IR 05000373/1986011

Insp Repts 50-373/86-11 & 50-374/86-11 on 860313-0414.No Violations Noted.Major Areas Inspected:Licensee Actions on Previous Insps Findings,Operational Safety,Surveillance, Maint & Emergency Drill & Exercise

ML20197J019
Person / Time
Site:	LaSalle
Issue date:	05/05/1986
From:	Wright G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20197H972	List: IR 05000373/1986011 ML20197H967
References
TASK-2.B.1, TASK-2.B.2, TASK-2.K.1, TASK-2.K.3.24, TASK-TM 50-373-86-11, 50-374-86-11, NUDOCS 8605190334
Download: ML20197J019 (11)

Text

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U. S. NUCLEAR REGULATORY COMMISSION

REGION III

Reports No. 50-373/86011(DRP); 50-374/86011(DRP)

Docket Nos. 50-373; 50-374 Licenses No. NPF-11; NPF-18 Licensee: Commonwealth Edison Company Post Office Box 767 Chicago, IL 60690 Facility Name: LaSalle County Station, Units 1 and 2 Inspection At: LaSalle Site,. Marseilles, IL Inspection Conducted: March 13 through April 14, 1986 Inspectors: ft. J. Jard: J. Bjorgen R. Kopriva E. Hare

, Approved By: G. g t, Ch ef 7/d b Reactor Projects Section 2C Date Inspection Summary Inspection on March 13 through April 14, 1986 (Reports No. 50-373/86011(DRP);

50-374/86011(DRP))

Areas Inspected: Routine, unannounced inspection conducted by resident inspectors of licensee actions on previous inspection findings; operational safety; surveillance; maintenance; Licensee Event Reports; training; regional requests; TMI action plan requirement followup; followup of 10 CFR 50.54(f)

request for information; and emergency drill and exercis Results: No notice of violations were issued in this inspection report. The licensee had several personnel error No other major occurrences this mont PDR ADOCK 05000373 G PDR 3

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Persons Contacted

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i- * J. Diederich, Manager, LaSalle Station  ;

,. *R. D. Bishop, Services Superintendent l

, - *C. E. Sargent, Production Superintenden .

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• D._Berkman, Assistant Superintendent, Technical Services 4 W. Huntington,' Assistant Superintendent, Operations I

.J. C. Renwick, Assistant Superintendent, Work Planning

• M. Jeisy, Quality Assurance ,

P. Manning, Tech Staff' Supervisor 'l j *T. Hammerich, Assistant Tech Staff Supervisor -

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W. Sheldon, Assistant-Superintendent,_ Maintenance  !

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i The inspectors also talked with and interviewed members of the operations, maintenance, health physics,-and instrument and control )

sections.

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• Denotes personnel attending the exit interview held on April 15, 1986.

] Licensee Action on Previous Findings (92701)

3 (0 pen) Open Item (373/86007-07(DRP))': The inspector continued to. review

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the conversion from plumbob depth readings to accurately correlated Standby Liquid Control (SBLC) tank volume. Verification.of tank i dimensions and review of the-General Electric (GE) design, specification j was still in progress by the licensee.

) (Closed) Open Item (373/85016-05; 374/85016-05(DRS)): The licensee was

! to develop a procedure for Inservice Testing of relief valves. Procedure LTS 600-10 has been issued to control the testing program. The

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} evaluation of this program will be monitored during future inspections, i

i (Closed) Open Item (374/85021-03(DRP)): The licensee was to revise the piping freeze seal procedure LMP-GM-14, to make the availability of an j emergency closure device a mandatory requirement prior to establishing a i freeze seal. The procedure has been revised to require a technical staff evaluation of each freeze application to assure fluid boundary integrity 1 is maintained during all stages of maintenanc For applications where i an emergency closure device is not deemed necessary, written technical

justification will be provided and included in the work package.

