IR 05000373/1987011
| ML20213G983 | |
| Person / Time | |
|---|---|
| Site: | LaSalle  |
| Issue date: | 05/08/1987 |
| From: | Ring M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20213G960 | List: |
| References | |
| 50-373-87-11, 50-374-87-12, NUDOCS 8705190078 | |
| Download: ML20213G983 (23) | |
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I U. S. NUCLEAR REGULATORY COMMISSION
REGION III
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Report Nos. 50-373/87011(DRP);50-374/87012(DRP)
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Docket Nos. 50-373; 50-374 Licenses No. NPF-11; NPF-18 Licensee: Comonwealth Edison Company Post Office Box 767 Chicago, IL 60690 Facility Name: LaSalle County Station, Units 1 and 2
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Inspection At: LaSalle Site, Marseilles, IL
i Inspe:: tion Conducted: March 10 through April 24, 1987 Inspectors: M. J. Jordan
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R. Kopriva J. Malloy Approved By: M. Ring, Chief T M M7 '7
- ReactorProjectsSectio/1C Ddte'
Inspection Suninary Inspection on March 10 through April 24, 1987 (Reports No. 50-373/87011(DRP);
I 50-374/87012(DRP))
Areas Inspected: Routine, unannounced inspection conducted by resident
- inspectors of licensee actions on previous inspection findings; operational
- safety; surveillance; maintenance; training; Licensee Event Reports; transportation of radioactive waste shipments; spent fuel pool activities;
) unit trips; design changes and modifications; and enforcement conference.
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Results: Of the eleven areas inspected, two violations were identified in two of the areas. One violation pertains to overfilling of the shipping cask well (Paragraph 3.d.) and one violation is associated with exceeding a Limiting Condition for Operation (LCO) (Paragraph 4.e.).
The operations department performed well in their recognition of a change in plant conditions. When the drywell cooler fan tripped on Unit 1, operations was aware of the change in drywell parameters through control room indications
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and promptly and correctly took appropriate actions. The outage planning and i scheduling continues to be effective as the current refueling outage is on I schedule.
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DETAILS Persons Contacted i
Commonwealth Edison Company (CECO)
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+* J. Diederich, Manager, LaSalle Station R. D. Bishop, Services Superintendent
- J. C. Renwick, Production Superintendent i D. Berkman, Assistant Superintendent, Work Planning '
+*W. Huntington, Assistant Superintendent, Operations I
- P. Manning, Assistant Superintendent, Technical Services T. Hammerich, Assistant Technical Staff Supervisor W. Sheldon, Assistant Superintendent, Maintenance J. Atchley, Operatina Engineer
+*R. W. Stobert, Qdality Assurance Supervisor D. Enright, Quality Assurance Engineer
- M. Richter, Assistant Technical Staff Supervisor
+L. O. DelGeorge, Assistant Vice-President
+ L. Graesser, Division Vice-President
+ L. Trubatch, Staff Attorney
+L. F. Gerner, Regulatory Assurance Superintendent
+ M. Allen, LaSalle Licensing Administrator
+ S. Turbak, Licensing Director, Operating Plants
+W. P. Sly, Shift Engineer, LaSalle Station
+W. F. Bejlovec, Instrument Foreman, LaSalle Station
+D. E. Paquette, Assistant Superintendent, Braidwood Station
+J. R. Phillips, Instrument Work Analyst, Braidwood Station
+S. J. Hedden, Master Instrument Maintenance, Braidwood Station U. S. Nuclear Regulatory Commission-(USNRC)
+ J. Paperiello, Acting Deputy Regional Administrator ^
+ E. Norelius, Director, Division of Reactor Projects
+ F. Warnick, Chief, Reactor Projects Branch 1
+M. A. Ring, Chief, Reactor Projects Section 1C
+M. J. Jordan, Senior Resident Inspector, LSCS
+*J. A. Malloy, Resident Inspector, LSCS
+B. A. Berson, Regional Counsel
- R. A. Kopriva, Resident Inspector, LSCS
+ Denotes those attending the Enforcement Conference at RIII on April 24, 198 * Denotes personnel attending the exit interview on April 21, 198 Additional licensee technical and administrative personnel were 1 contacted by the inspectors during the course of the inspectio I i
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. . Licensee Action on Previous Inspection Findings (92701)
(Closed) Violation (374/86040-03(DRP)): On Lctober 16, 1986, the reactor vessel residual heat removal cut-in permissive pressure high did not have the minimum operable channels per trip system and the affected system isolation valves were not locked closed within the allowed LC0 time limi The problems which led to this condition, failure of second verification and monitoring of plant status, are separate violations (373/86040-01 and 373/86040-02). The actions taken to correct the violation are adequate. This item is considered close <
(Closed) Violation (374/86046-01(DRP)): On January 6, 1987, the Unit 2 125V battery 2B service test discharge procedure, LTS 700-7, was found to be inadequate. The test procedure did not require Unit 2 Division II 125V batteries to be declared inoperable and entered into the Degraded Equipment Log when the test put the bitteries in an inoperable condition due to the discharg Also, procedure LOP-DC-07, " Battery Equalizing Charges", was found to be inadequate in that the procedure did not state or reference the Technical Specification category B requirements for operability of batteries and ser:e hanawritten instructions misled the operator resulting in the' Unit 1/ Unit 2 Division II 125V batteries being uncrosstied prior to the Unit 2 Division II 12EV batteries being operabl ,
All service and performance battery test procedures were revised to ^
require all batteries under test to be declared inoperable. The lessons
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learned fren this event have been combined into the current licensed operator retraining module. The inspector has found these corrective actions adequate. This item is considered close (Closed) Unresolved Item (374/87006-01(DRP)): On February 17, 1987, at 3:18 p.m. (CST), during the performance of LIS-VR-03, " Response Time Testing of the Secondary Containment Radiation Monitors Surveillance",
Unit 2 recaived a Group IV isolation caused by removal of a jumper prior ,
to resetting the Primary Containment Isolation System (PCIS) logi CFR 50, Appendix B.Section VI, Document Control, states in part,
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....such as instructions, procedures, and drawings, including changes thereto, which prescribe all activities affecting quality. These measures shall assure that documents, including changes are reviewed for adequacy and approved for release ....". Contrary to the above, precedure LIS-VR-03 was found to be inadequate in that it did not specifically prevent the Group IV isolation. However, due to the licensee's response to the event and the fact that the licensee did meet the criterin in 10 CFR 2, Appendix C, Section V, under Enforcement Action, no violation will be issue The licensee corrected the procedure to reflect the proper sequence for resetting the isolation and removing jumpers and instructed station personnel on the even The inspector has reviewed the licensee's corrective actions and finds these actions adequate. This item is considered close ,
