IR 05000373/1999015

Insp Repts 50-373/99-15 & 50-374/99-15 on 990729-0916.One Violation Noted & Being Treated as Ncv.Major Areas Inspected:Aspects of Licensee Operations,Maint,Engineering & Plant Support

ML20217A879
Person / Time
Site:	LaSalle
Issue date:	10/06/1999
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20217A765	List: IR 05000373/1999015 ML20217A760
References
50-373-99-15, 50-374-99-15, NUDOCS 9910120101
Download: ML20217A879 (18)

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U.S. NUCLEAR REGULATORY COMMISSION REGIONlli Docket Nos: 50-373, 50-374-License Nos: NPF-11, NPF-18 Report Nos: 50-373/99015(DRP); 50-374/99015(DRP) -

Licensee: Commonwealth Edison Company Facility: LaSalle County Station, Units 1 and 2 Location: 2601 N. 21st Road

~ Marseilles,IL 61341 Dates: July 29 - September 16,1999 Inspectors: R. Westberg, Acting Senior Resident inspector P. Krohn, Resident inspector

. L. Collins, Resident inspector Approved by: Melvyn N. Leech, Chief Reactor Projects Branch 2 1'

Division of Reactor Projects l

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9910120101 991006 73 DR. ADOCK 0

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EXECUTIVE SUMMARY LaSalle County Station, Units 1 and 2 NRC Inspection Report 50-373/99015(DRP); 50-374/99015(DRP)

This inspection report included aspects of licensee operations, maintenance, engineering and plant support. The report covers a 7-week period of inspection conducted by the resident staf Plant OperatioD1 -

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.. i Operator response to reactor water level oscillations was not in accordance with abnormal operating procedures and training. This was one of tFf./ examples in a non-l cited violation concoming procedural adherence and human perm. nance issues. The -

prompt investigation did not thoroughly address the operator performance issues and as a result very limited corrective actions were taken prior to reactor startup and additional feedwater system testing.- (Section 01.1) l

. The Unit 2' approach to criticality was conducted in a controlled and deliberate manner '

The material condition problems with the rod sequence control system / reactor manual control system were a challenge to the operators during the startup. (Section O1.2)

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. Several preventable human errors contributed to a Unit 1 automatic reactor shutdown on )'

low reactor vessel water level.- The errors were not isolated to one department and included operating outside of established procedures, incomplete communications,

. inadequate pre-job briefs, lack of direct oversight and supervision of activities outside '

- the control room, inadequate control room annunciator response, and lack of specific procedural guidance for the preventative maintenance activity performed. This event provided the second and third examples in a non-cited violation conceming procedure adherence and human performance issues. (Section 01.3) i The control room response to the automatic reactor shutdown was good and rapidly stabilizsd plant conditions. The licensee's prompt investigation was timely, focused, and highlighted several human errors. Site management made appropriate efforts to engage and improve human performance at the station. (Section 01.3)

. Unit 1 startup and retum to full power operations was performed in a slow and deliberate manner without problems. The control room crew exhibited a good questioning attitude in identifying, investigating, and resolving unerpacted turbine responses during initial turbine roll. (Section 01.4)

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. Operators were unnecessarily challenged on two occasions. First, when maintenance personnel acted outside of an approved troubleshooting procedure causing a combined

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intermediate valve to cycle and, second, when a half-scram occurred during an oscillating power range monitor modification. (Section 01.5)

Plant Suocort

.- Radiation Protection personnel performed satisfactory monitoring of new fuel receipt

" shipments. (Section R1.1)

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Radiation Protection and Chemistry personnel exhibited good radiation dose awareness !

by reducing hydrogen injection rates and mi.1imizing personnel radiation exposure !

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during maintenance following the return of Unit 1 to power operation. (Section R1.'1) )

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Reaprt Details

, Summary of Plant Status

During this inspection period, Unit 1 operated near full power until coastdown on August 9, 11999, in preparation for an upcoming refueling outage. Unit 1 continued to operate in coastdown until an automatic reactor shutdown on low reactor vessel water level occurred on September 2,1999. Unit i returned to full power operation on September 8,1999.' Unit 2 operated near full power until an automatic reactor shutdown on low reactor vessel water level t occurred on August 21,1999. Unit 2 retumed to full power operation on August 26,199 l. Operations

' 0 . Conduct of Operations

'0 Unit 2 Reactor Trio l.0soection Scone (71707)