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(0 pen) Unresolved Item (374/86008-03(DRP))

On March 10, 1986, the-

licensee reported two high reactor water level (+50 inches). isolation i switches on the High Pressure Core Spray (HPCS) and one high reactor l' water' level (+50 inches) isolation switch on the Reactor Core Isolation Cooling (RCIC) System were required to be Environmental Qualified (EQ)

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'and were not. Further investigation by the licensee determined that the i

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. installed switches met the harsh environment qualification requirements 1 and the switch did.not need to be changed ou ~

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The licensee's station personnel on March 29, 1985, had a telecon conversation with a member of the Station Nuclear Engineering Division

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(SNED) who stated the switches for the HPCS and RCIC systems do not need to be changed as they were not required to meet EQ requirements of '

10 CFR 50.49. This telecon conversation was never backed up by any formal memorandum from SNED confirming the telecon and modifying their original directive which required the switches to be replace An Engineering Change Notice (ECN) 161 was issued on February 14, 1985, that changed the qualified equipment list (Q list) to reflect these-switches were to be moved from " mild environment" to " harsh environment" on the_Q list. This ECN was lengthy and the station did not recognize this one change among many. The_ site personnel. wanted to-leave the existing switches (Barton) because they give a remote indication of '

reactor level at the instrument rac They had problems with not being able to have remote indication when needed for valving in of instrument The new EQ switches (Static-0-Ring) do not have remote indicatio Since the station had a telecon conversation from SNED indicating the ,

switches did not need to be changed out in March 1985, and did not recognize the ECN issued in February had moved the switch to a harsh environment, the modification which installed the EQ switches for Unit 2 was not completed prior to bringing the unit back to power after November 30, 198 A review of this event with the station management, QC manager, and QA manager determined that in the future a modification package will not be closed out for operation based on a telephone conversation without a backup letter from the engineering department which changes their original directiv The licensee ~ agreed to look at this same program as applied to maintenance item Since the licensee subsequently determined the installed switches met EQ requirements and would have functioned in a harsh environment, no notice of violation was issue This item will remain open until the licensee completes its evaluation j on how maintenance items which require engineering evaluation will be'

handle . Operational Safety Verification (71707)

The inspector observed control room operations, reviewed applicable logs ~

and conducted discussions with control room operators during.the inspection period. The inspector verified the~ operability of' selected emergency systems, reviewed tagout records,'and verified proper return to service of affected components. Tours of. Units 1 and 2 reactor' buildings and turbine butidings were conducted to observe plant equipment.'

conditions, including potential fire hazards, fluid leaks and excessive vibrations and'to verify that maintenance requests had been initiated for equipment in need of maintenanc The inspector by observation and

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direct interview verified that the physical' security plan was being implemented in accordance with the station security pla The inspector observed plant housekeeping / cleanliness conditions and verified implementation of radiation protection control During the month of March 1986, the inspector walked down the accessible portions of the following systems to verify operability:

Unit 1 and 2 Emergency Diesel Generators Unit 1 and 2 Standby Liquid Control Systems Unit 1 and 2 Standby Gas Treatment Systems A and B Emergency Diesel Fire Pumps On March 19 the afternoon Shift Control Room Engineer (SCRE) noticed the power removed to the Unit 2 High Pressure Core Spray (HPCS) full flow test valve (2E22-F023). The investigation determined an outage for Unit 1 had been hung on Unit 2 during day shift. This event prompted a special inspection and will be documented in Inspection Reports No. 373/86015; 374/8601 . Monthly Surveillance Observation (61726)

The inspector observed Technical Specifications required surveillance testing and verified for those actual activities observed that testing was performed in accordance with adequate procedures, that test instrumentation was calibrated, that limiting conditions for operation

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were met, that removal and restoration of the affected components were accomplished, that test results conformed with technical specifications and procedure requirements and were reviewed by personnel other than the individual directing the test, and that any deficiencies identified during the testing were properly t eviewed and resolved by appropriate management personne The inspector witnessed portions of the following test activities:

LOS-SC-M12A Standby Liquid Control System Monthly Operational Test LIS-NB-114 Unit 1 High Pressure Automatic Blowdown Calibration of the 1821-N039 CC Switch No items of concern were identifie The inspector, as followup to a previous concern with the adequacy of repairs to the 1E12F009 and F008 Residual Heat Removal (RHR) System shutdown cooling isolation valves, conducted a review of the post repair testing of the valves to assess the probability of the valves leaking in the future such that the low pressure RHR piping could become over pressurized. The licensee performed a low pressure air test (LTS 100-35)

on the valves to meet the type "C" Local Leak Rate Test requirements of Appendix J to 10 CFR 50. The "as-left" leak rate for the valves was:

