IR 05000373/1986003

Insp Repts 50-373/86-03 & 50-374/86-03 on 860101-0212. Violation Noted:On 860121,Unit 2 HPCS Min Flow Valve Taken Out of Svc in Open Position W/O Regard for Applicable Tech Spec Procedures

ML20214E256
Person / Time
Site:	LaSalle
Issue date:	02/26/1986
From:	Wright G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20214E249	List: IR 05000373/1986003 ML20214E246
References
50-373-86-03, 50-373-86-3, 50-374-86-03, 50-374-86-3, NUDOCS 8603070222
Download: ML20214E256 (13)

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U. S. NUCLEAR REGULATORY COPHISSION REGION II Reports No. 50-373/86003(DRP);50-374/86003(DRP)

Docket Nos. 50-373; 50-374 Licenses No. NPF-11; NPF-18 Licensee: Commonwealth Edison Company Pcst Office Box 767 Chicago, IL 60690 Facility Name: LaSalle County Station, Units 1 and 2 Inspection At: LaSalle Site, Marseilles, IL Inspection Conducted: January 1 through February 12, 1986

Inspectors

M. J. Jordan

J. Bjorgen

R. Kopriva S. Stasek A. Morrongiello E. Hare

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W. Guldemond i Approved By:

b C G. C. Wright, Cl(lef Mh/

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l Reactor Projects Section 2C Date'

Inspection Summary i

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Inspection on January 1 through February 12, 1986 (Reports N /86003(DRP); 50-374/86003(DRP))

Areas Inspected: Routine, unannounced inspection conducted by resident inspectors and one regional inspector of licensee actions on previous inspection findings; operational safety; surveillance; maintenance; training

assessment; Licensee Event Reports Followup; and followup of 10 CFR 50.54(f)

request for information. The inspection involved a total of 465 inspector-

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i hours onsite by 7 NRC inspectors, including 93 hours0.00108 days <br />0.0258 hours <br />1.537698e-4 weeks <br />3.53865e-5 months <br /> onsite during off-shifts.

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' 8603070222 860226 3 DR ADOCK 0500 E__________

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Results: Of the seven areas inspected, no violations or deviations-were.-

identified in six areas; one violation was identified in the remaining area (failure to follow procedure - Paragraph 3). This violation is an example of an ongoing problem the license has in complying with all Technical Specification requirements when removing equipment from service for maintenance. The inspectors considered, however, that the operation of Unit 2 during the inspection period was professional and conducted with a conservative approach to safet \

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DETAILS 1. Persons Contacted

• G. J. Diederich, Manager, LaSalle Station

• R. D. Bishop, Services Superintendent

• C. E. Sargent, Production Superintendent D. Berkman, Assistant Superintendent, Technical Services W. Huntington, Assistant Superintendent, Operations J. C. Renwick, Assistant Superintendent, Work Planning M..Jetsy, Quality Assurance P. Manning, Tech Staff Supervisor T. Hammerich, Assistant Tech Staff Supervisor W. Sheldon, Assistant Superintendent, Maintenance The inspectors also talked with and interviewed members of the operations, maintenance, health physics, and instrument and control section * Denotes personnel attending the exit interview held on February 12, 198 . Licensee Action on Previous Inspection Findings (92701)

(Closed)OpenItem (374/84-07-03(DRP)): Licensee was to verify seismic qualification of various motor control centers that were modified. The licensee completed this analysis as documented in AIR 374-01-84-4070 (Closed) Open Item (373/83-53-11 and 374/83-56-03(DRP)): The action required when control rod " full-in" or " full-out" position indication is lost. License amendments 26 (Unit 1) and 14 (Unit 2) dated October 2, 1985 were submitted and approved to resolve this concer (Closed) Unresolved Item (374/84-07-01(DRP)): Apparent discrepancies in the Unit 2 Technical Specifications for primary containment isolation functions. License amendment 14 dated October 2, 1985 was submitted and approved to resolve this ite (Closed) Open Item (373/84-17-01(DRP)): The licensee was to resolve repeated problems with the Radwaste Drum Processing Unit (DPU) that caused overfilling of the drums. A related concern was poor housekeeping in the radwaste control room. The licensee replaced faulty circuit boards in the DPU control circuit and has revised procedure LOP-WX-03 to better control operation of the DPU. Housekeeping has improved in the radwaste control roo (Closed) Open Item (373/83-20-01(DRP)): The licensee was to resolve continuous alarm problems with the radwaste discharge Process Radiation Monitor (PRM) due to high background radiation levels. The PRM was relocated to a low background radiation area in the turbine building in accordance with modification M-1-0-83-2 .

