IR 05000373/1999003
| ML20206T047 | |
| Person / Time | |
|---|---|
| Site: | LaSalle  |
| Issue date: | 05/19/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20206T014 | List: |
| References | |
| 50-373-99-03, 50-373-99-3, 50-374-99-03, 50-374-99-3, NUDOCS 9905240052 | |
| Download: ML20206T047 (22) | |
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U.S. NUCLEAR REGULATORY COMMISSION REGIONll!
Docket Nos:
50-373,50-374
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License Nos:
50-373/99003(DRP); 50-374/99003(DRP)
Licensee:
Commonwealth Edison Company Facility:
LaSalle County Station, Units 1 and 2 Location:
2601 N. 21st Road Marseilles,IL 61341 Dates:
April 1 - May 12,1999 Inspectors:
K. Riemer, Acting Senior Resident Inspector J. Hansen, Resident inspector R. Westberg, Acting Resident inspector J. Starefos, Resident inspector, Region 11 D. Pelton, Resident inspector, Region lil D. Muller, Reactor Engineer, Region Ill
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D. Chyu, Reactor Engineer, Region 111 E. Duncan, Reactor Engineer, Region lli J. Adams, Resident Inspector, Region ill R. Lerch, Project Engineer, Region 111 P. Prescott, Senior Resident Inspector, Region lil Approved by:
Melvyn N. Leach, Chief Reactor Projects Branch 2 Division of Reactor Projects 9905240052 990519 PDR ADOCK 05000373
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EXECUTIVE SUMMARY LaSalle County Station, Units 1 and 2 NRC Inspection Report 50-373/99003(DRP); 50-374/99003(DRP)
This inspection report included aspects of licensee operations, maintenance, engineering and plant support. The report covers a 6-week period of inspection conducted by the resident staff.
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Plant Operations In general, the inspectors observed that operations personnel were knowledgeable of
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plant and equipment status, maintained accurate records, effectively communicated operational information, and operated equipment in accordance with approved procedures. Unit 1 continued operating safely while considerable station efforts and resources were devoted to supporting the restart of Unit 2. (Section 01.1)
Operators generally performed well during the restart of Unit 2. Few material condition
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deficiencies occurred to significantly challenge the operators. Operator performance, good plant material condition, and acceptable support from other station departments all contributed to a relatively smooth and error-free restart of Unit 2. (Section 01.2)
Examples of weaknesses occurred during the performance of fundamental activities
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such as operator log keeping and entering items into the station's corrective action program. Those examples, combined with several examples of cumbersome written procedures, represented potential weaknesses in the barriers established to ensura sustained, error-free performance. An example of a non-cited violation was identified for failing to log suppression pool temperatures during a surveillance and a non-cited violation was identified for an incorrect annunciator response procedure. (Section 01.2)
The operators followed approved procedures and took prompt, conservative actions in
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response to equipment problems such as the trip of a condensate / condensate booster pump and control rod double notching. (Section O2.1)
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Drywell housekeeping was good following completion of the outage and the condition of
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the drywell was satisfactory to support the Unit 2 startup. No equipment abnormalities
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were found and the housekeeping items would not have impacted plant activities.
(Section 04.1)
A self-induced challenge to plant operations occurred when operators failed to ensure
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that the isolation valve for the turbine stop valve / turbine control valve fast closure alarm was in the correct position. An example of a non-cited violation was identified for the fact that operations personnel inappropriately "N/A'd" the requirement to verify the position of the isolation valve. (Section O4.2)
Operators did not always display a questioning attitude and ensure a thorough
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understanding of system operation. Operators were not cognizant of the reason for elevated Unit 2 pre-treatment off-gas radiation levels. Operator lack of understanding of the circulating water system operation contributed to a spill of 30,000 gallons of water in the circulating water pit. (Section 04.3)
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The circulating water spill accelerated investigation, after prompting by senior
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management, was thorough and provided comprehensive corrective actions.
(Section 04.3)
Maintenance In contrast to the residual heat removal (RHR) service water keep fill check valve failure
discussed in Inspection Report 99002, the operators responded conservatively to a similar failure and declared the system inoperable. (Section M1.1)
In response to a previous failure, the system engineer generated a procedure change
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request (PCR) that was narrow in scope as it did not evaluate the acceptance criteria for all RHR service water keep fill check valves. Also, the scheduled procedure revision
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was not timely as the procedure would have been completed several times prior to revision. Timely revision of the procedure was a concern as a division of the RHR system must be declared inoperable and maintenance performed on the system following each check valve failure. (Section M1.1)
Maintenance personnel normally performed work activities in a safe and controlled
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manner. Mechanics followed adequate procedures and work practices and work was properly scheduled. Mechanics responded promptly to a circulating water system leakage event. However, an inadequate work package for the traversing in-core probe system delayed the Unit 2 reactor startup. (Section M2.1) -
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Engineering personnel generally provided timely and accurate support to plant
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organizations. (Section E2.1)
' In some instances, engineers provided unclear, incomplete, or inaccurate information i
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while providing support to plant organizations. Reactor engineers did not adequately
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communicate the expected specific activity of the Unit 2 primary coolant to operators
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prior to the restart. Nuclear Fuels Management personnel did not clearly communicate the effects of the extended shutdown in the Unit 2 core target rod pattern, and system engineering's lack of understanding of the circulating water pump capabilities
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contributed to a spill of 30,000 gallons of water in the circulating water pit.