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(Closed) Open Item (374/86044-01(DRP)): On November 7,1986, Control Rod Drive #42-47 slowly drifted in when given an insert signal during
, a weekly surveillance. Metallic chips were found in the 123 insertion valve lodged under the valve seat. The metallic chips were analyzed
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and found to be of the same material as the valve body and the chips appeared to have come from the manufacturing of the valve. The metallic chips appeared to have been left in the valve body from improper cleaning of the valve. The licensee has contacted the manufacturer, General ElectMc, concerning this item and has checked other similar valv's e for the same problem. No other occurrences were noted and the licensee believds this to be an isolated case. The resident inspector finds these actions appropriate, but will monitor work in this area through routine inspection. This item is considered close (Closed) Open Item (373/86044-01(DRP)): This item pertains to control rod 10-47, which, on November 22, 1986, became uncoupled from its control rod drive during a weekly surveillance. Subsequently, W control rod was believed to be coupled, but the licensee has been unable to verify the coupling through the normal methods of a coupling check. The licensee has received a special Technical Specification change fer the operation and verification of coupling for control rod 10447. The inspector has reviewed the Technical Specification change and observed the licensee's operation of control rod .10-47 and finds the licensee's actions in compliance with their Technical Specifications. This item is considered close (Closed) Violation (373/85013-02iDRS); 374/85013-02(DP.S)): This item documented a failure to retain and maintain records fi1dicating that relay No. 1427-AP040X1 was replaced. This relay is utilized as an undervoltage relay for detecting undervoltage conditions and in load sheddirg of Safety Systems ESS 4160V switchgear. The inspector verified that during the first Unit i refuel outage, the 48 VDC HFA relay was removed and replaced with 125 VDC HFA relay in modification M-1-1-82-284. Document-A ation for replacement of relay No.1427-AP040X1' war verified in '
modif:cction package M-1-1-82-284. The inspector, after review of the package, finds these actions acceptable. This item is considered close (Closed) Open Item (373/33-49-10(DPRP)): This open item tracked the corrective acticns committed to by the licensee in response to violation 373/83-49-09. The form used on site to document telephone communicatio's n has been modified to require more detailed information and prompt clarificaticn of the subject discus:ed. LAP 1300-2, " Plant Hodifications,"
has been revised to require documentation of advance approval via a telephone memorandum by Station Nuclear Engineerin LAP 1300-2 also was revisad to require the responsible engineer to review the formal modification approval letter upon receipt on site. Training was also ,
conducted with those members of the Technical Staff and Station Nuclear Engineering' Department involved in plant modifications on violation (
373/83-49-09. The inspector finds these actions accep, table. This item is considered close i
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(Closed) Open Item (373/83042-06(DPRP)): This open item tracked the use of fast blow fuses in safety related Heating Ventilation Air Conditioning (HVAC) circuitry that requires slow blow fuses. The operators and maintenance personnel were trained on replacing fuses with the proper fuses. An investigation was made of other circuitry to determine if other circuitry requires slow blow fuses. Modification 1-1-83-131 was completed on May 12, 1986. This modification replaced fuses in circuits feeding three or more actuators in parallel per the investigation. The inspector finds the licensee's actions adequat This item is considered close (Closed) Open Item (373/85023-07(DRP); 374/85018-09(MP)): This July 19, 1985, Confirmatory Action Letter open item tracked the documented review of surveillances on EQ equipment prior to performance to ensure quali-fication is preserved. This review applied to all surveillances on EQ equipment initiated subsequent to July 19, 1985, and continued until the surveillance procedures had been updated to reflect EQ requirements. In Inspection Report 373/87003 and 374/87003, the inspectors reviewed the EQ surveillance program and found the licensee established an adequate EQ program in compliance with the requirements of 10 CFR 50.49. This item is considered close (Closed) Open Item (373/85023-08(DRP); 374/85018-10(DRP)): This July 19, G85, Confirmatory Action Letter open item tracked the review of one EQ component of each type for all EQ binders that have been issued to the site for which a site review has been performed. This review ensured that all appropriate EQ requirements were accomplished during installatio In Inspection Report 373/87003 and 374/87003, inspectors reviewed over 42 equipment qualification files for evidence of the environmental qualification of equipment within the scope of 10 CFR 50.49 and evidence of equipment qualification to NUREG-0588 Category II. The inspectors determined that the EQ files were acceptable. This item is considered close (Closed) Open Item (373/85023-09(DRP); 374/85018-11(DRP)): This July 19, 1985, Confirmatory Action Letter open item tracked the review of all EQ binders that have been received by the site, but had not yet been reviewed by September 2, 1985, to ensure that appropriate EQ requirements were accomplished during installation. In Inspection Report 373/87003 and 374/87003, the inspectors reviewed over 42 equipment qualification files for evidence of the environmental qualification of equipment within the scope of 10 CFR 50.49 and evidence of equipment qualification to NUREG-0588 Category II. The inspectors determined that the EQ files were acceptable. This item is considered close (0 pen) Open Item (373/85023-06(DRP); 374/85018-08(DRP)): This July 19, 1985 Confirmatory Action Letter open item tracked the implementation of a documented review of all environmental qualification (EQ) work requests prior to performing the work to ensure that qualification is preserved. This review applies to all EQ work requests initiated subsequent to July 19, 1985, and will continue until maintenance procedures have been updated to reflect EQ requirements. Maintenance procedures continue to be updated until the end of 198 i
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The inspector will follow this item through routine inspection. This item will remain ope flo violations or deviations were identified in this are . 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 Unit I and 2 reactor buildings and turbine buildings were conducted to observe plant equipment conditions, including potential fire hazards, fluid leaks, excessive vibrations, and to verify that maintenance requcsts 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 controls.