The inspectors reviewed licensee corrective actions in response to a Unit 2 automatic reactor shutdown on low reactor water level that occurred on August 21,1999. The inspectors evaluated both the technical and human performance issues contributing to the event and the licensee's prompt investigation and immediate and planned corrective actions Interviews were conducted with various licensee personnel. Dccument reviewed included:

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Problem identification Form (PlF) L1999-4002, " Unit 2 Reactor Scram Due to Low Reactor Water Leval," dated August 21,1999

Prompt investigation of Automatic Unit 2 Reactor Low Water Level Trip, Post

' PORC [ Plant Operating Review Committee], dated August 12,1999

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Root Cause Report AR15139, " Automatic SCRAM of Unit 2 on Low Reactor-Water Level Due to Failure of the 2A Turbine Driven Reactor Feedpump," dated l' September 9,1999

' '* LaSalle Station Units 1 and 2, and Common Operating Department General Procedure (LGP) LGP-3-2, "Ruactor Scram," Revision 42

. LaSalle Administrative Procedure (LAP) LAP-100-40, " Procedure Use and Adherence Expectations," Revision 18

• . LaSalle Station Operating Department Procedure (LOP) LOP-RL-01, " Operation of the Reactor Water Level Control System," Revision 14

.. LaSalle Station Unit i Operating Abnormai Procedure (LOA) LOA-FW-101,

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' " Reactor Level /Feedwater Pump Control Trouble," Revision 3

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. LAP-100-35, " Reactivity Management Controls," Revision : Observations and Findinas

The Unit 2 reactor tripped or 'ow reactor water level on August 21,1999, at 10:55 ' ' The inspe'ctors responded to the site and determined that the trip was uncomplicated and that the reactor was stable in hot shutdown. The I;censee's prompt investigation determined that the probable root cause of the reactor trip was inadequate procedure

- adherence by the reactor operator who did not enter the appropriate abnormal operating

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procedure when reactor level control problems occurred. Abnormal operating procedure LOA-FW-101 directed operators to place the controls of both turbine driven reactor feedpumps in manual and attempt to stabilize level. Contrary to these instructions, the operator responded to the level oscillations by placing the "A" feedpump in manual, leaving the "B" feedpump in automatic, and subsequently tripping the "A" pump and starting the motor-driven reactor feedpump. With these actions the operator was unable to control level and the reactor automatically tripped on low reactor water leve Technical Specification (TS) Section 6.2.A.a required that written procedures shall be established, implemented, and maintained for activities referenced in Appendix A of Regulatory Guide 1.33, Revision 2, dated Febr"ary 1978. LaSalle Abnormal Procedure LOA-FW-101 was a procedure regt ..ed by Regulatory Guide 1.33, Appendix A and, therefore, was required to be implemented in accordance with TS 6.2.A.a. The failure to adhere to Abnormal Operating Procedure LOA-FW-101 was an example where the requirements of TS 6.2.A.a were not met and was a violation (50-374/99015-01a(DRP)). This violation is one of the three examples of failing to follow procedures identified in this report. This Jeverity Level IV violation is being treated as a Non-Cited Violation, consistent with /.ppendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as Action Tracking Matrix Item 513 Operators had received training within the past year on reactor level control and the proper response to abnormal ccnditions because of a similar problem which resulted in a manual reactor trip in 1998. The inspectors questioned whether sufficient investigation had been completed to understand why the operator did not follow training and procedures and whether crew performance was appropriate for the situation. While the licensee intended to perform further reviews during the root cause investigation, about 4 days after the reactor trip, no further investigntion was completed, no further corrective actions had been taken, and the plant was proceeding with startup and feedwater system tuning which could have led to another level transient. The inspectors conveyed these concems to the licensee and after direct intervention by plant upper management, the root cause investigation became more vigorou The initial cause of the level oscillations was documented in the prompt investigation as a lack of complete tuning of the feedwater control system at less than full reactor powe Prior to the reactor trip, reactor power had been reduced to approximately 75 percent to support maintenance activities. Engineers later'ald the inspectors the feedwater control system was most susceptib!e to minor oscillations around this power level, but that previous system tuning had shown all parameters to be within design setting Additional tuning efforts during startup were planned to optimize feedwater control system response at all power levels. Five days after the reactor trip, during sta. tup and preparation for the tuning efforts, maintenance technicians identified that the mounting block for the "A" turbine driven reactor feed pump control oil servo assembly was loos Once tightened, operators reported that the feedpump control system response had changed. During subsequent tuning efforts, a gain adjustment was necessary to restore proper feedpump response. Engineers told the inspectors that it was likely that the loose servo assembly mounting had existed since reactor startup in the spring of 1999 and that previous tuning efforts had compensated for the effects of the loose servo assembly. Although not initially identified as an initiating event, the licensee's root cause investigation subsequently identified the loose servo assembly mounting cap screws as the primary cause for the level oscillation L

