IR 05000373/1998005
| ML20248M128 | |
| Person / Time | |
|---|---|
| Site: | LaSalle  |
| Issue date: | 06/05/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20248M123 | List: |
| References | |
| 50-373-98-05, 50-373-98-5, 50-374-98-05, 50-374-98-5, NUDOCS 9806150041 | |
| Download: ML20248M128 (73) | |
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U.S. NUCLEAR REGULATORY COMMISSION REGION 111 Docket Nos:
50-573;50-374 License Nos:
50-373/98005(DRS); 50-374/98005(DRS)
Licensee:
Commonwealth Edison Company Facility:
LaSalle County Station, Units 1 and 2 Location:
2601 N. 21st Road Marseilles,IL 61341 Dates:
March 19 through April 21,1998 Inspectors:
Eric Duncan, Team Leader Andy Dunlop, inservice Testing (IST) Program inspector George Hausman, Setpoint Control Program inspector lhor Jackiw, Electrical Engineering Inspector Michael Miller, Electrical Engineering inspector John Neisler, Electrical Engineering inspector Gerry O'Dwyer, Mechanical Engineering Inspector Darrell Schrum, Mechanical Engineering Inspector Donna Skay, Office of Nuclear Reactor Regulation Tom Tella, Electrical Engineering inspector Ronald Carbiener, Electrical Contractor Approved by:
John M. Jacobson, Chief Lead Engineers Branch Division of Reactor Safety
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9006150041 990605 PDR ADOCK 05000373 G
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EXECUTIVE SUMMARY LaSalle County Station, Units 1 and 2 NRC Inspection Reports 50-373/98005; 50-374/98005 Engineering Overall, the modifications reviewed were properly designed, installed, and tested.
e However, some minor errors due to a lack of attention-to-detail during the implementation of the modification process were identified. (Section E1.1)
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Engineering * hold points" placed on "at risk" design modifications wers properly e
controlled and released. (Section E1.2)
Overall, the temporary alterations reviewed were properly designed, installed, and
tested. However, two examples were identified where the temporary alteration procedure was not adequately implemented. (Section E1.3)
' The operability evaluations reviewed were of good quality and provided adequate
technicaljustification for the conclusions. (Section E1.4)
Overall, the calculations reviewed were properly performed. However, the team
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questioned whether terminal cell connection resistance limits specified in technical specifications and licensee procedures were acceptable. (Section 1.5)
Although material condition had improved overall, numerous minor discrepancies were
identified, which indicated a lack of thoroughness during system engineering walkdowns. In addition, housekeeping was inconsistent with areas such as the high pressure core spray and diesel generator rooms generally good, while other areas such as the residual heat exchanger (RHR) pump rooms and RHR heat exchanger rooms were in need of attention. (Section E2.1)
The actions planned or accomplished to address surveillance testing program
weaknesses as delineated by action step 1.9 of licensee Restart Action Plan 4.2 and action step 2.3.1 of licensee Restart Action Plaa 3.1 were thorough and, if properly implemented, appeared to be effective. In addition, for the surveillance observed and reviewed, system engineering personnel demonstrated good understanding and involvement with testing activities. Two weaknesses regarding surveillance testing of safety-related battery cells were identified. (Section E2.2)
The actions planned or accomplished to manage the engineering backlog as delineated e
by action steps 8.0 through 8.6 of licensee Restart Action Plan 4.2 were thorough and, if properly implemented, appeared to be effective. With the exception of engineering requests (ERs) related to Updated Final Safety Analysis Report discrepancies, the ERs reviewed were properly prioritized for resolution. In addition, other backlogs had been effectively reduced and were low. (Section E2.3)
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O Overall, the 10 CFR 50.59 screenings and safety evaluations reviewed were of good e
quality with the exception of some minor errors. in addition, the licensee had established an acceptable program for ensuring that trained and qualified personnel prepared and reviewed 50.59 screenings and safety evaluations. However, due to a procedural error, completed safety evaluations had not been reported to the NRC as required by 10 CFR 50.59(b)(2). (Section E3.1)
The licensee identified a number of significant deficiencies in the setpoint control e
program, inservice testing (IST) program, Generic Letter 89-13 heat exchanger inspection program, and the fuse control program and was in the process of taking corrective actions to improve these programs prior to Unit i restart. However, the team identified one additional problem regarding the identification and evaluation of fuse discrepancies. (Section E4.1)
The actions planned or accomplished to address system engineering qualifications as e
delineated by action steps 1.0,1.1,1.4, and 3.0 of licensee Restart Action Plan 4.1 were thorough and, if properly implemented, appeared to be effective. In addition, based on the review of training and qualification procedures and records, self-assessments, and corrective actions, the schedule for qualifying system engineers was progressing well.
(Section E5.1)
The actions planned or accomplished to ensure adequate engineering support as e
delineated by action steps 4.0,5.0, and 6.0 of licensee Restart Action Plan 4.1 and action steps 1.0,2.0,3.0,4.0, and 7.0 of licensee Restart Action Plan 4.2 were thorough and, if properly implemented, appeared to be effective. (Section E6.1)
The licensee had made good progress in addressing 10 CFR 50.54(f) commitments 15, e
24, and 323. (Section E7.1)
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R9 port Details Ill. Enaineerina The NRC performed a team inspection of engineering and technical support (E&TS) activities at the LaSalle County Station, Unit 1 and 2. During the inspection, the team focused primarily on the residual heat removal, high pressure core spray,' diesel generator, standby gas treatment, l
primary containment purge and vent,125 volt direct current (VDC),250 VDC, and 480 volt attemating current systems and reviewed the adequacy of selected modifications, temporary alterations,10 CFR 50.59 safety evaluations, operability evaluations, calculations, and root cause investigations associated with these systems. The team also conducted walkdowns and interviews with licensee personnel responsible for those systems.
In addition, the team reviewed the status of LaSalle Restart Action Plan actions related to engineering and reviewed the status of licensee's commitments in their March 28,1997, response to the NRC's request for information pursuant to 10 CFR 50.54(f).
E1 Conduct of Engineering E1.1 Modification Review a.
Insoection Scoce The team reviewed documentation associated with recently completed modifications and conducted system walkdowns to verify proper installation.
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Observations and Findings The team reviewed design change packages (DCPs) for the following recently installed modifications:
DCP 9200039 Diesel Generator (DG) Lube Oil Low Temperature Setpoint
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DCP 9400021 480 Volt Motor Control Center Setting Changes
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DCP 9400426 Diesel Generator Air Dryer 2DG09DB Replacement
DCP 9400431 1E51-F022 Magnetic Trip Setting Change
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DCP 9500070 Install Wiring Change For 1B DG Fuel Priming Pump
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DCP 9500324 Exempt Change To Remove Intemals From Check Valve
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DCP 9600114 1 A DG Volts Amperes Reactive Meter Replacement
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DCP 9600167 1E12-F003B Pressure Locking Modification
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DCP 9600225 480 Volt Trip Device Replacement
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DCP 9600339 1B DG Fuel Pump Failure Alarm
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DCP 9600448 1E12-F050B Carbon Steel Weld Boss Replacement
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DCP 9600460 1E12-F048A Control Circuit Modification
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DCP 9700284 1B DG Cooling Water Heat Exchanger Baffle Plate Bar
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DCP 9700341 Overpressure Protection For Primary Containment Piping
DCP 9700402 Unit i VG System Overpressure Protection I
DCP 9700403 Unit 2 VG System Overpressure Protection
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DCP 9800003 1 A Diesel Generator Speed Sensor Modification
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DCP 9800054 Residual Heat Removal Service Water Restricting Flow
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Orifice Re-Sizing Modification DCP 9800105 Relocation of 2A and 2B DG Rollup Door Curbs
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l 10 CFR 50.59 safety evaluation
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Operating and emergency operating procedure changes
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Operator training
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Revisions to as-built drawings
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Revisions to the Updated Final Safety Analysis Report (UFSAR)
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Design change calculations, analyses, and design output documents
Overall, the modifications reviewed by the team were adequately designed, installed, and tested. However, the team identified the following deficiencies:
DCP 94000426. " Diesel Generator Air Drver 2DG09DB Replacement"
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The team reviewed DCP 94000426, " Diesel Generator Air Dryer 2DG09DB Replacement," which replaced the 2B DG air dryer. During that review, the team noted that an incorrect date was recorded on the associated " Conduit Installation Checklist."
As a result, Problem identification Form (PlF) L1998-02233 was generated to document
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In addition, Okonite T-95 tape used in a splicing application for the modification was manufactured in August 1993 and had a manufacturer's shelf life of 18 months.
However, on October 26,1992, the shelf life of the tape was evaluated utilizing Electric Power Research Institute NP-6408, " Guidelines for Establishing, Maintaining, and
- Extending the Shelf Life Capability of Limited items," and declared indefinite. The team reviewed tho' actions subsequent to the shelf life extension and identifed the following concerns:
LaSalle Electrical Procedure (LEP) GM-137, " Taping Low Voltage Cable
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Terminations and Splices," Revision 6, dated October 30,1997, did not reflect the " indefinite" shelf life for Okonite T-95 tape that was derived in October 1992.
In particular, step D.3.2 of the procedure inappropriately referenced a letter from Okonite regarding the use of expired tape although the licensee had qualified the j
tape as having an indefinite shelf life. In addition, LEP-GM-137 stated that the shelf life for the Okonite T-95 tape was 18 months vice indefinite.
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testing and qualification of the Okonite tape unnecessarily since the shelf life had been extended indefinitely in October 1992.
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Commonwealth Edison (ComE:d) Standard N-EM-0052 stated that tiie shelf life
for Okonite T-95 tape was 18 months, when in fact the shelf 'ife was extended indefinitely in October 1992.
The team concluded that communications between the materials support group which performed the shelf life extension and other groups were poor. As a result, plant procedures were not revised to reflect the extended shelf life.
10 CFR 50, Appendix B, Criterion V, " Instructions, Procedures and Drawings," ren Jres that activities affecting quality shall be prescribed by documented instructions,
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. procedures, or drawings, of a type appropriate to the circumstances and shall be I
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accomplished in accordance with these instructions, procedures, or drawings. The failure to revise LEP-GM-137 to reflect the increased shelf life for Okonite T-95 tape was an example where the requirements of 10 CFR 50, Appendix B, Criterion V were not met and was a violation. However, since the error was in the conservative direction and did not adversely impact safety, this failure constitutes a violation of minor significance and is being treated as a Non-Cited Violation, consistent with Section IV of the Enforcement Policy (NCV 50-373/98005-01; 50-374/98005-01).
DCP 9400431. "1E51-F022 Maanetic Trio Settina Chanae" The team reviewed DCP 9400431, "1E51-F022 Magnetic Trip Setting Change," which was implemented on December 12,1995, and changed the magnetic trip setting associated with the breaker for reactor cooling isolation valve (RCIC) valve 1E51-F022 from setpoint "B" to setpoint "A". The team identified that on February 24,1997, during the performance of work request 950080303, the breaker trip setpoint was incorrectly changed back to the "B" trip setting. As a result, problem identification form (PIF)
L1998-02401 was generated. Subsequently, the licensee performed a root cause inves4gation and determined that the relay setting order (RSO) sheet associated with this valve was not appropriately revised to reflect the new trip setting following the completion cf the modification in 1995, although a design change request had been initiated. As a result, due to a lack of attention-to-detail, licensee personnel referred to the outdated RSO sheet and changed the trip setpoint back to the "B" trip setting. The team also noted that this error was made after the RCIC system was shutdown for the current maintenance outage.
10 CFR 50, Appendix B, Criterion ill, " Design Control," requires that measures shall be established to assure that the design basis is correctly translated into specifications, j
drawings, procedures, and instructions. The failure to adequately control the RSO data l
sheet associated with the 1E51-F022 RCIC valve supply breaker was an example where l
the requirements of 10 CFR 50, Appendix B, Criterion lil were not met and was a
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violation. However, because this violation was based upon activities prior to the events
leading to the current extended plant shutdown and satisfy the criteria in Section Vll.B.2, l
" Violations identined During Extended Shutdowns or Work Stoppages," of the " General Statement of Policy and Procedures for NRC Enforcement Actions"(Enforcement i
Policy), NUREG-1600, a Notice of Violation is not being issued (NCV 50-373/98005-02; l
50-374/98005-02).
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DCP 9700284. "1B DG Cooling Water Meat Exchanger Baffle Plate Soacer Bar" The team reviewed DCP 9700284,"15 DG Cooling Water Heat Exchanger Baffle Plate Spacer Bar," which was implemented to shorten the baffle plate spacer bar for the 1B r
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DG to remove it from the coolant flow stream. During that review the team identified the following deficiencies:
Modification Requirements Checklist Deficiency
The team identified that item 2.19 (Failure Effects Requirements) of Nuclear l
Engineering Procedure 04-01, Exhibit A, " Modification Requirements Checklist,"
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was not completed. As a result, the licensee generated PIF L1998-02175 to document the deficiency. Subsequently, the licensee reviewed the exempt change approval letter and the 10 CFR 50.59 safety evaluation and verified that failure effects requirements were discussed in the written evaluation.
l The team concluded that although the error was of miner significance since the L
conclusions were not adversely impacted, licensee personnel exhibited a lack of l
attention-to-detail during the completion of the Modification Requirements Checklist.
10 CFR 50.59 Safety Evaluation Deficiency
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The team identified that the 10 CFR 50.59 safety evaluation stated that the 1B DG heat exchanger contained four spacer bars, although the associated vendor drawings only indicated three. Subsequently, the licensee determined that the 10 CFR 50.59 safety evaluation was in error. As a result, PlF L1998-02488 was generated.
The team concluded that although the error was of minor significance since the conclusions were not adversely affected, licensee personnel exhibited a lack of
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attention-to-detail during the processing of the 10 CFR 50.59 safety evaluation.
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Conclusions
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Overall, the team concluded that the modifications reviewed by the team wem adequately designed, installed, and tested. However, the team also identified some minor errors due to a lack of attention-to-detail during the implementation of the
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E1.2 Review of"At Risk" Desion Chanoes l-(
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Insoection Scone The team reviewed the use of modification " hold points" which allowed the installation of plant design changes although one or more aspects of the modification, such as
. calculations, had not been completed.
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Observations and Findinas The team reviewed the modifications identified in section E1.1 and determined that in some cases engineering " hold points" for incomplete calculations and/or 10 CFR 50.59 screenings or safety evaluations had been established. In addition, the team determined that problem identification forms (PIFs) had been initiated to ensure that these hold points were properly released prior to declaring the components affected by the modification as operable.
To determine whether the use of enginee-ing hold points was an acceptable practice, the team reviewed Comed Topical Report CE-1-A, " Quality Assurance Manual,"
Section 3.5, Revision 65, dated February 10,1997, which required that " design verification for the stage of design activity accomplished shall be performed prior to release for procurement, manufacture, construction, or release to another organization for use in other design activities provided sufficient data exists." Topical Report CE-1-A also stated that,"Any unverified portion of the design shall be identified and controIIed."
In addition, Comed Nuclear Engineering Procedure (NEP) 04-01LA, " Plant Modification-LaSalle Site," Revision 2, permitted the installation of a design change to proceed prior to the completion of calculations and the 10 CFR 50.59 screening or safety evaluation process provided: (1) the decision to proceed had been approved by the safety engineering and maintenance managers, (2) the work was totally within an out-of-service boundary, and (3) an operability hold point was inserted which required completion of the DCP and 10 CFR 50.59 screening and/or safety evaluation prior to retuming the system to operable status.
The team conducted a review of DCPs which contained hold points and verified that the hold points were identified and controlled as required by Topical Report CE-1-A and NEP 04-01LA. No deficiencies were identified.
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Conclusions l
The team concluded that engineering " hold points" placed on "at risk" design changes were identified and controlled in accordance with licensee procedures.
E1.3 Temocrarv Alteration (TALT) Review l
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Insoection Scoos The team reviewed recently installed temporary alterations and conducted walkdowns to ensure that installed equipment had not been altered outside of the temporary alteration process.
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Observations and Findinas Installed Tarnoorarv Alteration Review The team reviewed the following temporary alterations:
TALT 1-0178-97 1 A DG Cooling Water Pump
TALT 2-0049-97 Install Temporary Power Frora MCC 236X to MCC 136X
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for Battery Charger 1DC38E TALT 1-0089-97 Install Temporary Power From Welding Receptacle to
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Radwaste Discharge Pump 1WF05P TALT 1-0206-97 Gag Open Valve 1E12-F090A
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TALT 2-0030-97 Install Equipraent to Drain Piping to Support 2E12-F068B
Work TALT 1-0122-97 Install Equipment to Drain Piping to Support 1E12-F068B
Work TALT 1-0101-97 Install Temporary Jumper to Support 1E12-N514 and
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Documents specifically reviewed included the following, where applicable:
10 CFR 50.59 safety evaluation
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Temporary alteration installation procedure
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Temporary alteration installation records
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Temporary alteration functional testing results
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Operator training
Onsite and offsite review documentation
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Overall, the completed TALTs reviewed by the team were adequately designed and installed. However, the team identified the following deficiency:
TkLT 2-0030-97. " Install Faminment to Drain Pinina to Suonort 2E12-FnR8B Work" The team reviewed TALT 2-0030-97 which installed equipment to drain piping associated with residual heat removal service water isolation valve 2E12-F068B.
As part of that review, the team reviewed Nuclear Engineering Procedure (NEP) 04-07, Revision 0, " Screening for Approved Fire Protection Program impact," which was performed to determine if additional compensatory measures were required as a result of an increased amount of combustible material in the area for the TALT. The team
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Although the length of 4-inch steel-reinforced fire hose was estimated at
200 feet, the total weight of this hose was grossly underestimated to be only 11 pounds, i
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e The hose length in feet was incorrectly multiplied by the combustibility of the
material in British Thermal Units per pound (BTUs/lb) to obtain the total increase in heat load from the fire hose in BTUs. In particular, not only were the units in error, but the numbers themselves (had the units been correct) were incorrectly multiplied.
As a result, an additional evaluation was not performed because the evaluation item was marked "no" when it should have been "yes" when the fire loading increased by greater than 1000 BTUs per square foot of fire zone area. The actual fire loading increased by 2500 BTUs per square foot. The licensee generated PlF L1998-02308 to document, review, and correct this problem. The team subsequently identified that this same type
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of combustible loading calculation error occurred during the design review of TALT 1-0122-97, 10 CFR 50, Appendix B, Criterion V, " Instructions, Procedures, and Drawings," requires that activities affecting quality shall be prescribed by documented instructions,
. procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. The failure to correctly perform combustible loading calcu!ations for TALT 2-0030-97 and TALT 1-0122-97 was an example where the requirements of 10 CFR 50, Appendix B, Criterion V, were not met and was a violation (50-373/98005-03; 50-374/98005-03).
System Walkdown Results The team conducted system walkdowns to ensure that systems had not been modifed outside the temporary alteration process. During these walkdowns, the following issue was identifed:
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Unauthorized TALT Receidisc Unit O.1 A. and 2A Emeroency Dianal Generators During a routine walkdown of the diesel generator steas, the team identified that the Unit 0,1 A, and 2A DG air box drains did not reflect the as-built drawings. In particular, the team identified that although the DGs had tygon tubing routed to a floor drain downstream of the respective engine air box stop valve, only the 1B and 2B DGs had incorporated this configuration on the associated piping and instrument drawings (P&lDs). The P&lDs associated with the three DGs in question indicated that the drain
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lines were capped and the installation of the tygon tubing was an unauthorized plant design change. As a result, the licensee generated PIF L1998-03959.