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During the txnth of March 1987, the inspector walked down the accessible portions of the following systems to verify operability:
Unit 1 Standby Gas Treatment System Unit 1 Standby Liquid Control System Unit 2 High Pressure Core Spray System On March 12, 1987, at 5:30 p.m. (CST), while operating at approximately 56% power, the Unit 1 Reactor Operator noticed an increase in the upset level, shutdown level, and drywell pressur Prcirpt investigation into the cause of the problem determined that the "B" drywell fan motor failed. The backup primary containment breaker tripped and the primary containment breaker did not tri The control room indication still showed the fan being powere Once the licensee determined the problem was in the fan motor and not the breakers, a shutdown of the unit was commenced at 9:45 While shutting down at 1:30 a.m. on March 13, 1987, the licensee declared an Unusual Event emergency classification required by their emergency procedures due to a required Technical Specification l shutdown. Technical Specification 3.6.1.7 required a commencement of a shutdown within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> if the average drywell temperature was i greater than 135 degrees F. The licensee was unable to determine l the average drywell temperature because the temperature monitors for average drywell temperature were indicating improperly due to the improper air flow. The flow from the operating 1A drywell fan l was flowing back through the shutdown IB fan. The licensee took the conservative action and shut the unit dow *
The licensee was able to terminate the Unusual Event on March 13, 1987, at 12:10 p.m. after entering the drywell and closing two
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dampers on the discharge of the IB drywell cooler fan. This then stopped the reverse flow through the IB fan ventilation duct work and allowed the accurate reading of i.he thermocouple on the suction to the 1A drywell cooler fa The inspector reviewed this event and determined that in October 1984, the licensee had a problem with the actuators for the drywell dampers (1VP14YA, IVP14Y8, IVP07YA and IVP07YB), and at that time they disconnected the actuators and wired the dampers open in accordance with an out-of-service (00S). The fans and dampers were originally designed to operate together, such that with a fan off, the associated isolation dampers would also have been closed. The 00S changed the design such that, with a fan off, the associated dairpers would not close. The cooling air from the operating fan would then circulate back through the shutdown fan ventilation system and discharge back into the bottom of the drywell and not force cool air into the upper parts of the drywell. The temperature monitors for drywell average air temperature are located in the bottom of the drywell near the irlets to both A & B drywell cooler Thus, the temperature instruments used in determining the average drywell air temperature required by Technical Specification 3.6. were no longer valid with one of the fans not operating. The system design was changed from two independent systems with one fan each to one combined system with two fan CFR 50.59 states licensed facilities may make changes in the facility as described in the Safety Analysis Report without prior commission approval unless the proposed change involves a change in the Technical Specifications or an unreviewed safety question. It requires records of the written safety evaluation which provides the bases for determining that a change does not involve an unre-viewed safety question. Quality Procedure 3-51, " Design Control for Operations - Plant Modifications," identifies the licensee's quality program for the documentation of the 50.59 review. The licensee implements QP 3-51 via LAP 1300-2, " Plant Modifications," for the 50.59 review for a permanent plant modification, and via LAP 240-6,
" Temporary System Changes," for the 50.59 review for a temporary plant tredification. The procedure LAP 900-4, " Equipment Out-of-Service Procedure," did not require a 50.59 revie Subsequent to the inspector's identification of a need for a 50.59 review on the change in damper operation, the licensee issued a temporary system change in accordance with LAP 240-6, performed a 50.59 review, and determined that the Technical Specification change was not warrante The licensee failed to perform and document a 50.59 review on the change to the facility when they wired open the dampers in the drywell which changed the drywell ventilation system from two independent systems with one fan each into one system with two fan The consequences of changing the drywell ventilation system could have resulted in a need for a change to Technical Specification
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3.6.1.7 to reflect that with either one or both drywell coolers not operating, the average drywell temperature could no longer be accurately measured and action to shutdown the unit should begi This is considered an unresolved item until the inspector determines if a Technical Specification change should have been sought (373/87011-01(DRP)). While cooling down Unit 1 on March 14 and March 21, 1987, the licensee was unsuccessful twice in opening the inboard shutdown cooling isolation valve (iE11'-F009) from the control room. The inboard and outboard isolation valves (1E12-F009 and IE12-F008)
to the Residual Heat Removal (RHR) system need to be opened in order to establish the path for shutdown cooling flow to cool down the reactor below 212 degrees F using the RHR system. This is the third time this year the licensee vas unable to open the inboard isolation valve for shutdown cooling from the control roo The other time was on February 13, 1987. This problem has occurred several times in the past and procedures were changed to allow for opening the valve in a particular sequence, and from September 30, 1984, until February 13, 1987, the valve worked successfully from the control roo Each time the valve failed to open, the licensee entered the drywell and assisted in the opening of the valve. The concern the inspector expressed to the licensee was that the containment would not be accessible during a loss of coolant accident and shutdown cooling using the normal shutdown cooling mode of RHR may not be achievable since opening of the "9" valve is not predictabl Thus, an alternate method of shutdown cooling would need to be initiated which entails flooding up through the safety relief valves and cooling the suppression pcol using the RHR syste This alternate shutdown cooling system is recognized in the licensee's Final Safety Analysis Report, however, the use of the RHR system through the normal shutdown cooling mode is the most desirable. The licensee has initiated a plan to investigate and evaluate actions to be taken to establish reliability in opening the inboard isolation shutdown cooling valve remotely. This includes an engineering evaluation on replacing the operator with a larger operator, looking at replacing the disk, and doing work on the seat during the upcoming June outage. Also, replacement of the valve in the future with another valve was being looked at. This item will remain as an open item until the licensee has determined the cause of the failures and the final corrective action on the valve (373/87011-02(DRP)).
d. On March 18, 1987, at 3:15 p.m. (CST), the Unit 2 nuclear station a operator (NS0) directed the Unit 2 equipment attendant (8 operator)
to open the cycled condensate fill valve to the Unit 2 fuel pool skimmer surge tank to increase the surge tank level. The B operator proceeded to the Unit 2 reactor building 832' elevation to the location that he thought was correct, knowing the valve location on Unit 2 is different from the location of the Unit 1 valve. At
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the valve which he had always believed to be the skimer surge tank fill valve (only valve in that room), he read the valve tag which read " fuel pool transfer canal fill from CY Stop (2FC111)".
