IR 05000295/1997018
| ML20211J806 | |
| Person / Time | |
|---|---|
| Site: | Zion File:ZionSolutions icon.png |
| Issue date: | 10/02/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20211J790 | List: |
| References | |
| 50-295-97-18, 50-304-97-18, NUDOCS 9710080303 | |
| Download: ML20211J806 (17) | |
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U.S. NUCLEAR REGULATORY COMMISSION REGION ll1 Docket Nos:
50 295,50-304 License Nos:
50 29$/97018(DRS); 50 304/97018(DRS)
Licensee:
Commonwealth Edison Company Facility:
Zion Nuclear Plant, Unita 1 and 2 Location:
101 Shiloh Boulevard Zion,IL 60099 Dates:
April 9,1997, through July 30,1997 Inspectors:
Z. Falevits, Reactor Engineer M, Miller, Reactor Engineer J. Yesinowski, Zion Resident Engineer, IDNS Approved by:
Mark A. Ring, Chief. Lead Engineers Branch Division of Reactor Safety
.9710080303 971002 PDR ADOCK 05000295
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EXECUTIVE SUMMARY p
Zion Nuclear Plant, Units 1 and 2 NRC Inspection Report 50 295/97018(DRS); 50 304/97018(DRS).
Engineering
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A violation was identified for failure to establish appropriate measures to control parts or e
components which do not confurm to design requirements in order to prevent their inadvertent use or installation.
A violation was identified for failure so implement timely and effective corrective actions
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by falling to update a procedure to include the latest design basis information and implement compensatory measurcs noted in a 1992 operability evaluation in a timely manner.
The quality of the Independent Safety Engineering Group (ISEG) calculation and design
review process conceming a Zion Unit i reactor vessellevelIndication system decrease during a reactor coolant system drain down was poor in that the calculation contained various errors and the reviewer failed to identify the errors.
The inspectors determined that recent design engineering efforts and activities to
identify and address long standing design deficiencies were more comprehensive.
Examples included, the identification of the unacceptable cable leakage current and the insufficient voltage to energize safety-related 4.16kV and 480V breaker coils.
The inspectors noted that system engineering activities and involvement in support of
plant activities needed improveinent. For example: (1) system engineering failed to promptly revise and issue operating procedure SOI 63K to incorporate design calculation results. This was to be correctly and promptly done to prevent future undesired cross-tie configuration of the 125Vdc buses; (2) once the initial evaluation was completed to operate the CC system down to below 40'F temperature, which was outside the design bases for the system, the system engineer demonstrated v%ry poor follow up on the recormnendations and compensatory actions for operating the system down to 40'F; and (3) system engineering failed to identify all scenarios where the power operated relief valve (PORV) instrument air accumulators would be called upon to operate the PORVs.
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Ill. Engineering flP 37550)
E2 Engineering Support of Facilities and Equipment E2.1 Steam Generator Pressure Transmitters Declared Inot su Due to UnacceAlable Cable Leakage Current and Non Environmentally Qualified Transmitteig a,
jnsoection Scone On April 23,1997, the licensee declared all Steam Generator pressure transmittors inoperable. The design engineering group identified unacceptable leakage current in the transmitters' instrument cables, in addition, the licensee noted that 4 of 12 pressure instrument transmitters were not environtnentally qualified (EQ) for the harsh environment during a main steam line break (MSLB) outside of containment. The inspectors evaluated the causes and licensee's corroctive actions to resolve thic :ssue, b.
Qhgervations and Findings On December 7,1984, the NRC issued Information Notice (IN) 84 90, " Main Steam Ur.e Break Effect on Environmental Qualification of Equipment". The IN informed licensees of a potential unreviewed safety question pertaining to plant analysis and equipment qualification with respect to a postulated MSLB with releases of superheated steam.
The !!censee conducted evaluations to !dentify a resolution to the Zion equipment EO concems; however, a nuclear tracking system (NTS) item was not initiated for engineering to evaluate the applicability of IN 84 90 to Zion.