1E12F008 Outboard Valve 2.2 Standard Cubic Feet Per Hour (SCFH) ;

1E12F009 Inboard Valve 43.2 SCFH

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In addition, the licensee performed two high pressure water tests on the l valves to determine the valve's ability to seal against operating system pressure. Initially, test LTS 900-7 was performed at system operating pressure. The leakage through each valve was measured and conservatively rounded off to .1 gallon per minute (GPM). To better. assess the amount of leakage actually attributable to the isolation valves and not through the inboard 1E12F020 valve, the licensee performed a special test, LST 86-3 At normal system operating pressure (reactor vessel pressure) the leakage through each of the F008 and F009 valves was found to be approximately .01 GP It was noted, however, that leakage in the 500 to 600 psig range was approximately 2.2 GPM for the F009 valve. Based on this intermediate range pressure leakage that is likely to occur during startups, the licensee intends periodically to vent the space between the inboard and outboard isolation valves to obtain better valve seating. At pressures

! above 600 psig, this process will be administrative 1y controlled with a

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special operating orde '

The inspector followed up with the licensee an event that occurred at the Cooper Station concerning the setting for Group I isolation of the main steam isolation valves at 140% steam flow. The Cooper Station

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identified on March 10, 1986, that the isolation switches had been set for 140% of the 105% safety analysis figure, giving a higher than intended setpoint. The inspector reviewed the method this licensee uses to determine

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the 140% setpoint. The licensee used the actual steam flow identified during startup testing and not the 105% design valve. However, the actual

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steam flow measured flow during startup testing x 140% gave a value of 4.93 x 108 lbs/hr/ steam line. The maximum " allowed value" for a steam line in the Technical Specifications was 116 psid which would be equivalent to 4.96 x 108 lbs/hr. The difference was 3 x 104 lbs/hr steam flow. The inspector discussed this difference with NR Since this difference was so small, less than 1%, the NRR agreed with the inspector that no significance should be attached to the difference and no action should be taken. This item is considered close . Monthly Maintenance Observation (62703)

Station maintenance activities of safety related systems and components listed below were observed / reviewed to ascertain that they were conducted in accordance with approved procedures, regulatory guides and industry codes or standards and in conformance with Technical Specification The following items were considered during this review: the limiting conditions for operation were met while components or systems were removed from service; approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and were inspected as applicable; functional testing and/or calibrations were performed prior to returning components or systems to service; quality control records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were implemented; and, fire prevention controls were implemented.

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Work equests were reviewed to determine status of outstanding jobs and to assure that priority is assigned to safety related' equipment maintenance which may affect system performanc ;

The-following maintenance activities were observed / reviewed:

The inspector followed the repair and testing of the IVG002 Unit 1 Standby Gas Treatment System (SBGT) inlet damper actuato During a

'recent surveillance test, an oil leak was noted on the actuator shaf Work Request L56050 was initiated to accomplish repairs. Repair and shop testing was accomplished in accordance with procedure LEP-EQ-127. The inspector noted that the repair was delayed while two' seals were ordered on an urgent basis. This is a repeat of a problem previously' identified in the spring of 1985, in Inspection Report No. 373/85009. .The' licensee-confirmed that the current problem was another vendor oversight. The'

actuator repair kit did not include all of the required seals. The licensee and the vendor are coordinating to provide improved packaging and identification of the contents required to be included in actuator repair kit In addition, the licensee intends to-include a marked-up exploded view of the actuator assembly in the receiving inspection procedure to assist Quality Control.in verifying receipt of all required kit content At 1:07 a.m. on March 17, 1986, while temporarily placing some safety-related pressure switches bacP into service (per out-of-service No. 1-87-86 and ;

1-99-86) on Unit 1, a high containment pressure signal was sensed which caused a Group 4 isolation'on Unit 1. This isolation also sends a cross- '

trip to Unit 2 reactor building Ventilation System (VR)'and starts both Standby Gas Treatment (SBGT) Systems; The switches were immediately taken back out-of-service and the Group 4 isolation rese The' Unit 2 reactor building ventilation system was restarted and the SBGT systems shutdown '

within 10 minutes from when they had starte Temporary lifting the equipment out-of-service' outages wa's to' allow the ;

