ML20138B809
| ML20138B809 | |
| Person / Time | |
|---|---|
| Site: | LaSalle  |
| Issue date: | 03/19/1986 |
| From: | James Keppler NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20138B803 | List: |
| References | |
| EA-86-019, EA-86-19, NUDOCS 8603250172 | |
| Download: ML20138B809 (3) | |
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NOTICE'0F VIOLATION AND PROPOSED IMPOSITION OF CIVIL PENALTY Commonwealth Edison Company Docket No. 50-374 LaSalle Nuclear Power Station License No. NPF-18 Unit 2 EA 86-19 An NRC inspection conducted October 1 through November 12, 1985 has identified a violation of NRC requirements. In accordance with the " General Statement of Policy and Procedure for NRC Enforcement Actions," 10 CFR Part 2, Appendix C (1985), the Nuclear Regulatory Commission proposes to impose a civil penalty pursuant to section 234 of the Atomic Energy Act of 1954, as amended, ("Act"),
42 U.S.C. 2282, PL 96-295, and 10 CFR 2.205. The particular violation and associated civil penalty are set forth below:
Technical Specification Limiting Condition for Operation (LCO) 3.5.1 for the emergency core cooling system (ECCS) requires that while in operational conditions 1, 2, and 3, ECCS Divisions 1, 2, and 3 shall be operable.
Technical Specification 1.25 defines a system or subsystem as operable when it is capable of performing its specified function and when all auxiliary equipment required is capable of performing its related support function.
With ECCS Divisions 1 and 3 inoperable, the applicable action statement is Technical Specification 3.0.3. It requires that when a limiting condition for operation is not met and the specific circumstance is not addressed in the associated action requirements, action will be initiated within one hour to place the unit in an operational condition in which the specification does not apply by placing it, as applicable, in:
- 1. At least STARTUP within the next six hours,
- 2. At least HOT SHUTDOWN within the following six hours, and
- 3. At least COLD SHUTDOWN within the subsequent 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Contrary to the above, on October 7, 1985 at 2:30 a.m. with Unit 2 in operational condition 1 and ECCS Division 3 already declared inoperable, the licensee rendered ECCS Division 1 inoperable by closing the minimum flow valve for the low pressure coolant injection pump A and continued to operate the unit in Mode 1 until 4:44 p.m. on that day. With ECCS Divisions 1 and 3 inoperable, the licensee failed to initiate action within one hour as required by Technical l Specification 3.0.3.
This is a Severity Level III violation (Supplement I). l (Civil Penalty - 550,000) '
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Notice of Violation 2 ER 191986 Pursuant to the provisions of 10 CFR 2.201, Commonwealth Edison Company is hereby required to submit to the Director, Office of Inspection and Enforcement, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555 with a copy to'the Regional Administrator, U.S. Nuclear Regulatory Commission, Region III, within 30 days of the date of this Notice a written statement or explanation, including for each alleged violation: (1) admission or denial of the violation, (2) the reasons for the violation if admitted, (3) the corrective steps that have been taken and the results achieved, (4) the corrective steps which will be taken to avoid further violations, and (5) the date when full compliance will be achieved. If an adequate reply is not received within the time specified in this Notice, the Director, Office of Inspection and Enforcement may issue an order to show cause why the license should not be modified, suspended, or revoked or why such other action as may be proper should not be taken.
Consideration may be given to extending the response time for good cause shown.
Under the authority of section 182 of the Act, 42 U.S.C. 2232, this response shall be submitted under oath or affirmation.
Within the same time as provided for the response required above under 10 CFR 2.201, Commonwealth Edison Company may pay the civil penalty by letter addressed to the Director, Office of Inspection and Enforcement, with a check, draft, or money order payable to the Treasurer of the United States in the amount of Fifty Thousand Dollars ($50,000) or may protest imposition of the civil penalty in whole or in part by a written answer addressed to the Director, Office of Inspection and Enforcement. Should Commonwealth Edison Company fail to answer within the time specified, the Director, Office of Inspection and Enforcement will issue an order imposing the civil penalty in the amount proposed above. Should Commonwealth Edison Company elect to file an answer in accordance with 10 CFR 2.205 protesting the civil penalty, such answer may: (1) deny the violation, (2) demonstrate extenuating circumstances, (3) show error in this Notice, or (4) show other reasons why the penalty should not be imposed. In addition to protesting the civil penalty in whole or in part, such answer may request remission or mitigation of the penalty.
In requesting mitigation of the proposed penalty, the five factors addressed in Section V.B of 10 CFR Part 2, Appendix C should be addressed. Any written answer in accordance with 10 CFR 2.205 should be set forth separately from the statement or explanation in rely pursuant to 10 CFR 2.201, but may incorporate parts of the 10 CFR 2.201 reply by specific reference (e.g., citing page and paragraph numbers) to avoid repetition. Commonwealth Edison's attention is directed to the other provisions of 10 CFR 2.205, regarding the procedure for imposing a civil penalty.
Upon failure to pay any civil penalty due which has been subsequently determined in accordance with the applicable provisions of 10 CFR 2.205, this t
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Notice of Violation 3 MAR 191986 matter may be referred to the Attorney General, anA the pyrialty, unless compromised, remitted, or mitigated, may be collected by civil action pursuant to Section 234c of the Act, 42 U.S.C. 2282.
FORTHENUhlEARREGULATORYCOMMISSIN YY James G.' Kepp er Regional Administrator ,
Dated atg Glen Ellyn, Illinois this 19 day of March 1986 , ,
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DEC 311985 Docket No. 50-373 Docket No. 50-374 Commonwealth Edison Company ATTN: Mr. Cordell Reed Vice President Post Office Box 767 Chicago, IL 60690 Gentlemen:
This refers to the routine safety. inspection conducted by Messrs. M. Jordan, J. Bjorgen, R. Kopriva, and N. Choules of this office on October 1 through November 12, 1985, of activities at LaSalle County Station, Units 1 and 2, authorized by Operating Licenses No. NPF-11 and No. NPF-18 and to the discussion of our findings with Mr. R. D. Bishop at the conclusion of the inspection.