During recent licensee restart walkdowns, a mininium bend radius violation was l
discovered in Unit 2 containment. To evaluate the significance of the bond radius violation, the lice'isee re examined the assumptions used in calculation Cl 91 IR-01,
" Insulation Resistance for Instrumentation Cables," performed on March 14,1991. The design engineers identified that the calculation erroneously used a cable length of 13 feet for main steam pressure transmitters (1(2) PT - 516,526,536 and 546) routed in the main steam tunnel a.nd valve rooms and exposed to harsh environment. A field walkdown determined that the cables routed were actually 430 feet long. The increased cable insulation resistance (IR) loss (using 430 feet cable) resulted in a +6% transmitter span bias error and would have caused the main steam prcssure low setpoint to be non-conservative. The safety injection (SI) actuation setpoint was also found to be inadequate. Problem identification form,PlF) 971313 was issued on March 13,1997, declaring 1(2) PT 516,526,536 and 546 transmitters and their associated main steam line pressure low coinc! dent with high steam flow safety injection t.ctuation signal inoperable.
In addition, calculation Cl 91 IR-01 erroneously assumed in 1991 that the transmitter cables would be exposed to a maximum temperature of 322 F after a high energy line break (HELB) outside the containment. Subsequently, in October 1993, " Zion Steam Tunnel Analysis," documented that the steam tunnel will reach a maximum of 480 F in
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less than 10 minutes. In addition," Environmental Qualification Report for High Temperature Operability Qualification for BlW Cable and Rosemount Trant,mitter,"
dated October 30,1995, used 495'F for HELB scenario testing Consequently, the licensee determined that the previous 1991 analysis at 322'F used to qualify the transmitters was not bounding and the IR bias error was non-conservative. This resulted in full scale pressure indication and rendering inoperable any protective
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functions associated with the steam pressure signal. PlF 971986 was issued on April 23,1997, declaring all main steam pressure indication and protection functions inoperable during a steam line break cutside containment accident. The licenses determined that in the event of a steam line break outside containment these instruments would not be available to operators for identifying the faulted steam generator.
The licensee developed modifications to replace the 4 Fisher Porter transmitters, and the existing instrument cables to the 12 transmitters. (Ref. LER 97-011).
c.
Conclusion
The inspectors concluded that design engineering and Nuclear Fuel Services (NFS)
were proactive in identifying the incorrect cable length assumption In the calculation and the failure to take into account the elevated temperature in the steam tunnel resulting from a MSLB; however, several opportunities existed to identify and address this significant issue earlier.
This item is considered unresolved pending licensee corrective action and further NRC follow up (50-295/97018-01(DRS); 50-304/97')18 01(DRS)).
E2.2 lasufficient Voltage to Energize Safetv Rela 5d 4.16kV and 480V Breaker Colls a.
insoection Scone The I;censee recently identified that insufficier.t voltages existed at the closing coils for 16 safety-related 480V and 4.16kV switchgear breakers. Consequently, the loads may not start on demand during a single loss of offsite power (LOOP) concurrent with loss of coolant accident (LOCA).
b.
Observations and Findings The inspectors determined that, in response to an electrical distribution safety functional inspection (EDSFI) concem, identified in 1991, relative to lack of a calculation to ensure that sufficient voltage was available to operate safety-related components, the licensee initiated calculation 22S B-007E-007, dated March 16,1992, " Control Power Volta 2e Drop to Safety-Related 4kV and 480V Circuit Breakers."
In March 1997, licensee engineers determined that the assumptions and methodology used in calculation 22S-B-007E-007 to determine 4.16kV and 480V switchgear breaker closing circuit voltage drops were non conservative (PlF 97-1419). The calculation also
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erroneously assumed that 110V was available at the switchgear distribution panels. As a result,16 safety-related circuits did not have the minimum voltage required by the breakers' manufacturer available at the breaker closing coil terminals.