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(0 pen) Violation (373/85017-04(DRP)): The licensee was to provide corrective action for failure to adequately calibrate the Automatic Depressurization System (ADS) actuation switches allowing inoperable switches to be returned to service. Procedure LIS-NB-104 was revised to minimize the potential for future errors. The licensee also committed to reviewing all instrument maintenance procedures which may contain similar problems and revise them, if necessary, by July 198 (Closed) Open Items (373/85016-08 and 374/85016-08(DRS)): These items documented completeness and legibility concerns with hard copy and

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microfilmed records of Inservice Testing (IST) activities. In response to these concerns, the licensee reviewed their IST records for activities conducted since each unit was placed in commercial service, ensuring their completeness. Additionally, a sample of microfilmed records was retrieved and checked for reproductibility with acceptable result (Closed) Open Items (373/85016-06 and 374/85016-06(DRS)): During a review of the licensee's IST program, it was identified that the program did not specifically identify closure test requirements for normally closed check valves. The licensee subsequently agreed to review their program, identify those check valves which have a safety-related closure function, and generate a cross reference between valves requiring closure testing and the procedures which assure valve closure capability. The inspector reviewed the results of the licensee's review, including the committed-to cross reference, and found them acceptabl (Closed) Unresolved Items (373/85016-07 and 374/85016-07(DRS)): These items tracked resolution of concerns relative to a lack of definitive guidance in the licensee's IST program for increased frequency testing of components tested only during cold shutdown. The inspector reviewed the licensee's revised IST program and determined that the indications requiring increased frequency testing are required to be resolved prior to plant recovery, thereby eliminating the need for increased frequency testin (Closed) Open Items (373/85016-01 and 374/85016-01(DRS)): These items tracked revision of the licensee's Inservice Testing (IST) program in response tc previously identified inspector comments relative to valves RV-18 and 19 and maximum valve stroke times. The inspector verified that the licensee revised their IST program, incorporating the previously identified comment (Closed) Open Items (373/85016-02 and 374/85016-02(DRS)): During a previous review of the licensee's IST program and associated administra-tive procedures, 10 specific weaknesses were identified. The inspector reviewed procedures LAP-100-12, LTP-600-4, LAP-1300-1 and determined that these procedures adequately addressed the identified weaknesse (Closed) Violation (374/85034-03(DRP)): The licensee failed to adequately document an engineering evaluation of replacement parts. The licensee conducted refresher training and revised procedure LAP 1300-1 to better control the evaluation of replacement part n

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(Closed) Open Item (373/83-01-03(DRP)): The licensee was to develop procedures for handling fuel and refueling. These procedures were satisfactorily completed prior to the Unit I refueling. The inspector reviewed these procedures while assessing the licensee's preparations for refueling as documented in Inspection Report 373/85-3 On January 15, 1984 Messrs. G. Diederich and C. Allen met with Messr L. Reyes, N. Choules, M. Jordan, R. DeFayette, and T. Taylor in the Region III office to discuss Inspection Report 50-373/85032; 50-374/8503 The licensee agreed to include the recommendations in Section 3 of the report on their tracking system, assign a cognizant person to each item and keep the region infonned of actions taken regarding the items. The Region informed the licensee that a followup inspection will be performed in the spring or summer of this year to evaluate the effectiveness of actions take . 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 buildings were conducted to observe 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 maintenance. The inspector, by observation and 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 January 1986, the inspector walked down the accessible portions of the following systems to verify operability:

Unit 2A Low Pressure Coolant Injection (LPCI) System Unit 1 and 2 Emergency Diesel Generators & Switchgear Unit 2 125 and 250 Volt Batteries and Switchgear Unit 2 Low Pressure Core Spray System During the report period, Unit I remained in Cold Shutdown with tha fuel removed from the reactor vessel. Major activities in progress it.c h ed repair and replacement of the main steam safety relief valves, control rod drive repairs, and several modifications to meet license commitment Unit 2 continued in power operations throughout most of the inspection perio _ _ _ _ _ _ . . _ _ - - - _ _ - _ _ _ _ _ _ - _ _ _ - - _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ - _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ - - _ _ _ - _ _ - - _ _ _ _

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P At 12:30 a.m. on January 21, 1986 with Unit 2 operating at approximately 90% power, the licensee removed the High Pressure Core Spray (HPCS)

minimum flow valve from service to adjust the limit switches. The valve was left in the open position and the power supply breaker was turned off. The valve and the HPCS system were appropriately declared inoperabl The day shift reactor operator coming on shift performed a walkdown of the control panels and recognized that the Technical Specification for primary containment isolation had not been addressed in taking the HPCS minimum flow valve out of servic Technical Specification 3.6.3 states in part, "With one (1) or more of the primary containment isolation valves inoperable maintain at least one (1) isolation valve operable in each affected penetration that is open and within four (4) hours restore the inoperable valve (s) to operable status or be in at least Hot Shutdown within the next twelve (12) hours

, and Cold Shutdown within the following twenty-four (24) hours."