Believing it to be the correct valve, he opened it approximately 3/4 full open. After 5 minutes, he became concerned because the Unit 2 NS0 had not called to indicate that the skimer surge tank was full and that he should close the valve. He left the room and called the NS0 to ask him if the surge tank was full. The NS0 ir.dicated that the tank was filling slowly. It was filling slowly from the cask well through the weir gate to the Unit 2 fuel poo At that time, the B operator decided that something must be wrong, and proceeded back into the room to close the valve that he had opened. After closing the valve, he observed dripping water coming from a ventilation duct, but did not realize what had happene The B operator called another equipment operator (EO) about the situation. The equipment operator asked him his location and which valve he had opened. The B operator informed the E0 that he was on the Unit 2 832' elevation and that he had opened the 2FC111 valv At that time, the equipment operator indicated that he thought the B operator may have opened the wrong valve and he immediately went to the Unit 2 832' elevation to assist the B operator. At this time, both operators realized that water had actually filled the shipping cask and had been overflowing into the ventilation system and they immediately notified the Unit 2 shift foreman. The shift foreman went to the area at approximately 3:55 p.m. where he observed water on the floor in the sipping room. The shift foreman discussed the situation with the operators briefly before walking down Unit 2 and Unit 1 reactor buildings looking for water on the floor. They notified the shift engineer and requested Rad / Chem to assist in locating and controlling the spread of contaminatio The plant public address system was used to warn people to stay clear of Unit 2 reactor building, all elevations, and all exits were roped off. Rad / Chem technicians were dispatched to escort contaminated individuals to the decon shower area and assist in decon. There were only 3 people with slight contamination on their shoes. A control point was set up at ^.he Unit I recctor building at the door between the units with Rad / Chem technicians stationed to frisk people out of Unit The stationmen foremen were called to clean up the contamination and station construction volunteered their laborers to assist in order to get the contractors back to work in Unit 2. They also mopped Unit 1 740' elevation and 710' elevation to limit the chance of contamination being tracked through these area The level of contamination was not high and was not in the heavily traveled areas. Estimates are that less than 100 gallons of water overflowed into the vent ducts, of which approximately 30 gallons leaked out onto the floors. Operators and Rad / Chem technicians installed drip trays and catch cones under the leaks and directed
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them to floor drains. Mechanical maintenance personnel were requested to open the vent duct drain plugs and drain the water to the floor drain The ventilation duct work and surrounding equipment was inspected for water damage and none was found. The ventilation system was operating and continued operating for the entire event with no problem Technical Specification 6.2.A states, in part, " Detailed written procedures including applicable checkoff lists covering items listed below shall be prepared, approved and adhered to:
l The applicable procedures recommended in Appendix 'A' of Regulatory Guide 1.33, Revision 2, February 1978."
Contrary to the above, procedure LOP-FC-03, " Fuel Pool Cooling System Startup, Operation, and Level Changes of the Fuel Pool Skimmer Surge Tank," was not reviewed or adhered to by either the equipment attendant (B operator) or the Unit 2 NSO prior to the jo This is a routine operation that is typically performed once each shift. The equipment attendant had never performed this evolution on Unit 2, but had done so many times on Unit 1. From his training, he had always thought the valve he opened was the skimmer surge tank I
fill valve, thus he had a pre-conceived notion that it was the )
correct valve that he operate This is considered a violation (374/87012-01(DRP)).
e. On April 10, 1987, at approximately 4:30 p.m. (CDT) while performing surveillance LIS-NB-202, " Unit 2 Reactor Vessel Low-Lou Water Level Main Steam Isolation Calibration," the licensee experienced a Group II outboard isolation, isolating the outboard isolation valves for both the primary containment ventilation and the reactor building '
closed cooling water systems. The cause of the isolation was a bad relay (the drywell pressure #2C71-K4D1) in one channel. The surveillance required jumpering out the other channel and when the jumper was installed, the isolation occurred. All systems responded as expected. Once the cause was identified, the isolation was reset and the relay replace On April 13, 1987, at approximately 6:50 a.m. (CDT), the licensee received an Engineered Safety Feature (ESF) actuation of the "A" control room ventilation train from the "B" ammonia detector. The i
I control room ventilation system isolated when the chemical cassette for the ammonia detector got jammed. All systems responded as expected. The chcc/ cassette was replaced and the isolation reset.
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. . On April 15, 1987, at approximately 11:31 a.m. (CDT), the Unit 2 Residual Heat Removal (RHR) Shutdown Cooling inboard isolation valve (2E12-F009) received an isolation signal and isolated. The licensee was performing the RHR Shutdown Cooling Suction Pressure Isolation Valves Water Leak Test 2E12-F008 and 2E12-F009 (LTS 900-7).
The system had been isolated and pressurized with the 2E12-F009 valve open while performing the leak rate test on the 2E12-F008 valve. The cause of the isolation was due to the actuation of the Division II differential pressure switch located between the F008 and F009 valves, which -indicates high flow. The valves to the differential pressuN switch had been closed per the procedur Leakage by one of the pressure switch valves pressurized the switch beyond its setpoint. Upon receiving the isolation signal, the F009 valve closed. All systems functioned as expected and the isolation was rese On April 16, 1987, at approximately 10:29 a.m. (CDT), the Unit 1 breaker for the reactor building ventilation dampers, MCC136X1D1, was opened. The cause of the breaker closure was a drop cloth used to protect the Motor Control Center from paint, which fell, catching the breaker handle and opening the breaker. The breaker opening caused the reactor building ventilation dampers to fail close The closure of the dampers caused the reactor building fans to trip. Closure of the reactor building dampers also occurs upon receipt of a secondary containment isolation signal. At approx-imately 10:58 a.m., the licensee reenergized the reactor building ventilation damper breaker, opened the dampers, and restarted the reactor building fans. All systems functioned as expected. The inspector reviewed the licensee's actions and the event. The licensee has issued directions on protecting the MCCs appropriatel Their actions are appropriat One violation, one unresolved item, and one open item were identified in the review of this functional are . Monthly Surveillance Observation (61726)
The inspector observed Technical Specification required surveillance testing and verified for actual activities observed that testing was performed in accordance with adequate procedures, that test instrumenta-tion was calibrated, that Limiting Condit!cns for Operation were met, that removal and restoration of the affected components were accomplished, that test results conformed with Technical Specification and procedure requirements and were reviewed by personnel other than the individual directing the test, and that any deficiencies identified during the i testing were properly reviewed and resolved by appropriate management personne )
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During the inspection period, the resident inspector followed the complete surveillance of LOS-HP-Q1, "High Pressure Core Spray (HPCS) l Inservice Test," covering the work request, out-of-services placed on the system, procedure review, observation of the actual surveillance, and post surveillance testing and revie !
