IR 05000373/1989019
| ML20248A238 | |
| Person / Time | |
|---|---|
| Site: | LaSalle  |
| Issue date: | 09/22/1989 |
| From: | Lerch R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20248A224 | List: |
| References | |
| 50-373-89-19, 50-374-89-19, IEB-88-007, IEB-88-7, NUDOCS 8910020166 | |
| Download: ML20248A238 (24) | |
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i U. S. NUCLEAR REGULATORY COMMISSION
REGION III
Report Nos. 50-373/89019(DRP); 50-374/89019(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 I u d 2 Inspection At: LaSalle Site, Marseilles, IL
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Inspection Conducted: July 25 through September 11, 1989 Inspectors: R. Lanksbury R. Kopriva D, Butler S. DuPont ,
Approved By: k in - h Reactor Projects S ction IB M~
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Inspection Summary Inspection on July 25 throuah Septmeber 11, 1989 (Reports No. 50-373/89019 (DRP); 50-374/89019(DRP))
Areas Inspected: Routine, unannounced inspection conducted by resident and regional inspectors of operational safety; surveillance; maintenance; ESF system walkdowns.; training; security; onsite followup of events at operating power reactors; temporary instructions; outages; and unit trip Results: Of the ten areas inspected, there were two violations identifie Both violations were for failure to follow procedures. One was for failure to follow procedures while swapping heat exchangers on the Reactor Building Closed Cooling Water system and the second was for not following procedures for temporary system changes and control of non-station personnel which resulted in water intrusion of the main generator. During this inspection period, there were eleven Emergency Notification System (ENS) notifications, three of which were courtesy call There was a reactor scram on Unit 2 during a planned shutdown to replace a recirculation pump seal. Several anomalies were noted during the scram and scram recovery, and a meeting was held in Region III office to discuss the even L PDR ADOCK 05000373 l- O PNU w _ _ ______ _____ _ _ __
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i, Because of the water intrusion into the generator, the licensee's six day outage has been significantly extended. .During this report period, there seemed to be an increasing number of events and errors. Since the Unit I refueling / maintenance outage started September 15. 1989, placing the site L in a dual unit outage, the inspectors will be following the site activities with particular attention in the area of control of non-station personnel l .as well as-the increased outage activitie .
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, Persons Contacted Commonwealth' Edison Company (CECO)
i 1 +*G. J. ' Die'd erich, Station Manager
+* . R.' Huntington, Technical Superintendent
+*J. C. Renwick,: Production Superintenden ..
- D. 'S. Berkman, Assistant Superintendent, Work Planning J; V~'Schmeltz', Assistant Superintendent, Operations
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J. Walkington,? Services Director
- +*T. A. Hammerich, Regulatory Assurance Supervisor W.' E. Sheldon, Assistant Superintendent, Maintenance-J. H. Atchley, Operating Engineer
- Betourne, Quality Assurance Supervisor M. G. Santic, Master Instrument Mechanic W. J. Marcis, Site BWR Engineering Supervisor
- J. Spieler, Quality Assurance
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W. Luett, Operational Lead for Health Physics D. Hieggelke,- Health Physics Services Supervisor
- *J. A.. Borm, Quality Assurance
- P. F. Manning, Quality Programs
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+ Wayne Morgan, Licensing
+Jeffrey Miller, Assistant Technical Staff Supervisor
+ Thomas Kovach, Nuclear Licensing Manager
+ James Marshall, Operating Experience Assessment
+ Ronald Grams, Nuclear Engineering Department
+Kurt uhlir, Nuclear Engineering Department
+Neldo Izquierdo, Jr., System Operations Analysis Department
+ John Horwath, System Operations Analysis Department U. S. Nuclear Regulatory Commission'(USNRC)
+ Robert Lerch, Acting Section Chief IB, DRP, RIII
+Hulbert Li, NRR/ICSB
+ Paul Shemanski, f(RR/ Acting Project Director PD 3-2
+*R. D. Lanksbury, Senior Resident Inspector, LaSalle
+ J. Jordan, Chief, Operator Licensing, Section 1
+ George Hausman, Reactor Inspector
+ David Butler, Reactor Inspector
+T. 0. Martin, Deputy Director, DRS
- R. Kopriva, Resident Inspector, LaSalle General Electric (GE) .
'+Lowell Claasson, Plant Analysis Services
+ Kent Green, Lead Systems Engineer, RPS
+Britton Grim, Manager, Special Projects
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s Illinois Department of Nuclear Safety (IDNS)
- J.. Roman, Resident. Engineer
+Denetes personnel attending the_ meeting on September 11, 1989, in the. Regional Office pertaining to the August 26, 1989 Unit 2 scra * Denotes personnel attending the exit interview on September 15, 198 Additional. licensee tdchnical and administrative personnel were contacted by the inspectors during the course of the inspection.
1; 2. Operational Safety Verification-(71707) The inspectors observed control room operations, reviewed applicable logs, and conducted. discussions with control room operators during the. inspection period. The inspectors verified.the operability of selected emergency systems, reviewed tagout records, and verified proper return to service of affected components. . Tours of Unit 1
- . 'and 2 reactor, auxiliary, and turbine buildings were conducted to observe plant equipment conditions. These tours included checking for potential fire hazards, fluid leaks, and excessive vibrations, l- and to verify.that maintenance requests had been initiated for equipment in need of maintenance. The inspectors, by observation and direct interview, verified that the physical security plan was being implemented in accordance with the station security pla This included verification that the appropriate number of security personnel were on site; access control barriers were operational;.