Subsequently, the team determined that although this same configuration had been E
identified by the NRC on June 19,1997, and was discussed in inspection report 50-373/97007; 50-374/97007, the licensee had not taken corrective actions to correct
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l 10 CFR 50, Appendix B, Criterion XVI, " Corrective Actions," requires that measures
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The failure to take corrective actions to address the unauthorized alteration to the Unit 0, 1 A, and 2A DGs is an example where the requirements of 10 CFR 50, Appendix B, Criterion XVI were not met and was a violation (50-373/98005-04; 50-374/98005-04).
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Conclusions The team concluded that, overall, the temporary alterations reviewed were properly designed and installed. However, the team identified two cases where the temporary alteration procedure was not adequately implemented. In the first case, combustible loading calculations for a TALT were incorrectly performed. In a second case, an unapproved plant alteration was identified during a system walkdown, although that unapproved configuration had been previously identified, but had not been corrected.
E1.4 Operability Evaluation (OE) Review a.
Insoection Scooe The team reviewed recently completed operability evaluations.
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Observations and Findinas The team reviewed the following operability evaluations:
OE 94017 Armature Binding of GE HMA Relays
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OE 95022 Step Change in VG Flow During Surveillance Test
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OE 96041 Failure of GE HEA Relays to Trip l
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OE 96064 DG Cooling Water Strainer Backwash Flow
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OE 97004 Potential Loss of Battery Capacity l
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OE 97015 Thread Engagement For Support M09-VG01-0031X
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OE 97017 Division 2 DG Loading Affected By Error In Brake Horse Power
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OE 97032 Loose High Pressure Core Spray Pump Discharge Pipe Rigid
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Support OE 97068 Safety-Related Panels Not Mounted Per Design
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OE 97077 Surveillance Requirements For DG And DG Fuel Oil Room
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Temperatures OE 97079 Maximum DG Room Temperature Limit
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OE 97115 VG System Support Strut Lacking Thread Engagement
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OE 97135 DG Cylinder Check (Kiene) Valves Installed improperly
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OE 98007 1B DG Jacket Water Temperature Outside High Limit
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Conclusions The team concluded that the operability evaluations reviewed were of good quality and provided adequate technicaljustification for the conclusions. No deficiencies were identified.
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E1.5 Calculation Review l
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inspection Scope
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The team reviewed recently completed calculations.
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Observations and Findinas The team reviewed the following calculations:
4266/19D27 125 VDC Division l Battery Sizing
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- 4266/19D28 125 VDC Division 11 Battery Sizing
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'4266/19D30 Capability of 125 VDC and 250 VDC Batteries During Station
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Blackout L92-008-0338 Extension of Qualified Life For Okonite Tape
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Ventilation Flow Requirements for the DG Fuel Oil and Day Tank
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Rooms
. L-001863 Initiating Event Frequency For LOCA/1E12-F024 Control Switch in
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Open L-001572 Determination of Required Heating Capacities of the DG Buildings
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Overall, the team concluded that the licensee had adequately performed the.
calculations reviewed However, one issue regarding the performance of safety-related battery sizing calculations was identified.
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Safetv-Related BmMarv Sizino Onimintion Review During the review of calculations 4266/19D27 and 4266/19D28, the team determined that the licensee used the electrical load monitoring system program for sizing the
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Division I and Division ll 125 VDC safety-related batteries. The team also determined
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that the program calculated the minimum battery capacity based on guidance contained l
in inctitute of Electrical and Electronics Engineers (IEEE) 485 which required data, such
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as battery intercell and interack resistances, to calculate voltage drops across the battery cells and racks.
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I The team reviewed the assumptions for intercell and interack resistances used to determine the voltage drops across the battery cells and racks and determined that the
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However, the team identified that Technical Specification 4.8.2.3.2 required that each
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125 VDC battery and charger shall be demonstrated to be operable at least once per l_
18 months by verifying that the resistance of each cell and terminal connection was less
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than 150 micro-ohms per cell, in addition, licensee procedures allowed a maximum of
150 micro-ohms intercell resistance and 375 micro-ohms interrack resistance, l
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At the end of the inspection, the team questioned whether TS 4.8.2.3.2 and licensee procedures concerning terminal cell connection resistance limits were acceptable. This is an inspection followup item (50-373/98005-05; 50-374/98005-05) pending further NRC review, c.
Conclusions Overall, the team concluded that the calculations reviewed were adequate. The team questioned whether TS 4.8.2.3.2 and licensee procedures concerning terminal cell connection resistance limits were acceptable.
E2 Engineering Support of Facilities and Equipment E2.1 Svstem Walkdown Observations The team conducted a walkdown of the accessible portions of the high pressure core spray (HPCS), residual heat removal (RHR), standby gas treatment (VG), primary containment purge and vent (VQ),125 voit direct current (125 VDC),250 VDC,480 volt alternating current (VAC), and emergency diesel generator (DG) systems to assess material condition and the effectiveness of engineering to identify problems.
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Observations and Findinas Walkdown Observations The team reviewed Appendix D," System / Component Walkdown Guidelines and Checklist," of the " Common Comed System Engineering Handbook," Revision 1, dated February 11,1997, which provided guidance regarding identification of problems during system walkdowns. Items contained in the handbook for observation during system engineering walkdowns included the following:
Mechanical Comoonents Dirt or debris covering cooling grates or filters.
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Equipment skid / foundation botting and odequate thread engagement.
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General Material Condition items Filters, screens, or louvers (clogged, dirty, or missing).
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Lines or pipes (loose, unbracketed, or vibrating).
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Fasteners or bolts (loose, stripped, or missing).
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Housekeeoina items Dirty or oily equipment or leaks.
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Rags, trash, or debris in the area.
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Loose or improperly stowed tools or equipment.
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e in addition, the handbook also directed system engineers to prepare an action request (AR) for problems identified during a system Walkdown or record any problems resolved on the walkdown that did not require an AR.
The team conducted independent walkdowns of the HPCS, RHR, VG, VQ,125 VDC, 250 VDC,480 VAC, and DG systems and identified a number of examples where
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problems included in the system engineering handbook and found in the field were not documented on an AR, although extensive walkdowns of these systems had been recently completed. These problems included:
Mechanical Comoonents The team identified that a concrete expansion anchor associated with the Unit 1 VG exhaust fan did not have full thread engagement. Subsequently, the licensee determined that the concrete expansion anchor was not installed in accordance with design documents. As a result, PlF L1998-02419 was generated and an engineering request (ER) 9801922 was initiated to technically evaluate the concern.
In addition, the team identified that the Unit 1 and Unit 2 HPCS waterleg pump motor cooling air intake vents were significantly blocked by oil-encrusted dust. Subsequently, the licensee verified that the waterleg pump motor temperatures were not elevated, and that the motors were adequately cooled. However, the licensee also determined that a preventive maintenance (PM) task existed to clean the waterleg pump motor air intakes during normal lubrication of the motor every 2 years. As a result, PlF L1998-02973 was generated to document the concem and to determine why the periodic cleaning task had not prevented the blockage.
The team also identified that a Unit 1 HPCS watedeg pump particle guard was not properly attached which could have potentially allowed the ingress of foreign material
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into the motor. As a result, the licensee initiated action request (AR) 246935 to document the condition.
Finally, in various diesel generator rooms, the team identified that gaskets for removable curbs to contain fuel oil spills and prevent the potential spread of a fire were degraded, absent, or improperly installed. As a result, the licensee generated PIF L1998-02437 to document the condition and to establish a PM task when it was determined that the removable curbs had not been included in the PM program. In addition, ARs were initiated to repair the curb gaskets. Subsequently, DCP 9800105 was initiated to relocate the 2A and 2B DG room curbs when the licensee discovered that the existing installation did not conform to design drawings.
10 CFR 50, Appendix 0, Criterion XVI, "Cerrective Actions," requires that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, and nonconformances are promptly identified and corrected.
The failure to identify degraded DG room curbs was an example where the requirements of 10 CFR 50, Appendix B, Criterion XVI were not met and was a violation.
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However, because this violation was based upon activities prior to the events leading to the current extended plant shutdown and satisfy the criteria in Section Vll.B.2,
" Violations identified During Extended Shutdowns or Work Stoppages," of the " General Statement of Policy and Procedures for NRC Enforcement Actions"(Enforcement Policy), NUREG-1600, a Notice of Violation is not being issued (NCV 50-373/98005-06;
.50-374/98005-06).
General Material Condition items The team identified a number of examples of broken, missing, or loose screws, clamps, and fasteners which had not been identified during recent system engineering walkdowns.
For example, the team identified that the flexible connection atsociated with the Unit 1
' VG cooling fan had two screws installed per draw band, and the Unit 2 connection did not have any screws installed. Subsequently, the licensee determined that design drawing Dl-21, " Class I (Seismic) Ductwork Flexible Connections," specified that screws be spaced at 6-inch outer circumference intervals, which did not conform to the Unit 1 and Unit 2 VG cooling fan as-built configuration. As a result, PIF L1998-02480 was generated to document the deficiency.-
The team also identified that a bolt and nut associated with the 18 DG jacket water temperature control valve was loose and spun freely in its associated flange hole. As a result, the licensee generated an.AR and initiated PlF L1998-02383.
Finally, the team identified a number of junction boxes and other components associated with safety-related and nonsafety-related systems with loose or missing
- screws.
Housekeeoina items
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The team noted that a number of areas such as the HPCS and DG rooms were generally clean and free of debris. However, the team also identifed a variety of housekeeping problems in other areas which had not been addressed. For example, the team identified accumulated dirt and debris undemeath the Unit 1, Division lil battery racks. As a result, the licensee generated PIF L1998-02383 to document the -
deficiency. Similarly, the team identified an excessive amount of debris in the Unit 1 and Unit 2 RHR pump rooms and RHR heat exchanger rooms.
In addition, the team identified a floor to ceiling support in a frequently traveled area which was housed inside the installed " cup" without any sealant material. Subsequently, the licensee determined that although the sealant material only provided a
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housekeeping function to keep debris out of the cup, the identified configuration was not in accordance with the as-built drawings. As a result, the licensee initiated an action
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request (AR) to fill the cup to prevent the accumulation of dirt and debris.
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Also, during a walkdown with licensee personnel, the team identified an unsecured
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handrail storage cart in the vicinity of safety-related VG system equipmer,t. The licensee removed the cart and generated PIF L1998-02880. Subsequently, the licensee determined that the handrail storage cart was not in an approved storage location or properly stored as required by LaSalle Administrative Procedure (LAP) 100-56,
" Equipment / Parts Storage in Plant Areas Containing Safety Related Equipment,"
Revision 0, dated December 13,1997, which required that equipment / parts storage in plant areas should be minimized to reduce the potential for impact on adjacent safety-related equipment during a seismic event.
10 CFR 50, Appendix B, Criterion V, " Instructions, Procedures and Drawings," requires that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. The failure to secure the handrail storage cart in the vicinity of safety-related equipment as discussed above and as required by LAP 100-56 was an example where the requirements of 10 CFR 50, Appendix B, Criterion V, were not met and was a violation.
However, since the VG system was not required to be operable in the plant condition which existed when the violation was identified, this failure constitutes a violation of minor significance and is being treated as a Non-Cited Violation, consistent with Section IV of the Enforcement Policy (NCV 50-373/98005-07; 50-374/98005-07).
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Conclusions The team concluded that although material condition had improved overall, numerous minor discrepancies were identified, which indicated a lack of attention-to-detail during system engineering walkdowns. The team also concluded that housekeeping was inconsistent with some areas such as the HPCS and DG rooms generally good, while other areas, such as the RHR pump rooms and RHR heat exchanger rooms, were in need of attention.
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E2.2 Review of NRC Restart Action Plan 0350 item C.4.e. " Surveillance Testina Proaram" a.
Inspection Scope The team reviewed NRC Restart Action Plan 0350 Item C.4.e, regarding the adequacy of the surveillance testing program, b,
Observations and Findinos b.1 Documented Licensee Actions The team reviewed the following documented information regarding surveillance testing for action step 1.9 of licensee Restart Action Plan 4.2 and action step 2.3.1 of licensee Restait Action Plan 3.1:
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O Restart Action Plan 4.2 - Plant Operational Readiness Restart Action Plan 4.2 was established to implement a system functional performance review (SFPR) and other focused assessments of plant systems to define the work required to be completed prior to Unit 1_ restart. This was required to establish confidence that plant systems were capable of operating reliably and in accordance with design basis requirements.
Action Sten 1.9 - Identifv Functional Testina Requirements The purpose of this action step was to identify functional testing requirements including overallintegrated testing and selected emergency core cooling system response demonstration testing. To implement this action step, functional testing requirements for each of the SFPR systems were identified during the reviews based on the criteria in the SFPR programmatic standard. Utilizing these criteria, a test recommendation document was developed for each of the systems reviewed that identified how the system functional testing re quirements were achieved and demonstrated. The result was a comprehensive list of the testing and observation activities that were necessary to demonstrate syste n functions, in the following categories:
_ Surveillance : testing following completion of related procedure revisions;
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Post-maintenance testing following completion of maintenance activities;
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Post-modifi :ation testing following modification installation;
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Testing des.gned for data collection to allow documentation of system
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performance baselines; One-time tests to verify or demonstrate specific design features; and
One-time tests to demonstrate integrated system functional performance.
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Testing was commenced utilizing the list developed for each system or component.
When a test or observation did not adequately verify that a component was capable of performing its required function, the SFPR review team generated an issue Resolution Sheet (IRS), An IRS database was developed to identify and compile tests to be performed prior to Unit 1 restart. Problems discovered during the perfom1ance of testing were or will be dispositioned through the Corrective Action Program.
Restart Action Plan 3.1 - Validate Surveillance and Preventive Maintenance (PM) Sggga When Unit i entered forced outage L1F35 in September 1996, the scope and schedulir.g for the next Unit 1 refueling outage, L1R08, had not begun. As the scope and duration of L1F35 grew, reviews were conducted in the areas of PM a9ies, surveillance, and regulatory commitments to identify the scope of 7
..ared to support Unit i restart.
Action Steo 2.3.1 - Validate Unit 1 Surveillance and PM Scooe The ' purpose of this action step was to validate the Unit 1 surveillance and PM scope.
To implement this action step, in early 1997 the system engineering PM program
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coordinator reviewed the PM program requirements to identify the scope of PMs that needed to be accomplished during L1F35, and to confirm the accuracy of existing frequency and operational modes to perform these surveillance. In addition, the environmental qualification (EQ) coordinator also reviewed the EQ-related PM items.
Based on the reviews conducted, during L1F35 LaSalle has or will perform all required preventive maintenance activities that support reliable equipment operation.
b.2 Team Review of Documented Licensee Actions The team reviewed the information identified above and concluded that the actions
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planned or accomplished as delineated by the actions steps were thorough and, if properly implemented, appeared to be effective. The team independently reviewed I
portions of these action steps, including findings in previous NRC inspections, and identified the following:
e Surveillance and Testing Observations The team noted that as discussed in inspection report 50-373/97018; 50-374/97018, the NRC observed functional testing associated with a 1 A residual heat removal service I
water system keep-fill modification and a 1 A DG load and acceptance test, and concluded that testing engineers adequately controlled the testing.
During this inspection, the team observed a number of surveillance related to the RHR, DG, and HPCS systems and identified the following:
Emeroencv Diesel Generator Testina Observations On April 9,1998, the team observed the performance of LaSalle Operating Surveillance (LOS) DG-M2, "1 A Diesel Generator Monthly Surveillance Test." Testing associated with the following modification and maintenance activities was also observed:
DCP 9800003 1A DG Speed Sensor Modification
LST-98-062 1 A DG Control Room Voltage Adjust Switch
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LST-98-052 1 A DG Control Room Govemor Adjust Switch
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l LST-98-055 1A DG Local Governor Adjust Switch
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LTS-400-18 Unit 1 Main Generator Dewpoint Measurement
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The team noted that all tests were completed satisfactorily. The team also noted that prior to the testing, a detailed pre-job brief was performed and test procedures were i
verified to be the correct revision. The cognizant system engineer was designated as l
the test director and surveillance coordinator, assumed full control of the evolutions l
performed, and appeared to be very knowledgeable. No deficiencies were identified.
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o Residual Heat Removal System Testina Observations On April 14,1998, the team observed the performance of LaSalle Special Test (LST)98-133, "1B RHR Pump Data Acquisition Test." During the testing, the team noted that the pre-job briefing was thorough and ensured that involved personnel were cognizant of all aspects of the testing, including their required tasks and test termination criteria.
Engineering personnel correctly followed procedures and demonstrated effective self-checking during the performance of this special test. Communications among test personnel, including system engineers, were clear. No deficiencies were identified.
l Hiah Pressure Core Sorav System Testina Observations On April 9,1998, the team observed the performance of LOS-HP-Q1, " Unit 1 HPCS System Inservice Test. In add; tion, on April 16,1998, the team observed the performance of LaSalle Administrative Procedure (LAP) 300-3, " Vibration Monitoring Program," and LaSalle Technical Surveillance (LTS) 300-7, " Leakage Reduction and Control Program," for the Unit 2 HPCS system.
i During the testing, the team noted that pre-job briefings were thorough and ensured that all personnel were cognizant of the required tasks. Engineering personnel correctly l
followed procedures and demonstrated effective self-checking during the performance
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of the surveillance tests. In addition, HPCS pump oil samples were properly obtained and labeled.
The team also determined that with the exception of the minor violation described in section E4.1 of this report, the surveillance procedure acceptance criteria was in conformance with the technical specifications, UFSAR, and American Society of Mechanical Engineers Code requirements.
Standbv Gas Treatment System Testino Observations On April 13,1998, the team observed the performance of LaSalle Electrical Surveillance (LES) FP-121, " Unit 1 VG Filter Deluge Channel Functional Test." The team noted that licensee personnel correctly performed this post-maintenance surveillance test and subsequently retumed the Unit 1 VG train to service. No deficiencies were identified.
Measurement of Main Generator Air Dewooint The team observed the performance of LTS 400-18, " Unit 1 Dewpoint Measurement of Service Air, instrument Nitrogen, and Generator Hydrogen." The team noted that licensee personnel, including the system engineer, performed the surveillance satisfactorily and verified that the dewpoint of the Unit 1 main generator was acceptable.
No deficiencies were identified.
e Surveillance Documentation Review
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The team reviewed documentation associated with the following recently performed surveillance and functional tests:
Inst Surveillance or Functional Test Title LEP:PM-02 Preventive Maintenance of Spare Battery Cells LOS-DC-Q6 Unit 1 Battery Quarterly Readings LOS-DC-Q2 Unit 1 Division 2125V Battery Surveillance LES-DC-101 A-D Division 1-4125 Volt Battery inspections for Unit 1 and 2 WR 980002173-01
"B" RPS Motor Generator Set Battery Performance Test WR 960076351-01 Unit 1 125V Battery Division 111 Performance Test WR 960076506-01 Unit 1 125 V Battery Division 1 Service / Discharge Test WR 960007651-01 Unit 2125V Battery Performance Discharge Test The team determined that overall, the surveillance results were properly and completely documented, that established acceptance criteria were met, and that the data was
- properly reviewed However, the following deficiencies were identified:
LFP-PM-02. " Preventive Maintenance of Soare Batterv Cells"
The team reviewed LaSalle Electrical Maintenance Procedure (LEP) PM-02, " Preventive Maintenance of Spare Battery Cells," and noted that the corrected specific gravity for a spare safety-related NCX-27 battery cell was recorded as 1.17 which was lower than a
" normal" specific gravity. In addition, the team identified that this surveillance was i
reviewed and approved as acceptable, although the recorded as-found specific gravity was abnormally low.