The licensee correctly placed the HPCS minimum flow valve in the closed position at 8:50 a.m. on January 21, 1986. Because the licensee had not initially considered the primary containment isolation function of the valve, they were unaware that they had exceeded the four (4) hour time clock to regain operability of the valve and were in the Action Statement of having to take the plant to Hot Shutdown status. The licensee did not exceed the Action Statement time cloc Technical Specification 6.2.A requires, in part, " Detailed written procedures including applicable checkoff lists covering items listed below shall be prepared, approved and adhered to:

Item Preventive and corrective maintenance operations which could have an effect on the safety of the facility."

In accomplishing corrective maintenance, the licensee's Equipment Out-of-Service Procedure LAP 900-4, Revision 23, Section E.3, requires, in part,

"If the equipment being removed from service is safety related, review applicable Technical Specifications for limiting conditions for

! operations, required surveillance, time limits .... ."

Contrary to the above, on January 21, 1986 the Unit 2 High Pressure Core Spray (HPCI) minimum flow valve was taken out-of-service in the open position and all applicable Technical Specifications pertaining to this valve were not considered. The licensee addressed Technical Specifica-tion 3.5.1, Emergency Core Cooling Systems (ECCS) operability, but neglected Technical Specification 3.6.3, Primary Containment Isolation Valves which has a more restrictive Limiting Condition for Operation (LCO).

This is considered to be a violation (374/86003-01(DRP)).

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On January 22, 1986 with Unit 2 at 100% steady state power, the licensee noticed a significant increase in the offgas activity. Subsequent offgas sampling verified suspected leaking fuel. Pretreatment samples found noble gas (Xenon and Krypton) activity had increased approximately 30 time This activity increase, corresponding to approximately 6% of the allowable limit, lasted for several days at which time the activity began droppin As of February 5,1986, the pretreatment activity remained at approximately 2% of the Technical Specification limit of 3.4 E5 microcuries per secon The licensee's investigation and discussion with the General Electric Company determined that continued plant operation should not be adversely affected if activity levels remain reasonabl The licensee initially instituted a twice a week sampling program but has subsequently relaxed sampling to once a wee On January 25, 1986, while performing the weekly turbine surveillance LOS-TG-W1, the number one turbine bypass valve failed to fast open from the 90 to 100% open positions. The bypass valve was declared inoperable and a load reduction to less than 25% power was initiated to comply with Technical Specification 3.7.10 which requires that the plant be less than 25% power within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. Subsequent investigation found water and loose connections in the junction box for the fast actino solenoid. The loose connections were tightened and the junction box m s dried. The load drop was terminated at approximately 20% power.

On February 8, 1986, the number one bypass vdive again failed to fast open similar to the January 25, 1986 incident. A load reduction was again l commenced to accomplish repairs. Investigatior found a leaking flange in a drain line off the bypass valve which was spraving steam and water on the fast acting solenoid. A temporary cover was placed over the solenoid, and the surveillance was repeated satisfactorily. The load had been reduced to approximately 60% power. Due to the apparent unreliability of

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the solenoid, the licensee instituted an accelerated surveillance of the turbine bypass valves. The number one bypass valve again shewed hesitant i action on February 10, 1986. The licensee elected to shutdown to accom-

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plish repairs. The unit was taken to Hot Shutdown, the solenoid assembly

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was replaced, the leaking flange was repaired and the unit restarted on 4 the evening of February 11, 198 On February 11, 1986, the licensee contacted the inspector regarding a potential problem with the controls to a vital access area. The information was passed to the Ragion III security branch for followup during the next routine safeguards inspectio . Monthly Surveillance Observation (61726)

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The inspector observed Technical Specifications required surveillance testing on the systems or components identified in the following paragraphs and verified, for the 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 reviewed and resolved by appropriate management personne .