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The inspector witnessed portions of the following test activities:
LIS-NB-106 Unit 1 Reactor Vessel Low Water Level Confirmed Automatic Depressurization System (ADS) Permissive Calibration LIS-NR-201 Unit 2 Source Range Monitor Rod Block Calibration LIS-NR-312 Unit 1 Average Power Range Monitor Rod Block and Scram Functional Test For Single Reactor Recirculation Loop Operation P On March 6, 1987, an engineer and an electrician were performing approved testing on modification M-1-2-82-014. This nx:dification relocated controls and instrumentation on the 2A Diesel Generator which could have been affected by engine vibration. While performing the modification test, the electrician mistakenly placed the jumpers and lifted the lead on terminal block 12, when the test procedure specified the jumpers and leads on terminal block 11. The error was not detected during the second verification performed by the enginee Since the jumpers used were the " switching" type, no action occurred until the jumpers were switched to the "on" position. When one of the jumpers was switched on, a 125V DC positive ground alarm annunciated. The unit operator imediately resporded to the alarms by notifying the engineer that the modification test might be causing the ground. At this ti.e. the engineer and electrician opened the test switch which resulted in the alarm clearing. The other jumper was momentarily closed causing a relay from the diesel generator DC lube oil pump to energize. At the request of the unit operator, the jumpers and lifted leads were returned to the original status, and testing was halted until the engineer identified that the jumpers had been installed on the wrong terminal block and notified his superviso The modification test was restarted after it was determined that equipment had not been damaged and the test procedure was verified correct. The jumpers were properly placed and the remainder of the test was performed satisfactoril An enforcement conference was held on February 13, 1987, in the Region III office on second verification problems. As a result of that meeting, escalated enforcement was not proposed, however, the licensee presented a program to prevent second verification errors and improve operator awareness. The licensee has comitted to full implementation of this program by May 1, 1987. Since the above second verification error occurred on March 6,1987, the licensee did not have adequate time to implement their corrective action program Therefore, at this time, a Notice of Violation !
I will not be issue OnMarch7,1987,at11:10a.m.(CST),whileperformingsurveillance LOS-HP-Q1, "HPCS System Inservice Test for Operating, Startup, Hot ,
Shutdown, Cold Shutdown and Refuel Conditions When CY Lines Are l
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Isolated," the High Pressure Core Spray (HPCS) water leg pump discharge check valve, IE22-F007, failed to close. The licensee declared HPCS inoperable and entered a fourteen day LCO. The licensee disassembled the check valve to clean and lubricate valve parts. The valve was reassembled and satisfactorily tested for leakage. On March 8,1987, at 3:00 p.m., HPCS was declared operable, On March 28, 1987, at 10:28 p.m. (CST), during the performance of Operating Surveillance LOS-RI-Q3, " Reactor Core Isolation Cooling (RCIC) System Pump Operability and Valve Inservice Tests," on Unit 1, the RCIC water leg pump tripped on breaker thermal overload Attempts to restart the pump were unsuccessful and mechanical binding sounds were noted locally at the pum One portion of the surveillance tests the RCIC pump suction from suppression pool check valve in accordance with the licensee's Inservice Testing Program. During this portion of the surveillance, flow is induced through the suppression pool check valve by the operating RCIC pump by opening the RCIC pump suction from the suppression pool stop valve. This valve is electrically interlocked with the RCIC pump suction from Condensate Storage Tank (CST) stop valve such that when the suppression pool stop valve is opened, the CST stop valve automatically closes. The closing of the CST stop valve caused the operating RCIC water leg pump to lose its suction from the CST. The Unit 1 RCIC system was declared inoperable in accordance with Technical Specification 3.7.3. A work request was initiated to repair the pump. At the time of this event, Unit 1 was in Operational Condition 1 (Run) at 57% powe The failure of the RCIC water leg pump was due to a procedural inadequacy in LOS-RI-Q3. When opening the RCIC pump suction from the suppression pool stop valve, LOS-RI-Q3 only directed the unit operator to verify that the RCIC pump suction from the CST stop valve closes. The procedure did not direct the unit operator to shut off the RCIC water leg pump prior to the closing of the CST stop valve. The RCIC water leg pomp lost its suction source (CST)
and appears to have failed due to potential excessive vibration, flashing, and/or cavitation across the pump impelle Preliminary inspection of the failed water leg pump revealed that the retaining ring / snap ring for the thrust bearing housing had failed. In addition, the thrust bearing housing was broken. The initial trip of the water leg pump was probably caused by the failure of the retaining ring which allowed the pump impeller to come in contact with the pump housing. It is possible that the attempted restarts of the pump may have caused the bearing housing to brea ... -
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Consequences of this event were minimal due to the fact that the High Pressure Core Spray System (HPCS) was operable in compliance with action statement "b" of Technical Specification 3. The licensee replaced the RCIC water leg pump and tested the new pum Also, LOS-RI-Q3 has been revised to incorporate precautions and steps to ensure that the RCIC water leg pump is shut off prior to closing the RCIC pump suction from CST stop valv By 2:10 p.m., on April 2, 1987, the Unit 1 RCIC system was declared operable. The damaged RCIC water leg pump is still being inspecte The resident inspector will follow the licensee's investigation for the RCIC pump failure. This will remain an open item 373/87011-0 On March 31, 1987, at 10:25 p.m. (CST), the licensee was performing logic testing on the RCIC system high flow isolation switch (IE31-N013AA). The instrument maintenance department had finished the physical work associated with the response time testing of the high flow switch and had notified the shift engineer that they were finished working on the switch, and had turned the paper work in for further review prior to final sign offs. At approximately 12:15 a.m. on April 1, 1987, the RCIC system unexpectedly isolated on high steam flow. The licensee determined that the isolation occurred due to a packing leak on the high side vent valve packin This packing leak drained the high side reference leg. No isolation valve movement occurred due to the fact that the isolation valves were already closed due to the logic testing surveillance and had remained closed while the paper review was being complete At the time of the isolation, the RCIC