The team discussed this finding with licensee personnel who generated PlF L1998-02033 to document the deficiency. Subsequently, the licensee determined that
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due to a lack of attention-to-detail, the corrected specific gravity was incorrectly calculated and was not noted by the individuals who performed or reviewed the surveillance. The team also noted that LEP-PM-02 did not contain acceptance criteria
regarding voltage or specific gravity for safety-related spare battery cells in storage.
l The team considered the practice to measure and record spare battery ce4 data without comparison to any acceptance criteria to be a weakness. However, the team also determined that prior to installation in a safety-related application, a number of tests were required to ensure that the spare battery cell was operable. Licensee personnel stated that in the future, they planned to upgrade their spare battery cell storage practices to maintain all of the spare battery cells on a constant float charge to ensure that the cells were in an optimum condition during storage.
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LES-DC-101 A-D. " Division 1-4125 Volt Batterv Inspections for Unit 1 and 2" The team reviewed LES-DC-101 A-D, " Division 1-4125 Volt Battery inspections for Unit 1 and 2," dated March 28,1994 through July 12,1996. During that review, the team identified that licensee personnel had not trended the intercell and terminal connection resistances for the safety-related batteries as required by institute of
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Electrical and Electronics Engineers (IEEE) 450. Upon further review, the team determined that this issue had been previously identified on January 30,1997 during the 125 VDC system SFPR. The team concluded that although the identification of the issue was good, appropriate corrective actions were not initiated. However, since the measured intercell and terminal connection resistances for the safety-related batteries l
were relatively low, the failure to trend this data was not significant and was considered l
a weakness. At the end of the inspection, the licensee had initiated corrective actions to ensure that the resistance data was trended as required.
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Conclusions l
The team concluded that the actions planned or accomplished as delineated by action l
step 1.9 of licensee Restart Action Plan 4.2 and action step 2.3.1 of licensee Restart Action Plan 3.1 were thorough and, if properly implemented, appeared to be effective.
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In addition, the team concluded that for the surveillance observed and reviewed,
. system engineering personnel demonstrated good understanding and involvement with testing activities. Two weaknesses regarding surveillance testing of safety-related battery cells were identified. Overall, the team concluded that the licensee had adequately implemented action step 1.9 of licensee Restart Action Plan 4.2 and action step 2.3.1 of licensee Restart Action Plan 3.1. NRC Restart Action Plan 0350 Item C.4.e will remain open pending a review of action steps 1.1,1.2,1.3, and 9.0 uf licensee Restart Action Plan 1.3C.
E2.3 Review of NRC Restart Action Plan 0350 itern C.4.k. "Enaineerina Backloa" a.
Insoection Scone
- The team reviewed NRC Restart Action Plan 0350 item C.4.k regarding the management of the engineering backlog.
b.
Observations and Findinas b.1 Documented Licensee Actions
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The team reviewed the following documented information regarding management of the l
engineering backlog for action steps 8.0 through 8.6 of licensee Restart Action Plan 4.2:
Restart Action Plan 4.2 - Plant Operational Readiness Restart Action Plan 4.2 was established by the licensee to implement a system functional performance review (SFPR) and other focused assessments of plant systems to define the work necessary to be completed prior to Unit 1 restart. This was required to establish confidence that plant systems were capable of operating reliably and in accordance with design basis requirements.
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Action Steo 8.0 - Backloo Review Backlogs consisted of work items tracked for closure by various controlled processes and databases. The purpose of this action step was to conduct a review of all backlog items and determine the importance of those items identified for safe and reliable plant operation. Many of the restart-required issues identified by the SFPRs were found to have been previously identified and tracked by the respective backlog processes. Many of these problems, however, were not properly evaluated or prioritized for effective and timely corrective action. Subsequently, the licensee determined that the backlog control process had not programmatically required performance indicators,' aging evaluations, or periodic progress reporting. To implement this action step, LaSalle completed the
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following activities:
Preparation of formal restart criteria.
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Screening of backlog items as well as emergent items for selection of issues
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requiring resolution prior to restart.
. Disposition of items screened and classified for resolution prior to restart.
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Schedule disposition of items screened and classified for resolution after restart.
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Preparation of a plan to improve control and timely disposition of the post-restart
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backlog items.
After the formal restart review criteria were adopted in February 1997, emergent issues were screened for restart as they emerged. The pre-existing backlog items were screened separately. Many of the backlog items were reviewed for screening as part of specific system-related reviews, such as system walkdowns and SFPRs. The types of backlogs specifically reviewed as part of action step 8.0 included: (1) Engineering Requests, (2) Licensee Event Reports (LERs), deviation reports (DVRs),~ and Root Cause Reports, (3) Operator Workarounds, Control Room Deficiencies and Work Requests (WRs)/ Action Requests (ARs), (4) Operability Evaluations, and (5) Technical Specification Clarifications.
Action Steo 8.1 - Preparation of Restart Review Criteria This action step specifically required the preparation of formal restart review criteria for backlogs. The restart review criteria were originally developed for use during SFPR activities to determine if items identified during the SFPRs should be resolved prior to plant restart. Restart review criteria were selected as a screening tool for identifying problems with the backlog that required resolution prior to restart. Issues which involved nuclear safety, personnel safety, and operability were given the highest priority. Actions to resolve significant design basis non-conformance problems, mitigate predictable component failures, and reduce excessive radiation exposure to personnel were also considered critical in the restart review criteria.
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Action Steo 8.2 - Enoineerino Recuest (ER) Review The review of the ER backlog resulted in 456 items that were screened for restart consideration, of which 314 were classified by the Restart Issues Review Committee as l
requiring resolution prior to restart.
Action Steo 8.3 - LER. DVR. and Root Cause Reoort Review The review of the LER, DVR, and Root Cause Report backlog involved a detailed review of 1103 LERs, DVRs, and Root Cause Reports as well as associated NTS item documentation. Previous corrective actions that were identified as ineffective were either resolved through a subsequent corrective action or had a PlF generated.
t Action Steo 8.4 - Workarounds. Control Room Deficiencies and WR/AR Review The review of operator workarounds involved screening the backlog and emergent items for restart consideration and classifying all but 7 for resolution prior to restart. The review of control room deficiencies involved screening the backlog and emergent items for restart consideration and classifying all but 1 control room deficiency for resolution prior to restart. The review of WRs and ARs involved screening the WR/AR backlog and emergent items for restart consideration. Emergent WRs and ARs were screened based on the implementation of the same restart screening criteria and classification process. The WR backlog was screened as part of the SFPR reviews and the prioritization would be re-confirmed as part of the System Readiness Reviews as systems were reviewed prior to startup.
Aciior, Steo 8.5 - Operability Evaluation Review The review of operability evaluations involved screening the backlog and emergent items for restart consideration. There were 55 outstanding operability evaluations, of which 22 were scheduled for closure prior to restart. The remaining 33 operability evaluations were either related to Unit 2 or were being reviewed to ensure that there were no issues that required resolution prior to Unit 1 restart.
Action Steo 8.6 - Technical Specification Clarification Review The review of technical specification clarifications involved a detailed review of 26 outstanding clarifications. Twenty-three were being deleted. The number of technical specification clarifications had been reduced to those necessary for safe plant operation and an effective process had been established to control emergent clarifications.
b.2 Team Rayjgw of Documented Licensee Actions The team reviewed the information identified above and concluded that the actions planned or accomplished as delineated by the action steps were thorough and, if properly implemented, appeared to be effective to manage the existing engineering
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backlog. The team independently reviewed portions of these action steps, including
findings from previous NRC inspections, and identified the following:
e Restart Review Criteria Review During this inspection, the team reviewed the ER backlog and identified a number of ERs related to UFSAR discrepancies associated with the primary containment purge and vent (VQ) system which were classified as post-restert in accordance with the restart classificat;on criteria, but in fact were restart-required since these UFSAR discrepancies could impact the plant's design basis. For example, PlF 97-2401 stated
- that the UFSAR description of the VQ system primary containment isolation valves did not conform to the as-built configuration. Specifically, the UFSAR stated that " vent and purge valves are air actuated to open and spring to close. Electrical power or air supply
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failure will not prevent their closing." However, VQ containment isolation valves 1(2)
VQ-32, -35, -47, -48, -50, -51, and -68 were motor-operated valves and would not close on the loss of electric power. At the end of the inspection, the licensee planned to review each UFSAR discrepancy identified during the SFPR and other reviews to ensure that the as-built plant configuration conformed to the licensing and design bases prior to restart.
The team concluded that the restart review criteria regarding the review of UFSAR discrepancies did not ensure that potential licensing and design bals issues were adequately evaluated prior to Unit 1 restart. However, at the end of the inspection, corrective actions appeared to be adequate to address the issue.
I e
Backlog Review The team noted that as discussed in inspection report 50-373/97018; 50-374/97018, the NRC reviewed the implementation of the restart review criteria and concluded that although the ERs reviewed were appropriately classified as restart-required or l
post-restart, some ERs were not reviewed as required.
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During this inspection, the team reviewed the ER backlog discussed above. The team l
l concluded that although the backlog of open ERs was relatively high (about 1765 items),
l a review of a representative sample of the ERs indicated that with the exception of ERs related to UFSAR discrepancies, the ERs had been properly prioritized for resolution as restart-required or post-restart.
The team reviewed the items a.sociated with the other backlogs that the licensee reviewed to address action steps 8.0 through 8.6 of licensee Restart Action Plan 4.2 and concluded that the operability evaluation, control room deficiency, technical specification clarification, and operator workaround backlogs had been effectively reduced and were l
relatively low. In addition, conceming operability evaluations, as discussed in inspection l
L report 50-373/97018; 50-374/97018 and section E1.4 of this report, the NRC concluded
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that overall, the operability evaluations reviewed provided the necessary technical i
justification to support the conclusions reached.
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Conclusions The team concluded that the actions planned or accomplished as delineated by action steps 8.0 through 8.6 of licensee Restart Action Plan 4.2 were thorough and, if properly implemented, appeared to be effective. In addition, the team concluded that with the exception of ERs related to UFSAR discrepancies, the ERs reviewed had been properly prioritized for resolution. In add 4 ion, the team concluded that other backlogs such as operability evaluations, control room deficiencies, technical specification clarifications, and operator workarounds, had been effectively reduced and were low. Overall, the team concluded that the licensee had adequately implemented action steps 8.0 through 8.6 of licensee Restart Action Plan 4.2. NRC Restart Action Plan 0350 Item C.4.k is considered closed.
E3 Engineering Procedures and Documentation E3.1 10 CFR 50.59 Proaram Review a.
Insoection Scone The team reviewed the implementation of the 10 CFR 50.59 program.
b.
Observations and Findines The team reviewed the implementation of the 10 CFR 50.59 program including
- procedures for screening changes, tests, and experiments and preparing safety evaluations; the processes for maintaining records, updating the UFSAR, and reporting to the NRC; and the training and qualifications of 10 CFR 50.59 screening and safety evaluation preparers. In addition, the team reviewed 10 CFR 50.59 screenings and/or safety evaluations associated with procedure changes, facility changes, temporary modifications, negative applicability determinations, UFSAR editorial changes, and defacto changes to UFSAR. The following issues were identir d:
e 10 CFR 50.59 Proaram LaSalle utilized nuclear station work procedure (NSWP) A-04, "10 CFR 50.59 Safety Evaluation Process," to perform 10 CFR 50.59 screenings and safety evaluations. The team reviewed NSWP-A-04 and verified that the guidance in this procedure was in conformance with 10 CFR 50.59 and NUREG-1606, " Proposed Regulatory Guidance Related to implementation of 10 CFR 50.59." The team concluded that NSWP-A-04 appropriately reflected 10 CFR 50.59 safety evaluation criteria and, if effectively l
implemented, would ensure that changes were performed in accordance with 10 CFR 50.59.
In addition, the team noted the following strengths associated with the 10 CFR 50.59 safety evaluation program:
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_ The licensee used a broad definition of the safety analysis report to make
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10 CFR 50.59 applicability determinations and included the UFSAR, Safety Evaluation Reports, Administrative Technical Requirements, Offsite Dose Calculation Manual, Core Operating Limits Report, the operating license, and technical specifications.
The program included an in-line review by the Engineering Assurance Group of
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10 CFR 50.59 screenings and safety evaluations for all modifications and
- engineering procedure changes.
The team also identified the following administrative weakness related to the program:
The team identified that the licensee did not have a comprehensive system for
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tracking changes, tests, and experiments that were determined not to req'9 e a t
full safety evaluation following a 10 CFR 50.59 screening. At the end of t se inspection, the licensee planned to revise NSWP-A-04 to assign tracking
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numbers to 10 CFR 50.59 screening review documentation similar to what was currently implemented for 10 CFR 50.59 safety evaluation review documentation.
10 CFP. 50.59 Prooram Reoortina Review The team reviewed the reporting of completed safety evaluations to the NRC as required by 10 CFR 50.59(b)(2). During that review, the team identified that although a safety evaluation for LaSalle Special Procedure (LLP)97-031, "Use of Main Condenser.
- as a Decay Heat Removal Method in Cold Shutdown," was prepared and implemented at least 22 times during 1997, it was not included in the 10 CFR 50.59 annual report to the NRC as required.
The licensee performed a root cause investigation and determined that the apparent cause for the problem was a lack of procedural controls during the preparation, review, and transmission of 50.59 summaries for the annual report. Specifically, +he preparer assembled the report based on information received throughout the year. However, this information was only a part of the total number of 50.59 safety evaluations conducted.
The preparer previously had no difficulty in preparing the report because site procedures provided the mechanism to send all 50.59 safety evaluations to the annual report l
preparer. However, in May 1997 the site procedure was replaced by corporate
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procedure NSWP-A-04 which did not contain guidance to send all safety evaluations to l
the annual report preparer. The licensee identified a total of 47 required 10 CFR 50.59 safety evaluations that were not reported to the NRC as required.
As part of the immediate corrective actions, on April 17,1998, the licensee submitted a supplement to the original 1997 annual report which identified the 4710 CFR 50.59 safety evaluations that had been performed and were previously unreported. In addition, the licensee planned to revise LAP-1200-24, *Roadmap for Safety Evaluation,"
to provide explicit controls for the review and transmittal of 50.59 summaries to ensure that in the future all changes, tests, or experiments for which a safety evaluation was
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required would be included in the annual safety evaluation report to the NRC. The team reviewed these corrective actions and had no further concems.
10 CFR 50.59(b)(2) requires that licensees submit a report containing a brief description l
of any changes, tests, and experiments, including a summary of the safety evaluation of l
each. The failure to include all changes, tests, and experiments in the 199710 CFR l
50.59 annual report to the NRC as discussed above is an example where the j
requirements of 10 CFR 50.59(b)(2) were not met snd was a violation l
(50-373/98005-08; 50-374/98005-08).
10 CFR 50.59 Prooram Trainina Review
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The team reviewed the materials used in the training course for personnel that prepared l
10 CFR 50.59 safety evaluations and verified that the information presented in the
course was consistent with corporate procedures and NRC guidance. This training course, which consisted of 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> of lecture and exercises, appeared to be comprehensive and included several examples. The inspector noted that in addition to successful completion of the training course, individuals were required to have at least two years of commercial nuclear experience, a reactor operator or senior reactor j
. operator license (or equivalent), and prepare a satisfactory 50.59 screening or safety l
evaluation before becoming qualified to prepare 50.59 safety evaluations. The team concluded that the licensee had an acceptable program for ensuring that trained and qualified personnel prepared and reviewed 10 CFR 50.59 screenings and safety evaluations.
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l 10 CFR 50.59 Safety Evaluation Review The team reviewed a sample of 10 CFR 50.59 screenings and safety evaluations and determined that, overall, the screenings and safety evalusilons were appropriately-prepared and were consistent with licenses procedures, in particular, the team determined that the preparers reviewed appropriate documents during the preparation of 50.59 screenings and safety evaluations; the 50.59 screenings and safety evaluations adequately addressed the effects of the proposed changes on plant operations, interactions with other systems and components, any new failure modes, and the effects on accidents and transients; and the 50.59 safety evaluations adequately addressed unreviewed safety question triteria. The team identified some minor instances of a lack of attention-to-detail similar to the example identified in section E1.1, however, these examples did not affect the conclusions of the 50.59 screening or safety evaluation.
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Conclusions Overall, the team concluded that the 10 CFR 50.59 screenings and safety evaluations were of good quality with the exception of some minor errors. In addition, the team concluded that the licensee has an acceptable program for ensuring that trained and qualified personnel prepared and reviewed 50.59 screenings and safety evaluations.
Honver, the team also identified that the reporting of completed satei/ evaluations to the NRC had not been completed as required.
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E4 Engineering Staff Knowledge and Performance E4.1 Review of Licensee Proarams a.
insoection Scooe The team reviewed the status of the inservice testing (IST), setpoint control, Generic Letter (GL) 89-13, and fuse control programs.
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. Observations and Findinas The team reviewed the IST, setpoint control, GL 89-13, and fuse control programs.
Also, the team reviewed NRC Action Plan 0350 items and licensee Restart Action Plan items associated with the IST and setpoint control program.
b.1 Inservice Testing Program Review b.1.1 Documented Licensee Actions l
The team reviewed NRC Restart Action Plan 0350 item C.7.a, regarding the adequacy of the inservice testing (IST) program. In particular, the team reviewed the following documented information regarding the IST program for action step 3.8 of licensee Restart Action Plan 4.2 :
Restart Action Plan 4.2 - Plant Operational Readiness Restart Action Plan 4.2 was established by the licensee to implement a system functional performance review (SFPR) and other focused assessments of plant systems to define the work necessary to be completed prior to Unit i restart. This was required to establish confidence that plant systems were capable of operating reliably and in accordance with design basis requirements.
Action Steo 3.8 - Review Comoleted IST Assessment Based on a number of known deficiencies, the licensee contracted an outside organization to perform an assessment of their IST program. During that review, significant programmatic problems were identified. These problems included inadequate testing of components in the IST program, missing systems and components within the scope of the program, and the lack of a clear basis for the
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program scope. Corrective actions included the development of an IST basis document to establish the foundation of the decision process for inclusion or exclusion of components and systems in the IST program. In addition, a revision to the second 10-year IST program was prepared and submitted to the NRC on March 4,1998.
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b.1.2 Team Review of Documented Licensee Actions The team reviewed the information identified above and concluded that the actions planned or accomplished as delineated by action step 3.8 were thorough and, if properly implemented, appeared to be effective. The team independently reviewed the implementation of this action step and identified the following:
lasgrvice Testino (IST) of Pumos and Valves The team reviewed Revision 3 of the LaSalle IST program including supporting documentation to determine if adequate actions were taken to resolve the concems briefly discussed above. Areas reviewed included program positions, justifications, and relief requests. In particular, the Unit 1 high pressure core spray (HPCS) and residual heat removal (RHR) systems were selected for review to ensure that all components required to be tested by the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (the Code) were included in the revised program and that adequate testing was identified to verify the safety functions, of each component.