The enclosed copy of our inspection report identified areas examined during the inspection. Within these areas, the inspection consisted of a selective examination of procedures and representative records, observations, and interviews with personnel.
During this inspection, certain of your activities appeared to be in violation of NRC requirements, as specified in the enclosed Appendix. A written response is required.
No written response is required to the violation identified in Section 3 of this report until you are notified of the proposed enforcement action. You will be notified by separate correspondence of our decision regarding enforcement action based on the findings of this inspection and results of the Enforcement Conference held on December 4, 1985. We are releasing this report at this time for your information.
In accordance with 10 CFR 2.790 of the Commission's reculations, a copy of this letter and the enclosures will be placed in the NRC's Public Document Room.
The responses directed by this letter (and the accompanying Notice) are not subject to the clearance procedures of the Office of Management and Budget as raquired by the Paperwork Reduction Act of 1980, PL 96-511.
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We will gladly discuss any questions you have concerning this inspection.
Sincerely,
Or;gir.al t ig. d ly C.E. Dri. in" Charles E. Norelius, Director Division of Reactor Projects
Enclosures:
- 1. Appendix, Notice of Violation
- 2. Inspection Reports .
No. 50-373/85033(DRP);
No. 50-374/85034(DRP) cc w/ enclosures:
D. L. Farrar, Director of Nuclear Licensing G. J. Diederich,. Plant Manager DMB/ Document Control Desk (RIDS)
Resident Inspector, RIII Phyllis Dunton, Attorney General's Office, Environmental Control Division
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NOTICE OF VIOLATION Commonwealth Edison Company Docket No. 50-374 As a result of the inspection conducted on October 1 through November 12, 1985, and in accordance with the General Policy and Procedure for NRC Enforcement Action (10 CFR Part 2, Appendix C), the following violations were identified:
10 CFR 50, Appendix B, Criterion III, as implemented by Commonwealth Edison Quality Requirements 3.0, requires that safety-related parts and equipment be reviewed for suitability of application.
Contrary to the above the licensee failed to perform a suitability of application review for replacement parts which were not like for like replacements during the maintenance activities listed below:
- 1. The licensee fabricated a spring button and installed same in the Unit 2 Scram Discharge Vent Valve 2C11-380 on August 17, 1985 after the original spring button was found to be broken.
- 2. On or about August 20, 1985 the licensee replaced the originally supplied screws on the handle of the Unit 2 2B Diesel Generator cooling water pump breaker, MCC 243-1, with longer screws.
This is a Severity Level IV violation (Supplement I).
Pursuant to the provisions of 10 CFR 2.201, you are required to submit to this office within thirty days of the date of this Notice a written statement or explanation in reply, including for each violation: (1) corrective action taken and the results achieved; (2) corrective action to be taken to avoid further violation; and (3) the date when full compliance will be achieved.
Consideration may be given to extending your response time for good cause shown.
l DEC 3195 g a 1.h 4 Dated Charles E. Norelius, Director Division of Reactor Projects 1
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U. S. NUCLEAR REGULATORY COMMISSION REGION III Reports No. 50-373/85033(DRP); 50-374/85034(DRP)
Docket Nos. 50-373; 50-374 Licenses No. NPF-11; NPF-18 Licensee: Commonwealth Edison Company Post Office Box 767 Chicago, IL 60690 Facility Name: LaSalle County Station, Units 1 and 2 Inspection At: LaSalle Site, Marseilles, IL Inspection Conducted: October 1 through November 12, 1985 Inspectors: M. J. Jordan J. Bjorgen R. Kopriva N. Choules Approved By: o.
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C. Wright, Chief /8!/7 O" Reactor Projects Section 2C Date Inspection Summary Inspection on October 1 through November 12, 1985 (Reports No. 50-373/85033(0RP);
50-374/85034(0RP))
Areas Inspected: Routine, unannounced inspection conducted by resident inspectors and one regional inspector of licensee actions on previous inspection findings; operational safety; surveillance; maintenance; preparation for refueling; Licensee Event Reports; emergency preparedness training; region requests; unit trips and followup on events. The inspection involved a total of 369 inspector-hours onsite by four NRC inspectors including 61 hours7.060185e-4 days <br />0.0169 hours <br />1.008598e-4 weeks <br />2.32105e-5 months <br /> onsite during off-shifts.
Results: Of the 10 areas inspected, no violations or deviations were identified in 8 areas; two violations were identified in the remaining two areas (failure to follow Technical Specification Limiting Condition for Operations - Paragraph 3; and failure to review and approve plant modifications - Paragraph 5). The licensee's effort to schedule and plan work was having some effect on jobs being accomplished in a reasonable time.
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Unit 2 restart has been delayed after the scram (see Paragraph 10) due to an extended inspection and replacement of non Environmentally Qualified wiring on limitorque operators. Approximately 160 valves required reinspection for proper wiring. Improper wiring appears to have been installed by the manufacturer.
The licensee is also completing the remaining Environmentally Qualified equipment replacement prior to returning Unit 2 to power. The licensee continued to have difficulty in identifying operability of safety related systems while changing component positions (see paragraph 3) resulting in safety systems not being operable. Also maintenance / modification was a problem in the failure to control unauthorized work during the inspection period.
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DETAILS
- 1. Persons Contacted
- a. Routine Inspection
- 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
- M. Jeisy, Quality Assurance P. Manning, Tech Staff Supervisor T. Hammerich, Assistant Tech Staff Supervisor
- W. Shelton, Assistant Superintendent, Maintenance The inspectors also talked with and interviewed members of the operations, maintenance, health physics, and instrument and control sections.
- Denotes personnel attending the exit interview held on November 12, 1985.