Instrument Mechanics to test the recently installed Environmental Qualified (EQ) pressure switches. Subsequent licensee investigation determined there was a personnel error in not adhering to procedure Attachment G, " Temporary Lift Checklist", of procedure LAP-900-4,

" Equipment Out-of-Service", (which was attached to out-of-service N .l 1-87-86 and 1-99-86) addressed reconnecting a lifted lead prior to- .

removal of a jumper wire. This-was not done and when the jumper wire was i removed it generated the high containment pressure signal causing the >

Group 4 isolatio '

The licensee halted any further work on switches which had a potential of causing another trip until continuity verification of the new EQ' switch was performed and prior to temporarily lifting any further out-of-service {

outages. .This item will remain as an unresolved. item until further j

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evaluation is made on the NSO failure to follow the procedure (373/86011-01(DRP)).

On April 3, 1986,'while performing.a routine calibration and functional-test of.the Unit 1, Division 1 bus overcurrent relays, an Operational Analysis Department (OAO) person inadvertently closed the contacts on an

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a, overcurrent relay which tripped the bus breaker, deenergized the bus, and automatically started the "0" Emergency Diesel Generator. Subsequent investigation determined that the maintenance activit accomplished in accordance with a general procedure (y was Work being Request L53841)

that invoked the manufacturer's technical manual for work instruction The adequacy of the work instructions being utilized is an item of concern and requires additional evaluation. Until this evaluation is completed, this will be tracked as an unresolved item (373/86011-02(DRP)). Licensee Event Reports (92700)

Through direct observations, discussions with licensee personnel, and review of records, the following Licensee Event Reports (LER's) were reviewed to determine that reportability requirements were fulfilled, immediate corrective action was accomplished, and corrective action to prevent recurrence had been accomplished in accordance with Technical Specification /86010-00 - Group 2 and 4 isolations caused by grounded jumper while performing LIS-PC-15. System design / connection method change needed. An open item was assigned in Inspection Reports No. 373/86007; 374/8600 /86009-00 - Group 4 isolation while performing LOP-RP-04. This event was discussed in Inspection Reports No. 373/86007; 374/86008. There was an open item assigned for permanent corrective actio /86-005-00 - Loss of Division I DC power caused multiple ESF actuation Personnel error while uncrosstieing Unit 1 & 2 Division I buses. This event was documented in Inspection Reports No. 373/86007; 374/8600 /86-006-00 - Missed conductivity sample. Notice of violation issued concerning this event in Inspection Reports No.373/86007; 374/8600 /86-006-00 - Reactor Water Cleanup Isolation (RWCU) due to mispositioned valves. This was a personnel error. A violation was issued in Inspection Reports No. 373/86007; 374/8600 /86-005-00 - Reactor scram on "Hi-Hi" Intermediate Range Monito This scram is documented in Inspection Reports No. 373/86007; 374/8600 /85-040-01 - The concentration of sodium pentaborate in the Standby Liquid Control tank was high and exceeded Technical Specifications. It took several attempts to obtain a correct concentration. This revision was issued to correct the date of the event and to clarify the repor /86-003-00 - Upon completion of Instrument Maintenance Department surveillances, the reactor mode switch was inadvertently placed in "run"

_ instead of " shutdown". This caused a reactor scram and Group I isolatio The reactor was already shutdown at 0% powe ;

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I 374/85-041-00 .High Pressure Core Spray-(HPCS) System declared inoperable because of HPCS low level initiation switch was malfunctionin Malfunction was caused by actual grounding on a switch terminal' lead. The tape insulation had worn through exposing the wire and allowing it to ground, l

j 374/85-048-00 - Unit 2 Reactor Core Isolation Cooling System (RCIC) water ,

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leg pump tripped on breaker thermal overload and could not be restarte i i RCIC water leg pump was replaced. RCIC was declared operable. Work Request L55105 was initiated to identify the cause of failure and repair of the failed water leg pump.

l 374/86-004-00 - A reactor scram occurred from 99% power resulting from -

l turbine control valve fast closure following an offsite phase to phase

fault on transmission line 0101. This scram is' documented in Inspection i Reports No. 373/86007; 374/86008.

f 7. Training (41400)

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! The inspector, through discussions with personnel and a review of training records, evaluated the licensee's training program for operations and maintenance personnel to determine whether the general knowledge of the individuals was sufficient for their assigned tasks.