The inspector witnessed the following test activities:

The control room portions of the quarterly operational test of the Unit 2 High Pressure Core Spray (HPCS) System, LLP 85-1 No items of concern were identifie On January 8,1986 the licensee performed the quarterly operational test LOS-RH-Q1ofthe"2A"LowPressureCoolantInjection(LPCI) System. The operator noted an approximate 1000 gallons per minute (GPM) flow fluctua-tion upon reaching 6000 GPM. The system was declared inoperable while the problem was investigated. The inspector observed a repeat of the test and noted no abnormalities. The licensee suspects that the "2A" Residual Heat Removal (RHR) System heat exchanger was not completely filled and vented. The system was revented prior to the second test. Due to the possibility of water hammer having occurred, the inspector and licensee personnel walked down the "2A" RHR and LPCI piping looking for possible damage. No damage was noted. The inspector discussed the venting procedure with the licensee. Due to the system configuration and the operator judgement required during venting to determine that no entrapped air remains in the piping, a slight possibility exists that a small amount of air may remain in the system. The noted event is considered to be an isolated case and additional action is not considered warranted at this time.

5. 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 implemente Work requests 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 .

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The following maintenance activities were observed / reviewed:

The inspector observed the initial inspection of the Unit 1 "10-A" feedwater check valve (Work Request L 51592) to investigate the condition

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of the soft seal materia It was noted that the seal material showed the same amount of deterioration (wear and cracking) as found in March 1985 as noted in Report 373/85-09. The as-found leak rates for the feedwater check valves were:

10-A Inboard: 1892 Standard Cubic Feet Per Hour (SCFH)

32-A Outboard: 72.9 SCFH 10-B Inboard: 23 SCFH 32-B Outboard: Not Measurable (High)

The licensee is proceeding with repairs to all four valves. As was done on Unit 2, the licensee intends to eliminate the soft seal material on the irboard valves. No items of concern were identifie The inspector, as a continuation from the previous inspection report, continued to follow the progress of the Unit 1 mechanical snubber testing being performed in accordance with LTS 500-14 to comply with the testing requirements of Technical Specification 3/4.7.9. At the close of the

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inspection period, the snubber testing results are as follows:

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LaSalle has grouped snubbers into two " types" for purposes of sampling for testing under Technical Specification 3/4.7.9. Both types must satisfy the following equation: Total Number Tested =55 (1+C/2), C= Failures.

l Type 1 - PSA 1/4's and 1/2's:

, Total Tested: 311

] Total Failures: 40

Remarks: All 401 PSA 1/4's and 1/2 s to be tested this outag (67 more to go).

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, Type 2 - PSA l's, 3's, 10's, 35's, 100's:

Total Tested: 162 Total Failures: 5 Remarks: A total sample of 220 required. (55 more to test). One snubber, LP02-10595, was defective as purchased. It has a defective thrust bearing.

, The licensee will initiate a work request to pull and test another 27 l

snubber The failure modes and associated analyses were discussed with the license The majority of failures were readily identifiable as construction defi-ciencies such as foreign material (e.g. weld slag) becoming lodged in the snubber internals or manufacturing defects. Due to the increased scope of snubber testing, a regional specialist was advised of the licensee's actions and will evaluate the licensee's actions in a future inspection repor ..

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The inspector also observed the licensee's actions to troubleshoot and

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repair the Reactor Core Isolation Cooling (RCIC) System outboard steam isolation valve. On February 6, 1986, the licensee attempted to cycle the valve (2E51F008) to verify that it would perform its required primary

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containment isolation function. The valve had a known packing leak that

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properly cycle from the control room. The RCIC system was appropriately declared inoperable. At the close of this inspection period, the

inspectors continued to follow the licensee's actions regarding this valve. Several areas of concern still require resolution including the environmental qualification of the valve, and the results of the licensee's investigation into repeated rework on the valve. Until the

inspector followup)is (374/26003-02(DRP) . completed, this will remain as an unresolved item The inspe: tor followed the repairs to the 1E12F008 and IE12F009 Residual Heat Removal Shutdown Cooling Suction Valves (Work Requests 35151 and

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35150). The inspector reviewed the work procedures and observed the

. final blue check of the 1E12F008 valve. No items of concern were j identified.