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' ~ Conclusions f

Operator response to reactor water level oscillations was not in accordance with abnormal operating procedures and training. This was one of three examples in a non-

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cited violation.conceming procedural adherence and human performance issues. The prompt investigation did not thoroughly address the operator performance issues and as a result very limited corrective actions were taken prior to reactor startup and additional feedwater system testin ; O1.2 Unit 2 Reactor Startuo and Retum to Full Power Operation Inspection Scooe (71707)

On August 23-24,1999, the inspectors observed portions of the Unit 2 startup and approach to criticality. ' Documents reviewed included the following:

a' LOP-RM-01, " Reactor Manual Control Operation," Revision 14

• LGP-1-1, " Normal Unit Startup, " Revision 5 b, Observations and Findinas in accordance with LOP-RM-01, control rod withdrawal and the approach to criticality were conducted in a controlled and deliberate manner. In addition to the normal control room crew, a reactivity senior reactor operator, an independent verifier (Qualified Nuclear Engineer), and an' assist reactor operator assisted the crew. Senior station management and the shift manager were also present during the approach to criticalit Although the approach to criticality was conducted in a controlled and deliberate manner, it was not entirely troubic free. Rods blocks were encountered during the startup from the Rod Sequence Control System (RSCS)/ Reactor Manual Control System (RMCS). The RSCS, a system which is abandoned in place, had been previously electrically bypassed. However, during the startup the RSCS caused unnecessary rod blocks. The output of the RSCS was subsequently manually jumpered and pulling of control rods resumed after a 5-hour delay, in addition, problemr with the Unit 2 station air compressor blow out valve caused a minor delay, Conclusions The Unit 2 approach to criticality was conducted in a controlled and deliberate manne Material condition problems with the rod sequence control system / reactor manual control system were a challenge to operators during the startu .3 Unit 1 Automatic Reactor Shutdown Insoection Scooe (71707)

. The inspectors reviewed the control room response, human performance issues, prompt investigation results, and the corrective actions associated with a Unit 1 automatic reactor shutdown on low reactor water level that occurred on September 2,1999, at 10:36 a.m. This was the second automatic reactor shutdown to have occurred at the

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LaSalle County Generating Statioa in 13 days. The first auto'matic reactor shutdown was discussed in Section 01.1 of this report. Documents reviewed included:

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PlF L1999-04173 " Unit i Scram Due to Low Level Resulting From a Feed Water Transient"

.*- Prompt Investigation of Unit 1 Automatic Scram'on Low Reactor Water Level,

' dated September 3,- 1999

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- Work Request (WR) 990085157, " Lubricate 1B TDRFP [ Turbine-Driven Reactor Feed Pump] LPEHC [ Low Pressure Electro-Hydraulic Control] B Servo Valve" 3

-' LAP-200 7, Event Frequency Reduction Post Event Review Program, " Unit 1 l'

Reactor Scram on September 2,1999,10:36 a.m."

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LOP-FW-14, "TDRFP LPEHC Filter Cleaning," Revision 3

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• LaSalle Station Manager Letter to LaSalle Station Personnel, " Human i Performance of LaSalle Station," dated September 1,1999

- LGP-3-2,' " Reactor Scram," Revision 42

LaSalle Station Unit 1 General Abnormal Procedure (LGA) LGA-01, "RPV

- [ Reactor Pressure Vessel ] Control (Unit 1)," Revision 18

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LAP-100-40, " Procedure Use and Adherence Expectations," Revision 1 Qbgervations and Findinas On September 2,1999, Unit 1 automatically shutdown on low reactor water level due to an' operator error related to the 1B Turbine-Driven Reactor Feed Pump (TDRFP) control oil system. A routine preventative maintenance task, WR 990085157, was in progress to lubricate the 1B TDRFP LPEHC "B" sub-loop control valve. Prior to the preventative maintenance, a heightened-level-of awareness (HLA) briefing was held in the control room with the Unit i supervisor, umlicensed operator (NLO), nuclear station operator (NSO), two instrument maintenaace department (IMD) technicians, end the IMD first-line supervisor in attendance. Senior management also observed the HLA as part of the routine monitoring requirements. The HLA specifically discussed the work to be performed on the "B" sub-loop and the need for the "A" sub 'oop to be in control. The j HLA focused on the communication of maintenance activities, radiation protection )

issues,' verification techniques, and personnel safet l The HLA did not discuss the specific procedure to be used by the NLO or the actions the NLO was to perform at the 1B TDRFP local control cabinet, panel 1FWO7JB. Since no specific procedural guidance for the lubricating activity existed, the NLO chose to ;

adapt another procedure, LOP-FW-14, as he thought appropriate. LaSalle operating department Procedure LOP-FW-14 was actually a procedure for the inspection, i cleaning, and replacement of TDRFP LPEHC filter / orifice assemblies and did not discuss lubrication of the LPEHC servo valves. The NLO made an error in adapting _