An IST basis document was developed to ensure compliance with the requirements of the 1989 Edition of the ASME Code,Section XI. Section XI required testing to be performed in accordance with various Operation and Maintenance (OM) standards including OM-6 for pumps, OM-10 for valves, and OM-1 for pressure relief devices. As noted above, the revised IST program was submitted to the NRC on March 4,1998. As a result, some procedures necessary to implement the testing of componeritc
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associated with the revised program were not available for review. However, the team determined that components which required testing were placed in the degraded equipment log pending successful completion of the required tests.
The team concluded that adequate controls were in place to ensure corrective actions and required testing would be completed prior to Unit 1 restart.
Technical Positions. Justifications. and Relief Recuest Review e
Technical Position Review The team reviewed the technical positions regarding the IST program. No deficiencies were identified.
e Cold Shutdown Justification and Refueling Justification Review The team reviewed various IST deferral justifications and concluded that overall, the cold shutdown justifications (css) and refueling justifications (RJs) were acceptable.
However, the following errors were identified:
CS-08: The cold shutdown justification description section stated that it was
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impractical to fully or partially stroke the subject valves on a quarterly basis.
However, the alternate frequency section of the cold shutdown justification
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cc adicted the description section and stated that the subject valves would be partially exercised on a quarterly basis. Subsequently, the licensee determined that the cold shutdown justification description section was in error since only the full-stroke exercise was impracticable.
CS-11: The alternate frequency section stated that the closed safety function of
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the subject valves would be tested. However, the section then identified that the closed safety function of valves 1(2)E12-F024A/B, would also be tested.
Subsequently, the licensee determined that in addition to testing valves 1(2)E12-F024A/B in the closed position, the description of these valves should have added an open safety function test, since these valves had an additional open safety function compared to the other valves listed.
RJ-12, RJ-17: The refueling justifications for these " testable check valves" were
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not clear regarding the impact of recent valve modifications on the ability to test the valves using the air-operators.
RJ-18: The refueling justification discussed the open exercise of the feedwater
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check valves as impracticable although the valves had no open safety function, but should have referred to the closed exercise function of these valves.
The team concluded that the errors identified during the review of cold shutdown justifications and refueling justifications indicated that engineering personnel occasionally failed to perform a thorough review of IST activities.
- Relief Request Review The licensee had submitted two relief requests for NRC approval. At the end of the inspection, these relief requests were still open pending the receipt of a safety evaluation review from the Office of Nuclear Reactor Regulation. No deficiencies were identified.
IST Basis Document Review The team reviewed the LaSalle revised IST program for the HPCS and RHR systems.
Overall, the team determined that the required testing established for the components associated with the systems was adequate. No deficiencies were identified.
In addition, the team reviewed'the IST basis document generated to support the revised IST program. The team determined that the basis document included information such as component safety functions, justifications for excluding components from testing, and component design information, and concluded that it was a good tool to compile component bases and design requirements. The licensee considered this a "living document" that would be updated based on changes associated with the plant.
However, the team identified the following minor errors in the HPCS and RHR system portions of the IST basis document:
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l HPCS Pump Suppression Pool Suction isolation Valve 1E22-F015: ' Safety
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position was listed as closed, although the valve also had a passive open safety functior'.
"C" RHR Pump Suppression Pool Suction Isolation Valve 1E12-F004C: Safety
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position was listed as closed, although the valve also had a passive open safety function.
A/B RHR Heat Exchanger RCIC Steam Isolation Valve 1E12-F052A/B: No
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safety positions identified.
A/B RHR Heat Exchanger RCIC Steam inlet Pressure Control Bypass Valve
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1E12-F087A/B: No safety positions identified.
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"B" RHR Fuel Pool Emergency Makeup Supply Testable Check Valve
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1E12-F089: The valve matrix correctly identified that the valves would be exercised open and closed, however, the IST basis document stated testing would be accomplished through disassembly and inspection.
"B" RHR Fuel Pool Emergency Makeup Supply Drain Valve 1E12-F097: The
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valve matrix did not identify the valve had an active safety function to close.
A/B RHR Cooling Water Supply Upstream Valve 1E12-F312A/B: Safety position
was listed as open, although the valve also had a closed safety function.
Section 3.2.11 of the IST program identified definitions for the safety function
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position (s) of valves. The section stated that the open/ closed safety position was open or closed, although it should have been identified as open and closed.
Overall, the team concluded that the IST basis document was a good tool to compile component bases and design requirements. However, the team also identified a number of minor errors in the document which indicated that engineering personnel, at times, failed to perform a thorough review of IST activities.
Testina Review The team reviewed selected inservice testing results associated with the HPCS and RHR systems. During that review, the following issues were identified:
HPCS Pump Inservice Testing Review
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The team reviewed LOS-HP-Q1, " Unit 1 HPCS Pump Run," Revision 36, which was completed on January 20,1998. During that review, the team identified that the HPCS pump flow rate fixed reference value was 6300 gallons per minute (gpm) although the acceptance criteria reference value was established at 6250 gpm. Subsequently, the team determined that although the fixed reference value had been recently revised to
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address concerns regarding the ability to read the flow instrument in 50 gpm increments, the pump was not re-baselined to establish a new acceptance criteria.
Technical Specification 4.0.5.a required that inservice testing of ASME Code Class 1,2, and 3 pumps and valves be performed in accordance with Section XI of the ASME Code. ASME Section XI, IWP-1100, " Pump Testing," required that pump testing be
l performed in accordance with the requirements of OM-6 which stated that if it is desirable to establish an additional set of reference values, a test shall be run at the new reference conditions, the results of which shall establish the additional set of reference values. The failure to establish a new set of reference values when IST procedure LOS-HP-Q1 was revised to change the fixed reference value of 6250 gpm to 6300 gpm was an example whera the requirements of TS 4.0.5 were not met and was a violation.
However, since the difference in flow rate was small and was within the readability of the instrument's smallest increment, such that the new acceptance criteria should not change appreciably, this failure constitutes a violation of minor significance and is being treated as a Non-Cited Violation, consistent with Section IV of the NRC Enforcement Policy (NCV 50-373/98005-09; 50-374/98005-09).
Safety Relief Valve Inservice Testing Review
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The team reviewed LTS-600-10, " Safety and Relief Valve Inservice Testing," Revision 13, which was completed on February 25,1997, to ensure testing was accomplished in accordance with OM-1. In general, the team determined that the procedure was adequate to perform as-found testing of relief valves. However, the following two minor issues were identified:
Section F.3.b of the procedure indicated that a seat tightness test was required
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to be performed at 90 percent of set pressure for 3 minutes. However, the team identified that Section 4.2 of OM-1 required that a 10-minute test be performed.
The failure to measure leakage for at least 10 minutes was an example where the requirements of TS 4.0.5 were not met and was a violation. However, since the effect of measuring seat leakage for 3 minutes vice 10 minutes would not change the results appreciably, this failure constitutes a violation of minor significance and is being treated as a Non-Cited Violation, consistent with Section IV of the NRC Enforcement Policy (NCV 50-373/98005-10; 50-374/98005-10).
The team noted that section E.2.c of the procedure allowed valve testing to be
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completed up to three months following removal. The team noted that although this delay in testing was allowed by the Code, a failure of one or more of the tested valves would require additional testing of other valves in the group.
Therefore, this statement had the potential to require taking systems out-of-service at power or performing a plant shutdown to perform the required additional testing.
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inservice Testina Prooram implementation Conclusions The team concluded that the actions planned or accomplished as delineated by action step 3.8 of licensee Restart Action Plan 4.2 were thorough and, if properly implemented, appeared to be effective. In addition, the team did not identify any major concems with the generic aspects of the revised IST program,and specifically for the two systems reviewed. A number of minor errors were identified with pro 0 ram documentation that indicated a lack of attention-to-detail. Although only a limited number of procedures were reviewed, two minor Code violations were identified. Overall, the team concluded that the licensee had adequately implemented action step 3.8 of licensee Restart Action Plan 4.2. NRC Restart Action Plan 0350 item C.7.a is considered closed.
b.2 Setpoint Control Program Review b.2.1 Review of NRC Restart Action Plan 0350 Item C.7.b The team reviewed NRC Restart Action Plan 0350 Item C.7.b, regarding the implementation of the setpoint control program, in particular, the team reviewed the following documented information regarding the setpoint control program for action step 6.0 of licensee Restart Action Plan 4.2:
Restart Action Plan 4.2 - Plant Operational Readiness Restart Action Plan 4.2 was established by the licensee to implement a system
- functional performance review (SFPR) and other focused assessments of plant systems to define the work necessary to be completed prior to Unit 1 restart in order to establish confidence that plant systems were capable of operating reliably and in accordance with design basis requirements.
Action Sten 6.0 - Desian Evaluations
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Both the SFPR program and independent Safety Assessment (ISA) identified concems with setpoint calculations. The SFPR program identified multiple instances where there was inadequate documentation for the basis of setpoints or calculations that, on preliminary review, identified a " negative margin." Negative margins occurred when the expected trip setpoint was set closer to the analytical limit and/or analytical value than the channel uncertainty would allow for a 95 percent compliance with 95 percent confidence. In addition, the ISA identified areas where procedural compliance was weak.
LaSalle and corporate engineering management established the Setpoint Adequacy Program and the Setpoint Control Program to address the programmatic weaknesses described above. The programs were also created to ensure that plant setpoints were correct and supported by calculations prior to Unit i restart, and that the instrument data sheets were transferred to the electronic work control system. In addition, design j
engineering established a process to verify that all safety significant automatic actuation j
setpoints, trips, or initiations were determined from the instrumentation tables of the i
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technical specifications (TSs) and that all of these setpoints were technically correct and had positivs margins to the enalytical limit. To accomplish these programmatic goals, design engineering established a plan to identify those safety significant instrument setpoints that required calculations prior to Unit i restart and to complete the required calculations.
The following were the functional categories, in order of safety significance, into which all LaSalle instrumentation was classified: (1) Reactor protection system (RPS)/ engineered safety feature (ESF)/ emergency core cooling system (ECCS)
actuation / trip setpoints, (2) Other TS and Regulatory Guide 1.97 setpoints/ indications, and (3) Other setpoints and indications. There were about 41 calculations identified that
- addressed the RPS/ESF/ECCS setpoints. Of these,17 calcu;ations were previously reviewed and determined to be acceptable. The remaining 24 functions either had incomplete information or the current calculation identified a negative margin.
Subsequently, new or revised calculations were completed and in al! cases included a positive margin between the analytical limit, analytical value, or design limit and the calibration setpoint. For the category of "Other TS and Regulatory Guide 1.97 Setpointsandications" dt. sign engineering completed calculations for the uncertainty associated with indications used to verify ECCS pump performance compliance with TS surveillance testing. After the above functiona were identified and reviewed, the rest of the functions in the reviewed TS tables wew valuated. However, because these were I
not required for automatic actuation of a safety system, they were deferred until efter Unit i restart. The final category of "Other Setpoints and Indications" was also comprised of lesser safety significant or nonsafety-related setpoints and were deferred
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until after Unit i restart.
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Based upon a review of the above areas, all restart-required satpoint control calculation had been reviewed and addressed.
l b.2.1 Team Review of Documented Licensee Actions The team reviewer'. the information identified above and concluded that the actions planned or accorr.plished as delineated by action step 6.0 were thorough and, if properly I
implemented, appeared to be effective. The team independently reviewed the implementation of this action step and identified the fnliowing:
Program Review l
The setpoint control program had been recently revised and was currently undergoing i
l another revision. In pasticular, the Comed corporate office was in the process of developing a common setpoint control program to be implemented at all Comed sites.
The current setpoint control program methodology adopted at LaSalle was the design i.
change approach and used Nuclear Engineering Procedure (NED) 04-01, " Plant
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Modifications," Revision 5; NEP-04-01LA, " Plant Modifications - LaSalle Site,"
Revision 2; and LAP-1300-9, " Control of Setpoint/ Scaling Changes," Revision 7. This setpoint controi program approach was made effective January 1998. Prior to that date, l
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the LaSalle setpoint control program was implemented using LAP 1300-19, " Controlled Design Changes," Revision 5, dated December 17,1997 (superseded).
In the licensee's Restart Action Plan 4.2.6, Attachment 4. " Project Plan for Development andIr.g antation of the Setpoint Control Program," a plan was established to develop a long-term stable setpoint control program for LaSalle. Licensee personnel stated that the plan would ensure rigor in the preparation of setpoint and scaling values as well as implementation of those values in the plant and in plant procedures. Although the team observed progress with respect to RPS/ESF/ECCS actuation / trip setpoint calculations, I
the implementation of the long-term plan had not been fully completed. Licensee j.
personnel stated that this work should be completed by June 1998.
l Calculation Review
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The team reviewed a number of RPS/ESF/ECCS calculations. Nthough no significant technical errors were identified, some attention-to-detail problems were noted. For example, NED-I-EIC-0201, " Reactor Vessel Low Water Level 3 Scram Setpoint Calculation - Unit 1," Revision 0, and HED-I-EIC-0203, " Reactor Vessel Low Water Level 3 Scram Setpoint Calculation - Unit 2," Revision 0, referenced incorrect assumptions, design inputs,' and non-existent calculation sections.
In addition, although the licensee documented that RPS/ESF/ECCS calculations were adequate, the team determined that the licensee had identified that some of the calculations contained unverified assumptions which required review to validate adequacy.
Setooint Control Proaram lmolementation Conclusions The team concluded that the actions planned or accomplished as delineated by action step 6.0 of licensee Restart Action Plan 4.2 were thorougl: and, if properly impemented,
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appeared to be effective. in addition, the team concluded that although a number of j
attention-to-detail errors were noted, no technical errors were identified and the setpoint I
control program was adequate. Overall, the team concluded that the licensee had adequately implemented action step 6.0 of licensee Restart Action Plan 4.2. NRC Restart Action Plan 0350 item C.7.b is considered closed.
b.3 Generic Letter 89-13 Program Review The team reviewed the Generic Letter (GL) 89-13 heat exchanger inspection program which was implemented to control and monitor fouling of service water system piping and components as described in GL 89-13 " Service Water System Problems Affecting
' Safety-Related Components." As part of that review, the team reviewed Quality and
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Safety Assessment (Q&SA) report QVS-01-98-003, " Assessment of Generic Letter 89-13." in addition, the team discussed the status of the GL 89-13 monitoring program j
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I The licensee had identified a number of significant problems associated with the l
i GL 89-13 program. These problems inc,luded: (1) deficiencies in design calculations I
which defined required system performance and margins, (2) deficiencies in the testing of system components, (3) deficiencies in the corrosion assessment and control program, and (4) single failure questions that had been identified, but not resolved.
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The GL 89-13 testing prograns 7 ailed to verify that the required heat transfer
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Calculations to define required heat loads and acceptance criteria for heat
exchanger tests were incomplete or inaccurate.
Although a largo number of inspections and repairs were recently completed, the
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results of these activities had not been evaluated.
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The original GL 89-13 program for inspections, evaluations, and trending of I
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ir spection results was inadequate to satisfy GL 89-13 requirements for a l
l corrosion control program.
l In addition, the team noted that the Q&SA report identified that although many commitments and issues had been identified relative to the GL 89-13 program, many activities which needed to be completed in order to upgrade the GL 89-13 program prior to plant restart had not been classified as " Restart-Required" activities. At the er.d of the (
inspection, the licensee had re-evaluated specific items and re-prioritized those items for-l completion prior to of after restart as necessary. This is an inspection follow up item
. (50-373/98005-11; 50-374/98005-11) pending further NRC review including a review of the prioritization of those items.
l b.4 Fuse Control Program Review -
r The team reviewed the fuse control program which provided the methodology for the installation and replacement of fuses, and ensured proper maintenance and control of l
the fuse list. As part of that review, the team reviewed Q&SA Audit 01-97-06, " Audit j
Report for Engineering / Design Control," performed in June 1997, and discussed the
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The licensee had identified a number of significant problems associated with the fuse control program. These problems included procedure deficiencies in LAP 400-11, " Fuse l
Replacement," regarding traceability, and record retention and storage, as well as i
. procedure implementation deficiencies in the engineenng, operations, and maintenance departments. The licensee concluded that the fuse control program was inadequate and opened corrective action record 01-97-052 for programmatic and implementation t
deficiencies identified in the area of fuse control.
During this inspection, the team reviewed the licensee's findings. Following that review, the team identified an additional item which the licensee had not identified during their
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previous audit. Specifically, the team identified that fuse size discrepancies identified by
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the licensee had not been addressed since 1994. As a result, several hundred deficiency reports regarding fuse size discrepancies associated with safety-related and nonsafety-related equipment had been identified, but had not been reviewed or evaluated.
10 CFR 50, Appendix B, Criterion XVI, " Corrective Actions," requires that measures shall be established to assure that conditions adverse to quality, such as faibes, malfunctions, deficiencies, and nonconformances are promptly identified and corrected.
In the case of significant conditions adverse to quality, the measures shall assure that the cause of the condition is determined and corrective action taken to preclude repetition. The failure to identify that the station fuse list for safety-related fuses had not -
been updated since April 1994 was an example where the requirements of 10 CFR 50, Appendix B, Criterion XVI were not met and was a violation (50-373/98005-12; 50-374/98005-12).
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Conclusions Overall, the team coricluded that the licensee had identified a number of significant deficiencies with the IST, setpoint control, GL 89-13, and fuse control programs, and was in the process of taking corrective actions to improve the programs prior to Unit i restart. The team concluded that the licensee had adequately implemented action step 3.8 of licensee Restart Action Plan 4.2 and NRC Restart Action Plan 0350 item C.7.a is considered closed. The team concluded that the licensee had adequately implemented action step 6.0 of licensee Restart Action Plan 4.2 and that NRC Restart Action Plan 0350 item C.7.b is considered closed.
E6 Engineering Staff Training and Qualification E5.1 Review of NRC Restart Action Plan 0350 item C.3.4.a a.
Inspection Scope The team reviewed NRC Restart Action Plan 0350 item C.3.4.a. regarding the adequacy of engineering personnel qualifications.
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Observations and Findinas l
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b.1 Documented Licensee Actions The team reviewed the following documented information regarding engineering personnel qualifications for action steps 1.0,1.1,1.4, and 3.0 of licensee Restart Action
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Plan 4.1:
' Restart Action Plan 4.1 - Enaineerina Caoability An NRC System Operational Performance inspection conducted from September 3 through September 24,1996, identified four apparent violations involving I
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noncompliance in ASME Code Section XI pump testing requirements, failure to provide required design controls during modifications, untimely corrective actions to resolve conditions adverse to quality, and inadequate control of surveillance testing. The inspection also revealed a fundamental deficiency in understanding the design basis of the safety-related service water system at LaSalle.
l Action Steo 1.0 - System Enaineerina Qualifications One of the improvement efforts initiated to resolve the deficiencies described above required completion of system qualifications for all system engineering personnel, including both incumbent and contractor personnel, with assigned systems.' The purpose of the training was to provide system engineers with the technical basis to: (1)
understand system performance requirements and design bases, (2) monitor, trend, analyze, and predict system performance, (3) provide technical support for plant
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l maintenance activities, (4) participate in the work control process, (5) provide technical support for system operations, (6) review plant and industry operating experience, (7)
participate in the design change process, and (8) participate in the investigation of emergent plant issues.