1 Following the Induction Heat Stress Improvement (IHSI) process being I performed on the Unit 1 Primary Coolant Recirculation System piping, the licensee has identified two cracks on 12" diameter pipin The first crack, located on A Loop piping, is 3/4" long, circumferential, i and 28 per cent through-the-wal It was found near the weld on a piece of transition piping known as the pup piece. This is a section of piping connecting a jet-pump riser to a recirculation header. The second crack

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was located in the B Loop also on a pup piece, but closer to the recircula-

! tion header than the jet pump riser. This crack is circumferential, 1" long, and 22 per cent through-the-wall.

i These confirmed cracks and two additional indications are being evaluated

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by the licensee to determine a course of corrective action. A Region III 1 specialist was advised of the cracks and has been following the licensee's

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actions. The evaluation of these actions will be documented in a future

{ inspection report.

j 6. Training Assessment (41301, 41400)

The inspector reviewed the training records of licensee personnel

! performing the maintenance and surveillance activities identified in l Paragraphs 4 and 5 of this report. This review was conducted to assess the adequacy of training relative to the specific activities being

< performed. The training of operations personnel was considered to be adequate. The training of maintenance personnel, however, was found to be weak similar to the evaluation previously documented in Inspection

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Report 373/85032; 374/85033. It is recognized that the licensee is aware of this weakr.ess and is in the process of upgrading the training of I maintenance personnel. The progress of the upgrade program will be j evaluated ir. future inspection reports.

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Through direct observations, discussions with licensee personnel, and review of records, the following Licensee Event Reports (LERs) 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 /85041-00 High Pressure Core Spray (HPCS) System Low Level Initiation i Switch Malfunction. The malfunction was an actual ground on a switch terminal lead. The taped insulation had worn i through exposing wire. There was no reason found why taped insulation was worn throug /85040-00 Standby Liquid Control (SBLC) Concentration Hig Concentration was not obtained within allowable time per Technical Specifications. An Unusual Event was declared and a unit shutdown initiated. When correct concentration was obtained the unit shutdown and Unusual Event terminated. Further evaluation of this event and

. closure of open item 373/85033-01 turned over to regional l

inspector , Followup of 10 CFR 50.54(f) Request for Information (71707, 72400)

By letter dated November 22, 1985, NRC concerns related to the overall operation of the LaSalle County Station were transmitted to the licensee with a request for information in accordance with 10 CFR 50.54(f) regarding l how the licensee was going to address those concerns. On December 23, i 1985, Commonwealth Edison responded in a letter from Mr. Cordell Reed to i Mr. J. G. Keppler, and outlined a program where each of the areas of concern would be addressed. A second response was submitted on February 4, 1986 which further delineated the licensee's proposed actions and included

a more detailed schedule when each action would be complete The inspector performed a review of the following areas to verify the licensee's commitments as outlined in their responses and the adequacy of

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! Procedures Backlog

! From discussions with licensee personnel and from review of documentation outlining the procedure change program, the inspector determined the following actions were ongoing at the station for better management control of this specific program.

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- A computer tracking system has been created to maintain current

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status of outstanding procedure changes.

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- A streamlining of the procedure change process is currently underwa Changes are now initially made prior to receipt by central file (which " officially" generates a formal proposed change) as opposed to the previous method where a change was only submitted after central file created a formal change reques The licensee is proposing to rewrite the administrative procedure which controls the procedure change process to better clarify it and to make it easier to follo A proposal is under review to streamline the current signature chain which is required to issue procedure change Each procedure change is now prioritized with the lowest priority requiring a turnaround within 90 day Another computer tracking system is being developed to provide a monthly turnaround report to track and trend times to process each procedure chang The licensee t:lieves that by using a 90 day turnaround rate, approximately 300-350 procedures changes outstanding at any particular time will be a manageable quantity. If the 90 day turnaround time cannot be met in any case, further actions are to be taken by plant management to ensure the proposed change is made in a realistic timefram The inspector observed, however, that the 90 day time limit is not specifically outlined in administrative procedures to date, nor are the specific actions to be taken if the time limit is exceede Presently, the licensee has approximately 800 procedure changes outstanding. This is a substantial decrease from the original of 1200

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outstanding in November 1985. The inspector performed a review of selected procedure changes completed in the three month period November 1985 - January 1986 including 5 operations surveillances, 4 system operating procedures, 2 instrumentation surveillances, 1 general operating procedure, 6 electrical surveillances, and 9 technical staff surveillances. The review indicated the procedure changes made in the aforementioned timeframe resulted in procedures of acceptable quality being issue The licensee plans to re-review the implementation of the procedure change program in April 1986 to determine acceptability of results achieved. A further review by the inspector will be conducted subsequent to the licensee's review in April to further ascertain progress in this are . 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 .

10. Exit Interview (30703)

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

throughout the month and at the conclusion of the insna '. ion period and summarized the scope and findings of the inspection sities. The licensee acknowledged these findings. The inspec . 30 discussed the likely informational contents of the inspection re, t 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 .

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