system had already been declared inoperable due to a faulty RCIC water leg pump. The licensee thought that since the RCIC system was still out-of-service for review of the completed surveillance and inoperable, the Engineered Safety Feature (ESF) actuation notification was not necessary. Dayshift management review of the event determined that notification was warranted and made the notification to the NRC at 10:20 a.m. on April 1, 1987. Once the licensee recognized the need to make the notification, they complied with the four hour notifi-cation as specified in 10 CFR 50.72. The licensee took corrective action and repaired the packing leak in the high side vent valve and tested the system. Further action taken was a notice to shift and operating engineers from the station management on the timeliness of reporting ESF actuations. The resident inspector will monitor the licensee's actions of NRC notifications on ESF actuations through the routine inspection progra e. On April 2,1987, at 4:35 p.m. (CST), while operating at 56% power, an afternoon shift instrument technician noticed when reentering surveillance LIS RP-08, " Primary Containment High Pressure Scram and Secondary Containment Isolation Response Time Test", that the drywell pressure switch, JC71-N002A, had been valved out-of-service and was inoperable. The instrument technician notified the shift engineer. The shift engineer promptly instructed the instrument
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technician to reopen the valve and IC71-N002A was returned to service. The Unit I reactor operator verified that the other drywell pressure switches, IC71-N002B, IC71-N002C, and IC71-N0020, were operable. After further investigation, the licensee discovered that IC71-N002A had been inoperable since 9:00 that morning when the day shift instrumeat technician began surveillance LIS RP-0 Technical Specification 3.3.la Table 3.3.1-1(a), Reactor Protection Instrumentation, and Technical Specification 3.3.2b Table 3.3.2-1(b),
Isolation Actuation Instrumentation, both allow one instrument channel to be inoperable during surveillance testing for two hours before that instrument channel is required to be tripped. Drywell pressure instrument channel Al had been inoperable for 7.5 hour5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> After two hours, drywell pressure instrument channel Al should have been tripped or have been returned to service. Subsequent investigation by the inspectors and the licensee revealed that both the technician performing the surveillance and the unit operator were unaware that the surveillance placed the unit in a 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> LCO time clock. Consequently, when the technician discovered a procedure change was necessary for the surveillance, he left the switch inoperable while he processed the procedure change. This issue is considered a violation of Technical S Table 3.3.1-1(a), and 3.3.2b, Table 3.3.2-1(b)pecifications 3.3.la,. (373/87011 The inspector also reviewed surveillance procedure LIS RP-08,
" Primary Containment High Pressure Scram and Secondary Containment Isolation Response Time Test". The review revealed that the precautions section of the procedure states the simultaneous opening of two drywell pressure switches in logic channel Al and B1 would actuate valves 1E21-F333, IE51-355, IE12-F327A, and 1E51-F354 to close and simultaneous opening of two drywell pressure switches in logic channel A2 and B2 would actuate valves 1E12-F3278,1E12-327C, and IE22-F354 to close. These seven testable check bypass valves have been removed per modification 1-1-84-003, however, this modi-fication package has not completed its review cycle. Review of the modification package revealed that during the review of procedures affected by this modification, surveillance procedure LIS RP-08 was not included. This is considered an open item (373/87011-05(DRP)).
f. At approximately 2:30 p.m. (CST) on April 2,1987, the 2B High Pressure Core Spray (HPCS) Diesel Generator was being tested in accordance with LTS 800-3. At this time, the 28 Diesel Generator (DG) was shut down with its control switch in Auto. The 2B DG output breaker was racked to remote test and closed per previous procedure steps. Step F.4.b.6 (which simulates an overcurrent trip on Diesel Generator 2B while a simulated ECCS actuation signal is present) was being performed. As part of this procedure step, the Station Auxiliary Transformer (SAT) feed breaker to Bus 243 opened '
and Bus 243 was deenergized in accordance with the procedur Procedure steps F.4.b.6.(d) and (e) said to reset SAT feed breaker to Bus 243 lockout, resynchronize, and close the SAT feed breaker to Bus 243. The technical staff engineer had the operator "A" man
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reset the SAT feed breaker to Bus 243 lockout. After the SAT feed breaker to Bus 243 lockout was reset, the technical staff engineer contacted and requested the Unit 2 nuclear shift operator (NS0) to resynchronize and close the SAT feed breake Before confirming that the SAT feed breaker to Bus 243 was closed and Bus 243 was reenergized, the test engineer instructed the operator "A" man he was working with to open the 28 DG output breaker and rack it to connec The test engineer believed that since there was no procedure step to rack the 28 Diesel Generator output breaker to connect that it would be satisfactory to do it at any time. When the operator opened the 2B DG output breaker in preparation for racking it to connect, the 2B DG auto-starte At the time the DG output breaker was opened in preparation for racking to the connect position, the SAT feed breaker to the bus was not yet closed Therefore, since the DG saw a bus undervoltage coincidental with < closed DG output breaker, an auto-start signal was receive When the 28 DG auto started, the Unit 2 NSO intnediately instructed the technical staff engineer to rack into connect the 2B DG output breaker as per standard operating practices. The technical staff engineer, after getting permission from the station control room engineer (SCRE), instructed the electrical maintenance "A" man in attendance to remove all jumpers and lifted leads that were installed per the above mentioned procedure so that the 2B DG would be in its normal operating mode. The 28 DG was then loaded and verified to operate satisfactor The root cause of the event was that the technical staff engineer should have verified with the Unit 2 NSO that the SAT feed breaker to Bus 243 was closed and that Cus 243 was reenergized prior to opening the DG output breaker. Proper communication practices were not strictly observe The technical staff engineer should have determined the impact of racking the 2B DG output breaker to connect. The technical staff engineers familiarity with the procedure may have contributed to overconfidence in performing the procedure steps. Also, the procedure did not give guidance to the technical staff engineer with regard to what step in the procedure he should rack the 2B DG output breaker to connec Corrective actions include:
(1) The remainder of the test will not be performed until an adequate test procedure is in place.