LOP-FW-14 to WR 990085157 and highlighted steps to place the "A", instead of the "B", l sub-loop in manual control. LaSalle Administrative Procedure LAP-100-40, Step B.11 '

required that supervisors review partial procedures and specifically authorize any subsections to be used in this case, the supervisory review by the NLO's supervisor, the Unit 1 supervisor, was not performe Since "A" sub-loop was in service prior to the automatic reactor shutdown, appropriate turbine speed control conditions for WR 990085157 would have left the "A" sub-loop on line, in automatic control from the control room controller. During the execution of WR 990085157, however, the NLO inappropriately took control of the 1B TDRFP at the

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local electronic cabinet by taking the mode switch for sub-loop "A"instead of sub-loop

"B" from the " Automatic" to the ? Manual" position. During the subsequent maintenance on the "B" sub-loop servo valve, a speed control error signal was generated and continued to build u During the lubrication of the "B" servo, an instrument maintenance control systems technician (CST), unrelated to the work activity, passed by the local control panel and noted that the panel was in alarm. The CST reviewed the local panel indicationa and informed the NLO that, in the present configuration with "A" sub-loop in " Manual", control of the 1B TDRFP had been taken away from the control room. The NLO considered the j CST's remarks and reviewed his adapted copy of LOP FW-14. After some l consideration, and without informing supervision or the control room, the NLO retumed the "A" sub-loop mode switch to " Automatic." When the "A" sub-loop was restored to automatic operation, a minimum speed demand signal was sent to the 1B TDRFP. This caused the 1B TDRFP to ramp to a zero demand signal with Unit 1 at approximately 94 percent reactor power. A rapid feed water transient followed that led to an automatic l reactor shutdown on low water level in about 12 second The Unit 1 NSO responded appropriately to the feed water transient by reporting the low reactor vessel water level to the Unit i supervisor, taking both 1 A and 1B TDRFPs to manual control, and attempting to start the motor-driven reactor feed pump (MDRFP).

Before feed water flow could be recovered, however, an automatic reactor shutdown occurred on low reactor vessel level. The control room crew responded satisfactorily to the automatic reactor shutdown and entered Procedure LGP 3-2 for the automatic j shutdown and LaSalle general abnormal procedure (LGA) LGA-01 to control reactor vessel watu level. The inspectors observed portions of the crew's response to the automatic reactor shutdown and noted rapid stabilization of plant conditions and timely, informative crew briefings. No emergency core cooling system actuations were required or occurred during the transient. All Unit 1 systems operated as designed with the exception of minor problems caused during the automatic auxiliary power fast bus transfer and a delay in restoring the 345 kilovolt ring bus due to difficulties in opening the main power transformer disconnect Following the automatic reactor shutdown, the licensee performeu r, prompt investigation of the conditions leading up to and including the automatic shutdown. The prompt investigation was adequate and highlighted several human urors which contributed to the automatic reactor shutd rn which included the following:

• The NLO's actions were not in accordance with Procedures LAP-100-40 and LOP-FW-14 when he retumed the 1B TDRFP local control panel mode switch to automatic control without informing the control room of either the original switch mispositioning or the action that was being taken to repostition the mode switc The NLO was unaware of the requirement of LAP-100-40, Step B.2.5 to stop work and inform supervision when he found that the procedura in use was not correc The NLO and unit supervisor were unaware of the requirements of L.AP-100-40, Step B.11 for supervisory review of partial procedures. This resulted in the NLO following a flawed procedure, LOP-FW-14, which he had chosen to adapt for the

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lubrication activity.' The partial procedure review did not occur and allowed the NLO to proceed with a procedure that was not required for the maintenance task being performed and which was flawe *. Work Request 990085157 was sufficiently descriptive to have performed the maintenance task satisfactorily without the NLO having adapted LOP-FW-14. In

- light of the work order instructions, the NLO's partial procedure was not required to correctly perform the maintenanc *