Action Sten 1.1 - Determine System Qualification Requirements One improvement effort initiated to upgrade the technical capability and judgement of system engineering personnel involved strengthening the system engineering qualification program. The revised qualification program emphasized system engineering knowledge and skills related to operations, maintenance, and equipment performance for assigned systems. The following actions were undertaken to accomplish this goal: (1) determine system qualification requirements and methods for ach;eving those requirements, (2) use an oral board comprised of the system engineering supervisor, group leaders, and external members to determine whether engineers have the skills, knowledge, and attitude required to be qualified as system
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engineers, (3) use the system functional performance review (SFPR) program as a part of the qualification process, and (4) use the System Readiness Review process as a part of the qualification process.
Action Stoo 1.4 - Perform Self-Assessment of Effectiveness of Justification Process The purpose of this action step was to determine the effectiveness of the qualification process changes described above. The initial self-assessment of the system engineering qualification process was completed on November 7,1997. The purpose of this assessment was to determine the effectiveness of the system engineering qualification program in evaluating system engineer capability. This assessment concluded that the qualification program satisfied the programmatic requirements of applicabic Institute for Nuclear Power Operations guidance, as well as corporate and site procedures.
Action Steo 3.0 - Use of SFPR and Enoineerina Assurance Group (EAG) Reviews
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The purpose of this action step was to use the SFPR program and EAG reviews as a fundamental tutoring process for assessing and improving the technical capabilities of engineering. Both of these programs provided feedback mechanisms to supplement the engineering training and qualification programs.
System engineer participation in the SFPR team activities and Systems Independent Review Group meetings provided additional training and tutoring on their systems. In addition, system engineers and their group leaders were responsible for the review and approval of discrepancy closeout packages for their systems. Engineering Assurance Group discussions with system engineers during EAG assessments provided further practical training in design control.
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b.2 Team Review of Documented Licensee Actions The team reviewed the information identified above and concluded that the actions planned or accomplished as delireated by the action steps were thorough and, if properly implemented, appeared to be effective. The team independently reviewed portions of these action steps, including findings in previous NRC inspections, and identified the following:
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Qualification Proaram Review
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The team determined that LaSalle Memorandum 10, "LaSalle County Station System Engineering Depanment Guidelines," itevision 6, dated March 13,1998, established both general qualification requirements as well as specific requirements for qualification on individual systems assigned to the system engineer.
Memorandum 10, Attachment F, listed areas of general knowledge a system engineer must demonstrate. Attachment G established qualification requirements for system engineers to complete for his or her assigned system (s). Attachment H was a walkdown
- checklM wherein the system engineer demonstrated his or her knowledge of their
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system during a system walkdown with the supervisor or section leader. Each system engineer was required to pass an oral board examination prior to final qualification.
The team noted that not all of the system engineers had completed the qualification'
training. The target date for having all system engineers qualified was May 15,1998. In i
addition, the team determined that the licensee had upgraded the system engineering staff with more experienced engmars.
The team concluded that the qualification program prescribed by Memorandum 10 and recent staffing changes were adequate to upgrade system engineering capability.
Self-68attamROBc00aw The team reviewed the self-assessment completed on November 7,1997, and the imple nentation of corrective actions to address the findings. To correct the findings and l
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assure that training requirements were met, the licensee assigned a full-time contract training coordinator. No deficiericies were identified.
i SFPR and EAG Mentorina Review As discussed in inspection report 50-373/97018; 50-374/97018, the NRC determined I
that following an EAG review and documentation of findings in an oversight review record, the EAG reviewer discussed identified concerns and potential product improvements with the document preparers to provide mentoring and receive feedback.
In addition, the document preparer's supervisor was provided with a copy of the EAG reviewer's comments for informational use. The inspector reviewed this practice and concluded that it was an effective means to mentor engineering personnel. In addition, i
as discussed in the inspection report, the inspector interviewed personnel who had
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prepared documents reviewed by EAG. These personnel indicated that the mentoring
process had been effective and the quality of their products had improved.
The inspector concluded that the EAG mentoring of engineering personnel was effective.
c.
Conclusions l
The team concluded that the actions planned or accomplished as delineated by action l
steps 1.0,1.1,1.4, and 3.0 of licensee Restart Action Plan 4.1 were thorough and, if properly implemented, appeared to be effective. In addition, based on the review of training and qualification procedures and records, self-assessments, and corrective
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actions, the team concluded that the schedule for qualifying system engineers was
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progressing well. Overall, the team concluded that the licensee had adequately l
implemented action steps 1.0,1.1,1.4, and 3.0 of licensee Restart Action Plan 4.1 NRC Restart Action Plan 0350 item C.3.4.a is considered closed.
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E6 Engineering Organization and Administration E6.1 Review of NRC Restart Action Plan 0350 item C.2.3.c a.
Inspection Scope The team reviewed NRC Restart Action Plan 0350 item C.2.3.c, regarding whether acequate engineering support was provided as demonstrated by the timely resolution of issues.
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Observations and Findinas
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b.1 Documented Licensee Actions -
The team reviewed action steps 1.0 and 3.0 of Restart Action Plan 4.1 in section E5.1 of this report. Action steps 2.0 and 7.0 will be reviewed and discussed in a future inspection report. The team reviewed action steps 6.0 and 8 0 of Restart Action Plan
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4.2 in sections E4.1 and E2.3 of this report. Action steps 5.0 and 9.0 will be reviewed and discussed in a future inspection report.
l The team reviewed the following documented information regarding engineering support for actions steps 4.0, 5.0, and 6.0 of licensee Restart Action Plan 4.1, and action steps
1.0,2.0,3.0,4.0, and 7.0 of licensee Restart Action Plan 4.2:
Restart Action Plan 4.1 - Enaineerina Caoability i
The overall objective stated in licensee Restart Action Plan 4.1 was to " Upgrade the
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capability of Engineering to support safe unit restart and power operation through the
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j addition of experienced personnel, additional training of existing personnel, and
organizational and programmatic changes to ensure that work products meet acceptable quality standards."
LaSalle planned to achieve the objectives of Action Plan 4.1 through the implementation of seven action steps. These steps included: (1) system qualifications, (2)
implementation of the Engineering Assurance Group (EAG), (3) use of the system functional performance reviews (SFPR) and EAG reviews to improve the technical capabilities of engineering, (4) revise the scope of design engineering responsibilities, (5) augment the engineering staff to complete backlog reviews, SFPRs, and design
reviews, (6) develop managers to achieve necessary management capability, and (7) perform self-assessments of the effectiveness of the above actions.
Action Steo 4.0 - Revise Scoos of Desian Enaineerina Responsibilities -
Following a root cause evaluation to address four apparent violations identified during an NRC System Operational Performance Inspection conducted from September 3 through September 24,1996, one of the contributing factors to these violations was that the authorized permanent complement for the design engineering department was too l
small for the current scope of responsibilities assigned to this group.
One of the improvement efforts initiated to resolve this deficiency involved the reduction
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in scope of design engineering personnel responsibilities to that necessary to maintain l
the design basis. The following specific actions were undertaken to accomplish this objective: (1) determine the detailed scope of design responsibilities for engineering, (2) determine the organizational changes required to implement the revised scope of responsibilities, (3) establish a transition plan without introducing a delay in the support
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of restart activities, and (4) complete the transition to the revised scope of responsibilities.
Action Steo 4.1 - Determine Desian Enoineerina Responsibilities l
l in order to maintain positive control of the design basis, the design engineering responsibilities were revised to include only those required to implement this process.
The principal role of the design engineering department was to act as the design authority to ensure that the plant was designed, fabricated, maintained, operated and
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tested in accordance with the plant design basis. In addition, design engineering performed engineering associated with equipment, component, and part replacements, including commercial grade dedication. Other respontbilities not consistent with the mandate to maintain the facility design basis that were assigned to the design engineering department, including operability evaluations, emergent engineering requests, most temporary alterations, SFPR support, and outage planning and scheduling support, were re-assigned to other organizations.
Action Steo 4.2 - Determine Reauired Organizational Chances The primary organizational change required to implement the revised scope of responsibilities was the formation of the Engineering Rapid Response Team (ERRT).
The purpose of the ERRT was to resolve emergent issues which required engineering action in order to allow design engineering to focus on maintaining and managing the design basis. Other organizational changes included the formation of System Restoration / Restart Teams (SRRTs) and the Engineering Project Controls Group. The SRRT was formed to define, plan, deliver, and implement the engineering work scope and to support the work of other departments that was required for Unit 1 and Unit 2 restart, the next operating cycle, and the next refueling cycle. The Engineering Project Controls Group assumed the responsibility for DCP planning and scheduling. These organizational changes have allowed design engineering to concentrate on its primary
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responsibility to act as the plant denign authority.
Action Steo 4.3 - Establish Transition Plan All of the changes discussed above were completed without any dolay in the support of restart activities.
Action Steo 4.4 - Comolete Transition to Revised Scone of Responsibilities Engineering has completed the transition to the revisc scope of responsibilities for the
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ERRT and the Engineering Project Controls Group.
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Aghon Steo 5.0 - Auament Enoineerina Staff Following a root cause evaluation to address the four apparent violations identified during an NRC System Operational Performance Review, one contributing factor to these violations was that the total engineering staff size was insufficient to resolve the scope of material condition deficiencies which existed.
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' One of the improvement efforts initiated to resolve this deficiency involved staff augmentation to complete the reviews and evaluations of backlogs, and to assist in the
completion of SFPRs and design reviews as required by action step 2.0 of licensee Restart Action Plan 4.2 The SFPR program was developed ard implemented at the direction of LaSalle senior management after it was recognized that several design implementation and
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configuration controlissues existed on certain systems. These detailed SFPR reviews involved a total of 42 systems and were conducted by an integrated team of Comed personnel and augmented by consultants drawn from the nuclear industry. By the time the discovery phase was completed, a total of 95 experienced industry representatives had participated in the SFPR and design review programs. In addition, a review of the engineering backlog was conducted from May to June 1997 with the assistance of contractor personnel with system and testing experience. This review determined whether any of the engineering backlog items, including engineering requests, should be classified as restart-required when compared to the Restart Review Criteria. In addition, an assessment was performed by five industry representatives to evaluate the effectiveness of engineering corrective actions. Although the action step was originally conceived to meet short-term needs, the use of augmented staff will continue, as necessary, to complete all actions required prior to Unit i restart.
Action Steo 6.0 - Develoo Selected Supervisors The LaSalle sealant injection event, various self-assessments, and NRC observations identified the need for improvements in engineering management capability, including
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I first line supervisors, in response to these concerns, two courses of action were taken.
The first was to fill existing position vacancies and increase staff experience levels. The other course of action was to screen, evaluate, develop, and implement continued
' training for supervisors. The performance of these two actions had provided Comed with the mechanisms to substantially improve engineering management capability.
Restart Action Plan 4.2 - Plant Operational Readiness The overall ot@ctive of licensee Restart Action Plan 4.2 was to " implement a system l
functional perfo.mance review and other focused assessments of plant systems to define work necessary to be completed prior to unit restart so that there is confidence that the system is capable of operating reliably and in accordance with design basis requirements."
The objectives of Restart Action Plan 4.2 will be achieved through the satisfaction of the -
. performance measures and implementation of a total of nine action steps. These steps l
included. (1) SFPRs and functional testing, (2) design reviews, (3) configuration control l-evaluations, (4) plant trips and transients review, (5) vendor information and operating l
' experience reviews, (6) design evaluations, (7) upgrade important plant drawings, L
(8) backlog reviews, and (9) system readiness revews.
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Action Sten 1.0 - System Functional Performance Reviews I
i-l The purpose of this action step was to perform SFPRs to establish a level of confidence that selected systems important to safe and reliable operation could demonstrate functional perform.ance consistent with the design basis prior to restart. The program consisted of two phases. Phase 1 involved a pilot effort focused on the review of five
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systems to assess the nature and significance of any identified problems which could affect the ability of the systems to perform their required design functions. Phase 2
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'L included completion of the documentation associated with the five systems reviewed during the phase i pilot effort, and completion of the SFPR program for additional systems based on the results of the phase 1 effort. Phase 1 was completed and established the scope of phase'2 to include a total of 42 systems for SFPR review. The following methodology was prescribed and employed during the SFPR reviews:
For each function and sub-function of the system, the following would be
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performed during the SFPR review: (1) identification of how each sub-fun'ction was achieved, (2) identification of the achievement criteria traceable to a design basis document which confirm that components were capable of accomplishing their required functions, and (3) identification of the specific surveillance or other tests which demonstrate that components met achievement criteria. This data was captured on a System Function Evaluation Matrix.
Throughout the implementation of the SFPR program, all new and/or previously
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identified problems or issues were to be documented on issue Resolution Sheets Recommended actions to resolve the identified issue were then classified as either a restart-required action (to be accomplished prior to restart),
short-term action (to be accomplished after restart, but prior to the end of the next refueling outage), or long-term action (to be accomplished s:+1etime after the next refueling outage after restart).
A Systems Independent Revimv Group was established to provide independent
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reviews of the implementation of the SFPR program. The objectives of these reviews were to ensure the following:
That the identification of system functions, the definition of system
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boundaries and interfaces, and the document reviews were of adequate
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approach, depth, and scope.
That the scope of the review of routine testing and operational
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. observations of the systems were of sufficient depth to ensure that the
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system was capable of performing its design function.
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.That issue identification and resolution activities implemented as part of
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. this program were adequate to assure that problems were identifwKi and appropriately resolved.
Action Steo 2.0 - Desian Reviews The purpose of this action step was to perform a detailed design review of certain l
. systems to identify and resolve problems as a complement to the SFPRs. To implement this action step, detailed design reviews of the following systems were performed: (1)
control room ventilation, (2) auxiliary electric equipment room ventilation, (3) 125 volt direct current (125 VDC), (4) core standby cooling system, (5) standby gas treatment (VG), and (6) primary containment purge and vent (VQ).
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The overall conclusion from the design reviews was that although processes in place were generally sound, the incomplete or ineffective implementation of design requirements during construction, pre-operational testing, and operational maintenance activities resulied in inadequate configuration control. To address these issues, the following actions were performed: (1) all specific unresolved issues were entered into
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the station Corrective Action Program or the Nuclear Tracking System (NTS) for I
evaluation and resolution, (2) SFPRs were performed for 42 plant systems to address the generic issues identified during the design reviews, and (3) a new Corrective Action
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Program was implemented in May 1997 to address problem identification, evaluation, corrective action implementation, and problem recurrence prevention.
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Action Steo 3.0 - Configuration Control Evaluation in late 1996, a root cause analysis of unauthorized design changes concluded that changes were made to the station's design basis outside of the modification process described in LAP-1300-18, "Roadmap to Plant Changes." The report summarized the root causes as inadequate action request (AR)/ work request (WR) screening criteria, limited understanding of the modification process, vague policies, and limited l
understanding of configuration management concepts. To determine the extent to which uncertainty existed in the configuration control process, the significance of the
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configuration control problem, and the need to institute controls to prevent recurrence, several efforts were initiated to focus on configuration control. These included:
l (1) investigation of the use of inappropriate methods, such as nuclear design information transmittals (NDITs) and engineering (CHRON) letters, to authorize design changes outside of the approved design change process, (2) investigation of potentially unauthorized design changes through the accomplishment of work requests, (3)
verification of physical plant configuration conformance to design documentation, (4)
verification of operational configuration with tne UFSAR, and (5) assessment of plant performance against design requirements.
Action Steo 3.1 - Review of CHRON letters The entire population of CHRON entries (more than 15,000) were screened and 104 letters associated with Unit 1 were identified where CHRON letters appeared to have been used to make design changes to the facility, Subsequently, ERs were initiated to review these issues prior to Unit i restart.
Action Steo 3.2 - Review of NDITs The 278 NDITs transmitted to maintenance and construction were reviewed for design changes and 6 cases were identified as having inadequate configuration control.
Subsequently, design change requests were generated to resolve these issues prior to Unit i restart.
With regard to the use of CHRON letters and NDITs, less than 1 percent of the population had inadequate configuration control problems associated or resulting from
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them. As part of the corrective actions, because the use of NDITs and CHRON letters
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did not provide adequate configuration control, the practice of using NDITs and CHRON
letters to accomplish plant changes has been stopped. In addition, engineering procedures were revised to clearly define what constituted a design change and training
.j was conducted to disseminate th;s information.
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l Action Steo 3.3 - Review of Work Reauests l
l To assess the effectiveness of configuration controlin maintenance, a sample of WRs
'I was reviewed for unauthorized design changes for the low pressure core spray (LPCS)
and "0" DG systems. This review identified five WRs that involved a design change.
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None were functional changes, and none had safety significance or affected plant j
operation.
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No expansion of scope was warranted due to the minor, non-functional nature of the design changes.- Based on the review, few unauthorized design changes were implemented by WRs. Configuration management training was conducted for maintenance personnel in 1997 that included specific discussions regarding unauthorized design changes.
Action Steo 3.4 - Unit "0" and LPCS Svstem Walkdowns The LPCS and "0" DG systems were walked down to verify drawings and to confirm the design configuration. The walkdowns identified no functional discrepancies. Some minor deficiencies were identified and corrected.
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Action Steo 3.5 - LPCS Seismic Sunoort Wa!kdown A total of 347 pipe supports in the electronic work control syctem associated with the
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LPCS system were reviewed. No as-built deficiencies were identified.
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Action Steo 3.6 - LPCS System Mechanical Lineuo Review
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A valve-by-valve comparison of the LPCS system and mechanical valve positions from the mechanical checklist procedure to the piping and instrument drawings (P&lDs) was j
l performed to demonstrate that all normal operating valve positions were indicated on
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the P&lD. The review determined that locked valve instructions in procedures were not consistent with the P&lDs. However, since the instructions in the procedure took l
precedence over the P&lDs, these discrepancies were considered of minor significance.
Action Steo 3.7 - Functional Testina Assessment Functional testing required for restart are being critically reviewed to ensure that unauthorized modifications are not being installed. To date,37 tests have been reviewed and have not revealed any unauthorized modifications on those systems tested. Functional testing was in progress and will continue through power ascension.
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The assessment of functional testing in consideration of potential unauthorized modifications is an ongoing activity.
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Action Steo 4.0 - Review of Plant Trios and Transients LaSalle County Station had experienced plant trensients and scrams in excess of the industry norm which unnecessarily challenged operators and plant equipment. As a resuit, management determined that an important element of attaining plant operational readiness was to ensure that adequate corrective actions had been taken to prevent recurrence of plant trips and transients.
To address this issue, the reactor engineering organization reviewed 39 transients and scrams which occurred during the last 5 years and concluded that in most cases the corrective actions adequately addressed the root cause. However, the review also i
identified 7 instances where the effectiveness of corrective actions was questionable.
l These items included: (1) vessel level instrumentation " ringing" following main steam isolation valve (MSIV) closures or turbine trips, (2) feedwater heater transients due to improper replacement of feedwater heater drain valves on certain heaters, (3) complications with the response of turbine-driven reactor feed pumps due to foreign material in the control oil system, (4) main condenser boot seal failures, (5) water intrusion into main power electrical components, (6) mechanical and electrical failurec associated with the electro-hydraulic control system, and (7) unplanned or undesired MSIV closures.
LaSalle station is taking appropriate corrective actions to resolve these deficiencies.