(Section E2.1)
The Y2K readiness review was completed with acceptable results. Tl 2515/141 was
closed. (Section E8.1)
Plant Suooort In general, actions taken by the licensee were adequate to protect personnel from
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radiological hazards. (Section R1.1)
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Report Details Summarv of Plant Status During this inspection period, the licensee operated Unit 1 at or near full power except for minor power reductions performed to support scheduled activities. Unit 2 remained shut down until April 9,1999, for an extended refueling outage. Operators commenced a reactor startup on Unit 2 on April 9,1999. The Unit 2 main generator was synchronized to the electrical grid on April 11,1999. Full power was reached on Unit 2 on April 17,1999, and the unit remained at or near full power for the remainder of the inspection period, l. Operations
Conduct of Operations 01.1 General Comments (71707. 61726)
The inspectors conducted frequent reviews of ongoing plant operations. These reviews included observations of control room shift turnovers and operator performance during plant evolutions. Also, the inspectors reviewed daily logs and interviewed operations personnel regarding plant status and events.
The inspectors observed discussions regarding the status of plant equipment, planned testing, and maintenance. In general, the inspectors observed that operations personnel were knowledgeable of plant and equipment status, maintained accurate records, effectively communicated operational information, and operated equipment in accordance with approved procedures. Plant personnel operated Unit 1 safely during the time when the Unit 2 restart activities were in progress. Operators remained focused on Unit 1 status during a time of potential distraction presented by the Unit 2 power ascension program. Other observations are detailed in the sections below.
01.2 Unit 2 Startuo Observations a.
Inspection Scooe (71707. 93802)
The inspectors observed Unit 2 startup activities continuously from initial rod withdrawal on April 9,1999, through initial power ascension testing activiti~ at 75% reactor power.
i Observed activities included control rod withdrawal to reactor criticality, reactor core isolation cooling (RCIC) testing, feedwater system testing, main generator synchronization to the grid, and other testing activities which occurred during the power ascension program. The inspectors also observed portions of the plant startup from 75% power through the completion of testing activities at 100% power.
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Observations and Findinas Operators commenced the Unit 2 reactor startup on April 9,1999, and made the reactor critical later on the same day. The main generator was synchronized to the grid, per the sequence specified in the licensee's power ascension plan, on April 11,1999. Full power was reached on April 17,1999, and the licensee formally exited the startup test program on April 21,1999.
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Few significant material condition deficiencies occurred that challenged the operators.
Operators also generally performed well and were provided acceptable support from othar station departments. The control room atmosphere was quiet and professional throughout the startup test program. Turnovers performed by the operations staff were l
good. The inspectors noted that both operators and senior reactor operators walked the control room panels down together and conducted detailed discussions concerning plant status. Operators consistently utilized three-way communications and formal repeat-backs. The inspectors also noted that non-operations personnel utilized three-way communications to formally transmit information to control room personnel.
For example, the station nuclear engineers utilized formal three-way communications when interfacing with operations during reactivity changes. Shift turnover and pre-evolution briefs were informative and designated individual roles and responsibilities as well as detailing specific information relative to the upcoming shift or startup activity.
The unit supervisors demonstrated good command and control over ongoing activities.
Oversight of the power ascension activities was good by both senior licensed operators and station managers. The inspectors noted timely and effective coaching of personnel by both senior management and senior reactor operators.
While the startup activities occurred relatively error-free, the inspectors noted a few examples of weaknesses in several functional areas. While the individual examples listed below each held minor safety significance, collectively, they represented a potential weakness in the barriers established to ensure error-and event-free unit operations. The inspectors noted weaknesses in operator log keeping, corrective action program implementation, and cumbersome proceduralissues. The specific examples are listed below.
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Operator Log Keeping i
in addition to observing operator performance during the power ascension activities, the
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inspectors reviewed control room logs to verify that the appropriate events and activities
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were formally documented. While operator logs usually documented relevant shift activities, the inspectors identified multiple instances where the control room logs did not capture all relevant information and the shift activities could not be recreated entirely by reading operator logs. Examples of items that the operators failed to log included the following:
problerns encountered during RCIC flow testing a
failed initial attempts to synchronize the main generator to the grid
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failure to comply with procedural documentation requirements during RCIC a
testing traversing in-core probe (TIP) system problems
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Additionally, the inspectors identified two instances where the shift managers did not document that the Shift Manager Log review was completed as required prior to shift tumover. In both instances, the inspectors determined that the shift managers were knowledgeable of plant conditions.
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b Corrective Action Program implementation While the licensee effectively addressed most problems as they occurred, the inspectors noted multiple examples where deficient conditions were not entered into the licensee's corrective action program via generation of a Problem Identification Form (PIF). The inspectors were concerned that, while the immediate problem may have been solved, long-term or broad corrective actions could not be implemented if the item was not formally captured and entered into the corrective action process. Examples of deficient conditions not formally documented included the following:
RCIC testing problems
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potential main generator synchronization problems
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RCIC procedural compliance concerns
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TIP system problems i
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Following prompting by the inspectors, the licensee initiated PIFs to document the above issues. Licensee management also initiated a PIF to look more broadly at why j
the issues were not initially captured and formally entered into the corrective action program. The Station's Nuclear Oversight organization identified similar concerns and during a subsequent review of operator logs conducted on April 18,1999, identified several more examples of the licensee's failure to document deficient conditions via the PlF process.
Procedural Weakness issues
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The inspectors also reviewed the procedures used during the conduct of startup activities. While most written procedures were adequate to support completion of the specific task, the inspectors noted examples of potentially weak or cumbersome procedures. While the specific procedural weaknesses documented below did not directly result in a significant safety concern, the inspectors noted one case where a cumbersome procedure may have contributed to an operator's failure to comply with all documentation requirements listed in the procedure. Specific examples of the procedural issues are listed below.