protected areas were well maintained; and vital area barriers were l_ 'well maintained. The inspector verified the licensee's radiological i protection program was implemented in accordance with the facility I
policies and programs and was in compliance with regulatory l, requirements, The inspectors performed routine inspections of the control room during off-shift and weekend periods; these included inspections between the hours of 10:00 p.m. and 5:00 a.m.. The inspections l
were conducted to assess overall crew performance and, specifically, control room operator attentiveness during night shifts. The inspectors also reviewed the licensee's administrative controls regarding " Conduct of Operations" and interviewed the licensee's I
security personnel, shift supervisors and operators to determine if shift personnel were notified of the inspectors' arrivals onsite during off-shift The inspectors determined that both licensed and non-licensed opt. ' tors were attentive to their duties,.and that the inspectors'
arrivals on site appeared to have been unannounced. The licensee has implemented appropriate administrative controls related to the conduct of operations. These include procedures which specify fitness for duty and operator attentivenes _ _ - _ _ __________
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ba i On July 27, 1989, at 4:45 p.m. (CDT), the licensee noted that the Unit 2 Division III (High Pressure Core Spray (HpCS)) battery chargers voltage had dropped low enough (to approximately 120 volts)
to cause the undervoltage annunciator in the control room to alar . After approximately 1 minute the voltage returned to normal (125 volts). At 5:00 p.m. the voltage again dropped for approximately 4 minutes. The licensee has been experiencing a number of failures associated with this battery charger (similar events on July 15 and 17, 1989, are discussed in Inspection Reports 373/89017 and 374/89017). At 6:20 p.m. the licensee declared the Unit 2 Division
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III battery charger and the Unit 2 HPCS system inoperable as of 5:00 p.m.. At 7:52 p.m. the licensee made the required Emergency Notification System (ENS) notification. At.9:25 p.m. the licensee cross-tied the Unit I and 2 Division III batteries and busses in order to supply Unit 2 loads and to allow work to be performed on the battery charger. The Unit 1 HPCS system was also declared inoperable. The licensee had previously investigated the cause of the fluctuations in voltage and amperage of the battery charger and was never' able to positively dttermine the cause. The licensee did note during-this event that a s1%, sbitage shutdown relay appeared to have hung up. The relay wa+ vaplaceo with the assistance of the vendor. At 10:30 p.m. on July ?fs 1989, the licensee uncross-tied the Unit I and 2 Division III batteries and busses and at 10:33 declared the Unit 1 HPCS system operable. Subsequent to the replacement of the high voltage shutdown relay, the only anomaly noted was a minor perturbation in voltage on August 3, 198 On August 10,.1989, at approximately 5:55 p.m. (CDT), the licensee received a Unit 1 Reactor Core Isolation Cooling (RCIC) system high steamline flow isolation signal. At the time of this event, the Unit 1 RCIC system was already ' inoperable and the licensee was in the process of returning the system to normal valve lineup after completing routine system surveillance LIS-RI 301, Unit 1 Steam Line High Flow RCIC Isolation Functional Test. The operator was cracking open the outboard isolation valve, IE51-F008, to warm the steamline and sufficient steam flow was apparently admitted to cause the high steam flow isolation signal to occur. The licensee immediately reset the isolation signal and completed returning the system to operability. At 9:05 p.m. the licensee made the required ENS notification. This is the second occurrence of this type in a three month period. The licensee had indicated previously that they believed they had a solution to prevent recurrence but this has not been effectiv In response to this event, the licensee has further investigated this type of event and has determined that if the inboard isolation valve is closed first and the steam trapped in the steamline is allowed to decay in pressure to approximately 400 psig prior to closing the outboard isolation valve, that upon return to service their previous corrective action (i.e. slowly cracking open the outboard isolation valve) will work. This methodology has already been successfully used during a recent Unit 2 surveillance tes In addition, the licensee is evaluating the removal of some redundant i
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h'igh flow sensing switches that appear to be the cause of the isolation signa .
On August 29, 1989, at approximately 3:44 p.m. (CDT),.the licensee was' preparing to transfer the Unit 2 B Reactor Protection System (RPS) bus from it's alternate power supply to normal power. The procedure l requires'the' operator-to hold the 2B21H-K35B relay in the, energized condition during.the transfer. The operator applied unequal. pressure to the relay bar causing some of the contacts to open, which actuated the suction valve for the shutdown cooling system, closing the. valve. With the suction valve closed the
. Residual Heat Removal'(RHR) system pump tripped, shutting down the
~s hutdown cooling system. Upon completion of the transfer of the 3 .RPS bus to normal power the operator reopened the, shutdown cooling r
isolation valves. The shutdown cooling system was restored to normal operation at 4:00 p.m.. The required ENS notification wa made at 5:21 p.m.. There was no temperature increase during-the time that the shutdown cooling system was isolated, 'On September-8,-1989, at'approximately 9:56 a.m. (CDT), the Unit 1 E . inboard isolation valve (1833-F019) for the reactor coolant sample line isolate Initial investigation by the licensee revealed that the power supply fuse had blown for an unknown reason. At 11:30
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a.m. the licensee closed, and took out-of-service, the outboard isolation valve (1833-F020) to comply with Technical Specification 3.6.3.. Sample capability still existed through the reactor water cleanup system. At 1:23 p.m. the licensee made the required ENS' notification. After investigating the problem, the licensee
.found a K-72 relay defective. This relay was replaced and the valve response time tested. On September 13, 1989, at 4:05 a.m.,
the inboard isolation valve was declared operable and the system returned to servic No deviations or violations were identified in this are . Monthly Surveillance Observation (61726) -
The inspectors observed surveillance testing including required Technical Specification surveillance testing and verified for actual activities
. observed that testing was performed in accordance with adequate procedur'es. The inspectors also verified that test instrumentation was calibrated, that Limiting Conditions for Operation were met, that renoval and restoration of the affected components were accomplished and that test results conformed with Technical Specification and procedure requirements. Additionally, the inspectors ensured that the test results were reviewed by personnel other than the individual directing the test, and that any deficiencies identified during the testing were properly reviewed and resolved by appropriate management personne The inspectors witnessed portions of the following test activities:
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g LOS-TG-SA2 Turbine Valve Tightness Surveillance -
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LOS-RI-Q2- Unit 2' Reactor Core Isolation Cooling System Valve Inservice Test for Refuel and Cold Shutdown Conditions-LIS-NR-303- Unit 1 Average Power Range Monitor Rod Block and Scram Functional Test LIS-PC-101 Unit 1 High Drywell Pressure Scram, Primary Containment Isolation and' Secondary Containment Isolation Calibration ~0n August 4,-'1989, at 9:45 a.m. (CDT), the licensee started performing surveillance LTS-300-2 (Drywell Personne1' Airlock Local Leakrate Test) on the Unit 2 primary ~ containment personnel airloc At 4:00 p.m. the primary containment personnel airlock was declared inoperable, invoking a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> time clock per the Technical
, Specifications, after it failed the Local Leak Rate Test (LLRT).