I Specific areas reviewed are identified in Paragraphs 4 and 5.' No items

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of concern were identified, j-i 8. Regional Requests (92705)

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The inspector received a regional request to respond to a memorandum dated November 27, 1985, from E. G. Greenman to Division of Reactor Projects

Branch Chiefs on "Use of Licensed Reactor Operators in Supervisory

! Positions." The subject was addressed due to an occurrence at Millstone Point Station, and for clarification and evaluation of 10 CFR 50.54(m)

(2) 111, 10 CFR 55.4(d) and 10 CFR 55.4(e) requirements. The inspector reviewed station procedure LAP-1600-2, " Conduct of Operator", which covered the areas of concern and has found no deviations from those Sections of 10 CFR listed above.

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9. TMI Action Plan Requirement Followup (25565)

f Closed (0 pen Items 373/81000-147 and 374/81000-67): TMI Item II.K.3(24)

Final recommendations confirm adequacy of space cooling for Reactor Core

! Isolation Cooling (RCIC) and High Pressure Core Spray (HPCS) Injection System.

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! RCIC pump cubicle temperature is maintained at less than 148 degrees Fahrenheit by a pump cubicle fan unit which is powered by the Division I i emergency alternating current bus. The HPCS system contains a single

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motor-operated pump which is powered by the Division 3 emergency

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alternating current bus.= The HPCS pump cubicle ventilation is provided

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by a cooler fan unit which is powered by the same emergency bus as the HPCS pump. The RCIC and HPCS systems can be operated with adequate space cooling for two hours in the event of a complete loss of offsite alternating current powe Closed (0 pen Item 373/81000-146 and 374/81000-66): TMI Item II.K.1(23)

IE Bulletins, Reactor Vessel Level Instrumentation - In Amendment 54 to the Final Safety Analysis Report, the licensee summarizes the reactor vessel level instrumentation used at LaSalle. The instruments that sense the water level are differential pressure devices calibrated for accuracy at a specific vessel pressure and liquid temperature conditio This instrumentation is extensively detailed in the General Electric Company Report NED0-24708, " Additional Information Required for NRC Staff Generic Report on Boiling Water Reactors," and has been reviewed by the NRC and evaluated in NUREG-0626, " Generic Evaluation of Feedwater Transients and Small Break Loss-of-Coolant Accidents in GE Designed Operating Plants and Near Term Operating License Applications." This complies with requirements of Item II.K.1(23).

Closed (0 pen Item 373/81000-86 and 374/81000-65): TMI Item II.B.2(3)

Plant Shielding Modifications Completed - Shielding and other modifications made as a result of the shielding design review include the following: the main stack monitoring panel will transfer its monitoring functions to the well shielded high range stack monitor when it measures a prescribed radiation leve The licensee has added shield doors and additional shielding walls to the reactor building in order to reduce radiation streaming and improve access to various plant areas (including the facilities adjacent to the control room) following an acciden The licensee has performed a design review of plant radiation and shielding for post accident operations. This review has shown that LaSalle meets the post accident shielding requirement . Followup of 10 CFR 50.54(f) Request for Information (71707, 92701)

On March 26, 1986, a monthly meeting was held at the LaSalle County Station to discuss the progress of the station resulting from the 50.54(f) letter issued. The meeting was attended by Mr. A. B. Davis of the NRC Region III and members of his staff and Mr. J. J. O'Connor of Commonwealth Edison and members of his staf Ms. E. Adensam and Mr. A. Bournia of the NRC, Nuclear Reactor Regulation office also attende The discussions covered the status of such issues as outage and non-outage work request backlog, modifications, procedure changes, and the Nuclear Safety Review prior to Unit 1 startup. The discussions also addressed recent history of scrams, Engineered Safety Feature (ESF) actuations, recent personnel errors, and a missed chemistry surveillance. The licensee also addressed the actions it was taking in regard to the items identified by the Maintenance Assessment Report of December 31, 1985, (Inspection Reports No. 373/85032; 374/85033).