Initial Plant Conditions Reauired For RCIC Testina:
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While observing reactor startup activities, the inspectors noted that the governing procedure for the startup was less restrictive than the Technical Specifications (TS) with respect to RCIC operability requirements. Specifically, Power Ascension Special Procedure (LLP)-98-033. Revision 0, step E.1.11.7 allowed the licensee to establish 165# (150 15 psig) pressure for low pressure RCIC testing. The procedure did not require that the 12-hour timeclock be entered until the bypass valve starts to open. Technical Specification 3.7.3 required RCIC to be operable in Mode 3 above 150#, with an additional 12-hour period to perform the testing.
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While the inspectors verified that the licensee met the applicable TS requirement, the potential existed for verbatim procedural compliance to result in TS noncompliance Incorrect Annunciator Response Procedure in Main Control Room:
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On April 13,1999, during the restart of Unit 2, the inspectors identified that LaSalle Operational Response (LOR) 2PM13J-A101, " Suppression Chamber /Drywell Oxygen Concentration High / Analyzer Trouble," Revision 1, did not provide actions specific to the associated annunciator tile. Specifically, the procedure provided actions to respond to drywell air humidity trouble. The nuclear station operator (NSO) reviewed the LOR following receipt of the alarm and identified that the procedure was not accurate. The NSO reviewed the applicable Unit 1 procedure and did not inform the unit supervisor or initiate a PlF due to the fact that a yellow sticky note with a procedure change request (PCR) number was attached to the inaccurate procedure.
Technical Specification 6.2.A.a, Plant Operating Procedures and Programs, states that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Appendix A, of the Regulatory Guide 1.33, Revision 2, February 1978. Regulatory Guide 1.33 requires implementing procedures for each abnormal, off normal or alarm condition. The failure of the licensee to properly maintain a written alarm procedure applicable to the drywell or suppression chamber oxygen concentration is a violation of Technical Specification 6.2.A.a. However, this Severity Level IV violation is being treated as a Non-Cited Violation, consistent with Appendix C of the NRC Enforcement Policy (50-374/99003-01(DRP)). This issue is in the licensee's corrective action program as PIF No. L1999-01984.
The licensee completed an investigation and identified the LaSalle Operating Abnormal (LOA) to LOR upgrade project as the cause of the several procedure errors. The licensee determined that 6 of 83 LORs which had been revised to mcorporate design changes were inappropriately replaced with text from a previous revision. Additionally, eight editorial errors were identified which ranged from minor to procedures whose designators had been reversed. The licensee's validation process did not identify the problems. Also, the inspectors identified that operations procedure writing personnel had canceled the PCR written on the oxygen concentration LOR without reviewing the alarm response to ensure that the concerns in the PCR had been addressed. The investigation did not include the failure of the NSOs to inform the unit supervisor of the procedure error.
Traversina incore Probe (TIP) System Difficulties:
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On April 12,1999, during restart of Unit 2, the TIP system failed to communicate with the computer. The inspectors noted that the unit log entries did not fully describe the TIP problems and the corrective actions. The inspectors
determined that a PIF describing the problem and entering the problem into the i
licensee's corrective action program was not generated. Following questions from the inspectors, the licensee initiated a PIF on April 28,1999. Reference Section M2.1 for additional details.
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I Station Method for Defeatina Annunciators:
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The inspectors reviewed the licensee's procedure for defeating annunciators.
LaSalle Administrative Procedure (LAP)-240-7," Defeating Annunciators,"
Revision 6, provided guidance to the operators on the station-accepted method for defeating main control room alarms. The procedure provided guidance for defeating nuisance alarms; a note in the procedure directed operators to i
Attachment C ("TS Required Alarms") that listed alarms required by TSs. The inspectors noted that the procedure did not direct operators to verify alarm status against Updated Final Safety Analysis Report (UFSAR) requirements. While the inspectors noted no specific concerns associated with defeating alarms referenced in the UFSAR, the procedure provided no guidance to verify whether a 10 CFR 50.59 safety evaluation was required in order to defeat annunciators listed in the UFSAR. The procedure provided guidance to aid operators in meeting TS requirements, but did not provide the same level of reference to ensure that the plant design requirements as specified in the UFSAR were met.
The inspectors observed a separate Unit 1 issue with respect to operators defeating alarms. The operators had defeated nuisance alarms associated with various first and second stage moisture separator reheater drain valves. The j
operators documented this occurrence on December 4,1998, per Attachments A and B of LaSalle Operating Procedure (LOP)-TG-06. The operators removed the temporary modification defeating these annunciators on December 8,1998, but did not update the control room attachment sheets showing this removal until prompted by the inspectors on April 15,1999. The licensee documented this occurrence via PlF No. L1999-02022. Operators verified that no other similar deficiencies existed in the Unit 1 and Unit 2 main control room paperwork. The inspectors considered this to be an isolated example of operator lack of attention to detail.
Loaaina of Suporession Pool Temoeratures Durina RCIC Testina:
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The inspectors observed RCIC system testing during the Unit 2 startup activities and identified an example of operator noncompliance with procedural requirements caused, in part, by a cumbersome procedure. The operations surveillance procedure was not a " stand-alone" procedure and referenced a separate procedure for data taking purposes. During the observed test, operators met the intent of TS requirements, but violated the procedural requirements to log all pertinent data.