E 'At?l:15 a.m. on August 5, 1989, a second attempt of the LLRT o the personnel hatch was made. Again, the seal' failed the tes :At 4:10 a.m. the licensee made a courtesy ENS notification for the inner. personnel access hatch door failing its LLRT and,having the outer personne1' airlock door open. .This made primary containment technically' inoperable. At 4:53 a.m. the outer personnel airlock
, door was closed which stopped the one (1) hour time clock on the
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. inoperable primary containment. At 2:50 p.m. the technical staff I- had verified that the excessive leakage was coming from the inner door, and had closed and . locked the outer personnel airlock doo At 4:40 p.m. the technical staff declared the primary containment operable. Subsequent investigation by the licensee during the Unit 2 maintenance outage that commenced August 25, 1989, revealed that the LLRT failure was caused by a bad seal around the shaft for the operating mechanism. The seal was replaced and the LLRT successfully reperformed.
l On September 7, 1989, at approximately 12:00 a.m. (CDT), with i Unit 2 in cold shutdown, the licensee was performing surveillance LIS-MS-401, Unit 2 Main Steam Line Low Pressure MSIV Isolation Functional Test. At 1:08 a.m. the procedure required the technician I _to lift a lead, which would cause a Channel A2 signal (one half of a Group I isolation). At that time there was already a Channel B1 signal present, and when the technician lifted the lead a Group 1 isolation occurred. There was no valve movement because all the valves were already closed due to the unit being in cold shutdow The cause of the isolation was due to a procedural deficiency for not having the technician verify with the unit operator that there were no other isolation signals present prior to lifting the lea The residents'were informed that the procedure had been revised in November 1988 and had not been performed, with the unit shutdown, before this time. The isolation signal was reset and the surveillance completed at 1:35 a.m.. The ENS notification was L made at 3:00 a. No violations or deviations were identified in this are L J_-_ ___ - - _ _ _ _ _ _ _ . _ - _ _ - - - - _
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i 4. Monthly Maintenance Observation (62703)
Station maintenance activities of safety related systems and component !
listed below were observed / reviewed to ascertain that they were conducted i in accordance with approved procedures, regulatory guides and industry
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' codes or standards and in conformance with Technical Specification The-following items were considered during this review: the Limiting Conditions for Operation were met while components 'or systems were l removed from service; approvals were obtained prior to initiating the ,
work;. activities were accomplished using. approved procedures and were l inspected as applicable; functional testing and/or calibrations were :
performed prior to returning components or. systems to service; quality control" records were maintained; activities were accomplished by ,
qualified personnel; parts and materials used were properly certified; !
radiological controls were implemented; and, fire prevention controls were implemented. Work requests were reviewed to determine status of outstanding jobs and to assure that priority is assigned to safety related equipment maintenance which may affect system performanc Portions of the following maintenance items were observed during the !
inspection period: !
Unit 2 - Turbine driven reactor feed pumps
Unit 2 - Generator disassembly )
Draining, drying and checking humidity of the station air system On August 28, 1989, at approximately 12:00 p.m. (CDT) with Unit 2 in cold shutdown, the station received orders from the Joliet load dispatcher to hang'special work cards for taking the Unit 2 east and 2 west main transformer cooling fan feed breakers out of service in preparation for cleaning the cooling fans. At this time, the Unit 2 main generator was being purged with air in preparation for shutting down the turbine lube oil system for planned maintenance. At 12:45 p.m. the Sub-Station Construction crew started cleaning the Unit 2 east main transformer cooling fan radiators. They had connected a hose from the clean condensate water supply to the station air i supply by means of a Wye connection. They believed that the air would improve their cleaning effort. At 12:45 p.m. the control room received a generator field ground alarm. At 12:53 p.m. the control j room received a hyarogen panel normal alarm. The Unit 2 Nuclear j Station Operator (NS0) dispatched an equipment attendant to !
investigate the alarm. Also at 12:53 another equipment attendant I reported to the control room that the Unit 2 main generator casing l liquid detector full alarm had actuated on a local panel. He attempted to acknowledge and reset the alarm, but it would not reset. The equipment attendant reported back that the main generator liquid detector was full and needed to be drained. At 12:55 p.m. the Unit 2 shift foreman and the equipment attendant l arrived where the air purge of the generator was taking plac !
They found the hose supplying service air to purge the generator i kicking and noticed water drops at the hose coupling. The hose coupling was disconnected and a solid stream of water was observed
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coming from the station air outlet. The shift foreman traced th air header back and discovered a . hose leading to the Unit- 2 main
. transformer. He. noticed the Wye connection which crosstied the
' clean condensate water to the service air and had it immediately secure The clean condensate water system is-nominally 180 psig while o the: service air system pressure is.110 psig. When.Sub-Station Construction intentionally cross-tied these two systems it allowed the water to intrude the air system. Sub-Station Construction did not' have authorization to crosstie the .two systems, nor had they informed.the operations. department of their intentions. .Up to.that
' time,3 cross connecting of the water and air systems had not been done before at LaSall 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:
The appli:able procedures ~ recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 197 ' Appendix A of Regulatory Guide 1.33 includes administrative procedure LaSalle administrative procedure LAP-240-6, Temporary. System Changes, states, in part ..... Examples of Temporary System Changes are as follows:
9. Temporary connection such as hoses, tubing or piping that joins two systems together....thus, altering the' system design or configuratio Procedure LAP-240-6, steps F.2 and F.3 pertain to Initiation of a Temporary System Change. Steps F.4 and F.5 pertain to onsite review and approval, and the shift engineer's review of Temporary System Change authorizatio Administrative procedure LAP-100-4, Control of Non-Station Personnel, which includes sub-station construction, step states, in part:
All non-station Commonwealth Edison supervisors, who perform or control work, shall be familiar with the work control process with particular attention to the procedures listed under Section B, references and the procedures listed belo ' LAP-240-6 Temporary System Changes Contrary to the above on August 28, 1989, neither Sub-Station Construction nor operations had initiated or had approval, authorizing the temporary system change cross-connecting the clean condensate vtater system and station air system. Also, the decision to cross-connect the systems was made by the Sub-Station Construction
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crew without-authorization from the supervisor. The supervisor had '
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LAP-100-4. This is a violation for failure to adhere to procedures-(374/89019-01).