The actions required prior to restart were either complete, or were being tracked by a DCP, AR, or a nuclear tracking system item for resolution.
j Action Steo 7 0 - Review Imoortant Plant Drawinos To attain plant operational readiness, LaSalle management recognized that the as-built facility had to be accurately represented on drawings used to operate, maintain, modify, and maintain the design integrity of the plant. Accordingly, action step 7.0 was initiated
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to " upgrade important plant drawings for systems known not to be accurately depicted and for all systems reviewed as part of the SFPRs."
To address this action step, the following activities were planned: (1) operations was requested to provide a list of known plant drawings which required revision, (2) drawing discrepancies identified during the 42 system SFPRs were documented and corrected, and (3) functional walkdowns of the LPCS and "0" DG systems were performed and drawmg discrepancies were documented and scheduled for resolution.
l As a result, operations identified that the instrument air, service air, and electro-hydraulic control system P&lDs did not accurately reflect the configuration in the plant.
All three of these s'ystems were completely walked down and identified discrepancies were al! minor changes with no major functional impact. In addition, an audit of the Unit 1 and Unit 2 critical control room drawings was conducted and determined to be of the correct revision with the exception of two drawings which required corrections to the revision level number or drawing revision date. Finally, operations identified that some drawings required upgrading to improve legibility. Walkdowns of the LPCS and "0" DG
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systems revealed that although some discrepancies were identified, the errors were minor in nature and did not affect system operability. Similarly, discrepancies identified during the SFPR reviews were either minor editorial errors or non-functional changes to make drawings consistent with as-built conditions. All known drawing corrections had been corrected or were being tracked for correction.
b.2 Team Review of Documented Licensee Actions The team reviewed the information identified above and concluded that the actions planned or accomplished as delineated by the actions steps were thorough and, if properly implemented, appeared to be effective. The team independently reviewed portions of these action steps, including findings in previous NRC inspections, and identified the following:
System Functional Performance Reviews and Design Reviews
The team noted that the NRC had previously reviewed and documented the implementation of the SFPRs and design reviews in inspection report 50-373/97013; 50-374/97013 and concluded that the SFPRs were effective in identifying problems.
During this inspection, the team reviewed SFPR findings and design review findings for the RHR,125 VDC, VG, VQ, HPCS, and DG systems. Following that review, the team similarly concluded that the SFPRs were effective in identifying problems.
- Configuration Control Evaluation As discussed in sections E1.3 and E2.1 of this report, the team identified a number of configuration controlissues during the inspection. Specifically, during system walkdowns the team identified the following configuration control issues:
The team identified that a concrete expansion anchor for the Unit i VG system
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did not have full thread engagement. Subsequently, the licensee determined that the anchor was not installed in accordance with as-built drawings.
The team identified that gaskets for removable curbs to contain fuel oil spills in
various DG rooms were degraded, missing, or improperly installed.
Subsequently, the licensee determined that the curb installation was not in conformance with as-built drawings.
The team identified that flexible connections associated with the Unit 1 and
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Unit 2 VG cooling fans were installed differently. Subsequently, the licensee determined that the installation for both units was not in accordance with the as-built drawings.
The team identified a floor to ceiling support in a frequently traveled area which
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was housed inside the installed " cup" without any sealant material.
Subsequently, the licensee determined that the configuration was not in accordance with the as-built drawings.
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The team identified that although the Unit 0,1 A, and 2A DGs had tygon tubing
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routed to a floor drain from the respective air box stop valve, this configuration was not in accordance with the as-built drawings, and represented an unauthorized alteration to the plant.
The team reviewed the discrepancies identified above and concluded that although in each case the plant configuration did not conform to the as-built drawings, these deficiencies were relatively minor in nature and did not significantly impact safety.
e Staffing The team determined that LaSalle had augmented the engineering staff with additional contract engineers. Seven new experienced managers were hired in 1997 resulting in a broader nuclear experience background at the management level, c.
Conclusions The team concluded that the actions planned or accomplished as delineated by action steps 4.0, 5.0, and 6.0 of licensee Restart Action Plan 4.1 and action steps 1.0, 2.0, 3.0, 4.0, and 7.0 of licensee Restart Action Plan 4.2 were thorough and, if properly implemented, appeared to be effective. In addition, the team concluded that the licensee had adequately implemented these action steps. NRC Restart Action Plan 0350 item C.2.3.c will remain open pending a review of action steps 2.0 and 7.0 of licensee Restart Action Plan 4.1, and action steps 5.0 and 9.0 of licensee Restart Action Plan 4.2.
E7 Quality Assurance in Engineering Activities
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E7.1 10 CFR 50.54m Letter Commitment Review
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a.
Insoection Scone The team reviewed the status of commitments pertaining to LaSalle's March 28,1997 response to the NRC's request for information pursuant to 10 CFR 50.54(f). The following commitments related to engineering were reviewed by the team. The commitment numbers correspond to those used by the licensee in their March 28,1997 response.
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Commitment 15: " Design records were transferred from the contract design engineering organizations to Comed, and onsite design engineering capabilities were created along with a clearer NOD Corporate engineering role. During this time, progress was made in the development and issuance of a series of common nuclear engineering processes at
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l The team verified that design records were transferred from contract design organizations.' Specifically, the team determined that the licensee had obtained about 46,000 design calculations, and most design drawings and specifications, in addition, j
' the team determined that common engineering procedures had been developed and i
implemented to delineate processes at the Comed sites and to clarify the roles and l
responsibilities of corporate and onsite design engineers.
Commitment 24: " Additional training will be conducted to address arec ; identified for improvement such as design basis adherence, configuration management implementation, operability determinations, and safety evaluation preparation."
The team verified that extensive engineering training including subjects such as design basis adherence, configuration management implementation, operability evaluations, and safety evaluation preparation had been conducted. In addition, design basis adherence and configuration management training was conducted for operations and maintenance personnel.
Commitment 323: " Design authority and design records were transferred from the contract design engineering organizations to Comed, onsite design engineering capabilities were increased, and we are developing a series of common engineering processes and procedures for the division."
The team verified that the licensee had increased onsite design capabilities by l
increasing the size of the design engineering staff through the hiring of additional, experienced personnel. Also, as discussed above, a series of common engineering l
procedures were developed and implemented for all the Comed sites, and a large number of records had been transferred to the onsite design engineering organization.
c.
Conclusions The team concluded that the licensee had made good progress in addressing 10 CFR 50.54(f) commitments 15, 24, and 323.
E8 Miscellaneous Engineering issues E8.1 (Closed) Violation 50-373/93031-02: 50-374/93031-02: Failure to Take Action to Adequately Address 4.0 kilovolt (kV) and 6.9kV Breaker Failures.
l The team verified the corrective actions described in the licensee's response letter, dated April 4,1994, to be reasonable and complete. No similar problems were identified.
L-E8.2 (Closed) Violation 50-373/93300-01: 50-374/93300-01: Inadequate Corrective Actions I
to Address Reactor Building Ventilation Damper Problems.
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The team verified the corrective actions described in the licensee's response letter, dated April 4,1994, to be reasonable and complete. No similar problems were identified.
E8.3 (Closed) Violation 50-373/96005-01: 50-374/96005-01: Degraded Reactor Core
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l Isolation Cooling Support and Undersized Motor-Driven Pump.
i-The team verified the corrective actions described in the licensee's response letter, l
dated September 24,1996, to be reasonable and complete. No similar problems were
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identified.
E8.4 (Closed) Violation 50-373/96005-06: 50-374/96005-06: Traversing Incore Probe Storage Not in Accordance with the UFSAR.
The team verified the corrective actions described in the licensee's response letter,
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dated September 24,1996, to be reasonable and complete. No similar problems were I
identified. Also, in accordance with licensee Restart Action Plan 4.2, step 1.0, the licensee conducted System Functional Performance Reviews on systems important to safe and reliable operation to ensure that those systems were designed and operated in
_conformance with the UFSAR.
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l E8.5 (Closed) Violation 50-373/96011-01: 50-374/96011-01: Failure to implement Design i
Controls on a Modification.
The team verified the corrective actions described in the licensee's response letter, dated December 20,1996, to be reasonable and complete. No similar problems were identified. Licensee Restart Action Plan 4.1 was initiated to upgrade the capability of the engineering department, including programmatic changes in the modification process to ensure that work products met acceptable quality standards.
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E8.6 (Closed) Violation 50-373/96011-10: 50-374/96011-10: Failure to Provide Acceptance
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Limits for Testing, ii-The team verified the corrective actions described in the licensee's response letter,
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dated December 20,1996, to be reasonable and complete. No similar problems were
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identified. The licensee conducted SFPRs on systems important to safe and reliable
- operation to ensure that acceptance limits in surveillance conformed to regulatory i
requirements, technical specifications, ASME Code requirements, and the UFSAR.
E8.7 (Closed) Violation 50-373/96011-11: 50-374/96011-11: Failure to Evaluate Adverse Trend on 2B RHR Heat Exchanger.
The team verified that the corrective actions described in the licensees response letier, dated December 20,1996, to be reasonable and complete. No similar problems were
~ identifiect As discussed in section E4.1, the licensee identified significant deficiencies in the Generic Letter (GL) 89-13 heat exchanger inspection program. At the end of the
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inspection, the licensee was in the process of revising the GL 89-13 program to address these deficiencies.
E8.8 (Closed) Violation 50-373/96011-13: 50-374/96011-13: Failure to Provide Documented Instructions When Removing Silt.
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The team verified the corrective actions described in the licensee's response letter, dated DecemLu 20,1996, to be reasonable and complete. No similar problems were identified.
E8.9 (Closed) Violation 50-373/96011-14: 50-374/96011-14: Failure to Meet Requirements of TS 4.7.1.3.C.
The team verified the corrective actions described in the licensee's response letter, dated December 20,1996, to be reasonable and complete. No similar problems were identified.
E8.10 (Closed) Violation 50-373/96011-17: 50-374/96011-17: Failure to incorporate Design Requirements into Calculation.
The team verified the corrective actions described in the licensee's response letter, dated December 20,1996, to be reasonable and complete. No similar problems were identified.
i E8.11 (Closed) Violation 50-373/96011-18: 50-374/96011-18: Failure to Update the UFSAR Following a 1989 License Amendment.
The team verified the corrective actions described in the licensee's response letter, dated December 20,1996, to be reasonable and complete. No similar problems were identified.
E8.12 (Closed) Violation 50-373/96013-05: 50-374/96013-05: Inadequate Freeze Seal Procedure and Engineering Request (ER) Process.
As discussed in inspection report 50-373/96013; 50-374/96013, LaSalle Maintenance Procedure GM-14, "Use of Freeze Jackets," failed to provide appropriate temperature limits. In addition, LaSalle Administrative Procedure (LAP) 1300-16, " Engineering Request (ER)," and LAP 1300-18, "Roadmap to Plant Design Changes," failed to provide sufficient controls to ensure timely completion of engineering work.
The team verified the corrective actions described in the licensee's response letter, dated February 27,1997, to be reasonable and complete. No similar problems were identified. In particular, the team verified that LAP-1300-16 had been revised to include
- improvements such as the use of work prioritization codes, explanation of various ER types, sequencing of responsibilities, and periodic ER review. The updated process,
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including prioritization and increased design and system engineer expectations, was discussed at engineering communications meetings on February 24, and March 3, 1997.
. Also, the team determined that management had placed an increased emphasis on ER prioritization. Specifically, licensee Restart Action Plan 4.2, step 8.0 included a review of the ER backlog to identify the ERs important to safe and reliable operation and to assess the timeliness of planned actions to determine whether resolution was required prior to Unit 1 and Unit 2 restart.
E8.13 (Closed) Violation 50-373/96019-01: 50-374/96019-01: Failure to Follow Procedures.
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The team verified the corrective actions described in the licensee's response letter, dated March 21,1997, to be reasonable and complete. No similar problems were identified.
E8.14 (Closed) Violation 50-373/96019-02: 50-374/96019-02: Failure to Review and Approve Nuclear Engineering Procedure 12-03LA, Revision 2.
The team verified the corrective actions described in the licensee's response letter, dated March 21,1997, to be reasonable and complete. No similar problems were identified.
E8.15 (Closed) Violation 50-373/97003-04: 50-374/97003-04: Failure to Perform RHR Discharge Pressure Alarm Surveillance.
The team verified the corrective actions described in the licensee's response letter, dated June 13,1997, to be reasonable and complete. No similar problems were identife' d.
E8.16 (Closed) Deviatien 50-373/95002-05: 50-374/95002-05: Inadequate Trending of Rosemount Transmitters.
The team verified the corrective actions described in the licensee's response letter,
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dated April 13,1995, to be reasonable and complete. No similar problems were I
identified.
E8.17 - (Closed) Unresolved item (URI) 50-373/93031-01: 50-374/93031-01: HFB-Type Circuit Breaker Failures.
I As discussed in inspection report 50-373/93031-01; 50-374/93031-01, the licensee l
L identified that Westinghouse HFB-type molded case circuit breakers with magnetic-only -
overload protection exhibited an abnormally high trip failure rate. At the end of the inspection, the root cause for these breaker failures had not been determined.
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During this inspection, the team noted that all Westinghouse HFB-type magnetic-only molded case circuit breakers had been replaced with HMCP-type breakers. Each
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HMCP breaker was tested satisfactorily prior to installation to ensure that it would be capable of tripping on fault currents. The root cause analysis indicated that poor work l
practices during original installation that resulted in metal shavings inside the breakers I
- caused the observed failures.
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E8.18 (Closed) URI 50-373/95003-01: 50-374/95003-01: Licensee Event Reoort (LER)
50-373/95009-01-Flood Protection Features Not Described in the UFSAR.
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As discussed in inspection report 50-373/95003; 50-374/95003 and LER 50-373/95009-01, the licensee identified an intemal flooding scenario which had not been identified in the UFSAR. Section 3.4.1.4, " Flood Protection Measures," of the UFSAR stated that due to the design of the circulating water system, flooding due to a circulating water pipe rupture was precluded and that interior flooding by gravity flow from the lake through a service water pipe rupture would be possible only within flood-protected areas. However, the licensee identified seismically-qualified circulating
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water and service water piping located outside the flood protected zones which, in the
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event of a pipe break, could result in flooding in the turbine building The licensee also determined that this flooding pathway, if allowed to progress, could substantially flood both reactor buildings and potentially effect safety-related equipment.
Subsequently, the licensee performed an evaluation and concluded that the pipe break scenario discussed above was not a credible event because even if a break was postulated to occur, flooding rates were so low that sufficient time existed for compensatory actions to isolate or limit the flooding prior to an adverse impact on safety-related equipment. In addition, the licensee determined that the Standard l
Review Plan did not require an analysis for seismically-qualified piping breaks.
Therefore, the licensee concluded that this flooding scenario was not an operability concem.
The licensee also identified that the watertight doors for the core standby cooling system (CSCS) pump rooms were designed to prevent flooding in only one direction. Further, L
the licensee determined that for Unit 1, flooding in either the Division 1 or Division 3 CSCS pump rooms would result in flooding of the Division 2 CSCS pump room; and for l
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Unit 2, flooding in the Division 3 CSCS pump room would result in flooding the Division 1 and Division 2 CSCS pump rooms.
During this inspection, the team verified that as discussed in LER 50-373/95009-01, modifi::ations were installed for the Unit 1 and Unit 2 CSCS pump room watertight doors j.
to assure flood protection from either direction. However, the team also noted that the licensee had identified additional flooding concems. These included a previously l.
unidentified flooding path through a Unit 2 heating, ventilation, and air conditioning
(HVAC) duct, plugged floor drains in the CSCS rooms that increased the risk of flooding,'
and a concem regarding the potential failure of the CSCS return piping to the ultimate
' heat sink that could raise the interior flood level above the maximum potential flooding elevation identified in the UFSAR.
_ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _
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To address these concerns, corrective actions included a modification to the Unit 2 HVAC duct, CSCS pump room floor drain flushing, and a revision to the UFSAR to reflect the as-built plant configuration. The team reviewed the corrective actions to address the new issues discussed above. No deficiencies were identified.
E8.19 (Closed) URI 50-373/95009-01: 50-374/95009-01: Turbine Building Positive Pressure Contrary to the UFSAR.
' As discussed in inspection report 50-373/95009; 50-374/95009, the licensee identified that the turbine building was operated routinely at a positive differential pressure although the UFSAR stated that the turbine building ventilation system functioned to
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maintain the turbine building at a negative differential pressure.
During this inspection, the team determined that modifications to the tuibine building ventilation (VT) system were being installed to ensure that a negative pressure was
- maintained in the turbine building during plant operation. These included the installation of additional turning vanes in the VT exhaust ducts to reduce flow resistance, the addition of bypass ducts around the exhaust heat extraction coils to reduce exhaust flow resistance, and the installation of recirculation bypass ducts from the discharge to the suction of the VT supply fans to reduce the volume of air entering the turbine building.
At the end of the inspection, the tuming vane and exhaust bypass duct modifications had been completed on both units with post-modification testing complete for Unit 1.
The installation of the bypass ducts associated with the Unit 1 VT supply fans was scheduled to be completed by June 13,1998, and for Unit 2 prior to startup.
The team conciuded that the corrective actions were appropriate.10 CFR 50, Appendix B, Criterion Ill, " Design Control," requires that measures shall be established to assure that the design basis is correctly translated into specifications, drawings, procedures, and instructions. The failure to adequately translate the design basis, l
which required that the turbine building be maintained at a negative pressure, into the
,
configuration of the plant was an example where the requirements of 10 CFR 50,
'
Appendix B, Criterion 111, were not met and was a violation. However, this licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy (NCV 50-373/98005-13; 50-374/98005-13).
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E8.20 (Closed) URI 50-373/96016-03: 50-374/96016-03: LERs 50-373/96011-00/01:
Pneumatic Air-Operated Valves With Less Than Designed Diaphragm Area.
I i
. As discussed in inspection report 50-373/96016; 50-374/96016, and LER 50-373/96011-00, the licensee identified 36 safety-related air-operated valves with an incorrect effective diaphragm area which could have potentially rendered the valves inoperable due to insufficient closing force. As discussed in LER 50-373/96011-01, following additional evaluation the licensee determined that the valve actuators had sufficient margin to perform their design function.
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During this inspection, the team reviewed the as-found valve actuator test data and L
verified that the actuators had sufficient margin to perform their design function. In
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addition, the team determined that the affected valves had passed previous local leak l
rate tests with the closing forces provided by the valve actuators.
At the end of the inspection, the licensee was in the process of modifying all affected j
valve actuators to increase the closing force to provide additional margin. The Unit 1
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modifications, including post-modification testing, had been completed. The Unit 2 modifications were also completed and post-modification testing was planned prior to l
Unit 2 restart.
E8.21 (Closed) URI 50-373/96018-01: 50-374/96018-01: Potential Operation of the Standby Gas Treatment (VG) System Outside the Design Basis.
l As discussed in inspection report 50-373/96018; 50-374/96018, to prevent the intake of cold air and freezing of station heating system piping, the licensee secured all normal ventilation systems and operated the VG system to maintain the secondary containment at a negative pressure. However, based upon a review of system configuration and operating procedures, the inspectors were concemed that the licensee was operating
_
the VG system outside of its design basis. The inspectors questioned whether the i
l licensee had evaluated system operating procedures and the effects of operating the
[
VG system as the primary ventilation system, and the long-term effects of continuous l
system operation on certain components such as charcoal and high efficiency particulate air filters.