- b. Persons Attending Enfurcement Conference on December 4, 1985 Commonwealth Edison B. L. Thomas, Executive Vice President C. Reed, Vice President of Nuclear Operations D. P. Galle, Assistant Vice President and General Manager for Nuclear Station Division L. O. DelGeorge, Assistant Vice President of Licensing and Engineering D. Farrar, Director of Nuclear Licensing K. L. Graesser, Division Vice President, Nuclear. Stations M. S. Turbak, Operations Plant Licensing Director G. P. Wagner, Operations Manager J. Bitel, Operations QA Manager L. F. Gerner, Superintendent - Regulatory Assurance S. L. Trubatch, Staff Attorney G. J. Diederich, Station Manager, LaSalle Station W. R. Huntington, Assistant Superintendent - Operations, LaSalle Station C. E. Sargent, Production Superintendent, LaSalle Station T. A. Hammerich, Assistant Technical Staff Supervisor, LaSalle Station NRC Representatives A. B. Davis, Deputy Regional Administrator C. E. Norelius, Director, Division of Reactor Projects J. A. Hind, Director, Division of Radiological and Material Safety Programs 3
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1 G. C. Wright, Chief, Reactor Projects Section 2C W. H. Schultz, Enforcement Coordinator !
B. Stapleton, Enforcement Coordinator B. Berson, Regional Counsel M. Jordan, Senior Resident Inspector, LaSalle J. Bjorgen, Resident Inspector, LaSalle R. Kopriva, Resident Inspector, LaSalle R. B. Landsman, Project Manager, Projects Saction 2C T. C. Poindexter, HQ Enforcement Staff
- 2. Licensee Action on Previous Inspection Findings (92702)
(Closed) Open Item (374/85018-03(DRP)): The licensee was to provide additional guidance to contractor Quality Control groups in the areas of drawing updates, QC holdpoints, and operability tests. The inspector has reviewed the implementation documentation and the revised licensee procedures for Quality Control and has no further concern in this area at this time.
(Closed) Open Item (374/85018-04(DRP)): The licensee was to upgrade contractor Quality Control programs by August 1, 1985. The inspector has reviewed the documentation and revised licensee and contractor procedures and has no further concern in this area at this time.
(Closed) Open Item (374/85018-02(DRP)): The licensee was to provide test results, conclusions, and a summary of corrective actions taken in response to the June 17, 1985 Confirmatory Action Letter. The inspector reviewed the information provided via memorandum from G. Diederich to M. Jordan dated July 10, 1985 and, based on discussions with the licensee staff, considers that this item may be closed. The licensee has implemented plans for increased involvement of the engineering staff, conducted training, improved the methods of identifying post modification testing and declaring systems operable.
(Closed) Open Item (373/85012-02(DRP); 374/85012-02(DRP)): The licensee was to evaluate procedure LOS-VG-M1 to assure that heater performance of the Standby Gas Treatment System was adequately monitored. The licensee has revised the procedure to require checking the local system thermometers as well as the remote temperature indicators in the control room.
(Closed) Open Item (374/8100-51D): The licensee was to upgrade the emergency response procedures and have them in place by September 30, 1985. The inspector verified that the new LGA procedures are in place and that operator training for the new procedures has been completed.
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- 3. 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 4
- ' and turbine buildings were conducted to observe plant equipment conditions, i i including potential fire hazards, fluid leaks, and excessive vibrations
, and to verify that maintenance requests had been initiated for equipment i 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 plan.
The inspector observed plant housekeeping / cleanliness conditions and verified implementation of radiation protection controls.
! During the month of October 1985, the inspector walked down the accessible portions of the following systems to verify operability:
! Unit 1 Standby Liquid Control System Unit 1 Standby Gas Treatment System
- Unit 1 and 2 Emergency Diesel Generators Unit 1 and 2 Division I & II 125 and 250 Volt
] Batteries and Switchgear Unit 2 Reactor Core Isolation Cooling System Unit 2 Low Pressure Core Spray System Unit 1 Residual Heat Removal System Service Water Pump Rooms and Related Piping Unit 1 Division III Battery and Switchgear While reviewing the Shift Engineer's log on September 30, 1985, the j inspector noted that the 2B Diesel Generator cooling water _ pump breaker J had tripped when an attempt was made to start the diesel. The inspector
, realized that this was the second time in a week that the pump breaker had tripped. On October 1, 1985, this concern was relayed to a region based inspector for investigation. The results of this investigation was documented in the maintenance portion (paragraph 5) of this inspection i
report.
! At 6:35 p.m. on October 4, 1985, the licensee declared the Unit 2B Diesel Generator cooling water pump and the High Pressure Core Spray System (HPCS) inoperable due to continued problems with the cooling water pump i breaker tripping. The licensee then commenced troubleshooting the problem with the breaker. At 10:40 a.m. on October 7, 1985, while reviewing the Shift Engineer's log, the inspector noted that the Division 1 "2A" Low Pressure Coolant Injection (LPCI) minimum flow valve 2E12F064A had been removed from service at 2:30 a.m. on October 7, 1985. The unit was at 100% power.
The inspector requested the Shift Engineer to explain why Emergency Core
Shift Engineer referred to Technical Specification 3.3.3 which allows the LPCI pump "A" discharge flow-low (bypass) switch, which opens the minimum flow valve on low flow, to be tripped for up to seven days. Accordingly, the licensee considered that'the valve should be capable of being out of '
service for up to seven days. What the licensee failed to recognize, was ,
that the switch actuated on decreasing flow and as such tripping the switch (required action statement for T.S. 3.3.3. for inoperable switch)
OPENS not closes the valve.
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l Subsequent discussion with Region III management and NRR confirmed the NRC position that with the minimum flow valve out of service the LPCI pump was inoperable. Section 6.3.2.8 of the Updated Final Safety Analysis Report assumes no operator action for ten minutes during postulated accidents. Accordingly, with the minimum flow valve closed and upon initiation, the assumption was that the "A" LPCI pump would operate dead headed for a minimum of ten minutes. A significant concern exists that the pump may overheat and fail prior to the operator taking action to provide a flow path. Based on this evaluation, the inspector requested the licensee to reevaluate the operability status of the "A" LPCI subsystem. The licensee subsequently declared the "A" LPCI system inoperable at 3:45 p.m. on October 7, 1985. The minimum flow valve was returned to service and the "A" LPCI system was declared operable at 4:44 p.m. on October 7, 1985.