The NLO did not receive a pre-job brief for his activities at the local control pane Rather, the HLA in the control room was relied upon as the pre-job brief for the NLO. The HLA did not address the NLO's specific actions at the local control -

panel, expsetations conceming communications and notifications of activities from the local control panel, the specific procedural guidance to be us,ed, or related contingency actions. During local panel manipulations, no equipment piece numbers were specified and specific actions were not reported to the control roo * ' No direct oversight or field supervision was provided to the NLO at the local control pane Control room operator response to an annunciator failed to identify that the wrong sub-loop had been selected by the NLO.~ During lubrication of the "B" servo, annunciator 1H13-P803-A510, "1 A/B TDRFP Speed Control System Trouble Alarm," was received in the control room when the equipment operator

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initially took the "A" local control cabinet mode switch to manual control. The

' NSO contacted and questioned the NLO at the local panel about the annunciator, but became convinced that the alarm was expected. Annunciator response procedure, LOR-1H13-P603-A510, Revision 0, " Operator Action,"

Step B.3 directed the NSO to dispatch an operator to the 1FWO6JA/JB panel at the 749' level in the Auxiliary Building to view the specific alarm description on the programming and diagnostic unit touch screen. No operator was dispatched to this panel. Proper attention to thic alarm would have alerted the NSO to the fact that the inservice sub-loop "A" mode switch had been placed in " Manual."

Technical Specification Section 6.2.A.a required that written procedures shall be established, implemented, and maintained for activities referenced in Appendix A of Regulatory Guide 1.33; Revision 2, dated February 1978. LaSalle Administrative Procedure LAP-100-40 was a procedure required by Regulatory Guide 1.33, Appendix A and, hence, is required to be implemented in accordance with TS 6.2.A.a. Contrary to the above, the unit supervisor and NLO violated TS 6.2.A.a by failing to follow LAP-100-40 in two ways. First, the unit supervisor and NLO failed to follow the  !

requirements of LAP-100-40, Step B.11 when the NLO's partis,1 procedure was not i reviewed by eupervision (50-373/990015-01b(DRP)). Second, the NLO failed to follow the requirements of LAP-100-40, Step B.2.5 by not stopping work and informing supervision when it was found that the procedure in use was not correct (50-373/990015-01c(DRP)). The failure to adhere to the requirements of TS 6.2. constitutes a Severity Level IV violation and is considered the second and third examples of failing to follow procedures. This Severity Level IV violation is being treated as a Non-Cited Violation, consistent with Appendix C of the NRC Enforcement Polic ,-

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This violation is in the licensee's corrective action program as Action Tracking Matrix ltem 1578 The licensee's prompt investigation of the Unit 1 automatic reactor shutdown was timely and probing. The investigation correctly identified the multiple barriers and incorrect actions that led to the automatic reactor shutdown. Site management took strong actions to improve human performance through station standdowns, letters to all site

- personnel, initiatives to improve Hl.A pre-job briefings, and daily orders to operations personnel. As an example, one daily order directed that, for high risk activities, the NSO and field operator will establish communications and discuss particular steps before and after completion. Another daily order required the field supervisor to be present at all HLA's that required field work by the operators and then to be present in the field, directly supervising the critical activities identified in the briefing, Conclusions Several preventaNe human errors contributed to a Unit 1 automatic reactor shutdown on low reactor vessel water level. The errors were not isolated to one department and included operating outside of established procedures, incomplete communications, inadequate pre-job briefs, lack of direct oversight and supervision of activities outside the control room, inadequate control room annunciator response, and lack of specific procedural guidance for the preventative maintenance activity performed. This event provided the second and third examples in a non-cited violation concerning procedure adherence and human performance issue '

The control room response to the automatic reactor shutdown was good and rapidly stabilized plant conditions. The licensee's prompt investigation was timely, focused, and

' highlighted several human errors. Site management made appropriate efforts to engage and improve human performance at the statio .4 Unit 1 Reactor Startuo and Return to Full Power Operation tr13paction Scooe (71707)

On September 3-4,1999, the inspectors observed portions of the Unit 1 reactor startup, approach to criticality, synchronization to the electrical grid, and ascension to full power operation. Documents reviewed during this inspection included the following:

• LOP-RM-01, " Reactor Manual Control Operation," Revision 14 i LGP-1-1, " Normal Unit Startup," Revision 59