.~After the connection between the station air and clean condensate water. systems was. separated, the generator liquid detector. and
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station air drops (outlets) were. drained. It took approximately 30 g minutes for;the systems to drain.
L The safety significance of this event was minimal. The Unit 2
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generator was off line at the time of this event for 2B reactor recirculation, pump seal. replacement. Air from the station air filter-dryer' train is discharged to separate' instrument air and
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service air headers. The'two receivers are~ interconnected through l
piping and' valving, so that source flow is sent into either system-l . from the compressors, i.e., not from service air to in'strument air receiver or visa versa. Water' intrusion into the station air system would only affect the air to the supply drops throughout the building. This water would eventually collect in the station air l receivers which are equipped with water drain traps to remove water l' that accumulates in the system due to condensatio The. licensee drained the water out of the system and checked all of the supply drops (outlets) for moisture. After verifying that all of the water had been removed from the supply air system, the licensee started inspecting the main generator. The generator was disassembled and.it was determined that the generator rotor needed to be sent offsite to be repaired. The Unit 2 generator rotor is expected to be sent offsite approximately September 17, 1989, and be returned around November 19, 198 The residents, through observation, have been following this event and the maintenance work related to the generator disassembly and inspection. There has been interest in this event expressed from NRC Region III and NRC headquarters pertaining to: (1) water
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intrusion into the plant air system (s) and (2) licensee's control of non-station personne No deviations were identified in this area, however, one violation was identifie . ESF System Walkdown (71710)
During this report period, the High Pressure Core Spray (HPCS) system for
. Unit 2 was inspected. A complete walkdown of the accessible portions of the HPCS system was performed to verify its operability. Areas reviewed included the HPCS motor and pump, HPCS water leg pump, certain portions of HPCS piping and valves, the diesel generator and storage tanks, the HPCS batteries, and HPCS instrumentatio Other items considered during the inspection were:
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g a 2 verification that the system lineup procedures matched the plant I drawings housekeeping was adequate and appropriate levels of cleanliness were being maintained valves in the' system did not exhibit gross packing leaks, bent stems, missing handwheels, or improper labeling major system components.were properly labeled, no leakage was detected, and the compenents appeared to be lubricated and cooled adequately instrument calibration dates appeared current support systems essential to the system actustion or performance were operational proper breaker positions at local panels and indications on control panel were verified valves in the flow path were inspected for correct positions as required by procedure Prior to performing the inspection, the resident inspector reviewed the Final Safety Analysis Report (FSAR), Technical Specifications, the licensee's System Lesson Plans, and the main system procedure No violations or deviations were identified in this are . Training (71707)
The inspector, through discussions with personnel, evaluated the licensee's training program for operations and maintenance personnel to determine whether the general knowledge of the individuals was sufficient for their assigned task In the areas examined by the inspector, no items of concern were identifie No violations or deviations were identified in this are . Security (71707)
The licensee's security activities were observed by the inspectors during routine facility tours and during the inspectors' site arrivals and departures. Observations included the security personnel's performance associated with access control, security checks, and surveillance activities, and focused on the adequacy of security
, staffing, the security response (compensatory measures), and the l security staff's attentiveness and thoroughness. The security force's l performance in these areas appeared satisfactor w_ _ _ _ . . _ . .__
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H-Observations were also made of.the perimeter' fence. The licensee'is modifying a gate on the north side of the protected area.
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.No. violations or deviations were identified in this are , Onsite Followup of Events at Operating Power Reactors (93702) On August 1, 1989, at approximately 1:52.p.m. (CDT), with Unit 2 at 98% power, the' licensee was in the process of performing routine n surveillance LIS-FW-201, Unit 2 Reactor Narrow Range Level Calibration, when it was noted that the B Turbine Driven Reactor
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Feedwater Pump (TDRFP) was acting erratically. The Nuclear. Station Operator'(NS0) had just changed level control from the B narrow range to the A narrow range and had just placed the A TDRFP in_ auto (the B TDRFP was still in manual). Approximately 30 seconds late the erratic behavior began. The flow from the B TDRFP initially increased and the B TDRFP did not appear to be' responding correctly to the NS0s actions. .The NSO placed the A TDRFP back in manual and -
changed level control back to the A narrow range. Since the B TDRFP did not appear to be-responding correctly, the NSO manually tripped
.it and started the Motor Driven Reactor Feedwater Pump (MDRFP). A second NSO also began quickly reducing power using the Reactor Recirculation (RR) system. The tripping of the B TDRFP caused a-runback of the A Reactor Recirculation Flow Control Valve (RRFCV).
The initial reduction in power using the RR system resulted in a reduction in core flow to just above the boundary of the instability region B (surveillance) on the licensee's power to flow map. When the runback of the A RRFCV occurred it further reduced core flow and.resulted in a slight entry into the instability region B on the licensee's power to flow map. This point would lie within region C (monitoring) shown in NRC Bulletin 88-07, Supplement 1. The licensee immediately inserted the predetermined cram rods and increased RR flow, and thus core flow, on the B RR loop in order to exit the instability region. The licensee also performed the surveillance to monitor for core instability and verified that no core instabilities occurred. During this event, water level varied between approximately 18" and 51".