Technical Specification 3.5.1 requires three divisions of Emergency Core Cooling Systems to be operable in Operating Condition 1 with:
- a. ECCS Division 1 consisting of:
- 1. The OPERABLE Low Pressure Core Spray (LPCS) System.
- 2. The OPERABLE Low Pressure Coolant Injection (LPCI) Subsystem "A" of the RHR system.
- b. ECCS Division 2 consisting of:
- 1. The OPERABLE Low Pressure Coolant Injection (LPCI) Subsystems "B" and "C" of the RHR system.
- c. ECCS Division 3 consisting of the OPERABLE High Pressure Core Spray (HPCS) System.
When the "A" LPCI pump minimum flow valve was closed the licensee should have declared the system inoperable and followed the requirements of TS 3.0.3 as the HPCS system was already inoperable. The licensee did not declare the LPCI system inoperable until thirteen hours and fifteen minutes after the minimum flow valve was removed from service, The licensee returned the minimum flow valve to service and declared the "A" LPCI pump operable within the one hour time limit of Section 3.0.3.
once the LPCI pump had been declared inoperable. Notwithstanding the actions taken once the LPCI pump was declared inoperable this event is considered a violation of Technical Specification, Section 3.0.3 which requires that action be taken within one hour when an LC0 is not met to place the unit in an operational condition where the LCO is not applicable. (374/85034-01(DRP)).
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i Refer to Paragraph 5 of this report for additional evaluation of the HPCI diesel cooling water pump breaker problem.
The licensee declared an Unusual Event at 6:30 a.m. CDT on October 16, 1985 due to a Unit 2 shutdown required by Technical Specifications. The Primary Containment Atmosphere Particulate and Gaseous Monitoring System spuriously tripped and could not be immediately restarted and the Primary Containment Air Coolers Condensate Flow Monitoring System was isolated.
This left the Containment Sump Flow Monitoring System as the only operable Coolant Leakage Detection System and thus, required a unit shutdown per Technical Specification 3.4.3.1. The Containment Atmosphere Monitoring System was repaired and the Unusual Event terminated at 7:40 a.m. on October 16, 1985. The licensee is investigating the cause of the trip. It appears that the 2PL15J monitor tripped due to a flow setting drift. The 2PL75J monitor was found to have a leaking connection in the "0" ring seal area of the iodine canister. The Technical Staff is evaluating the reliability of these monitors for possible maintenance procedure improvements. Completion of this action will be followed as an
! open item (374/85034-02DRP)).
- 4. Monthly Surveillance Observation (61726)
On October 2, 1985, the licensee found an instrument isolation valve for an alarm function 2C11F361, out of position while performing surveillance LOS-RD-W1, Scram Discharge Volume Water Test. All remaining valves in the area were checked and found satisfactory. The investigation of this event determined that the second verifier, to reduce radiation exposure, had stood back and observed the first operator operate the valve and did not adequately verify that the valve was positioned properly. All personnel involved were briefed on how to properly verify valve positioning. No further action will be taken.
The inspector observed the operation of the 2A Diesel Generator during performance of LOS-DG-M2. The inspector visually inspected the Diesel Generator for fluid leaks, abnormal noise or vibration, and satisfactory indication of operating parameters, both locally and in the control room. ,
The Diesel Generator was considered to be operating satisfactorily in conformance to Technical Specification requirements.
The inspector observed the closing time testing of the Primary Containment Isolation Valves, LOS-PC-Q1 and the scram functional testing of the Main Steam Isolation Valves, LOS-RP-M1. The inspector verified the use of technically adequate procedures, appropriate preparation and adherence to required precautions and plant conditions, proper operation of equipment, and satisfactory return of equipment to operational status. The inspector and unit operator noted a typographical error on pages 14 and 15 of I procedure LOS-PC-Q1. The licensee personnel took appropriate action to i correct the procedure during the next routine revision. ]
The inspector observed weekly testing of the "A" Emergency Diesel Fire Pump, LOS-FP-W2 and the monthly operation of the "A" Standby Gas Treatment Train during the performance of LOS-VG-M1. The inspector verified the use l 7
of technically adequate procedures, conformance to Technical Specifications, that instruments used for test data had current calibrations, that equipment operated satisfactorily and was properly returned to standby status.
The inspector observed troubleshooting and functional testing of the "B" t Control Room Ventilation Ammonia and Chlorine Detectors using procedures LIS-VC-01, LIS-VC-053, and LIS-VC-03. The "B" train had tripped on September 29, 1985. The two chlorine detectors and the two ammonia detectors were functionally tested and were found to be satisfactory.
Due to an ongoing concern with the number of trips related to this equipment, the inspector reviewed the surveillance procedures, the vendor manuals, and the preventive maintenance procedures LIP-GM-939 (chlorine) and LIP-GM-940 (ammonia). This review failed to identify a reason for the continuing problems. As discussed in report No. 373/85030; Np. 374/85031, the licensee is continuing to evaluate corrective action plans.
- 5. Monthly Maintenance Observation (62703)
The inspector monitored the licensee's activities during the first refuel outage preventive maintenance of the 1A Emergency Diesel Generator, procedure LMS-DG-01. The inspector verified the use of technically adequate procedures and observed portions of the post maintenance testing per procedures LOS-DG-M2 and LTS 800-5. The inspector observed the proper operation of the Diesel Generator during the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> run.
The inspector also observed the electrical wiring inspection of the Main Steam Isolation Valve Leakage Control Valve 2E32F001J (Work Request 52489). The inspector verified the use of technically adequate procedures and appropriate radiological controls. This inspection was being performed as a followup to a 10 CFR 21 Report issued by the Zion Station. Zion had identified the use of incorrect wiring that invalidated the component's Environmental Qualifications. To date, the licensee has identified twenty seven wires which were known to be incorrect and replaced.