During the performance of LaSalle Operating Surveillance (LOS)-RI-R1,
" Reactor Core isolation Cooling Turbine Overspeed Test," Revision 14, the inspectors noted that the licensee was not formally documenting suppression pool temperature. The procedure required that the suppression pool average temperature be verified as less than or equal to 105 degrees F at least once per 5 minutes. This is a Technical Specification Surveillance requirement when performing testing that adds heat to the suppression pool. In addition, the procedure directed that the operator log in LOS-AA-S201, Unit 2 "Shiftly Surveillance," that this was accomplished.
o The inspectors discussed this requirement with the NSO who indicated that he was monitoring temperature and that he would document that this was performed in the LOS-AA-S201 procedure. Subsequently, the inspectors reviewed procedure LOS-AA-S201, Unit 2 "Shiftly Surveillance," and noted that an appendix existed to document suppression pool temperature at 5-minute intervals. This was brought to the NSO's attention who appeared unaware of the requirement and indicated that he would retrieve the temperatures from the comouter and document them on the form.
Technical Specification 6.2.A.a " Plant Operating Procedures and Programs,"
states that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Appendix A of the Regulatory Guide 1.33, Revision 2, February 1978. Regulatory Guide 1.33 requires implementing procedures for each surveillance test listed in the Technical Specifications. Procedure LOS-AA-S201, Revision 1, Attachment G, provides a table for the documentation of suppression pool temperature on 5-minute time increments during testing which adds heat to the suppression chamber. On April 10,1999, the licensee performed Unit 2 RCIC system testing which added heat to the suppression chamber without documenting the performance of the temperature monitoring. This Severity Level IV violation is being treated as a Non-Cited Violation, consistent with Appendix C of the NRC Enforcement Policy (50-373/374/99003-02a(DRP)). This violation is in the licensee's corrective action program PlF No. L1999-01969.
In addition, the licensee did not promptly document this NRC-identified issue in the corrective action program. Subsequently, the issue was documented in the corrective action program when brought to the licensee management's attention by the NRC.
Locaina Reauirements for Control Rod Double Notchina-
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While observing Unit 2 restart activities, the inspectors noted that the procedures associated with control rod manipulations contained redundant documentation requirements. On April 15,1999, two control rods double-notched during the performance of weekly rod exercising per LOS-AA-W1, " Technical Specification Weekly Surveillances." Operators complied with the procedural requirements to log control rod drive problems per an attachment to the surveillance. However, the inspectors noted that LOP-RM-01, " Reactor Manual Control Operation," also required that operators document control rod problems via an attachment to that procedure. This was not done for the two control rods that double notched. In addition, the inspectors noted that the operations staff still maintained control rod problem identification sheets in the control room from operating procedure LOP-RD-27, " Control Rod Operations While Defueled," even though the plant was in an operating condition and had exited the defueled mode some time earlier.
While the operators identified and documented control rod drive problems, they did not fill out the required documentation for all of the associated control rod procedures. The cause was due to a combination of redundant procedural requirements and a lack of attention to detail on the part of the operators.
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The category of inspector identified concerns related to log keeping, corrective action program implementation, and procedural weaknesses did not result in a direct, safety-significant issue.
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Conclusions Operators generally performed well during the restart of Unit 2. Few material condition deficiencies occurred to significantly challenge the operators. Communications among the operators and with other departments were good. Operator performance, good plant material condition, and acceptable support from other station departments all contributed to a relatively smooth and error-free restart of Unit 2.
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J However, examples of weaknesses occurred during the performance of fundamental I
activities such as operator log keeping and entering items into the station's corrective action program. Those examples, combined with several examples of cumbersome written procedures, represented potential weaknesses in the barriers established to ensure sustained, error-free performance. An example of a non-cited violation was
identified for failing to log suppression pool temperatures during a surveillance and a non-cited violation was identified for an incorrect annunciator response procedure.
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Operational Status of Facilities and Equipms.H O2.1 Operators Responded Conservatively to Eauioment Failures or Malfunctions a.
Insoection Scope (71707)
The inspectws observed or reviewed the licensee's response to several equipment problems. In addition, the inspectors reviewed LaSalle Operational Response and LaSalle Abnormal Procedures and interviewed operators.
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Observations and Findinas The operators responded to several equipment malfunctions or problems.
On April 25,1999, with Unit 2 at 100% reactor power, the D condensate /
condensate booster pump tripped on neutral overcurrent. The NSO started the standby pump prior to tne pump receiving an automatic start signal from low feedwater pump suction pressure. The operators stabilized the plant and informed the unit supervisor. The D pump was removed from service for trouble shooting. The licensee identified that the motor needed repair, possibly due to a loose washer being located near the motor windings. The D condensate /
condensate booster pump had also tripped on April 3,1999, but the pump breaker was identified as the root cause and the breaker was replaced.
On April 27,1999, during performance of normally scheduled weekly rod single
notch exercises on Unit 2, rod 10-19 double notched from step 48 to 44. The rod was flushed in accordance with procedure and retested. When the Notch in signal was applied, the rod triple notched from step 48 to 42. The operators implemented LOA-RD-201, " Control Rod Drive Abnormal," Revision 1, for the
mispositioned control rod and reduced power. The operators consulted reactor engineering personnel, retumed the rod to step 48, and increased reactor power j
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to 100% The licensee determined the rod mispositioning to be caused by a faulty directional control valve. Maintenance personnel replaced the valve during a scheduled down power, satisfactorily tested the rod, and returned the rod to service.
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Conclusions The operators followed approved procedures and took prompt conservative actions in response to equipment problems such as the trip of a condensate / condensate booster pump and control rod double notching.