When the operator incrdsed RR flow with the B RRFCV, the mismatch between the A and B RR loop flows increased to the point where it exceeded the 10% Technical Specification limit. At 2:10 p.m. the licensee entered the applicable Technical Specification Limiting Condition for Cperation (LCO) (3.4.1.3) which started a 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> time clock to correct the mismatch or declare the RR loop inoperabl Because of the high differential pressure across the RRFCV with it in the runback position and the RR pumps running at full speed, the licensee could not get the RRFCV to open any further. At approximately 4:00 p.m. the licensee manually tripped the A RR pump so that the RRFCV could be opened. This also terminated the 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> time clock and started a 4-hour time clock for being in single loop operation. At approximately 4:05, after increasing the degree that the RRFCV was open, the A RR pump was restarted and the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> time clock terminated. At 4:15 p.m. the licensee made a courtesy ENS call to inform the NRC of the entry into the instability regio _______-____- _ _ -
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Event recovery consisted of re pulling. control-rods to approximately the 90% flow control line and increasing core flow to achieve v 'approximately 85% power. :The A~TDRFP and the MDRFP were left.on 0'
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to provide.feedwater to the reactor and the B TDRFP was left off to allow investig'ation of its performance. .The inspector arrived in the. control room'approximately.five minutes into the event and observed the licensee's actions during the event itself.as well as L the recovery phase.. The operators did an excellent' job of handling-the event and communicating with each other during the event and
'during: the recovery phas The' inspectors followed up on the licensee's investigation of the apparent erratic behavior of the Unit' 2 B;TDRFP. At the time of
.the event, as noted previously, the Instrument Mechanics (IMs) were in the process'of performing surveillance procedure LIS-FW-20 The feedwater (FW) reactor level transmitters (2C34-N004A and 2C34-N004B) provide level information to the reactor feed pump flow control circuitry. The NSO may select either A or B level instrument loop.to provide an input signal. The'IMs had just completed the.2C34-N004A and 2C34-N004C instrument loop calibration (the C level loop provides indication only). The surveillance procedure did provide,a step to have the NSO select the level loop
.that was not being calibrated. In this case, the NSO had placed ;
the Level Select switch.(2C34-SI) to position A Level in preparation for calibrating the 2C34-N004B loop. Following this, the B TDRFP appeared to begin acting erratically causing the reactor water level to vary between approximately 18" and 51". The inspector determined that the surveillance test did not result in the erratic control system behavio The licensee' investigated the apparent erratic behavior of the B TDRFP. The inspector discussed this item with the licensee in regard to a possible erratic control system. The licensee indicated that the plant has in the past been subjected to erratic FW control system behavior. The apparent cause was traced to intermittent,
. high resistance' control . relay contacts. The relay contacts were designed for a higher current application. The licensee believed that the lower control currents were not effectively wiping clean the contacts during make and break operations, such as selecting manual or automatic control modes, which could result in the control system controlling erraticall The licensee is currently testing each FW control system relay during each refueling outage and the relays that do not pass the contact resistance test are replaced. Also, the licensee has contacted the relay manufacturer and is seeking a replacement relay with gold plated contacts. The gold plated contacts should be less susceptible to corrosion buildup and have lower contact resistanc The inspector is satisfied that the licensee is adequately addressing the above issu The licensee's investigation of the erratic behavior of the FW system during this event, however, has revealed that the above known problem was not the cause of the erratic behavior in this case. The
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4-E licensee has indicated that the initial actions of the A TDRFP appeared to be due to a slow response of the TDRFP control valve actuator. This did not appear to affect the steady operation in manual significantly because manual changes by the operator are small and infrequent. Once the controller was placed in auto, the slow response caused the controller to apply ever-increasing demands to achieve the desired feedpump flow. As level slowly decreased, the NSO bumped the B TDRFP up, eventually reaching the speed limiter
' setpoint. Because of the design of the TDRFP speed limiter, once the high speed limit is reached, the Control Valve (CV) is demanded to full close. This will then result in a coastdown of the TDRFP to below the limiter setpoint, and the CV will re-open to a high valu By this method, speed is controlled at the setpoint, but possibly with large changes in CV position, which are observable by the operator as the feedwater turbine being uncontrolle The licensee's evaluation of the event is that all indications from the data obtained after the event are that the B TDRFP performed as designed. The value of the speed limiter setting appeared to be correct to support its design function protection of the Feedwater Controller Failure transient on the core. The observed flow rates appeared to be consistent with the analysis inputs, when the system operation with both FW pumps is considered. The B TDRFP CV
. operation was checked on August 2, 1989, by performing demand steps on the control valve with the TDRFP off-line. The actuating hardware (linkages, etc.) was inspected to ensure that the large position swings which occurred did not damage any component Portions of this inspection were witnessed by the inspecto The A TDRFP CV actuctor (or actuator positioner) appeared to have operated more slowly than desired. During the second and third Startrec recordings, the CV position response to demands is seen to be better than at the onset of the event. The A TDRFP operation may have eventually settled ou On August 9, 1989, the B TDRFP was placed back on line and the A TDRFP taken off line and inspecte The results of this inspection found that the actuator positioner to be very slow responding in the close direction. The positioner was subsequently replaced and the licensee is continuing their attempt-to determine the cause of the failure. The inspectors, through observation, watched portions of the testing and inspection of the 2B TDRFP and found no problems with the licensee's activitie The inspectors also followed up on the licensee's investigation of the A RRFCV runback. The RRFCV's will runback if the reactor water level is -31.5" (Level 4), or less, coincident with less than two FW pumps running. The FCV runback occurred following the trip of the 2B TDRFP by the NSO. Just prior to tripping the pump, the NSO had noted that the FW CONT RX WTR LVL 4 NORMAL annunciator had cleare The licensee determined that the 2C34-K626A permissive alarm card I (runback permissive A flow controller loop) had a higher Level 4 reset value than the annunciator alarm card (2C34-K635). The inspector reviewed the past calibration records for Units 1 and 2 i alarm cards, and noted the following:
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Inst. N Description Reset (Volts)
y IC34-626A- Flow Loop A. Runback Permissive 0.019 1C34-6268- Flow Loop B Runback Permissive 0.018 a IC34-635 FW CONT RX WTP. LVL4 NORMAL' O.031 2C34-626A Flow. Loop A Runback Permissive 0.100 2C34-626B F1ow Loop B Runback Permissive 0.015 2C34-635 FW CONT RX WTR LVL4 NORMAL 0.020 The 2C34-626A permissive alarm card was resetting 0.080 volts higher than the 2C34-635 annunciator alarm card on an increasing reactor water level which corresponds to approximately 1.29" of reactor water level. Thus,.although to the NS0 it appeared that the level
. input to the runback circuitry had cleared (since the annunciator
'for ' level 4 cleared) in fact, due to the higher reset value in the A RRFCV runback circuitry, it had not cleared and when he tripped the B TDRFP three seconds-after the level 4 annunciator cleared, he completed the remainder of the logic for the A RRFCV to runbac The Unit 1 permissive alarm cards have a reset value that is less
- than the annunciator alarm card. Thus, Unit I should not experience a spurious.RRFCV runback for this type of scenari The inspector reviewed vendor manual section GEK 4574K15-100, Type 745 Single and Dual Alarm, initial checks and adjustments for the above alarm cards. The reset (dead band) is adjustable from 0.5'4 to 5'4 of span (0.02 to 0.2 Vdc). All of the above reset values were within the vendor's specified range of. adjustment. Thus, the higher Lreset value of the 2C35-K626A permissive relay card was not a malfunction. As can be seen from the above table, the licensee was not controlling the setting of the reset valu In addition, the calibration sheets did not provide a range and tolerance that the relay card reset values should be to determine if they were acceptable. Pending further review by the licensee to develop a method for controlling multiple alarm card reset values for all control' systems to assure that the control function is fulfilling the indicated annunciator function, this is considered an open item (373/89019-01; 374/89019-02).