On September 27, 1985, the NRC Resident Inspector noted that the Unit 2 shift turnover sheet listed under " Abnormal Technical Specification Condition", SDV vent valve. Review of the Degraded Equipment Log showed the following entry on August 27, 1985, " MMS replaced tension plate in valve actuator with non-safety related parts. Valve works: LOS-RD-MI done sat. Valve is only administratively inop." The inspe' r was told
" administrative 1y inop" means operable but lacking final paperwork.
The Resident Inspector expressed concern about the valve. The licensee proceeded to replace the spring tension plate with a qualified part and tested the valve. This was completed on September 27, 1985. The spare part was received on September 24, receipt inspected on September 25, and maintenance notified on September 26. The subsequent followup inspection by a regional based inspector and the resident inspector determined the following information. On August 17, 1985 at 4:30 a.m., Unit 2 vent Valve 2C11-F380 on the Scram Discharge Volume (SDV) failed to completely close 8
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during surveillance test LOS-RD-M. An investigation determined that the valve was about 90% closed. A Work Request, L51278, was written to adjust the spring tension on the valve. It was determined that the spring tension could not be adjusted at about 10:00 a.m.. The Work Request was amended to disassemble and repair the valve. Between approximately 2:00 p.m. and 4:00 p.m., the valve was disassembled. It was discovered that the spring tension button was broken. No replacement part was available on site. The vendor was contacted and indicated the part was available in his storeroom and it would require about one week to get the part to the plant. Subsequently, the vendor determined they did not have the part and it would have to be manufactured.
Since a spring button was not available, the licensee decided to machine a button from steel bar stock. Plant personnel concluded that since the button appeared to be a cast material, the steel bar stock would be as good or better than the original material. The button was machined and installed in the valve. The part was tested by cycling the valve, which it did successfully. The installation and testing was completed by approximately 9:00 p.m. on August 17, 1985.
At the time the steel button was installed, no contact was made with Station Nuclear Engineering (SNED) nor was any kind of an evaluation of the replacement part documented. Commonwealth Edison Quality Requirements 3.0, requires that safety-related parts and equipment be reviewed for suitability of application and the evaluation documented.
ANSI N 18.7-1976, which the licensee is committed to, requires in 5.2.13(1), sentence 3, 4, and 5 that:
"In those cases where the QA requirements of the original item cannot be determined, an engineering evaluation shall be conducted by qualified individuals to establish the requirements and controls. This evaluation shall assure that interfaces, interchangeability, safety, fit and function are not adversely affected or contrary to applicable regulatory or code requirements. The results of this evaluation shall be documented."
The failure to perform and document an engineering evaluation of the replacement of the spring button part for Valve 2C11-F380 with a button made by the licensee is considered to be an example of a violation of 10 CFR 50 Appendix B, Criterion III. (374/85034-03A).
SNED was contacted on September 27, 1985 and an evaluation of the spring button made by the licensee was performed. The evaluation concluded that the part was better than the original part.
On August 19, 1985 breaker MCC 243-1, which controls power to the Unit 2 ;
2B Diesel Generator (D/G) cooling water pump, failed. A Work Request, !
L51369, dated August 20, 1985, was i..itiated to repair the breaker. The' l breaker was repaired. On August 23, 1985, surveillance test LOS-DG-M3 was performed and the breaker and cooling pump functioned properly and was declared operable.
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i On September 23, 1985, surveillance test LOS-DG-M3 was again performed as i required by the Technical Specifications by the operations department.
The 2B D/G cooling pump did not start because the MCC 243-1 breaker l tripped at 10:30 a.m.. At 10:40 a.m., LOS-DG-M3 was performed and the breaker and pump functioned properly. Operations thought it was ran*
] failure and maintenance was not contacted. The pump was declared operable.
On September 27, 1985 due to other work on the 28 Diesel Generator, the cooling pump was started and the pump and breaker functioned properly.
On September 30, 1985 due to other work on the 28 Diesel Generator, surveillance LOS-DG-M3 was run. During this test, the cooling water pump l breaker MCC 243-1 tripped and the pump did not start. Maintenance was contacted to investigate the failure.
, Work Request L52347 was written to investigate the problem: During this 4 investigation it was determined that the screws holding the handle on the
) door of the breaker were too long and could interfere with operation of l the breaker. The screws were replaced with screws of the proper length, i The breaker was tested several times and operated properly. At this time it was thought that the long screws were the cause of the breaker trips.
} However, during the initial troubleshooting, the breaker tripped with the i
door open and the screws not contacting THE breaker switch mechanism. This l
trip was observed by different personnel than those that determined the j long screws were the apparent problem. The breaker trip with the door
- open apparently was not communicated to anyone else.
j The installation of the long screws is another example of installing i different parts than original replacement part without a documented evaluation as required by section 3.0 of Commonwealth Edison Quality l Requirements and section 5.2.13(1) of ANSI N 18.7-1976. This is 4 considered to be an example of a violation of 10 CFR 50 Appendix B, j Criterion III (374/85034-03B(DRP)).
On October 4, 1985 at the request of the Senior Resident Inspector, the I surveillance was again performed and the pump and breaker performed properly. Also on this date, the licensee's management became concerned i and it was determined that the long screws could not have caused the failure. The Senior Resident Inspector concluded that if this was the ,
case, the original problem had not been solved. The licensee performed
- extensive testing and troubleshooting including cycling the breaker, meggering the pump and other wiring, and checking breaker trip currents.
l The breaker tripped several times. No problems were found with the pump
- and wiring.
1 Inspection and testing of the breaker and spare breaker showed they were
- tripping at approximately 1000 amp vs 1650 nominal' breaker setting. A
- new breaker was obtained and the trip points checked at 1650 amps. The ,
i new breaker was installed and tested and no trip occurred.