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LOP-TG-02, " Turbine Generator Startup," Revision 3 . Observations and Pndinas Control rod withdrawal and approach to criticality were conducted in a controlled and deliberate manner in accordance with the requirements of LOP-RM-01. A qualified nuclear engineer, senior reactor operator, and NSO aJgmented the normal control room ataff and performed all control rod manipulations during startup. These personnel remained attentive to all reactivity manipulations and kept the duty control room staff informed of all actions taken. Heightened-level-of-awareness briefings were held at appropriate points during reactor startup and power ascension. Senior management ;

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observed reactor startup and power ascension and ensured HLA briefings were of good qualit The inspectors observed turnover between the oncoming and off-going shift manager and the Unit 1 supervisor and NSO prior to rolling the main turbine. The tumover included control room board walkdowns, discussion of alarming annunciators, activities accomplished on the previous shift, and upcoming plans. The tumovers observed by the inspectors were complete and accurately reflected plant condition Synchronization of the main turbine to the electrical grid was performed in a controlled and deliberate manner. The inspectors observed two instances of a good questioning

- attitude by the Unit 1 control room crew During the first instance, the NSO noted that during preparations to synchronize the main turbine to the grid, the turbine load set function did not respond as expected. LaSalle Operating Procedure LOP.TG-02, Step E.1 instructed the NSO verify that the Load Set Meter on panel 1PM02 was set at approximately 50 megawatts (MW) or greater. The NSO noted that when the Load Set meter was adjusted to greater than 40 MW, a limiter in the electro-hydraulic control (EHC) system caused the Load Set to decrease to approximately 20 MW. Since Step E.1 could not be performed as written, the NSO stopped and informed the unit supervisor and shift manager of the unexpected Load Set Meter response. System engineers were contacted ar d it was learned a procedure revision on Step E.1 had already been submitted and that, with the given turbine configuration, the EHC system was responding as expected. A temporary procedure change was completed for Step E.1 to allow the Load Set Meter to be set to approximately 40 MW and the turbine c roll to 1800 revolutions per minute (rpm) proceede On the second occasion, the same NSO questioned the turbine intercept valve j response on the initial turbine roll to 100 rpm during performance of LOP-TG-02, !

. Step E.16. The NSO observed that after the intercept valves opened to accelerate the j turbine as expected, three of tha six intercept valves partially closed once the turbine i reached 100 rpm.- The turbine vendor representative and system engineer were contacted it was determined that the turbine control valves were leaking slightly and 1 that the intercept valves had responded as expected to limit turbine speed to the )

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Synchronization to the electrical grid occurred without problems and power ascension continued at a deliberate rate until full power was reached on September 8,199 l Conclusions -

Unit 1 startup and return to full power operations was performed in a slow and deliberate manner without problems. The control room crew exhibiteo a good questing attitude in identifying, investigating, and resolving unexpected turbine responses during initial L ' turbine rol ,

O1.5 Qgerator Challences Durino Troubleshootino and Modification Activities i Inspection Scope (71707)

~ The inspoetors reviewed licensee corrective actions in response to an unexpected opening of the #4 combined intermediate valve (CIV) during troubleshooting on

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August 24,1999. The inspectors also reviewed the circumstances surrounding a Unit 1 half-scram that occurred on August 30,1999, during pre-outage wiring for an upcoming oscillating power range monitor (OPRM) modification. Documents reviewed during this inspection included the following:

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PIF L1999-04047, " Main Control Room Unaware of Troubleshooting Plans,"

dated August 24,1999

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Accelerated Investigation of Deviation from Troubleshooting Plan for the #4 CIV Solenoid datri August 25,1999

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Work Requent 99008588-01, " Valve Closed But Wouldn't Reopen While Doing

[LaSalle Operating Department Surveillance] LOS-TG-SR3," dated August 24, 1999

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Nuclear Station Procedure (NSP) NSP-WC-3010, Attachment A Troubleshooting -

Data Sheet

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LaSalle Prompt Investigation Report L1999-04127, " Unit 1 Half-Scram During Wire Pull for OPRM Installation" -

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PIF L1999-03655, " CAP [ Corrective Action Program] Identified: Adverse Trend in Half-Scrams."

b. - Observations and Findinos On August 24,1999, during troucle shooting activit'ies on the #4 CIV, which had closed and failed to reopen during survenme testing, the valve unexpectedly went open. The troubleshooting crew, composed of maintenance supervision, electrical maintenance personnel, and a corporate turbine control expert, had deviated from the proposed troubleshooting plan and had not informed the control room. in addition, the troubleshooting plan had not been completed or approved at the time of the event. The tentative p!sn had documented verifying the depth of the plungers of the fast acting rand test solenoids and to manually move the plungers including tapping with a rubber mallet if needed to determine if the solenoids were mechanically bound. However, after determining that the test solenoid plunger was not fully extended and could not be released, the troubleshooting crew stopped and discussed what would take place if the electrical connector was removed. A decision was made to disconnect the amphenol connector to determine if the solenoid was being held electrically. This step was not covered in the troubleshooting plan and the control room was not notified of the change in the plan. The connector was removed with no change in the operating condition of the valve. The turbine expert and maintenance personnel tested the upper test solenoid similar to the lower test solenoid and when the amphenol connector was removed, the

