ,

The inspector examined the ISEG Review Logs (one each for reviews of external and internal documents) which provide a record of the reviews performed. Using these Logs, the inspector selected 12 ISEG reviews for inspection. The inspector found that each ISEG review was documented by a memorandum which includes a Background section which identifies the event or issue reviewed. This is followed by a Discussion section where the event is evaluated in depth along with an identification and evaluation of the programs in

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place at Seabrook or design features that are relevant to the issue. The discussion identifies if programs or design features at Seabrook are such that the event would have been precluded or mitigated, or if similarities exist which might be changed to minimize the potential for the event at Seabrook. A Recommendation section identifies ISEG's recommendations. ISEG recommendations are entered into the Integrated Commitment Tracking System (ICTS). The ;

inspector found the ISEG evaluations were well documented and thorough. The ,

documentation indicated that the ISEG reviewers had clear understandings of the issues or ;

events. The inspector concluded that ISEG is effective in informing management of  ;

opportunities to improve safety using experience at other facilitie One of the evaluations (ISEG # 9201-004) reviewed by the inspector related to another

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organization's analysis of and recommendations for elements essential to improving human performance. The focus of the ISEG evaluation was a review of the Seabrook Station human ,

i performance program to evaluate policies, procedures, and training to determine if the essential elements recommended are included. ISEG concluded that existing Seabrook programs incorporate the recommended elements. The ISEG documentation described how '

the programs would function to minimize human errors. The inspector noted that the scope of the ISEG evaluation was limited to determining if the essential elements were incorporated >

in the Seabrook programs and 9d not include an evaluation of the effectiveness of those programs in actually accomplishing the desired effect. The inspector concluded that this is a potential weakness in the ISEG review. While the essential elements may be present, the !

desired human performance improvement might not be realized if the program is not effectively implemented. The inspector noted that some of the Seabrook programs related to ,

human performance have only recently been adopted for use in the station and an effectiveness review might not have been meaningful at the time Qe ISEG evaluation was ,

performed. However, while ISEG could have recommended that an effectiveness review be l performed in the future, such a recommendation was not made, t

ISEG prepares a comprehensive monthly report ofits activities which summarizes the status l of reviews undertaken by ISEG, new issues selected for evaluation, and statistical 1" information regarding the status of ISEG recommendations. The inspector concluded that the ISEG provides an effective review of operating experience and events, and that the results of these reviews are effectively communicated to management. The inspector assessed that !

ISEG is operating in conformance with the Technical Specifications and the ISEG Charter as :

identified in NAMM 1127 , MEETINGS (30702)  ;

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Two resident inspectors were assigned to Seabrook Station throughout the period. The inspectors conducted back shift inspections on June 28, July 15, and 16, and deep back shift inspections on June 20 and 27. On June 26 and 27, the respective section chief toured the facility, met with plant management, and attended the exit meetin :

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Throughout the inspection, the inspectors held periodic meetings with station management to discuss inspection findings. At the conclusion of the inspection, the inspector held an exit meeting with the station manager and his staff to discuss the inspection findings and :

observations. The licensee acknowledged the inspector's findings and commented on the i 10 CFR 50.59 issues. These comments are discussed in the pertinent sections in this repor No proprietary information was covered within the scope of the inspection. No written ;

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material regarding the inspection findings was given to the licensee during the inspection perio ;

DATE SUBJECT REPORT N INSPECTOR  !

June 25 Engineering / 93-09 J. Trapp Tech Support ,

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