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,- ,._.-.... - ., - .- . - , - . - . . , - - , - . - . - - . - - . , - , - , - , , - . . - ~ -- ---
The root cause of the breaker trips is that the breaker tripped at a lower amperage than the nominal setpoint amperage for the breaker.
Review of the breaker specifications showed the setpoint to be +40-25%
accurate. Based on this accuracy, any breaker of this type needs to be tested prior to installation.
Review of this event indicates that there was a lack of proper communications during the period from September 23 to October 4,1985.
On September 23, operations never contacted maintenance regarding the breaker trip. On September 30, the root cause of the problem may have been determined had all the available information been available in one place. It was not until October 4 after the NRC got involved, that an indepth review of the problem was performed by plant management.
- 6. Preparations For Refueling (60705)
On October 18, 1985 at 12:01 a.m. (CDT), Unit 1 commenced a scheduled shutdown as they began a twenty (20) week first refueling / maintenance '
outage. The inspector observed the shutdown including power reduction, shutdown of the turbine generator, shutdown surveillances, and reactor shutdown. Also observed were control room work practices and certain valve operations when the unit was taken to Cold Shutdown. Major items to take place during the outage are as follows: refueling, Environmental Qualification (EQ) modifications, Induction Heat Stress Improvement (IHSI), and electrical and mechanical maintenance work items.
The inspector reviewed the licensee's preparations for refueling by procedure review, attendance in meetings, and discussion with licensee personnel. The inspector verified completion of training of operations and maintenance personnel. The inspector also reviewed administrative, maintenance, surveillance, and accident procedures to assure that all Te:hnical Specification and industry standard requirements were being implemented. Since this is the licensee's first refueling, the inspectors intend to closely monitor the licensee's activities.
- 7. 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 Specifications.
374/85040 Standby Liquid Control (SBLC) Tank Concentration High.
This event report identified several regulatory concerns as follows:
- a. The event date stated in the report is wrong. The date should be August 22, 1985 not August 23, 1985.
11
- b. Licensee did not declare the Standby Liquid Control System inoperable in a timely fashion. Per the surveillance procedure, LCP 110-9, revision 4, the Chemistry Supervisor and the Shift Engineer are to be notified immediately if the concentration is not within the Technical Specification limits. These persons were notified and the SBLC system was not declared inoperable for two (2) hours. This is poor operating practice.
- c. By delaying the declaration of inoperability of the SBLC system, the licensee delayed the start of their time clock as stated in the Technical Specifications,
- d. By having delayed the declaration of the SBLC system inoperable, therefore, initiating the time clock per Technical Specifications, the initiation of the nuclear plant shutdown required by the plant's Technical Specifications was delayed.
- e. Having delayed the plant shutdown, also delayed the notification of the NRC by the licensee of the non-emergency event.
- f. There are discrepancies in SBLC tank volume used to calculate the concentration and for deciding if the SBLC tank volume is within specifications.
The licensee has recognized that there are several inconsistencies within this LER and will be issuing a revision to this LER to more accurately reflect the facts of the occurrence. The licensee also has identified i
several items which they are going to resolve:
- a. Change procedure for more accurate determination of results and for reporting of those results.
4
- b. Increase communications between Chemistry and the Shift Engineers.
- c. Discuss with management a declaration of equipment inoperability.
- d. Adequacy of SBLC tank level indication.
- e. Revising the LER.
These will be tracked as open item (373/85033-01 (DRSS)) and has been transferred to regional based inspectors for closure.
- 8. Emergency Preparedness Training (82206)
The inspectors participated in an assembly drill involving all site
' personnel. This drill was done to assess the licensee's ability to <
account for all onsite personnel during an accident that might require site evacuation. The inspectors also wanted to assess the time required for essential personnel to arrive at designated emergency response
, locations. For example, it took 10 minutes for the inspector to reach the control room from the service building. The inspector noted that the 12
l l
assembly drill was executed in a reasonably timely manner and that all but two onsite personnel were readily accounted for. The licensee I considers these two individuals experienced a problem with the assembly l area card reader. The individuals apparently did not verify that the reader responded to their badges.
- 9. Region Requests (92705)
Region III management requested the inspector to investigate the l 1 licensee's evaluation and corrective action plans for an excessive number of failures of the Residual Heat Removal System Service Water Pump Motors.
The licensee considers that the majority of electrical short failures was caused from a buildup of concrete dust during construction combined with the moist pump room environment. This situation caused eventual insulation wear and shorting of the motor windings. The licensee has not done a generic evaluation of all Reliance motors based on the failure mode. The inspector also discussed the continuing problems with the Standby Gas Treatment (SBGT) System radiation monitors with the licensee.
The monitor has a digital readout and a pen recorder to monitor the activity in the train. The pen recorder has experienced spurious spiking that the licensee has been unable to resolve. This included several visits from the equipment vendor's representative. This will be tracked as an open item (373/85033-02(DRP); 374/85034-04(DRP)).
- 10. Unit Trips (93702)
Unit 2 received a Group I isolation and scrammed from 100% power at 12:48 p.m. CDT on October 21, 1985 while performing surveillance testing on the "B" Main Steam Line Low Pressure isolation logic. Concurrently, the licensee was troubleshooting the Reactor Water Cleanup High Flow isolation which apparently caused a spurious spike in the "A" Main Steam line High Area Temperature isolation logic. This completed the Group I isolation signal. All systems functioned as expected. The licensee elected to enter Cold Shutdown to complete some Environmental Qualification work. The cause of the spurious isolation signal was determined to be a voltage dip from the Reactor Water Cleanup System isolation timer. When the timer coLpleted its cycle, the resultant voltage dip caused a perturbation in the Group I power supply. The licensee has initiated a system change to dampen the voltage dip.
- 11. Followup on Events (93702)
The licensee reported to the resident inspector an event where three (3) contract individuals were working in the offgas building and a security guard passing through detected the smell of marijuana smoke. The three individuals were escorted off site for testing. They were prevented access to the site until the results of the testing was determined. Two i of the individuals passed the testing and one failed. The individuals '
who passed were allowed access back to the site and sent back to work and the one who failed was not allowed back on site.