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' On August 13, 1989, the licensee was in the process of taking the Unit 1 A Reactor Building. Closed Cooling Water (RBCCW) heat exchanger out-of-service for cleaning. The licensee planned on swapping the common (0) RBCCW heat exchanger from the Unit 2 lineup it was in to a Unit I lineup to support this work. At the time this evolution was to commence, the Unit 2 A RBCCW pump was out-of-servic In preparation for this evolution, the Unit 2 Shift Foreman (SF) discussed what was going to be done with the individuals who would be involved. The Unit 2 Nuclear Station
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.k Operator (NS0) expressed a concern that the procedure (LOP-WR-02, Startup'and Operation of the Reactor Building Closed Cooling Water System), did not specifically address this evolution but rather i addressed swapping the O RBCCW heat exchanger from a Unit I lineup
- to a Unit 2 lineup. The Unit 2 SF, based on his review of LOP-WR-02, had decided that step F.4 was sufficient-for use. His assessment was that steps F.4.c. and d. could be swapped with steps F.4.e. and f. (i.e. just change the procedure's valve numbers to l reflect the opposite unit). This change would require the Unit I common RBCCW heat exchanger inlet and outlet to be opened and to
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then close the Unit 2 common RBCCW inlet and outlet and would for a period of time crosstie the two units RBCCW systems. The Unit 2 SF intended.to perform this procedure change as a procedural deficiency per LAP-820-1, Station Procedures. The Unit 2 SF and the Unit 2 NSO were not aware at that time that the 2A and 2B RBCCW heat exchanger outlet valves were closed and that the 0 RBCCW heat exchanger was the only source of cooling for the Unit 2 RBCCW system. This status is not available in the control roo Subsequently, the Equipment Attendant (EA) proceeded into the plant to perform the procedure as modified by the SF. The EA had advanced to the point of opening.the Unit I common RBCCW heat exchanger inlet and outlet stop valves (thus, crosstieing the Unit 1 and 2 RBCCW systems) and was closing the Unit 2 common RBCCW heat exchanger outlet valve when he was instructed to stop and return the valves to their original lineup. The initial actions taken by the EA resulted in the overflow of the Unit 1 RBCCW expansion tank which caused water to run from the 820 foot elevations down the exterior of the primary containment wall to the reactor building basement, and the overflow of the north reactor main floor drain sump (due to input from the expansion tank overflow); Division I 125 volt DC and .
Division 2 125 volt DC system ground alarms due to equipment being wetted by the overflow; the tripping of the refrigeration unit for the reactor building process sample sink causing the Unit 2 reactor coolant conductivity monitor to be declared inoperable; and the loss of flow to the reactor recirculation pump motor and seals resulting in the 2B reactor recirculation pump seal number 2 pressures increasing from 280 psig to 330 psig (this seal had already been in a degraded condition).
LaSalle administrative procedure LAP-820-1, step E.2., indicates that under certain limited circumstances procedural deviations are permissible such as the case where a procedure is obviously in error and what was intended by the procedure is obvious. It then provides three examples which, in essence, indicate the changes intended are those necessary due to typographical errors. The change that the SF wanted to make clearly did not fall into this type of change but was rather an instance where a new section of the procedure needed to be written to describe how to swap the common RBCCW heat exchanger from a Unit 2 to a Unit I lineup. LOP-WR-02 should have been revised in accordance with LAP-820-2, Station Procedure Preparation and 1 Revisions, instead of the process that was use In addition, step '
E.2 also requires that an Addendum Deficiency Sheet be completed in
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, .i accordance with LAP-820-6, Identification of. Procedure Deficiencies, signed by the identifier's . supervisor and forwarded to the Procedure Manager, prior to continuing performance of the procedure. None of the above were accomplished prior to this change.being implemente '
10 CFR 50, Appendix B, Criterion V, requires that activities affecting quality be prescribed by procedures of a type appropriate to the circumstances and be accomplished in accordance with those procedures. The failure to adhere to approved procedures
. LOP-WR-02, LAP-820-1 and LAP-820-2 is a violation (374/89019-03).