l (2) The test procedure as well as other similar DG test procedures will be revised before they are performed again to prevent a reccurrence of this proble _
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(3) All technical staff personnel will be trained on this event with emphasis on the station's policy guideline on proper communications and on the importance of initiating procedure revisinns when precedural inadequacies are identifie (4) All station personnel will be informed of this even The inspector has reviewed the licensee's corrective actions and found them adequate. The inspector will monitor the licensee's actions through routine inspection for continued adherence to their corrective action One violation and two open items were identified in the review of this functionai are . Monthly Maintenance Observation (62703)
Station maintenance activities 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 During the inspection period, the 1:1spector observed portions of the following maintenance activities:
Unit 2 Repair of the Feedwater Check Valves Unit 2 Control Rod Drive Maintenance Unit 2 Repair of Air Start Motors on the Unit 2A Diesel Generator No violations or deviations were identifie . Training (41400)
The inspector, through discussions with personnel and a review of training records, evaluated the licensee's training program from operations and maintenance personnel to determine whether the general knowledge of the individuals was sufficient for their assigned task In the areas examined by the inspector, no items of concern were identified other than those addressed in Paragraph 3, item d., having to do with poor training of an equipment attendant for filling the Unit 2 fuel pool and in Paragraph 4, item d., on the station's policy guide-lines on proper comunication No violations or deviations were identifie . Licensee Event Reports (92700)
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 .
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(Closed) 373/87005-00 - Reactor scram due to loss of generator excitatio The scram could have been prevented if proper Preventive Maintenance (PM)
would have been performed. The licensee reviewed the outstanding PM program to update outstanding PMs. The licensee's actions appear to be adequate to prevent future events of this kin (Closed) 373/87009-00 - A Group II isolation was received while removing jumpers that had been installed per LIS-VR-03 because the operator had not reset the seal-in isolation logic prior to removing the jumpers. The reactor building ventilation system tripped and Standby Gas Treatment (SBGT) systems started. Prompt and efficient operator action was taken to isolate and correct the problem. There was a concern of the resident inspector regarding insufficient initial operator action. This was documented in inspection report 373/87006 as unresolved item 373/87006-01. The corrective actions stated in the LER are adequate to prevent further isolations of this natur (Closed) 373/87000-00 - Missed off gas hydrogen sample. The radiation chemistry foreman had an alarm clock to remind him of the need for the sample every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. While waiting for the return of the radiation chemistry technician, the time clock slipped his n.ind and the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> LC0 time clock ran out. The missed sample took 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> and 25 minutes to be accomplishe (Closed) 373/87005-01 - Reactor trip due to generator lockout trip caused by loss of the alternator exciter field. The brushes which supply excitation voltage to the alternator exciter were allowed to degrade due to the licensee failing to perform weekly inspection The collector brush inspection has been scheduled on a weekly basi The brushes were replaced. The licensee has reevaluated their inspection program and informed station personnel on this event. The inspector believes these actions should be adequat (Closed) 373/87011-00 - High Pressure Core Spray (HPCS) water leg pump discharge check valve failed to seat while performing quarterly surveill-ance. The HPCS was declared inoperable, the valve disassembled, and surface irregularities on the valve seat repaired. The HPCS was then returned to service after reassembly and successful testing of the valv The inspector finds these actions adequat No viclations or deviations were identifie . Transportation of Radioactive Waste Shipments (86740)
On March 27, 1987, a low level radioactive waste shipment left LaSalle for the waste disposal facility in Nevada. The driver stopped for the night near Des Moines, Iowa, during a heavy snowstorm on March 28, 198 He was asked later to move his truck and while repositioning it, the truck slid several feet off the roadway. A Polk County sheriff's deputy assisted the driver in returning the truck to the roadway. The driver's blood alcohol level was found to be above the legal limit and the deputy arrested the driver. The driver reported that he had wine with his dinner before moving the truck. The truck was impounded in Polk County, Iow ,
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The shipping contractor, Westinghouse-Hittman, sent a replacement driver and the licensee sent a team to survey the truck and escort the shipment back to the LaSalle site. No evidence of damage was observed, and no abnormal radiation levels were detected. The truck arrived at the LaSalle site on March 30, 1987. The inspector observed the cask containing fourteen barrels of low level radioactive waste on the truck being disassembled. The barrels were then inspected for damage. No evidence of damage was observed. The cask was resealed and the truck was resent to the waste disposal site in Nevada on March 30, 198 The shipment arrived safely on April 3, 198 '
No violations or deviations were identifie . Spent Fuel Pool Activities (86700)
During the inspection period, the inspector observed fuel sipping activities that took place in the Unit 2 spent fuel pool. The Unit 2 reactor core is presently unloaded and the fuel assemblies are being inspected through a sipping process to detect any possible leaking fuel assemblies. During the observation, several items were noted and found to be sufficient:
fuel pool water level contamination controls
procedures for fuel assembly movement operator training monitoring for radioactivity and possible airborne activity is in place No violations or deviations were identifie . Unit Trips (93702) On March 19,1987,at1:52p.m.(CST),whileoperatingUnit1at approximately 54% power, a reactor scram occurred due to a generator lockout and subsequent turbine trip. The generator lockout was caused by an electrical fault that occurred on the non-segregated bus ducts feeding the 6.9 and the 4.1 KV loads from the Unit Auxiliary Transformer (UAT). During this event, the VAT deluge actuated and fire / smoke was reported in the Unit 1 Diesel Generator corridor and at the location where the bus ducts enter the plant from the UAT. The station's fire brigade responded and the fire / l smoke was reported out at 2:15 p.m.. Following the scram, Unit 1 l was placed in the hot shutdowr. conditio Investigations by the licensee determined that the apparent cause of the event was moisture intrusion into one of the bus ducts during i temperature inversions coupled with the cycling of the UAT, during unit startups and shutdowns, over the same period. The moisture intrusion could have had the compounding effect of leaving contam-inants on the bus bars and insulators which over a period of time could have contributed to the cause of the fault. Additionally, an inspection of the bus duct turbine building penetrations revealed l small cracks in the insulating material. It is not known whether l the cracks were present before the fault or resulted from the forces l l
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< .o generated during the fault. Had the cracks been present prior to the fault, a path for moisture tracking from phase to ground would have existed. The destructive nature of the fault hampered the investigation process, and it is not known on which bus duct ( or 6.9 KV) the fault occurre The licensee immediately isolated the UAT and associated ducts for repair. The UAT and two main power transformers were inspected and tested utilizing gas and oil sample analyses, turns ratio tests, and meggar test The testing revealed no damage to the UAT or either main transformer. A meggar test was performed on the main generator stator windings by the licensee. The testing revealed no damage. The licensee performed inspections and infrared checks of other energized bus ducts in both Units 1 and 2. The Unit 2 UAT bus duct penetration revealed small cracks in the insulating materia This penetration is scheduled to be replaced prior to startup after the Unit 2 outag The licensee perfor ad an engineering evaluation to allow operation of Unit I with all audliary power supplied by the System Auxiliary Transformer. Temporary procedures were written and approved to address operation without the UAT. Following the engineering analysis and procedure generation, Unit I was returned to operations on March 25, 198 b. On April 14, 1987, at 4:00 p.m. (CDT), Unit 2 received a full reactor scram signal when placing the reactor mode switch from shutdown to refuel. Unit 2 has been shut down and defueled since the early part of 1987. There was no control rod movement. All systems operated as expecte It has been determined that the full scram signal was received from the Control Rod Drive (CRD)
charging header low pressure circuitry. Investigation found three fuses for relays 2C71-K101A, B, and D blown. Because three of the four fuses in the Reactor Protection System (RPS) for detecting low CRD charging header pressure had failed, they received a full scram signal. One CRD pump was running and actual header pressure was not low. Earlier in the day, surveillance LES-RP-205, " Unit 2 Reactor Protection System (RPS) Relay Logic Test," had been performed in which jumpers had been placed around the relays. The surveillance was completed satisfactorily. The licensee has investigated the root cause of the blown fuses and has found that the relays were cycling frequently while removing the jumper The interruption of the circuit causing the relays to cycle caused
'; enough of an electrical surge to blow the fuses. The fuses were replaced and the reactor protection system reset. The licensee is examining precautionary measures such as deenergizing the breakers when removing the jumpers. The inspector finds these actions adequate and will follow up during routine inspectio . - . - _ _ _ _ _ .