13 l
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- 12. Open Items Open items are matters which have been discussed with the licensee, 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 7 and 9.
- 13. Exit Interview (30703)
The inspector met with licensee representatives (denoted in Paragraph 1) throughout the month and at the conclusion of the inspection period and summarized the scope and findings of the inspection activities. The licensee acknowledged these findings. The inspector also discussed the likely informational contents of the inspection report with regard to documents or processes reviewed by the inspector during the inspection.
The licensee did not identify any such documents or processes as proprietary.
14 Enforcement Conference An Enforcement Conference was held in the Region III office on December 4, 1985 as a result of a routine safety inspection which identified an apparent violation of NRC requirements. The purpose of the conference was to (1) discuss the apparent violation, its significance and causes, and the licensee's corrective actions, (2) determine whether there were any aggravating or mitigating circumstances, and (3) obtain other information which would help determine the appropriate enforcement action.
Mr. A. Bert Davis, Deputy Regional Administrator, Region III, opened the meeting by describing the purpose and scope of the meeting as well as the NRC enforcement policy and concerns raised as a result of the October 1 through November 12, 1985 inspection.
In addressing the apparent violation the licensee acknowledged the facts and presented corrective actions to prevent recurrence. The licensee felt that the violation resulted from a lack of complete understanding concerning the function of the switch. The licensee's representatives did not believe the event resulted from a breakdown in management controls.
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e DEFINITIONS LINEAR HEAT $ GENERATION RATE *-
1.20 LINEAR HEAT GENERATION RATE (LHGR) shall be the heat generation per unit length of fuel rod. It is the integral of the heat flux over the heat transfer area associated with the unit length.
LOGIC SYSTEM FUNCTIONAL TEST 1.21 A LOGIC SYSTEM FUNCTIONAL TEST shall be a test of all logic components, i.e., all relays and contacts, all trip units, solid state logic elements, etc. of a logic circuit, from sensor through and including the actuated device to verify OPERABILITY. THE LOGIC SYSTEM FUNCTIONAL TEST may be performed by any series of sequential, overlapping or total system steps such that the entire logic system is tested.
MAXIMUM FRACTION OF LIMITING POWER DENSITY 1.22 The MAXIMUM FRACTION OF LIMITING POWER DENSITY (MFLPD) shall be the highest value of the FLPD which exists in the core.
MINIMUM CRITICAL POWER RATIO 1.23 The MINIMUM CRITICAL POWER RATIO (MCPR) shall be the smallest CPR which exists in the core.
OFFSITE DOSE CALCULATION MANUAL 1.24 The 0FFSITE DOSE CALCULATION MANUAL (00CM) shall contain the methodology and parameters used in the calculation of offsite doses due to radioactive gaseous and liquid effluents and in the calculation of gaseous and liquid effluent monitoring alarm / trip setpoints OPERABLE - OPERABILITY _
1.25 A system, subsystem, train, component or device shall be OPERABLE or have OPERABILITY when it is capable of performing its specified function (s),
and when all necessary attendant instrumentation, controls, a normal and an emergency electrical power source, cooling or seal water, lubrication or other auxiliary equipment that are required for the system, subsystem, train, component or device to perform its function (s) are also capable of performing their related support function (s).
OPERATIONAL CONDITION - CONDITION 1.26 An OPERATIONAL CONDITION, i.e., CONDITION, shall be any one inclusive combination of mode switch position and average reactor coolant temperature as specified in Table 1.2.
PHYSICS TESTS 1.27 PHYSICS TESTS shall be those tests performed to measure the fundamental nuclear characteristics of the reactor core and related instrumentation and 1) described in Chapter 14 of the FSAR, 2) authorized under the provisions of 10 CFR 50.59, or 3) otherwise approved by the Commission.
LA SALLE - UNIT 2 1-4 e., ,..n-- ..-. . , - . r m - .e
3/4.5 EMERGENCY CORE COOLING SYSTEMS 3/4.5.1 ECCS - OPERATING LIMITING CONDITION FOR OPERATION 3.5.1 ECCS divisions 1, 2 and 3 shall be OPERABLE with:
- a. ECCS division 1 consisting of:
- 1. The OPERABLE low pressure core spray (LPCS) system with a flaw
' path capable of taking suction from the suppression chamber and ,
transferring the water through the spray sparger to the rec:ctor vessel.
- 2. The OPERABLE low pressure coolant injection (LPCI) subsystem "A" of the RHR system with a flow path capable of taking suction from the suppression chamber and transferring the water to the reactor ves sel'.
- b. ECCS division 2 consisting of:
- 1. The OPERABLE low pressure coolant injection (LPCI) subsystems i "B" and "C" of the RHR system, each with a flow path capable of taking suction from the suppression chamber and transferring the water to the reactor vessel.
- c. ECCS division 3 consisting of the.0PERABLE high pressure core spray (HPCS) system with a flow path capable of taking suction from the suppression chamber and transferring the water through the spray sparger to the reactor vessel.
APPLICABILITY: OPERATIONAL CONDITION 1, 2*# and 3*.
" The ADS is not required to be OPERABLE when reactor steam dome pressure is less than or equal to 122 psig.
- 5ee Special Test Exception 3.10.6.
LA SALLE - UNIT 2 3/4 5-1
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EMERGENCY CORE COOLING SYSTEMS LIMITING CONDITION FOR OPERA' TION (Continued)
ACTION:
- 1. With the LPCS system inoperable, restore the inoperable LPCS system to OPERABLE status within 7 days.
- 2. With LPCI subsystem "A" inoperable, restore the inoperable LPCI subsystem "A" to OPERABLE status within 7 days.