No deviations were identified in this area, however, one violation and one open item were identifie . Temporary Instructions (25590)
(Closed) TI 2515/90 " Scram Discharge Volume Capability"
.The numbering (04.01, 04.02, etc.) used in sections of this paragraph relates to the applicable Sections of TI 2515/9 Scram Discharge Header Size (04.01)
(i) Criterion The scram discharge headers shall be sized in accordance with General Electric (GE) design, GE 0ER-54, and shall be hydraulically coupled to the instrumented volume in a manner to permit operability of the scram level instrumentation before loss of system functio (ii) Actions Taken at LaSalle
.(a) Based upon analysis performed at LaSalle, the Scram Discharge Volume (SDV), including the instrument volume (IV) has the capability of receiving a scram discharge of 3.34 gallons per control rod drive. The analysis did not include the entire volume of the IV (in excess of 90 gallons) or the one inch vent and two inch drain line piping to provide conservative assurance pf scram capabilit The SDV sizing requirement of 3.34 gallons per control rod drive, as stated in GE OER 54 (dated March 14,1972)
is based upon the following:
Control rod drive stroke tim Ten (10) seconds of scram breakage flow of 10 gpm (10 gpm x 10 sec/60 sec/m = 1.667 gal / drive).
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. The current volume at LaSalle equals the GE OER 54 (3.34 gallons) requiremen (b) In addition, the instrumentation at LaSalle provides redundancy and diversity. The current design incorporated
. diverse'and redundant instrumentation utilizing safety related float type water level switches and differential pressure water level transmitter Each of the two SDVs has its own.IV. Each IV has six water level sensing instruments. One float type level switch annunciated that water is present in the IV; one float type level switch prevents further control rod withdrawal (Rod Block); two safety related float switches and two safety related differential pressure water level transmitters automatically scram the reactor while sufficient water volume still exists in the SDV to ensure safe shutdow The IV scram instrumentation incorporates a one-out-of-two-twice logic with each of the two IVs having the ability to independently scram the reacto (c) Adequate hyoraulic coupling was also assured by positively venting each.SDV and IV to assure drainage in preparation for scram reset. Additionally, because the IVs are located remotely from the SDV, each SDV has its own independent vent line and each of the IVs has its own independent drain lin Based upon the review of LaSalle's current SDV and IV design, this criterion (04.01) is considered to be close b. Automatic Scram on High Level (04.02)
(i) Criterion -
Level instrumentation shall be provided for automatic scram initiation while sufficient volume exists in the SD (ii) Actions Taken at LaSalle
As stated above, the IV water level instruments were designed to provide redundancy and diversity. The scram logic is also redundant in that either of the IVs one-out-of-two-twice logic will provide an automatic reactor scram at less than 50 gallons. The IV volume is capable of holding in excess of 90 gallons and the analysis, to ensure adequate scram volume, assumes only 40 gallons for the IVs in the calculated total volume of SDVs plus IVs during a scra Based upon the redundancy and diversity of the LaSalle design, this criterion (04.02) is considered to be close h ___a__mm__-___.-_____.__
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c. InstrumentTapsNotonConnectingPiping(04.03]
(i) Criterion Instrument taps shall be provided on the vertical IV and not on the connected pipin (ii) Actions Taken at LaSalle The inspector reviewed the design drawings and FSAR (updated)
and verified that the IV instrument taps are directly connected to the vertical IV and not to the SDV/IV pipin This criterion (04.03) is considered to be close d. Detection of Water in the IV (04.04)
(i) Criterion The scram' instrumentation shall be capable of detecting water accumulation in the IVs assuming a single active failure in the instrumentation system or the plugging of an instrument lin (ii) Actions Taken at LaSalle The scram instrume:1tation is set up with one-out of-two-twice logic. The logic is divided into two channels (A and B)
containing two relays in each (Channel A - relays A and C, Channel B - relays B and D). Each relay has two associated diverse sensors (one float and one differential pressure type).
One relay from each of the channels (either relays A or C in Channel A and either relays B or D in Channel B) will initiate an automatic scram if de-energized. Each relay is de-energized if either of its sensors indicate water level in the IVs at or.less than 50 gallons or if electrical power is los The sensors are arranged such that, if one of the two inch instrument lines associated with an IV is blocked, only one of the floats and one of the differential pressure type sensors will be inoperative. This would not degrade or prevent the protection logic from initiating a reactor scram since the other sensors associated with the affected channel are from the unaffected IV. Additionally, if a generic failure of either type cf sensor would make all four (two on each IV)
, inoperative, automatic scram capability would still be provided by the other type of sensor. This combination of protection logic redundancy and diversity of type of sensors would still provide automatic scram capability with a complex failure of complete blockage of one IV and a generic failure of either type of sensor in that the two remaining sensors on the operable IV would still provide an automatic scra This criterion (04.04) is considered to be close _ - _ _ - _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _
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i e Vent and Drain Valve System Interfaces (04.05)
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(1) Criterion l-/. Vent and drain functions shall not be adversely affected by l
other system interfaces. The objective of this requirement is to preclude water backup in the scram IV, which would cause a spurious scram.
l (ii) Actions Taken at LaSalle The SDV header piping is pitched in such a manner as to continuous'y gravity drain water to the IVs. All vent and drain lines have been installed free of loop seals to ensure
! venting and drainage. Additionally, redundant vent and drain valves were installed to assure the capability of venting and drainin This criterien (04.05) is considered close f. Vent and Drain Valves Close on Loss of Air (04.06)
(i) Criterion l The power-operated vent and drain valves shall close under loss of air and/or electrical power. Valve position indication shall be provided in the control roo (ii) Actions Taken at LaSalle All vent and drain valves are air operated such that they will fail closed on loss of motive air or electrical power to the valve pilot Each valve has control and position indication in the control roo This criterion (04.06) is considered to be close g. Operator Aid (04.07)
(1) Criterion Instrumentation shall be provided to aid the operator in the detection of water accumulation in the IVs before scra (ii) Actions Taken at LaSalle The inspector verified that float switches are provided on each IV to alert the operator of water accumulation (alarm in the control room) and to prevent rod withdrawal if accumulation continue This criterion (04.07) is considered to be close _ _ _
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h. Active Failure in Vent and Drain Lines (04.08)
(1) Criterion Vent and drain line valves shall be provided to contain the scram discharge water with a single active f ailure and to i minimize operational exposure.