Operator Knowledge and Performance (71707)
04.1 Drvwell Closecut insoection a.
Inspection Scope (71707)
The inspectors assessed the condition of the Unit 2 drywell prior to the Unit 2 restart.
The inspection was performed after the licensee informed the inspectors that the drywell was ready for closure.
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Observations and Findinos During the closeout inspection, the inspectors verified that selected manual valves were in the correct position and appropriately locked. The inspectors identified no material condition concerns during the inspection. Drywell housekeeping was good with only a small number of minor items identified. The inspectors noted that a small amount of additional dose was expended after station senior management toured the drywell and re-directed plant staff cleanup efforts. These activities occurred prior to the final NRC drywell inspection.
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Conclusions Drywell housekeeping was good following completion of the outage and the condition of the drywell was satisfactory to support the Unit 2 startup. No equipment abnormalities were found and the housekeeping items would not have impacted plant activities.
04.2 Confiouration Control Error a.
Inspection Scope (71707)
The inspectors reviewed the licensee response to a self-revealing configuration control error that occurred due to improperly performing valve position checks prior to the i
restart of Unit 2.
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Observations and Findinos l
During power ascension activities on Unit 2, a self-revealing configuration control error was identified when operators raised reactor power above 25% The turbine stop valve / turbine control valve (TSWTCV) fast closure alarm was expected to clear when the plant exceeded 25% power. On April 13,1999, operators raised reactor power l
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above 25%, in accordance with the approved startup plan, and noted that the TSV/TCV fast closure alarm did not clear as expected. Operators halted control rod withdrawals,
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I entered the appropriate TS limiting condition for operation (LCO) action statements, and reduced reactor power to less than 25% to exit the TS LCOs.
The licensee's investigation revealed that the isolation valve associated with the instrument that feeds the alarm was incorrectly in the closed position. Licensee personnel placed the valve in the open position to correct the problem. Further licensee investigation determined that operators had inappropriately "N/A'd" the verification requirements for this valve during the conduct of pre-startup valve position checklists.
The licensee expanded the investigation to include a review of all valve positions that had been "N/A'd" during the performance of the valve checklists. Licensee personnel verified that all other valves in this category were in their proper positions. The licensee entered this item into the corrective action program via the generation of PIF No. L1999-0977.
Technical Specification 6.2.A.a," Plant Operating Procedures and Programs," stated that written procedures shall be established, implemented, and rnaintained covering the applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978. Regulatory Guide 1.33 required implementing procedures for equipment control. LaSalle procedure LOP-MS-06M (" Unit 2 Cold Startup Mechanical Checklist") required that valve 2B21-F390A (" Main Steam High Pressure Turbine First Stage RPS Pressure Switch Root Valve") be verified in the open position.
Contrary to this, on April 13,1999, a self-revealing event demonstrated that the valve was in the closed position. This Severity Level IV violation is being treated as a Non-Cited Violation, consistent with Appendix C of the NRC Enforcement Policy (50-373/374/99003-02b(DRP)). This violation is in the licensee's corrective action program as PlF No. L1999-01977, c.
Conclusions A self-induced challenge to plant operations occurred when operators failed to ensure that the isolation valve for the TSV/TCV fast closure alarm was in the correct position.
An example of a non-cited violation was identified for the fact that operations personnel inappropriately "N/A'd" the requirement to verify the position of the isolation 1-Ive.
04.3 Operator Knowledae issues a.
Inspection Scope (71707)
The inspectors interviewed operators during control room observations and subsequent to operational events, b.
Observations and Findinas In general, the operators were knowledgeable of plant equipment status. However, in two instances the operators did not question equipment indications or alignments even though they did not fully understand the current indication. One of the instances resulted in a circulating water spill.
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On April 28,1999, during a routine control room panel walkdown, the inspectors noted
that the Unit 2 pre-treatment off-gas radiation monitor indicated 450 mrem /hr while the Unit 1 radiation monitor indicated 350 mrem /hr. The operations shift manager and control room operators were not aware of why the Unit 2 indication would be higher as Unit 1 was operating with a known fuelleak. Operatiens management contacted reactor engineering and chemistry personnel to resolve the discrepancy. The Nuclear Fuels Management personnel had informed the reactor engineers that Unit 2 would experience increased reactor coolant system specific activity levels following startup due to previous Unit 2 fuelleaks. The reactor engineers indicated that they had verbally informed operations management but had not provided training or written guidance to the operators. The inspectors identified that the licensee did not initiate a PIF regarding the lack of knowledge by the operators or poor communication from reactor engineering.
On May 2,1999, during the isolation of the Unit 2 west main condenser water box in
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preparation for condenser tube repairs, the licensee inadvertently spilled 30,000 gallons of circulating water in the condenser pit. The operators closed the inlet isolation valve and opened the water box vent in accordance with LOP-CW-10, " Dewatering The Circulating Water System (CW)," Revision 16. The water box was drained using the
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eductor effect created by the outlet valve remaining open and the in rush of air was
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noted at the vent by the operator. When the air inrush stopped, maintenance personnel were directed to remove the upper water box man-ways. The operators continued with '
the procedure and shut the water box outlet valve. A short time later, maintenance personnel identified that water was coming out the upper man-ways and informed the operators. The mechanics reinstalled the man-way covers within 10 minutes.
Approximately 30,000 gallons of circulating water from the water box man-ways filled the condenser pit to a level of 10 inches above the floor. The circulating water pumps would have tripped at a level of 18 inches. Operators drained the condenser pit.