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g s & On April 17, 1987, at approximately 10:16 a.m. (CDT) with Unit 2 in Cold Shutdown for refueling, the licensee was performing the scram discharge volume level alarm, rod block and scram calibration surveillance on Unit 2 when they received a full scram signal. The performance of the surveillance initiates a half scram signal. At the time the surveillance was in progress, contractors working untMr the reactor vessel were cleaning the Local Power Range Monitor (LPRM) electrical connections. During their work, a contractor bumped an LPRM initiating a half scram signal in the other RPS channel, providing a full scram signal. No control rod movement occurred and the scram signal was reset. Work on the calibration surveillance was stopped until work under the reactor vessel is finishe No violations or deviations were identifie . Design Changes and Modifications (37700)
On April 2, 1987, at 10:44 a.m. (CST), the Operational Analysis Department (OAD) engineers were performing electrical construction tests for Alternate Rod Insertion (ARI) Modification M-1-2-84-061. This modification, in addition to providing for ARI, lowers the isolation setpoint for the Main Steam Isolation Valves (MSIVs) and instrument nitrogen to -129 inches. The testing for the ARI portion of the modi-fication was completed and the OAD engineers were proceeding to test the isolation logic changes. On the morning of April 2,1987, the engineers informed the unit foreman, Station Control Room Engineer (SCRE), and the Unit 2 Nuclear Station Operator (NS0) that they would be testing the Group I isolation logic changes. Since the MSIVs were closed, the testing of Group I logic would not change the position of the valves. It was thought that no other plant equipment was potentially affected. In addition to testing the Group I auto isolation chain, the test also verified the function of an added relay in the manual initia-tion circuit. To test this new relay, the circuit was broken upstream of the point where the tie-in was made. The OAD test consisted of verifying the new relay changed state with the existing relay. Both new relays, K35BX1 and K35DX1, were verified to operate correctl At the time of the testing, the Unit 2 NSO observed that the Post Loss of Coolant Accident (LOCA) Containment Monitoring System was operatin This system may be initiated either manually or automatically by the isolation logic. The operators quickly identified that the activities of the OAD engineers resulted in the Group 2 isolation signal. The ,
i operator immediately stopped further testing and notified the SCRE and shift enginee The cause of this unexpected Engineered Safety Feature (ESF) actuation was personnel error - inattention to detail. The OAD engineers stated that they did not review the entire relay development for the existing relays. The engineers assumed that the schematic diagram details all pertained to the MSIV isolation logic because the relays (K35BX1 and K35DX1) were identified as manual isolation on the MSIV Group I logic l
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( i o schematic. The OAD engineer did not review other circuits effected by the change of state of the relays. The relays are the initiating logic for the manual isolation logic for all isolations. The resultant isolations were minimized due to present plant conditions. Most of the potentially effected valves and equipment were isolated due to the actual low water level in Unit 2 and the secondary containment isolations that were jumpered on Unit 2 to prevent isolations due to low vessel level and high drywell pressur Actions taken by the licensee to mitigate further ESF actuations during 0AD testing will be:
Further isolation logic testing for this modification will be reviewed by a Senior Reactor Operator (SRO) in the planning group for intersystem interactio AD will discuss testing associated with modifications with the cognizant modification engineer prior to performance of the testin A review of 0AD procedures will be conducted to determine if additional detail and/or reformatting is appropriat A review of the necessity for 0AD site specific training will be conducte Since OAD testing performed at the station seems to be lacking control, and since the station has taken steps to minimize future errors, the resident inspector will follow the licensee's corrective actions through routine inspectio No violations or deviations were identifie . Enforcement Conference (30702)
On April 24, 1987, an Enforcement Conference was held in Region III between the licensee and the NRC to cover the violation of exceeding the Technical Specification LC0 identified in Paragraph 4 of this repor In this case, the violation was identified by the licensee and corrective actions were taken. A Severity Level IV violation has been issued. The attendees to the conference are listed in Paragraph 1 of this repor . Unresolved Items l
Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, open items, i deviations, or violations. An unresolved item disclosed during the i inspection is discussed in Paragraph l
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l 14. Open Items Open items are matters which have been discussed with the licensee, i which will be reviewed further by the inspector, and which involve some action on the part of the NRC or licensee or both. Open items disclosed during the inspection are discussed in paragraphs 3 and 4.
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15. 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
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sunearized the scope and findings of the inspection activities. The licensee acknowledged these findings. The inspector also discussec the
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. likely informational centent of the inspection report with regard to documents or processes rcviewed by the inspector during the inspectio The licensee did not identify any such documents or processes as proprietary.
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