l (ii) Actions Taken at LaSalle The inspector verified that operational' exposure is minimized by posting and restriction of access to the vent and drain ,
lines. Additionally, redundancy is provided, with independent j vents on both SDVs and independent drains on both IVs, to assure the single active failure criterion is satisfie ]l This criterion (04.08) is considered to be close i. Periodic Testing of Vent and Drain Valves (04.09)
(i) Criterion Vent and drain valves shall be periodically teste (ii) Actions Taken at LaSalle The inspector verified that the Scram Discharge System vent and drain valves are periodically tested per Technical Specifications 4.1.3.1.1 and 4.1.3. This criterion (04.09) is considered to be close Periodic Testing of Level Detection Instrumentation (04.10)
(i) Criterion Level detection instrumentation and verifying level detection instrumentation shall be periodically tested in plac (ii) Actions Taken at LaSalle The inspector verified that the IV water level detection instrumentation is functionally tested quarterly and calibrated once per refueling outage per Technical Specification This criterion (04.10) is considered to be close k. Periodic Testing Operability of the Entire System (04.11)
(i) Criterion The operability of the entire system as an integrated whole shall be demonstrated periodically and during each operating
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cycle by demonstrating scram instrument response and valve function at pressure and temperature at approximately 50%
control rod densit (ii) Actions Taken at LaSalle An integrated test involving a scram at 50% rod density is accomplished per Technical Specification 4.1.3.1.4 once per 18 months.
l This criterion (04.11) is considered to be close No violations or deviations were identified in this are . Outages (71707)
On August 25, 1989, the licensee shutdown Unit 2 in preparation for a six day maintenance outage. The primary purpose of the outage was to replace the B reactor recirculation pump seal assembly. The monitored parameters of this seal have been degrading since the unit was returned to service in February after a seventeen week refueling / modification outage. The number two seal cavity pressure was at approximately 300 psig (normal is approximately 500 psig) and the licensee has experienced periodic high leakoff flow alarms (alarm setpoint is 0.8 gpm). The licensee believes that the service life of the* seal may have been reduced by cold, high speed runs of the B pump during the refueling / modification outage in an attempt to locate a missing part from the recirculation pumps discharge valve. During the outage, the licensee had also repaired the inoperable inner door of the drywell personnel hatch as well as other repairs that can not safely be performed with the unit operating. After having been shutdown for three days, the licensee experienced water intrusion into the main generator (see Paragraph 4.a. for details). This caused the licensee to disassemble the main generator and send the generator rotor offsite to be repaired. Unit 2 is expected to be shutdown for a minimum of eight week .
No violations or deviations were identified in this are . Unit Trips (93702)
On August 26, 1989, while in the process of shutting Unit 2 down for a !
scheduled maintenance outage the reactor scrammed from approximately 10% power. It was noted at that time that the reactor protection system (RPS) indicating lights for subchannels A2 and A3 did not immediately extinguis Subsequent investigation by the licensee has not been able i to confirm the cause of the reactor scram. It was originally reported I that the cause appeared to be a momentary spike in turbine first stage pressure that caused the automatic bypass of a reactor scram from turbine stop valve position (three stop valves were closed and the fourth was closing), when reactor power is less than 30%, to be momentarily 1 un-bypassed. The licensee believes that the scram was not caused by a J change in any plant process variable but was caused by some disturbance not representative of actual plant conditions that is unknown at this 22 I
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time. This is based on no indication being detected on process indicating instrumentation and the short duration time (less than 40 milli-seconds) of the spike. Also at least one of the eight, but no more than two, of the scram contactors did.not respond correctly to the event. The suspect scram contactors have now been replaced and the contactors were being analyzed to determine the failure mod A factor complicating the investigation of the scram was that the annunciator alarm printer had been turned off approximately 50 minutes prior to the scram due to its memory having been overloaded by several alarms that were coming in repeatedly and were distracting the operator .
On September 8, 1989, at approximately 4:20 a.m. (CDT), with Unit 2 in cold shutdown the licensee was performing a routine surveillance of the intermediate range monitors (IRM's) (LIS-NR-402). After completing the testing of the D IRM, the Instrument Mechanic (IM) was returning the IRM to the operable mode. A half-scram of the B RPS channel was expected when this occurred due to a spike in the charmel as the IRM's mode switch was move However, when the mode switch was moved to the operate position only the RPS indicating lights for subchannels B2 and B3 extinguished. The indicating lights for subchannels B1 and B4 remained energized. The licensee made a courtesy Emergency Notification System (ENS) notification at 8:12 a.m. . The licensee is continuing to investigate the cause of this event and how it possibly relates to the event on August 2 The resident inspectors have closely followed the licensee's investigations and actions for both of these e"rnt A meeting was held in Region III with the licensee on September 11, 1989, to discuss these events and the licensee's findings and conclusions as a result of their investigation. To date, the cause of the scram remains unknown. Investigation of the suspect contactors is continuing and is being closely followed by the Division of Reactor Safet No violations or deviations were identified in this are . 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. One open item disclosed during the inspection is discussed in Paragraph . Meetings (30703)
On Monday, September 11, 1989, a meeting was held in the NRC Region III office with members of the NRC, Commonwealth Edison and General Electri The subject of this meeting was the review of the LaSalle Unit 2 August 26, 1989 scram which is discussed in Section 11, Unit Trips. Items of concern at the time of the scram and scram recovery were: what caused the scram why did two of the scram contactors not actuate discussion of other anomalies during scram recovery
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.y o-At the time of the meeting, the reason for the scram was still undefine A second, followup meeting is scheduled for October 6,198 . Exit Interview (30703)
The inspectors met with licensee representatives (denoted in Paragraph 1)
throughout the month and at the conclusion of the inspection period and summarized the scope and findings of the inspection activities. The licensee acknowledged these findings. The inspectors also discussed the likely informational contents of the inspection report with regard to documents or processes reviewed by the inspector during the inspectio The licensee did not identify any such documents or processes as proprietary.
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