1. 4 CIV was heard to change position. The troubleshooting crew verified that the valve had changed position and contacted the control roo On August 30,1999, instrument maintenance (IM) technicians were removing excess local power range monitor (LPRM) wire from OPRM D, installing and wiring test pointe from average power range monitor (APRM) D, and wiring OPRM channel D to various digital isolation blocks in accordance with WR 990065855. As an IM technician passed wires from the front of control panel 1H13-P60P to another IM technician located in the rear of the same panel, a reactor protection system channel B1 and B2 half-scram occurred on Unit 1. A thermal trip half-scram signal had been generated by APRM channels R and F and a comparctor trip of flow units C and D had occurred. Work was immediately stopped and the half-scram reset. The work request had been identified as a risk sensitive activity and the action plan developed per Attachment B of LAP-1300-24 12-i L

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had concluded that APRM channel D being out-of-service would preclude any problems caused by APRM D. The action plan for the work request was inadequate in that it did I not recognize the potential for the half-scram to occur with D APRM out-of-servic Conclusions Operators were unnecessarily challenged on two occasions. First, when maintenance personnel acted outside of an approved troubleshoot!ng procedure causing a combined intermediate valve to cycle and, second, when a half-scram occurred during an oscillating power range monitor modificatio ll1. Ennineerina

~E8- Miscellaneous Engineering issues -

E (Closed) LER 50-374/99001-00: Failure to Comply with Suppression Chamber - Drywell Vacuum Breaker Technical Specification Action Statement Due to a Management Deficienc ~ On August 4,1999, the licensee declared suppression chamber - drywell vacuum  ;

breaker 2PC001 A inoperable after it was determined thct the action requirements of l TS 3.6.4.b h d not been met. Technical Specification 3.6.4.b required that, with one !

position indicator of any operable suppression chamber - drywell vacuum breaker  ;

inoperable, the vacuum breaker must be visually verified to be ci: sed at least once per !

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24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Otherwise, the vacuum breaker must be declared inoperabl During surveillance testing of the 2PC001A vacuum breaker on June 30,1999, in accordance with LOS-PC-M2, " Multiple Headers Drywell - Suppression Pool Vacuum Breaker Operability, inservice Test, and Channel Calibration," Revision 8, the Division 1 open indication failed to function. The licensee declared the indicator inoperable, entered the TS 3.6.4.b action statement and initiated visual checks of the vacuum i

. breaker every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The visual check consisted of an operator visually verifying that the manual actuator assembly on the vacuum breaker was in the closed position by examining a closed scribe mark'on the actuator assembly. On August 4, site I engineering discovered that this method of visual verification was inadequate. The design of the vacuum breaker was such that the actuator assembly was not directly attached to the valve disk. When the vacuum breaker was closed the actuator arm hung down and did not contact the vacuum breaker disk. Therefore, the closed scribe :

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mark did not provide positive verification that the vacuum breaker was actually close The safety significance of this event, however, was low since during the time the visual check was erroneously performed, the vacuum breaker was capable of performing its pressure relief safety function. In addition the Division 2 position indicator was operable, 4 and had continuously indicated that the vacuum breaker was closed. This event demonstrated a lack of understanding by site engineering and operation personnel of the mechanical arrangement of the vacuum breaker actuator arm assembl During the time period of June 30 to AJgust 4,1999, the licensee did not adequately verify that the Unit 2A suppression chamber - drywell vacuum breaker, 2PC001 A was

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' closed as required by TS 3.6.4.b. However, this failure constituted a violation of minor safety significance and is 'not subject to formal enforcement actio IV, Plant Support R1 _ Radiological Protection and Chemistry (RP&C) Controls R1.1' : Radiation Protection (RP) Department Suooort of New Fuel Receiot and Unit i

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Hvdrooen Water Chemistry (HWC) Addition : Insoection Scone (71750)