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During this inspection, the team verified that the operation of the VG system had not been outside of its design basis. The team also verified that test results documented
'
that the high efficiency particulate air and charcoal filters met technical specification
requirements despite the increased service time. The team determined that the l
environmental qualification life of affected components, such as relays, had been i
[
administratively reduced to compensate for the increased system operating time. The L
team verified that the system and components were properly analyzed, tested, and maintained to ensure VG system operability, i
E8.22 (Closed) URI 50-373/97003-05: 50-374/97003-05: Diesel Generator (DG) Fuse Sizing
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lasue.
~ As' discussed in inspection report 50-373/97003; 50-374/97003, during the investigation regarding a DG ventilation exhaust damper failure, the licensee identified that a 1/16 ampere fuse in lieu of a required 1/10 ampere fuse was installed in the 1 A DG (
ventilation system. Unresolved item 50-373/97003-05; 50-374/97003-05 was opened l
pending a review of the licensee's investigation regarding the impact of the incorrect fuse size on DG system operability and the status of fuses in the other DG ventilation control systems.
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During this inspection, the team reviewed the results of the investigation and determined I
that the failure of the exhaust damper to open was caused by a crimped control wire.
The blown fuse and the testing following fuse replacement indicated that the fuse protected the equipment as required.
The licensee inspected other damper control circuits and found three additional
controllers with incorrectly sized fuses. As discussed in section E4.1, during a June 1997 audit, the licensee identified significant deficiencies in the implementation of the fuse control program.
E8.23 / Closed) URI 50-373/97006-08: 50-374/97006-08: Review of Klockner-Moeller (K-M)
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Relay Failures.
i As discussed in inspection report 50-373/97006; 50-374/97006, on April 9,1997, the j
electrical power supplied to the Unit 0 DG fuel oil transfer pump was secured, however, the power supply failed to automatically transfer as required. Subsequently, the licensee determined that the power supply transfer failure was caused by a degraded K-M "AR1" relay in the Unit 0 DG control circuitry. Further analysis revealed that
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significant crystal deposits had formed within the interior of the relay preventing proper
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relay operation. The formation of the crystal deposits was attributed to relay coil
offgassing.
The licensee had identified a similar event on February 10,1994, when the primary containment water chiller pump failed to operate. The troubleshooting and failure analysis revealed that the K-M "CR" relay had failed due to a buildup of organic crystal deposits within the interior of the relay preventing proper relay operation. The corrective
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actions at that time included a revision to the environmental qualification (EQ) program i
procedures to inspect the K-M relays for signs of coil degradation.
The team examined the K-M relay documentation, reviewed the associated corrective actions, and noted the following:
)
A total of 112 K-M motor control centers (MCCs) were used in either EQ, i
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safety-related (SR), important to safety (ITS) or nonsafety-related (NSR)
applications (4 MCCs in Unit 0,56 MCCs in Unit 1, and 52 MCCs in Unit 2). The 112 MCCs contained about 2500 K-M Model DIL 00Lb-22-NA universal relays.
Twenty of the K-M MCCs were designated as SR/EQ and contained a total of 677 K-M Model DIL univemal relays (411 SR/EQ relays required inspection and 4 SR relays were previously replaced,116 were in spare cubicles, 50 were downgraded to ITS, 38 were downgraded to NSR and 58 were to be deleted in association with the MSIV leakage control modification). Twelve of the SR/EQ MCCs (6 per unit) were included in the EQ program and contained 330
EQ-designated K-M Model DIL universal relays.
The failed EQ-designated "AR1" relay for the Unit 0 DG fuel oil transfer pump
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had not been periodically inspected as required by the EQ inspection program.
'Although previous corrective actions were implemented to inspect the K-M relays
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for signs of coil degradation, no instructions existed which directed maintenance to inspect K-M relays physically located in the rear cubicles of K-M MCCs. The
"AR1" relay was part of the control circuit located in MCC 135Y-2, cubicle F3, but was physically located in the rear of cubicle E5 and from September 29,1983, to August 20,1997, had not been periodically inspected as required by the EQ inspection program. Subsequently, the licensee added the inspection of K-M relays in these cubicles to the inspection program.
10 CFR 50 49(a), " Environmental Qualification of Electric Equipment important to Safety for Nuclear Power Plants," required that licensees sha!l establish a program for qualifying the electrical equipment important to safety, including safety-related and nonsafety-related electric equipment relied upon to remain functional during and following design basis events, and certain post-accident monitoring equipment. The failure to include instructions to inspect safety-related EQ-designated K-M relays physically located in the rear cubicles of K-M MCCs was an example where the requirements of 10 CFR Part 50.49(a) were not met and was a violation. However, this licensee-identified and corrected
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violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy (NCV 50-373/98005-14; 50-374/98005-14).
The team determined that an inspection and replacement program had been
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implemented for the K-M relays in conjunction with the EQ and preventive i
maintenance (PM) programs and that all EQ, SR and ITS K-M relays would i
either be inspected or replaced and tested prior to startup. In particular, the i
licensee revised LES-GM-109," Inspection of 480V Klockner-Moeller Motor Control Center," to inspect K-M relays located in the rear cubicles of the K-M MCCs and to require a visual inspection of the K-M relays for relay coil insulation degradation or crystal growth.
The K-M PM program relay replacement criteria required that all EQ-designated
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K-M relays be replaced and SR and ITS designated K-M relays be replaced if the K-M relay exhibited any sign of crystal formation or when the relay coil was discolored and cracked or if the relay failed to pass the inspection criteria of 1 LES-GM-109 (i.e.,' no damaged parts or other abnormal conditions, free -
movement of armature and proper opened / closed contact operation checked using an ohmmeter). During a review of the K-M PM program inspection documentation, the team identified that due to a lack of attention-to-detail, an ITS-designated K-M relay located in MCC 132Y-2; cubicle B1, had been identified by the licensee as containing crystal deposits that met the K-M PM program relay replacement criteria on August 23,1997, but had not been replaced as required. As a result, on April 17,1998, the licensee initiated PlF L1998-02934 and generated AR 980024645 to replace the relay during the K-M PM program inspections prior to Unit i restart. In addition, a review was performed on all relays addressed by the K-M PM program completed inspections. No additional examples of inadequate K-M relay replacements were identified.
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10 CFR 50, Appendix B, Criterion XVI, " Corrective Actions," requires that
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measures shall be established to assure that conditions adverse to quality, such
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as failures, malfunctions, deficiencies, and nonconformances are promptly I
l identified and corrected. The failure to include and follow the relay replacement
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criteria instructions for ITS-designated K-M relays was an example where the requirements of 10 CFR 50, Appendix B, Criterion XVI were not met and was a l
violation (50-373/98005-15; 50-374/98005-15).
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The K-M relays did not exceed their EQ-qualified life. The licensee stated that
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based upon testing as contained in report SEAG 97-000374, " Determination of Cause for Crystallization in the Klockner-Moeller (K-M) Universal Relays,"
Revision 0, dated September 26,1997, the cause of crystallization in the K-M universal relays was not an end-of-life issue, but was due to high temperature.
The high temperature caused the relay coil vamish and/or the coil wrap material to evaporate and deposit residue (crystals)inside the relay. The high temperature was due to continuous elevated operating voltage at about 132 VAC (actual station measured voltage). The report stated that the temperature rise in the relay was about 16.5"F higher than that used during the initial EQ evaluation.
The report stated the present qualified life did not reflect the true qualified life of the K-M relays, since the appropriate temperature rise was not used in the qualified life evaluation. Based upon a revised calculation, the licensee concluded that the K-M Model DIL universal relay was qualified for 19.6 years at 132 VAC at an aggregate ambient temperature of 96*F.
The team was initially concerned that the K-M PM program inspection frequency
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interval of every 3 years was inadequate to protect the station from the K-M relay crystal growth failure problem. The licensee stated that based upon testing, as identified in Nutherm Test Report 7938-TR1, "Klockner-Moeller Thermal Aging Test for Kiran Consultants, Inc.," Revision 1, dated September 24,1997, the test results indicated there was at least 11 years of service life remaining following the initial formation of crystal growth.
The K-M MCC program inspection status as of April 30,1998, was as follows:
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K-M Relay FM Program Inspection Status
,
[# of SR Relays)
[# of ITS Relays)
[#of Relays)
UNIT
[# insp/ Tested]
[# insp/ Tested]
[# Replaced]
[# Replaced]
[# Replaced]
O
[0][NA]
[0] [NA)[NA]
[0] [NA][NA]
[163][163]
[48][48][30]
[149][149][86]
[167][39]
[33][28][13]
[146] [10][5]
Total
[330][202]
[81] [76][43]
[295][159][91]
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The team concluded that although some concerns were initially identified with the K-M relay testing methodology and the PM inspection and replacement program, the licensee had provided adequate resolution.
E8.24 (Closed) Insoection Follow un item (IFI) 50-373/94017-02: 50-374/94017-02: System Engineering involvement in the Electronic Work Control System Process.
As discussed in inspection report 50-373/94017; 50-374/94017, the inspectors identified that system engineering involvement in the electronic work control system process did j
not emphasize post-maintenance testing and work history review until after work was
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performed. In addition, there appeared to be no explicit requirement for system engineers to review work requests for root cause identification prior to performing maintenance activities.
During this inspection, the team noted that licensee Restart Action Plan 4.2, step 8.0 included a review of the action request (AR) and work request (WR) backlog to identify the ARs and WRs important to safe and reliable operation and to assess the timeliness of planned actions to determine whether resolution was required prior to restart. In addition, the team verified that system engineers routinely reviewed work requests for root causes prior to ma ntenance and that overall, system engineers were knowledgeable of the outstanding work requests associated with their assigned systems.
E8.25 (Closed) IFl 50-373/95004-03: 50-374/95004-03: System Engineering Program Lacked Standards and Expectations.
As discussed in inspection report 50-373/95004; 50-374/95004, the ability of system engineering personnel to improve plant material condition was characterized as inconsistent and weak. In addition, system walkdowns were not being adequately performed and documented, and deficiencies were not being identified. System engineering notebooks were also found to be out of date and lacked current trending data. A lack of defined management expectations and standards for system engineers was identified as a significant contributing factor.
During this inspection, the team noted that licensee Restart Action Plan 4.1 was j
specifically initiated to upgrade the capability of the engineering department and i
included programmatic changes to ensure that work products met established quality standards. In addition, the team reviewed the Comed System Engineering Handbook, Revision 1, dated February 19,1998, and verified that management expectations and standards for system engineer performance was clearly defined and documented. The team verified that overall, system engineering notebooks were current and provided useful trending information and data. Although many material condition issues were
.
identified during the inspection, based upon the number of significant problems that had been identified recently, the team concluded that the ability of system engineers to identify material condition problems had substantially improved.
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E8.26 (Closed) IFV 50-373/95007-01: 50-374/95007-01: Group 1 Isolation and Subsequent
- Reactor Scram.
As discussed in inspection report 50-373/95007; 50-374/95007, on August 16,1995, a Unit 1 electrical protection monitoring assembly breaker tripped open which resulted in the loss of a reactor protection system bus. This caused the reactor building ventilation system to isolate and resulted in the actuation of the main steam isolation valve (MSlV)
isolation logic, which in turn caused a reactor scram despite operator actions to bypass the isolation logic.
During this inspection, the team determined that the licensee initiated an MSIV isolation
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logic modification to resolve this issue. At the end of the inspection, modification installation and testing activities were in progress and were planned for completion prior to Unit 1 and Unit 2 restart.
E8.27 (Closed) IFl 50-373/96006-02: 50-374/96006-02: Battery Charger Oscillations.
As discussed in inspection report 50-373/96006; 50-374/96006, on June 3,1996, the Unit 1, Division 1,125 volt direct current (VDC) battery charger experienced unexpected current and voltage oscillations.
During this inspection, the team reviewed the root cause investigation report and determined that the oscillations did not recur following the installation of diagnost;c testing equipment. The team also noted a root cause investigation report for a similar event which occurred on July 17,1996. However, similar to the June 3,1996 event, the oscillations ended prior to the performance of testing to isolate the source.
At the end of this inspection, battery charger current and voltage oscillations had not recurred. In the event that oscillations do recur, the licensee had plans and procedures in place to troubleshoot and repair the charger.
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E8.28 (Closed) IFl 50-373/96006-03: 50-374/96006-03: RMS-9 Breakct Trip Device Failure.
As discussed in inspection report 50-373/96006; 50-374/96006, on May 29,1996, the licensee identified that General Electric (GE) RMS-9 overcurrent trip devices on four 480 VAC GE breakers were not functioning properly, in particular, the instantaneous.
l trip function was tripping the circuit breaker prematurely. The failed breakers were used
' in the control room and auxiliary electric equipment room heating, ventilation, and air conditioning systems. The licensee promptly replaced these breakers with operable
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breakers. The licensee conducted testing on two failed RMS-9 unit circuit boards and
identified a thin film of unknown material around the sliding contacts of the circuit board that was causing the failures.
i NRC Information Notice (IN) 96-62, " Potential Failure of the Instantaneous Trip Function of General Electric RMS-9 Programmers," was issued on November 11,1996, as a
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result of LaSalle's findings. The team reviewed IN 96-62 and 10 CFR Part 21
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notification SC96-04, "Possible Failure of GE Type RMS-9 Overcurrent Trip Device Programmers With Instantaneous Trip Functions," which stated that the root cause of the problem was the presence of a polyester epoxy film on the intemal switch contacts which was caused by insufficient curing of the polyester epoxy by the vendor during final assembly.
As part of their coresctive actions, the licensee revised maintenance and surveillance procedures to require inspection of the RMS-9 switches prior to and following breaker testing as outlined in the GE notification. In addition, training was provided to Electrical Maintenance Department personnel on this issue. The team reviewed these corrective actions and had no additional concerns.
EB.29 (Clossd) IFl 50-373/96006-04: 50-374/96006-04: Five Licensee-ldentified UFSAR Discrepancies.
As disce; ed in inspection report 50-373/96006; 50-374/96000, the licensee identified five UFSAR discrepancies. During this inspection, the team rrsviewed the corrective actions and determined that the issues were minor in nature and that the corrective actions were appropriate.
E8.30 (Ocen) IFl 50-373/97013-01: 50-374/97013-01: Review of inforrnation Notice 87-10.
As d' iscussed in inspection report 50-373/97023; 50-374/97023, the inspector reviewed the response to information Notice (lN) 87-10 related to the potential for waterhammer in the RHR system if a Loss-Of-Coolant-Accident (LOCA) concurrent with a Loss-Of-Offsite-Power were to occur while the system was aligned for suppression pool cooling.
The inspector reviewed the watorhammer analysis prepared by Sargent 8 Lundy to address Ms concem. The report concluded that although a waterhammer would occur, the RHR system would maintain its pressure boundary integrity, structural stability, and functional capability during the event. However, the inspector noted that plastic deformation and ovalization cf system piping was expected to occur, During this inspection, the team determined that in accordance witn Section 6.13,
" Piping and Pipe Support Requirements," of Generic Letter 91-18, " Resolution of Degraded and Nonconforming Conditions," upon the discovery of a nonconformance with piping and pipe supports, licensees may use the enteria in Appendix F of Section 111 of the ASME Code for operability determinations. Article F-1000 of Appendix F of Section ill of the ASME Code permitted pross general deformations of piping with some consequent loss of dimensionst staoiiity and damage (i.e., plastic deformation) requiring repair and removal of the component from service pruv!ded the structura; integrity of the
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piping is maintained.
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l in addition, following further discussions with LaSalle personnel, the licensee provided a
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March 24,1998, evaluation which concluded that the probability of the scenario l,
described by IN 87-10 was below the threshold considered by the NPC for inclusion in L
the design bases. The evaluation referenced a number of documents to substantiate
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this position, including the Standard Revis*:* Plan, Regulatory Guides, and industry guidance and standards.
At the end of the inspection, the team questioned whether the use of probability
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l calculations to justify exclusion of this event from the design basis was appropriate.
l This question has been forwarded to the Office of Nuclear Reactor Regulation for
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technica! review. Inspection follow up item 50-373/97013-01; 50-374/97013-01 will l
remain'open pending the results of that review.
l E8.31 (Closed) LER 50-373/96016-00: Hot Short Could Result in Damage to Motor-Operated
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Valves (MOVs).
As discuased in LER 50-373/96016-00, NRC Information Notice 92-18 described a l
concem regarding potential damage to MOVs due to a postulated hot short.
L Specifically, if a hot short occurred in such a way as to bypass the mechanical
L protection (i.e., torque switch or limit switch) of a valve while energizing tne opening or
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closing cdl, the valve may be damaged. Depending on the nature of the damage, an operator may not be able to position the MOV manually or from the remote shutdown j
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panel.
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Subsequently, the licensee identified that a hot short due to a postulated control room
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- fire at LaSalle would result in mechanical damage to MOVs required to achieve and
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maintain hot shutdown. A total of 15 valves for Unit 1 and 15 valves for Unit 2
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associated with the RHR and reactor c are isolation cooling system were identified as susceptible to the problem.
The licensee performed a root cause evaluation and determined that the problem was
' due to a failure to recognize the potential for mechar.ical valve damage caused by a hot j
short when the safe shutdown analysis was originally performed.
~
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As discussed in the LER, the licensee planned the following corrective actions to address the issue:
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A design change was initiated for each of the affected valves except the RHR a
pump minimum flow valve, to eliminate the potential for mechanical damage due to a control room fire hot short.
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A procedure change was initiated to address the potential mechanical damage
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- (in the open position only) fo the RHR pump minimum flow valve. The procedure
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change was to provide instructions to close a downstream valve as an altemative to closing the minimum flow valve.
During this inspection, the teun verified that the design changes had been completed or planned on the affected MOVs to eliminate the susceptibility to hot shorts. In addition,
- the team verified that procedures had been revised as appropriate.
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The NRC issued a letter dated May 9,1998, which granted enforcement discretion in accordance with Section Vll.B.2, " Violations identified During Extended Shutdowns or Work Stoppages," of the " General Statement of Policy and Procedures for NRC Enforcement Actions,"(Enforcement Policy), NUREG-1600. As a result, the NRC will not issue a Notics of Violation or propose a civil penalty in this case.
E8.32 (Closed) LER 50-373/96019-01/02/03: ASME Section XI IST Anomalies Due to Personnel Error.
As discussed in LER 50-373/96019-01/02/03, on October 7,1996, the licensee initiated a comprehensive self-assessment of the IST program. The IST program assessment focused on verifying that the required systems and their components were being tested in accordance with regulatory requirements, technical specifications, and ASME Codes.
Following that review, significant deficiencies were identified in the program and included: (1) required systems not in the program, (2) pump vibration acceptance limits
. not correctly revised to updated ASME Code criteria, (3) valves not manually cycle tested as required. (4) position indication testing not documented, and (5) valve stroke time measurement deficiencies.
During this inspection, the team verified that the components not included in the IST program that were identified by the licenses during self-assessment activities were incorporated into the revised IST program. Also, as part of the corrective actions for this LER and licensee Restart Action Pian 4.2, step 3.8, an IST basis document was developed as discussed in Section E4.1 of this report. As discussed in section E4.1, although a number of minor errors were identified, the team did not identify any major
concems with the generic aspects of the revised IST program.