The licensee initially attributed the spill to the water box inlet valve which leaked significantly until manually closed. However, during additional investigation prompted by the Site Vice President, the licensee determined the apparent cause of the event to be lack of understanding of several mechanical fundamentals associated with the condenser water box dewatering. In particular, the operators did not question the assumption that two circulating water pumps could not provide sufficient lift to fill the water box to the man-ways. This lack of understanding resulted in inadequate planning and command and control of the evolution to ensure the water levels in the condenser were properly controlled prior to removing the man-way access covers. Specifically, the licensee concluded that the man-way should not have been removed prior to the verification that the dewatering of the condenser water box was complete and the water box outlet valve was out-of-service closed.
The licensee implemented corrective actions which included a procedure change to clo.se the outlet valve and verify the water box level prior to removing the man-ways.
Additionally, several additional corrective actions were recommended including additional operator training, revision of guidance on Plant Operations Review Committee (PORC) Independence during reviews, and senior management accountability sessions for lessons leamed.
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l Operators did not always display a questioning attitude and ensure a thorough l
understanding of system operation. Operators were not cognizant of the reason for elevated Unit 2 pre-treatment off-gas radiation levels. Operator lack of understanding of the circulating water system operation contributed to a spill of 30,000 gallons of water in the circulating water pit. The circulating water spill accelerated investigation, after prompting by senior management, was thorough and provided comprehensive corrective actions.
II. Maintenance M1 Conduct of Maintenance j
M1.1 Procedure Problem Results in an Residual Heat Removal (RHR) Service Water Check j
Valve Failure
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Inspection Scope (61726)
The inspectors interviewed maintenance and engineering personnel and observed all or portions of several surveillance activities including:
LOS-FC-Q1, " Fuel Pool Emergency Makeup Pump inservice Test and RHR
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Service Water System Flush," Revision 16 LaSalle Instrument Surveillance (LIS)-RR-101C, " Unit 1 Recirculation Flow
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Convertor C Calibration," Revision 2 In addition, the inspectors reviewed the licensee's response to the failure of an RHR service water keep fill check valve during the performance of LOS-RH-Q1, "RHR ([ low pressure coolant injection] LPCI) and RHR Service Water Pump and Valve Inservice Test for Operational Conditions 1,2,3,4, and 5," Revision 44. The inspectors reviewed
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the check valve work package number 990044147-01, " Disassemble and Inspect the Check Valve," Revision 0, and the completed surveillance test and interviewed operations and engineering personnel, b.
Observations and Findinas In general, the licensee performed surveillance activities in accordance with plant procedures and were well trained and knowledgeable of the activities assigned.
On April 27,1999, during performance of LOS-RH-Q1, the division 2 RHR service water l
keep fill check valve,2E12-F445, failed to meet the reverse flow acceptance criteria.
Specifically, the check valve leaked 2 gpm when the acceptance criteria required no back leakage. The operators declared division 2 of the LPCI system inoperable and entered Technical Specification Limiting Condition for Operation (LCO) Action Statement 3.5.1.b.2. The LCO required the valve be repaired and the system returned l
to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or the unit be shutdown within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
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Maintenance personnel disassembled and inspected the check valve. The mechanics found no abnormalities during the inspection. The mechanics reassembled the check l
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O valve and the operators satisfactorily leak tested the valve. The operators declared the system operable and exited the LCO.
Operations personnel had requested that the system engineer initiate a PCR as a corrective action as a result of the failure of two similar RHR service water keep fill check valves on March 18,1999. The earlier check valve failures were discussed in
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Inspection Report 50-373/374/99002 and resulted in a Non-Cited Violation due to operations personnel declaring the valve operable without an engineering evaluation.
However, the PCR initiated as part of the corrective actions was not scheduled to be implemented for several months even though the test will have been completed several times prior to that date. Also, the system engineer recommended corrective actions in the PCR that only revised the leakage acceptance criteria for the two check valves that failed in March of 1999. Following discussions with the inspector, the system engineer initiated a PCR to change the testing on the 2E12-F445 valve.
c.
Conclusions In contrast to the RHR service water keep fill check valve failure discussed in inspection Report 99002, the operators responded conservatively to a similar failure and declared the system inoperable. However, the system engineer generated a PCR that was narrow in scope as it did not evaluate the acceptance criteria for all RHR service water keep fill check valves. Also, the scheduled procedure revision was not timely as the procedure would have been completed several times prior to revision. Timely revision of the procedure was a concern as a division of the RHR system must be declared inoperable and maintenance performed on the system following each check valve failure.
M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Maintenance Suocort of Plant Activities a.
Inspection Scope (62707)
The inspectors observed several maintenance activities including TIP system repairs during Unit 2 startup and Unit 2 condenser tube repair.
b.
Observations and Findinas Maintenance personnel normally performed work activities in a safe and controlled manner. Mechanics followed adequate procedures and work practices and work was properly scheduled.
Sianificant Decrease in Unit 2 Condenser Inteakaae Followina Tube Pluaaina
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On April 30,1999, the licensee decreased power to 60% to support condenser tube plugging in an effort to lower circulating water infeakage. This was the first time this had been attempted at a Commonwealth Edison boiling water reactor and, with the exception of the 30,000 gallon circulating water spill, the effort went smoothly. (See Section O4.3) Prompt action by the mechanics prevented a potential turbine trip and the resultant reactor trip. The licensee completed the condenser tube repairs with five tubes being plugged on the two condenser
P 1 s halves. The circulating water in leakage was decreased from 0.18 gpm to 0.042 gpm.