The inspectors observed and evaluated the support of the RP Department during new fuel receipt for the upcoming Unit 1 outage and the return of the HWC system to service following the Unit 1 automatic reactor shutdown and subsequent power ascension. On a sampling of new fuel shipments received at the licensee's facility, the inspectors verified that radiation technicians had performed the appropriate contamination and

. radiation surveye required by LaSalle Fuel Handling Procedure (LFP) LFP-200-1,

" Receiving New Fuel," Revision b.- Observations and Findinos The inspectors reviewed the new fuel contamination survey results and noted no discrepancies. Portions of fuel handling observed by the inspectors met the requirements of LFP-200- Durirg Unit i HWC system restoration following Unit i startup on September 7-8, the inspectors noted good RP and Chemistry department control of the hydrogen injection rate. The hydrogen injection rate was maintained at a lower than ncrmal value to -

minimize personnel radiation exposure during maintenance and troubleshooting in the vicinity of Unit 1 steam lines. When the maintenance was complete, the hydrogen ,

injection rate was retumed to its normal value.: Maintaining the hydrogen injection rate at a lower than normal value reduced the general area radiation levels in the vicinity of the maintenance and demonstrated a gocd awareness of ways to minimize personnel exposur Conclusions -

Radiation Protection personnel performed satisfactory monitoring of new fuel receipt shipment ,

- Radiation Protection and Chemistry personnel exhibited good radiation dose awareness by reducing hydrogen injection rates and minimizing personnel radiation exposure duringl maintenance following the return of Unit 1 to power operation I j

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p-V V. Manaaement Meetines X1 Exit Meeting Summary The inspectors presented the results of the inspection to licensee management at an exit meeting on September 16,1999. The licensee acknowledged the findings presented. The inspectors asked the licensee if any materials examined during the inspection should be considered proprietary. No proprietary information was identifie I i

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' PARTIAL LIST OF PERSONS CONTACTED Comed

• J. Benjamin, Site Vice President D. Bost, Site Engineering Manager D. Farr, Operations Manager

' T. Gierich, Work Control Manager

- *G. Kaegi, Site. Training Manager -

• R. McConnaughay, Shift Operations Superintendent

J. Meister, Station Manager

• W. Riffer, Q & SA Manager

• F, Spangenberg, Regulatory Assurance Manager

• R. Stachniak, Nuclear Oversight Assessment Manager

• Present at exS meeting on September 16,1999.

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INSPECTION PROCEDURES USED

IP 37551 Onsite Engineering i

' IP 61726 Surveillance Observation -

IP 62707 Maintenance Observation .

IP 71707 Plant Operations IP 71750 - Plant Support Activitie IP 92700 Onsite Follow-up of Written Reports of Nonroutine Events IP 92901 Followup - Plant Operations IP 92902 Followup - Maintenance IP A2903 Followup - Engineering ITEMS OPENED, CLOSED, AND DISCUSSED Ooened

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50-373/374-99015-01 NCV Three examples of failing to adhere to TS required abnormal and administrative procedures Clos # ,

- 50-374/99001-00 LER Failure to comply with suppression chamber -

drywell vacuum breaker TS action statement due to l a management deficienc /374-99015-01 NCV Three examples of failing to adhere to TS required abnormal and administrative procedures i

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Discussed -

None'

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LIST _OF ACRONYMS USED

APRM '- - Average Power Range Monitor -

CIV' ' Combined Intermediate Valve CST' Control Systems Technician DRP: l Division of Reactor Projects 1 EHC- ; Electro-Hydraulic Control .

HLA( Heightened-Level-of-Awareness -

H W C_- (' Hydrogen Water Chemistry .

IM -' Instrument Maintenance

,IMD . Instrument Maintenance Department -

IR : Inspection Report

' LAP < LaSalle Administrative Procedure:

LER- Licensee Event Report LFP LaSalle Fuel Handling Procedure

' LGA ~LaSalle General Abnormal Procedure

- LGP

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LaSalle General Procedure LOA- LaSalle Abnormal Procedure

LOP _ LaSalle Operating Procedure

LOS- LaSalle Operating Department Surveillance LPRM ' _ Local Power Range Monitor:

LPEH _Low Pressure Electro-Hydraulic Control MDRFP Motor-Driven Reactor Feedwater Pump

- MW Megawatt - NL Non-Licensed Operator NSO- Nuclear Station Operator

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OPRM' l Oscillating Power Range Monitor PlF ' Problem identification Form PORC' Plant Operations Review Committee RSCS Rod Sequence Control System-RMCS1 Reactor Manual Control System -

' RP Radiation Protection rpm . Revolutions Per Minute ;

TSL Technical Specification

.WR - Work Request -

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