The Resident Inspectors addressed the station's good performance in housekeeping and the continued effort in maintaining a safe working

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environment'for their workers. Also, the work the-station-is doing to

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-install alarms on high radiation doors was thought to be good. The

inspectors addressed the NRC's concern over the increased personnel

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errors, the latest increase in ESF actuations, and the(increase in .

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' scrams. The particular personnel errors discussed were: 1)-the method ,

.by which personnel were installing jumpers required by procedures

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! causing ESF actuations; 2) the control of the feedwater system at low l powers and .3) the use of the Reactor Water Cleanup Systems. (See ,

Inspection Reports No. 373/86007; 374/86008).. These.are all known ,

j~ problems which have been at the station for a long tim The licensee agreed to address these issues to prevent reoccurrence. The meeting was .

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{' adjourned with an agreement to meet in one month in Region III to discuss additional progres '

i The inspector performed a review of the licensee's work request backlog commitments in relation to the licensee's response to the 10 CFR 50.54(f)

i letter. A review of Work Request backlog was done by the licensee to l i define the optimum backlog of Work Requests. LaSa11e's goal is to maintain a backlog of 1400 non-outage related Work Requests, which is to be attained i prior to Unit 2 fall refuel outage. As of April 16, 1986, the licensee +

had 1469 outstanding non-outage Work Request

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i The Total Job Management (TJM) computer printouts 1.ist the Work Request i number, whether outage /non-outage related, priority assigned, Technical Specification if applicable, and testing requirements if applicable.

i Through TJM, the licensee has the capability to sort the Work Request by

priority, departme.nt assigned, safety related, ASME Code related, and whether its a modificatio A review of the outstanding Work Requests for Unit 1 was done by the ,

j licensee to identify those with a safety impact. The review was done by *

l the individual departments which were assigned the Work Requests and the j Unit 1 Operating Engineer and the results cross compared. Of the 700

, outstanding Work Request with a safety impact on Unit 1, the licensee is i committed to having less than 300 outstanding Work Requests remaining '

! prior to startup of Unit 1. As of April 15, 1986, the licensee had 540 l outstanding Work Requests on Unit 1 and trending downward. The licensee ;

i has committed that the 300 outstanding Work Requests will h' ave no direct '

I safety impact on the Uni The licensee has identified eight repetitive equipment problems needing a long-term solution. The review was performed by the Maintenance

. Department and documented in a letter from the Production Superintendent

to the Services Superintendent. The projected completion dates to 3'

identify alternatives, feasibility / cost study, and schedule for.

implementation has not been determined pending Tech staff review.

j 1 Emergency Drill and Exercise (82206, 82301) '

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I On March 25, 1986, the station conducted a drill of the Generating i Stations Emergency Plan (GSEP). The drill started at approximately 8:00

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a.m. and continued until.3:00 p.m.. Region III personnel participated in the drill by responding to the site, Emergency Offsite Facility (EOF),

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be and the Incident Response Center (IRC) in Region III. The drill was conducted satisfactorily in preparation for the annual exercis On April 8,1986, the station conducted an annual exercise of GSEP. The exercise had involvement by NRC Region III and headquarters personne Also state and county officials participate The licensee manned the control room, the Technical Support Center (TSC), EOF, and its corporate headquarter center. The NRC manned the Region III IRC, EOF, site TSC, control room, and headquarter's IRC. The results of this exercise are documented in Inspection Report 373/86001; 374/8600 . Unresolved Items Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, violations, or deviations. Unresolved items disclosed during the inspection are discussed in Paragraph . Exit Interview (30703)

The inspectors met with licensee representatives (denoted in Paragraph 1)

throughout the month and at the conclusion of the inspection period and summarized the scope and findings of the inspection activities. The licensee acknowledged these findings. The inspector also discussed the likely informational contents of the inspection report with regard to documents or processes reviewed by the inspector during the inspectio The licensee did not identify any such documents or processes as proprietar _ __ _ , _ , ._ . .