Inadeauate Work Packaae Delayed Plant Startuo
On April 12,1999, during restart of Unit 2, the TIPS system was required to verify core conditions prior to exceeding 25 percent reactor power. The operators attempted to complete a TIP set but the TIP system failed to communicate with the computer. Power ascension was placed on hold until the problem was identified and resolved. The system engineer and instrument maintenance (IM)
technicians determined that the work package did not provide provisions to adjust cards in the TIP drawers which had been replaced during the outage. The technicians package was revised, the cards adjusted, and the TIP set completed satisfactorily. The operators recommenced the power ascension. Reference Section 01.2 for inspector observations concerning operator response to the TIP system difficulties.
c.
Conclusions Maintenance personnel normally performed work activities in a safe and controlled manner. Mechanics followed adequate procedures and work practices and work was properly scheduled. Mechanics responded promptly to a circulating water system leakage event. However, an inadequate work package for the traversing in-core probe system delayed the Unit 2 reactor startup.
Ill. Enaineering E2 Engineering Support of Facilities and Equipment E2.1 Weaknesses identified in Enaineerina Support to Other Oraanizations a.
Inspection Scope (37551)
The inspectors observed several plant activities which required engineering support.
The inspectors reviewed several documents developed by engineering personnel and interviewed engineers.
b.
Observations and Findinas Engineering personnel provided support to other organizations that was generally adequate. The information was normally timely and accurate. However, there were
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instances where engineers could have provided better support to plant organizations.
Reactor engineers had not adequately communicated the expected specific
activity of the primary coolant during the Unit 2 startup to operations or chemistry personnel. On April 28,1999, during a routine control room panel walkdown, the inspectors noted that the Unit 2 pre-treatment off-gas radiation monitor was indicating 450 mrem /hr while the Unit 1 radiation mon! tor was indicating i
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350 mrem /hr. The operations shift manager and control room operators were not aware of why the Unit 2 reading would be higher as Unit 1 was operating with a fuelleak. Operations management contacted reactor engineering and
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chemistry personnel to resolve the discrepancy. The Nuclear Fuels Management had informed the reactor engineers that Unit 2 would experience increased specific activities in the reactor coolant system following startup due previous fuel leaks and that the increased specific activity could cause the
off-gas radiation monitor to indicate higher than normal. The reactor engineers
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indicated that they had verbally informed operations management but had not provided training or written guidance to the operators or chemistry personnel.
Nuclear Fuels Management did not clearly communicate the decision not to
include the effects of the extended shutdown in the Unit 2 core target rod patterns. Thw contributed to an unexpected shortfallin predicted core reactivity which required the control rods be pulled additional steps to achieve full reactor i
power and significant load reductions to support rod maneuvers to maintain full power. Reactor engineering determined that TS requirements for reactivity anomalies and shutdown margin were satisfied and thermal limits were conservative due to the less reactive core. The inspectors identified that formal communication mechanisms from Nuclear Fuels Management to reactor engineering were not discussed during the investigation.
System engineers lackoJ understanding of the ability of the circulating water
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pumps to fill the condenser water box above the upper man-ways during the condenser tube repairs. The PORC questioned the possibility of water exiting the man-ways during a meeting and engineering personnel indicated that the water would not be able to achieve the height of the man-ways with the current lineup of two circulating water pumps running. However, the engineer used previous l
experience and engineering judgment to respond to the question and did not perform formal calculations. The lack of adequate engineering assessment
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contributed to the 30,000 gallon spill of circulating water.
c.
Conclusions While engineering personnel generally provided timely and accurate support to plant organizations, in some instances engineers provided unclear, incomplete, or inaccurate information. Reactor engineers did not adequately communicate the expected specific activity of the Unit 2 primary coolant to operators prior to the restart, Nuclear Fuels Management personnel did not clearly communicate the effect of the extended shutdown in the Unit 2 core target rod pattern, and system engineering's lack of understanding of the circulating water pump capabilities contributed to a spill of 30,000 gallons of water in the circulating water pit.
E8-Miscellaneous Engineering issues (92902)
i E8.1 (Closed) Temocrary Instruction 2515/141. " Review of Year 2000 (Y2K Readiness of Comouter Systems at Nuclear Power Plants" i
a.
Insoection Scooe (Tl 2515/141)
The purpose was to review the licensee's Y2K program activities designed to achieve Y2K readiness in accordance with Generic Letter (GL) 98-01 or GL 98-01, Supplernent 1. The basis of the inspector's review was a software application or embedded component from the reactor protection system or engineered safety features
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t P
systems (RPS/ESF), the feedwater system or the balance of plant systems (FWS/ BOP),
the radiation monitoring system (RMS), the emergency sirens (ENS), the plant process computer (PPC), and the plant security system (PSS). The inspectors recognized that some reactor protection systems may not have any software applications or embedded components that process date-related information. However, the RPS was included here because of its importance to safety.
b.
Observations and Findinos Overall the documentation packages supporting Y2K readiness were acceptable.
However, documentation packages for the ENS, PPC, and PSS could not be assessed without requesting additionalinformation. For example, there was no documentary l
evidence in these packages to support cold rollover (shutting the computer off, allowing the intemal clock to advance, and then restarting the computer) to the year 2000. The information to complete these reviews was provided to the inspector and the packages were found acceptable.
C.
Conclusions
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The Y2K readiness review was completed with acceptable results. Tl 2515/141 was
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closed.
IV. Plant Support R1 Radiological Protection and Chemistry (RP&C) Controls R1.1 Radiation Protection a.
Inspection Scope (71750)
The inspectors interviewed radiation protection (RP) technicians and observed routine activities. In addition, the inspectors observed the RP technicians performance in support of startup activities.