The NRC issued a letter dated May 9,1998, which granted enforcement discretion in accordance with Section Vll.B.2, " Violations identified During Extended Shutdowns or Work Stoppages," of the " General Statement of Policy and Procedures for NRC Enforcement Actions," (Enforcement Po: icy), NUREG-1600. As a result, the NRC will not issue a Nciice of Violation or propose a civil penalty in this case.
E8.33 (Closed) LER 50-373/96022-00- Thermal Overload Protection Devices for RHR Valves Not Bypassed.
As discussed in the subject LER, the licensee identified that the design of the thermal overload bypass circuits for 16 RHR system valves were not in conformance with the requirements of UFSAR section 6.3.2.2.13 and TS 3.8.3.3. Specifically, the UFSAR and TSs require that the thermal overload protection devices for these MOVs be bypassed whenever they are required to perform a safety-related fu1ction under accident conditions. However, the licensee identified that the thermal overload p?otection devices for these valves were only bypassed while the automatic actuation signal was present.
, Therefore, when the automatic signal was removed by a manual override signal or the contro! circuit, the thermal overload bypass signal was also rernoved.
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The licensee performed a root cause investigation and determined that the thermal overload bypass logic was installed in Unit 1 and Unit 2 prior to initia! startup and was i
not in accordance with the existing design requirements.
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To evaluate the safety significance of the event, the licensee determined that NRC
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Regulatory Guide 1.106, " Thermal Overload Protection For Electric ",otors on Motor-Operated Valves," prescribed two methods for ensuring that thermal overload protection devices for safety-related MOVs did not prevent the valve from perfonning its
safety function. Method 1 required that the thermal overload protection device be
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bypassed under accident conditions. As an alternative, however, Method 2 required j
that the thermal overload protection device trip setpoint be established with all
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uncertainties resolved. The li:ensee determined that although the requirements of Method 1 were not met, a review of the calculations for the existing thermal overload protection device settings for the affected valves indicated that the established trip setpoints met the requirements of Method 2. Therefore, the licensee concluded that the
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thermal everloads would not have resulted in an inadvertent trip during required valve operation. As part of their corrective actions, the licenree planned to perform modifications on the affected valves to comply with the requirements of the UFSAR and TSs.
During this inspection, the team verified that the licensee had completed modifications to the thermal overload bypass circuits for all the affected valves. The team verified that post-modification testing had also been successfully performed.
E8.34 (Closed) t FR 50-373/97005-00/01/02/03: Potential Loss of Both Trains of the Standby Gas Treatment (VG) System.
As discussed in LER 50-373/97005-00/01/02, during a review of the draft Improved Technical Specifications, the licensee questioned whether the VG system would be over-pressurized in the event of a LOCA during the purging or venting of the drywell or the suppression chamber. The isolation damper between the VG filter train and the primary containment purge and vent (VQ) system v as rated for a maximum differential pressure of 2 pounds per square inch differential (psid). The effect of a LOCA while operating the VQ systom was evaluated in the UFSAR. In that response, the pressurization effect on the VG system was only evaluated with the 2-inch bypass valve open. However, the operating procedure for venting and purging containment opened the 26-inch main purge valves, instead of the 2-inch bypass valves. If a LOCA occurred with the main purge valves opened, the pressure at the VG isolation damper would t,e much higher than 2 psid. Since the VG trains were cross-connected to both trains of VQ, the excess diMerential pressure experienced during s LOCA on either unit could result la the loss of both trains of VG.
/nother concem identified during the review was the potential to bypass the pressure suppression pool function during a LOCA. Plant operating procedures allowed
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simultaneous purging and venting of the drywell and suppression chamber. If a LOCA l
occurred while both the drywell and suppression pool was being purged or vented, a p
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o bypass path would be created through both the 26-inch exhaust paths and the 8-inch nitrogen supply lines. These paths would reduce or eliminate the pressure suppression function of the suppression pool.
The licensee conducted a root cause investigation and determined that the original design of the VQ system was that the 26-inch main purge valves would not be opened with the unit at power. In addition, with regard to the bypass path, the licensee determined that although the UFSAR recognized that the drywell and suppression pool purge and vent valves could not be opened simultaneously at power, administrative controls were never incorporated into the technical specifications or plant procodures to prohibit the condition.
I The licensee reviewed the safety significance of this event and concluded that since both trains of the VG system were directly connected to the VQ system of both units, it was probable that in the event of a LOCA during containment venting at power, the pressure in the VQ and VG piping would exceed the 2 psid design pressure at the VG system inlet dampers and could result in a loss of both trains of the VG filter function.
>
The loss of the VG filter function would result in increased radiological dose consequences at the site boundary.
During this inspection, the team determined that to address the VG system over-pressurization concems, the licensee installed normally closed isolation valves to prevent a LOCA from adversely impacting the VG t.ptem. As discussed in section E1.1, the team reviewed this modification, which included a review of the modification package, post-modification testing, and system walkdowns. No deficiencies were identified. In addition, to ensure that the technical specifications did not allow the simultaneous opening v' Ooth the drywell and suppression chamber isolation valves, the l
licensee obtained an amendment to TS 3.6.1.8, "Drywell and Suppression Chamber j
Purge System," to prohibit the configuration.
The NRC issued a letter dated May 9,1998, which granted enforcement discretion in accordance with Section Vll.B.2, " Violations identified During Extended Shutoowns or Work Stoppages," of the " General Statement of Policy and Procedures for NRC l
Enforcement Actions,"(Enforcement Policy), NUREG-1600 for this issue. As a result, the NRC will not issue a Notice of Violation or propose a civil penalty in this case.
,l E8.35 (Ooen) i FR 50-373/97015-00: Diversion of Low Pressure Coolant Irdection (LPCI) Flow to the Suppression Pool.
As discussed in LER 50-373/97015-00, the licensee identified that if the RHR test return valve was in the process of being manually opened such as during surveillance testing, and a simultaneous emergency core cooling system (ECCS) actuation occurred, the
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manual overnde logic would be activated and the valve would not automatically close.
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Section 6.3.2.8, " Manual Actions," of the UFSAR stated that with regard to the ECCS
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. system, 'the initiation of the ECCS is completely automatic. No operator action is
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l assumed for at least 10 minutes after initiation." However, with the valve in the open f
position, and barring manual action to re-position the valve c Osed, LPCI flow would be e6
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diverted to the suppression pool, bypassing the reactor vessel. The diversion of LPCI flow to the suppression pool (due to an ECCS actuation while opening the RHR test i
return valve) in combination with the loss cf one of the other divisions wii; result in a condition with fewer avaltable systems than assumed in the accident analysis. The RHR test return valve 'wa: opened during full flow testing and during operation in the suppression pool cooling mode of RHR.
During this inspection, the team 'Hermined that based on the low probability of the condition occurring (since the valve is estimated to be in the procecs of being opened only 10 minutes pu year), the licensee considered the event to be outside their design basis.
At the end of the inspection, the team questioned whether the use of probability to justify exclusion of this event from the design basis was appropriate. This question has been forwarded to the Office of Nuclear Reactor Regulation for technical review.
Licensee Event Report 50-373/97015-00 will remain open pend:ng the results of that review.
E8.36 (Closed) LER 50-373/97019-QQ: Post LOCA Hydrogen Analyzers Do Not Monitor To i
10 Per.,ent.
As discussed in LER 50-373/97019-00, the licensee idenufied that although the UFSAR required that the primary containment hydrogen concentration be analyzed and recorded up to 10 percent hydrogen by volume, the hydrogen analyzers had only been calibrated to 4 percent hydrogen by volume.
The licensee subsequently determined that the root cause for this event was ineffective design control for increasing the capability to monitor the primary containment hydrogen concentration from 4 percent to 10 percent during initial plant construction.
As part of their corrective actions, the licensee olanned to revise the calibration method of the hydrogen analyzers prior to restart of either unit. In particular, the licensee planned to calibrate the analyzers to the full range of 10 percent as spe'ified in the UFSAR. In addition, the licensee planned to revise the applicable prowdures which were utilized to calibrate the analyzers and review the applicable technical specifications.
The team verified that Technical Specification Table 4.3.7.5-1 had been revised to
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reflect the correct hydrogen concentration requirements. In addition, the team verified that LOP-CM-02, "Startup, Operation, and Shutdown of Post LOCA Primary Containment Atmosphere Hydrogen and Oxygen Monitoring System," had been revised to reflect the correct calibration gas concentration to conform with the TSs and UFSAR.
The NRC issued a letter' dated May 9,1998, which granted enforcement discretion in accordance with Section Vll.B.2, " Violations identified During Extended Shutdowns or Work Stoppages," of the " General Statement of Policy and Procedures for NRC
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Enforcement Actions,"(Enforcement Policy), NUREG-1600. As a result, the NRC will not issue a Notice of Violation or propose a civil penalty in this case.
E8.37 (Closed) LER 50-373/97030-00 Containment integrated Leak Rate Test (ILRT) Error Due to Failure to Track an Issue to Resolution.
As discussed in inspection report 50-373/97018: 50-374/97018, the inspector reviewed this LER which remained opened pending a review of a channel weld and liner plug evaluation by the Office of Nuclear Reactor Regulation (NRR).
During this inspection, the team determined that NRR reviewed the proposal to leave certain leak chase channels plugged during the performance of the containment ILRT and found it to La reasonable.
10 CFR 50, Appendix E, Criterion XVI, * Corrective Actions,' requires that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, and nonconformances are promptly identified and corrected.
The failure to track, follow up, and resolve this iceue when it was identified in 1981 was an example where the requirements of 10 CFR 50, Appendix B, Criterion XVI were not met and was a violation. However, this licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy (NCV 50-373/98005-16; 50-374/98005-16).
VI. Management Meeting i
X1 Exit Meeting Summary
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The team presented the results of these inspections to licensee management at an exit meeting on April 21,1998. The licensee acknowledged the findings presented.
The team asked the licensee if any materials examined during the inspection should be considered proprietary. No proprietary information was identified.
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_________ _____ _ _ _ _ _ _ _ _ _ _ _
e PARTIAL LIST OF PERSONS CONTACTED Comed L. Bukantis, System Engineering G. Campbell, Site Engineering Manager E. Connell, Design Engineering Supervisor D. Henry, System EngineeJng M. Hill, Engineering Assurance Group Manager D. Kapinus, System Engineering T. O'Connor, Station Manager R. Palmieri, System Engineering Supervisor J. Pollock, Support Engineering Supervisor H. Pontius, Acting Regulatory Assurance Manager W. Riffer, Quality and Safety Assessment Manager INSPECTION PROCEDURES USED inspection Procedure 37001, "10 CFR 50.59 Safety Evaluation Program" inspection Procedure 37550, " Engineering" Inspection Procedure 37551, "Onsite Engineering"
' inspection Procedure 37700, " Design Changes and Modifications" inspection Procedure 61726, " Surveillance' Observations" Inspection Procedure 73756, " Inservice Testing of Pumps and Valves" Inspection Procedure 92700, "Onsite Follow up of Written Reports of Non-Routine Events" Inspection Procedure 92701, " Follow up" Inspection Procedure 92702, " Follow up of Corrective Actions for Violations" Inspection Procedure 92703, " Follow up - Engineering" inspection Procedure 93801, " Safety System Functional Inspection" l
inspection Procedure 93807, " Systems-Based instrumentation and Control Inspection" Inspection Procedure 93809, " Safety System Engineering Inspection" i
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e ITEMS OPENED, CLOSED, AND DISCUSSED i
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. 50-373/98005-01;50-374/98005-01 NCV Failure to Revise LEP-GM-137 50-373/98005-02;50-374/98005-02 NCV-RCIC Breaker Magnetic Trip Setting Error l
50-373/98005-03;50-374/98005-03 VIO Fire Loading Calculation Errors 50-373/98005-04;50-374/98005-04 VIO DG A!r Box Drain Unauthorized TALT
50-373/98005-05;50-374/98005-05. lFI Battery Intercell and interrack Resistances
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50-373/98005-06;50-374/98005-06 NCV EDG Rollup Door Curb Gasket Degradation 50-373/98005-07;50-374/98005-07 NCV Unsecured Handrail Cart 50-373/98005-08;50-374/98005-08 VIO Failure to Provide Annual 10 CFR 50.59 Report-l 50-373/98005-09;50-374/98005-09 NCV HPCS System Testing Deficiencies 50-373/98005-10;50-374/98005-10 NCV Safety Relief Valve Leakrate Testing Error 50-373/98005-11;50-374/98005-11 IFl GL 89-13 Program Deficiencies 50-373/98005-12;50-374/98005-12 VIO Fuse List Discrepancies 50-373/98005-13:50-374/98005-13 NCV Turbine Ventilation System Design Error -
50-373/98005-14;50-374/98005-14 NCV Failure to inspect K-M Relays 50-373/98005-15;50-374/98005-15 VIO K-M Relay Replacement Error
50-373/98005-16;50-374/98005-16 NCV Containment Integrated Leak Rate Test Error i
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50-373/93031-02:50-374/93031-02 VIO Failure to Take Action For 4.0kV & 6.9 kV Breakers 50-373/93300-01;50-374/93300-01 VIO Inadequate Actions to Address VR Problems 50-373/96005-01:50-374/96005-01 VIO Degraded RCIC Support and Undersized Pump 50-373/96005-06;50-374/96005-06 VIO Failure to Document Determination for Storing TIP 50-373/96011-01;50-374/96011-01 VIO Failure to implement Design Controls 50-373/96011-10;50-374/96011-10 VIO Failure to Provide Acceptance Limits forTesting 50-373/06011-11:50-374/96011-11 VIO Failure to Evaluate 2B RHR Heat Exchanger 50-373/96011-13;50-374/96011-13 VIO Failure to Provide Instructions When Removing Silt 50-373/96011-14;50-374/96011-14 VIO Failure to Meet Requirements of TS 4.7.1.3.C 50-373/96011-17;50-374/96011-17 VIO Failure to incorporate Design into Calculation 50-373/96011-10:50-374/96011-18 VIO Failure in Update UFSAR Following Amendments 50-373/96013-05;50-374/96013-05 VIO Inadequate Freeze Seal and ER Procedures
50-373/96019-01:50-374/96019-01 VIO Failure to Follow Procedures j
i 50-373/96019-02;50-374/96019-02 VIO Faiiure to Review and Approve NEP-12-03LA 50-373/97003-04;50-374/97005-04 VIO Failure to Perform Instrument Surveillance Test 50-373/95002-05;50-374/95002-05 DEV Trending Rosemount Transmitters'
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- 50-373/93031-01;50-374/93031-01 URI Results of Testing for 250 Volt DC Magnetic Circuit 50-373/95003-01;50-374/95003-01 URI Flood Protection Features Not Described in UFSAR 50-373/95009-01;50-374/95009-01 URI Positive Pressure in the Turbine Building 50-373/96016-03;50-374/96016-03 _ URI Air-Operated Valves With Undersized Actuators
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50-373/96018-01;50-374/96018-01 URI.
Use of VG System to Maintain RB Pressure l
50-373/97003-05;50-374/97003-05 URI DG Ventilation Fuse Sizing issue L
50-373/97006-08;50-374/97006-08 URI Review of K-M Relay Failures b
' 60-373/94017-02;50-374/94017-02 IFl System Engineering involvement in EWCS
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0-50-373/95004-03;50-374/95004-03 IFl System Engineering Program Lacked Standards 50-373/95007-01;50-374/95007-01 IFl Group 1 Isolation and Reactor Scram 50-373/96006-02;50-374/06006-02 IFl Battery Charger Oscillations 50-373/96006-03;50-374/96006-03 IFl RMS-9 Breaker Trip Device Failure 50-373/96006-04;50-374/%006-04 IFl Disparities Batween UFSAR and Plant Procedures 50-373'95009-01 LER Flood Protection Features Not Described in UFSAR 50-373/96011-00 LER Air-Operated Valves With Undersized Actuators 50-373/96011-01 Air-Operated Valves With Undersized Actuators
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50-373/96016-00 c.crt Hot Short Could Result in Damage to MOVs 50-373/96019-01 LER RHR Containment isolation Valves Not Tested 50-373/96019-02 LER ASME Section XI IST Ano.mlies
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50-373/96019-03 LER ASME Section XI IST Anomalies 50-373/96022-00 LER Thermal Overloads for RHR Va'ves Not Bypassed 50-373/97005-00 LER Potential Loss of Both Trains of VG 50-373/97005-01 LER Potential Loss of Both Trains of VG 50-373/97005-02 LER Potential Loss of Both Trains of VG 50-373/97005-03 LER Potential Loss of Both Trains of VG 50-373/97019-00 LER Hydrogen Analyzers Do Not Monitor To 10 Percent 50-373/97030-00 LER Containment ILRT Error Discussed 50-373/97013-01;50-373/97013-01 IFl Review of information Notice 87-10 50-373/97015-00 LER Diversion of LPCI Flow to Suppression Pool
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l LIST OF ACRONYMS USED l
AR Action Request
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ASME Amcrican Society of Mechanical Engineers BTU
' British Thermal Unit CFR.
Code of Federal Regulations Comed
. Commonwealth Edison Company CS Cold Shutdown Justification CSCS Core Standby Cooling System DCP Design Change Package DEV Deviation DG Diesel Generator DRS Division of Reactor Safety E&TS Engineering and Technical Support
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EAG Engineering Assurance Group ECCS Emergency Core Cooling System EQ Environmental Qualification ER Engineering Request ERRT Engineering Rapid Response Team ESF Engineered Safety Feature GE General Electric GL Generic Letter gpm gallons per minute-
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HVAC Heating, Ventilation, and Air Conditioning IEEE Institute of Electrical and Electronic Engineers IFl Inspection Follow up Item ILRT Integrated Leak Rate Test IN information Notice j
ISA Independent Ssfety Assessment i
IST Inservice Testirg ITS Important To Safety K-M Klockner-Moeller i
kV Kilovolt I.AP LaSalle Administrative Procedure LEP LaSalle Electrical Maintenance Procedure-LER Licensee Event Report j
LES LaSalle Electrical Surveillance LLP LaSalle Special Procedure
LOCA Loss Of Coolant Accident LOS LaSalle Operating Surveillance LPCI Low Pressure Coolant injection
- LPCS Low Pressun. Core Spray
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LST.
LaSalle Speciel Test i
LTS
~ LaSalle Technical Surveillance MCC Motor Control Center
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MOV Motor-Operated Va!ve
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l MSIV Main Steam isolation Valve NDIT Nuclear Design Information Transmittal NEP Nuclear Engineering Procedure NOD Nuclear Operating Division NRR Nuclear Reactor Regulation NSR Nonsafety-Related NSWP Nuclear Station Work Procedure NTS Nuclear Tracking System OE
- Operability Evaluation OM Operating and Maintenance PDR Public Document Room
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P&lD Piping & Instrument Drawing PIF-Problem identification Form PM Preventive Maintenance psid pounds per square inch differential Q&SA Quality and Safety Assessment RCIC Reactor Core Isolation Cooling RHR Residual Heat Removal RHRSW Residual Heat Removal Service Water RJ Refueling Justification RPS Reactor Protection System RSO Relay Setting Order SFPR
_ System Functional Performance Review SR Safety-Related SRRT System Restoration / Restart Teara TALT Temporary Alteration TS Technical Specification UFSAR Updated Final Safety Analysis Report URI Unresolved item VAC Volts Attemating Current VDC-Volts Direct Current
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VG Standby Gas Treatment VIO Violation VQ Primary Containment Vent anti Purge VT -
Turbine Building Ventilation WR Work Request
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