- 3. With the LPCS system inoperable and LPCI subsystem "A" inoperable, restore at least the inoperable LPCI subsystem "A" or the inoperable LPCS system to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
- 4. Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
f rc . 41 %5 , A=ce
- 1. With either LPCI subsystem "B" or "C" inoperable, restore the inoperable LPCI subsystem "B" or "C" to OPERABLE status within 7 days.
- 2. With both LPCI subsystems "B" and "C" inoperable, restore at least th'e inoperable LPCI subsystem "B" or "C" to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
- 3. Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />".
- 1. With ECCS division 3 inoperable, restore the inoperable division to OPERABLE status within 14 days.
- 2. Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
- 1. With LPCI subsystem "A" and either LPCI subsystem "B" or "C" inoperable, restore at least the inoperable LPCI subsystem "A" or inoperable LPCI subsystem "B" or "C" to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
~
- Whenever two or more RHR subsystems are inoperable, if unable to attain COLD
, SHUTDOWN as required by this ACTION, maintain reactor coolant temperature as low as practical by use of alternate heat removal methods.
l LA SALLE - UNIT 2 3/4 5-2
g.
4 EMERGENCY CORE COOLING SYSTEMS LIMITING CONDITION FOR OPERATION (Continued)
ACTION: (Continued)
With the LPCS system inoperable and either LPCI subsystems "8" or 2.
"C" inoperable, restore at least the inoperable LPCS system or inoperable LPCI subsystem "B" or "C" to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
- 3. Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> *.
- e. For ECCS divisions 1 and 2, provided that ECCS division 3 is-OPERABLE and divisions 1 and 2 are otherwise OPERABLE:
- 1. With one of the above required ADS valves inoperable, restore the i
inoperable ADS valve to OPERABLE status within 14 days or be.in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and reduce reactor steam dome pressure to 5 122 psig within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
- 2. With two or more of the above required ADS valves inoperable, be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and reduce reactor steam dome pressure to 1 122 psig within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
- f. With an ECCS discharge line " keep filled" pressure alarm instrumenta-tion channel inoperable, perform Surveillance Requirement 4.5.1.a.1 at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
- g. With an ECCS header delta P instrumentation channel inoperable, restore the inoperable channel to OPERA 3LE status within.72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or determine ECCS header delta P locally at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />; otherwise, declare the associated ECCS inoperable.
- h. With Surveillance Requirement 4.5.1.d.2 not performed at the reqaired interval due to low reactor steam pressure, the provisions of Specifi-cation 4.0.4 are not applicable provided the surveillance is performed within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after reactor' steam pressure is adequate to perform the test,
- i. In the event an ECCS system is actuated and injects water into the Reactor Coolant System, a Special Report shall be prepared and submitted to the Commission pursuant to Specification 6.6.C within 90 days describing the circumstances of the actuation and the total accumulated actuation cycles to date. The current value of the usage factor for each affected safety injection nozzle shall be provided in this Special Report whenever its value exceeds 0.70.
- j. With one or more ECCS corner room watertight doors inoperable, restore all the inoperable ECCS corner room watertight doors to OPERABLE status within 14 days, otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
- Whe sever two or more RHR subsystems are inoperable, if unable to attain COLD SHLTDOWN as required by this ACTION, maintain reactor coolant temperature a's les as practical by use of alternate heat removal methods.
LA SALLE - UNIT 2 3/4 5-3
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l 3/4.0 APPLICABILITY '
l LIMITING CONDITION FOR OPERATION 3.0.1 Compliance with the Limiting Conditions for Operation contained in the
- succeeding Specifications is required during the OPERATIONAL CONDITIONS or other i conditions specified therein; except that upon failure to meet the Limiting i Conditions for Operation, the associated ACTION requirements shall be met.
3.0.2 Noncompliance with a Specification shall exist when the requirements of the Limiting Condition for Operation and associated ACTION taquirements are not met within the specified time intervals. If the Limiting Condition for '
Operation is restored prior to expiration of the specified time intervals, completion of the ACTION requirements is not required.
3.0.3 When a Limiting Condition for Operation is not met, except as provided in the associated ACTION requirements, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> action shall be initiated to place the unit in an OPERATIONAL CONDITION in which the Specification does i not apply by placing it, as applicable, in:
- 1. At least STARTUP within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />,
- 2. At least HOT SHUTDOWN within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, and
- 3. At least COLD SHUTDOWN within the subsequent 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Where corrective measures are completed that permit operation under the ACTION
. requirements, the ACTION may be taken'in accordance with the specified time
- limits as measured from the time of failure to meet the Limif.ing Condition for l Operation. Exceptions to thes~e requirements are stated in the individual j Specifications.
l j This specification is not applicable in OPERATIONAL CONDITION 4 or 5.
3!0.4 Entry into an OPERATIONAL CONDITION or other specified condition shall
- l not be made unless the conditions for the Limiting Condition for Operation are 1
met without reliance on p:'ovisions contained in the ACTION requirements. This provision shall not prevent passage through OPERATIONAL CONDITIONS as required to comply with ACTION requirements. Exceptions to these requirements are
' stated in the individual Specifications.
i 3.0.5 When a system, subsystem, train, component or device is determined to l be inoperable solely because its emergency power source is inoperable, or j solely because its normal power source is inoperable, it may be considered
! OPERABLE for the purpose of satisfying the requirements of its applicable Limiting Condition for Operation provided: (1) its corresponding normal or ,
- emergency power source is OPERABLE; and (2) all of its redundant system (s),
l subsystem (s), train (s), component (s) and device (s) are OPERA 8LE, or likewise i
satisfy the requirements of this specification. Unless both conditions (1)
- and (2) are satisfied, within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> action'shall be initiated to place the l unit in an OPERATIONAL CONDITION in which the applicable Limiting Condition i
for Operation does not apply by placing it, as applicable, it i
- 1. At least STARTUP within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />,
- 2. At least HOT SHUTDOWN within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, and '
. , 3. At least COLD SHUTDOWN within the subsequent 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
i This specification is not applicable in OPERATIONAL CONDITION 4 or 5.
I LA SALLE - UNIT 2 3/4 0-1
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