I b.
Observations and Findinas I
Radiological control personnel performed duties in accordance with procedures and surveys were thorough. The technicians decontaminated several areas of the plant which had become contaminated during the extended maintenance outage which supported plant personnelin the performance of normal activities. The technicians were knowledgeable of area dose rates and activities which could affect radiological conditions.
c.
Conclusions In general, actions taken by the licensee were adequate to protect personnel from radiological hazards.
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g.
F8 Miscellaneous Fire Protection Issues F8.1 (Closed) Licensee Event Report (LER) 50-373/95015-01: Failure to include a fire protection valve in surveillance procedures. On August 24,1995, the licensee identified that valve 1FP228, cable spreading room sprinkler system isolation valve, was not included in Procedure LOS-FP-M2," Fire Protection Flow Valve Check Program." This l
valve was installed as part of a modification in 1986, but was never added to the surveillance procedure. The licensee immediately verified the valve to be in its correct position (locked full open). The safety significance was minimal because the sprinkler system in the cable spreading room was capable of performing its designed function.
The inspectors verified that LOS-FP-M3, " Fire Protection Flowpath Valve Position Verification," Revision 28, now required verification of the locked open position for the subject valve. In addition, the inspectors verified that LOS-FP-A1, " Fire Protection Flowpath Valve Cycling Test," Revision 10, required cycling of and verification of locked open position for valve 1FP228. The corrective actions were considered acceptable.
This item is closed.
V. Manaaement Meetinas X1 Exit Meeting Summary The inspectors presented the results of these inspections to licensee management listed below at an exit meeting on May 12,1999. The licensee acknowledged the findings presented. The inspectors asked the licensee if any materials examined during the inspection should be considered proprietary. The licensee identified none.
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X3 Management Meeting Summary Senior Comed management met with senior Region 111 management in a public forum on April 6,1999, to discuss final utility plans and preparations in place to support the restart of Unit 2. Licensee handouts used for the meeting were provided in separate, docketed correspondence.
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r-PARTIAL LIST OF PERSONS CONTACTED Licensee
- S. Barrett, Maintenance Manager
- J. Benjamin, Site Vice President
- C. Berry, Chief of Staff D. Bowman, Chemistry Supervisor E. Connell, Design Engineering Supervisor
{
C. Crane, Vice President, BWR Operations
{
- D. Farr, Operations Manager
- G. Kaegi, Site Training Manager j
- M. Lohmann, Engineering Administration Manager
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R. McConnaughay, Shift Operations Superintendent
- E. McVey, Reactor Engineering Supervisor J. Meister, Engineering Manager T. O'Connor, Plant Manager
- R. Palmieri, System Engineering Manager
- J. Place, Health Physics Supervisor j
K. Poling, Work Control Manager
- J. Pollock, Support Engineering Supervisor
- W. Riffer, O & SA Manager E. Shankle, Support Services Manager
- F. Spangenberg, Regulatory Assurance Manager R. Stachniak, Nuclear Oversight Assessment Manager
- Present at exit meeting on May 12,1999.
INSPECTION PROCEDURES USED l
lP 37551:
Onsite Engineering IP 61726:
Surveillance Observation IP 62707:
Maintenance Observation IP 71707:
Plant Operations IP 71750:
Plant Support Activities
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IP 92700:
Onsite Follow-up of Written Reports of Nonroutine Events IP 92901:
Followup - Plant Operations IP 92902:
Followup - Maintenance IP 92903:
Followup - Engineering
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ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-374/99003-01 NCV inadequate annunciator response procedure 50-374/99003-02a NCV Procedural compliance with respect to logging data during a RCIC surveillance 50-374/99003-02b NCV TSV/TCV fast closure alarms Closed 50-373/95015-01 LER Failure to include a fire protection valve in surveillance procedures 50-374/99003-01 NCV Inadequate annunciator response procedure 50-374/99003-02a NCV Procedural compliance with respect to logging data during a RCIC surveillance 50-374/99003-02b NCV TSV/TCV fast closure alarms Discussed
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None j
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LIST OF ACRONYMS USED i
BOP Balance of Plant Systems CW Circulating Water DRP Division of Reactor Projects DRS Division of Reactor Safety ENS Emergency Notification System ESF Engineered Safety Feature FWS Feedwater System GL Generic Letter IDNS lilinois Department of Nuclear Safety IM instrument Maintenance j
LAP LaSalle Administrative Procedure LCO Limiting Condition for Operation LER Licensee Event Report LIS LaSalle Instrument Surveillance LLP Power Ascension Special Procedure LOA LaSalle Operating Abnormal LOP LaSalle Operating Procedure LOR LaSalle Operational Response LOS LaSalle Operating Surveillance LPCI Low Pressure Coolant injection NCV Non-Cited Violation NRC Nuclear Regulatory Commission NSO Nuclear Station Operator OPRM Oscillation Power Range Monitor PlF Problem Identification Form PCR Procedure Change Request PDR NRC Public Document Room PORC Plant Operations Review Committee PPC Plant Process Computer PSS Plant Security System RCIC Reactor Core Isolation Cooling System RHR Residual Heat Removal RMS Radiation Monitoring System RP Radiation Protection RPS Reactor Protection System TCV Turbine Control Valve Ti Temporary Instruction TIP Traversing in-Core Probe System TS Technical Specification TSV Turbine Stop Valve UFSAR Updated Final Safety Analysis Report VIO Violation Y2K Year 2000
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