On March 19,1997, the licensee performed operability assessment No. ER9701754 and by using calculational conservatisms, concluded that there was reasonable assurance that the Lffected coils could perform their intended safety related functions. However, to resolve this issue, the licensee planned to perform design changes. Modification packages were assembled to either add interposing reiays or parallel conductors in the breaker control circuits to increase the voltages at the affected colls to values greater than or equal to the manufacturer's published values. In addition, the licensee recently identified that the scope of the original calculation, issued in 1992, failed to include all breakers which were part of the battery duty cycle for a single unit LOOP /LOCA or dual unit LOOP. The licensee committed to expand the original scope to include all of the newly identified loads and to perform the design changes prior to either U1 or U2 s;artup.
c.
Conclusion
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The inspectors concluded that the licensee's corrective action to address voltage drop operability concerns identified by the NRC in 1991 were not effective. However, recent licensee actions to address the voltage drop concems appeared to be more comprehensive. This item is considered unresolved pending licensee action and NRC follow up review (50 295/97018 02(DRS); 50 304/9'018 02(DRS)).
E2.3 Dotential to Ooerate the Plant Bevond The Battery Desian Basis Due to Inadcaua10 Load Shed Procedure a.
Insoection Scoce The inspectors reviewed the battery calculation for load shedding and the " Loss of All AC Power" procedure used to shed loads following a LOOP /LOCA with the loss of the battery charger. The procedure was to be updated to conform to the updated load shed profile per the calculation.
b.
Qb2IYallQna_and Findings On April 3,1997, PIF 971639 documented that procedure FCA-0.0, Rcvision 23. " Loss of All AC Power," failed to include various DC loads that must be shed off the bus as determined by calculation 22S B-007E-001,"125Vdc Battery Load Profile Analysis." The calculation which was performed on December 12,1991, identified loads for each battery (011, iii,112,211 and 212) that needed to be shed within 30 minutes to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for the batteries to fulfill their 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> load profile design function follow!ng a LOOP /LOCA with a loss of the battery charger. Examples of loads that needed to be
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shed from the 112 bus included: RF129 reactor trip switchgear, RF136 345kV control panel, and steam generator feed pump (SGFP) Turbine 18 and 1C emergency oil
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i pumps. Examples of loads that needed to be shed from the 111 bus included:
generator excitation cabinet and control rod position indication inverier. A potential existed to operate the plant beyond its design basis profile. The licensee was in the process of determining root cause and corrective action, c
CQaclu1LQD The inspectors determined that thn licensee failed to identify that the procedure had to be promptly updated to include various DC loads that must be shed off the bus as determined by a design calculation. This item is considered an example of a violation of 10 CFR 50, Appendix B, Criterion XVI. (50-295/97018-03a(DRS);
50 304/97018-03a(DRS)).
E2.4 125Vdc Cross Tie Configuration Concems a.
Insoection Scoce The inspectors examined concerns relative to cross tying a 125Vdc battery from a unit in mode 5,6 or defueled to a second unit in modes 1 to 4 in order to supply tne design basis accident duty cycle for the same division battery.
b.
. Observations and Findings 125Vdc cross tle calculation 22S B 007E-026, dated September 30,1996, concluded that it was not acceptable to cross tie a battery from a unit in modes 5,6 or defueled to supply the complete design basis duty cycle for the same division of the opposite unit in modes 1-4. The cross tle was not acceptable because the 125Vdc battery would not be capable of supplying the cross-tie loads (Ref. PIF 97-1156, dated March 41997).
However, Technical Specification 3.15.2.E and improved Technical Specification 3.8.4 bases, page B3.8-55, stated that the cross tie configuration (found to be unacceptable by calculation 22S B-007E-026) was allowed to fulfill the operability requirement of the unit in modes 1-4.
The results of the design calculation were transmitted to system engineering via NDIT No. ZDE-96-026 in September 1996. System engineering was tasked with revising and promptly issuing operating procedure SOI-63K using the calculation results to prevent operations from performing the undesired cross tie configuration in the future. On March 8,1997, Operation Standing Order No. 97-08, was issued to prevent planned isolations of one battery or battery charger supplying two DC buses without system engineering and operations management concurrence. The inspectors noted that the required procedure changes were not implemented and issued until June 9,1997. The inspectors were informed by the system engineer that information to determine if Zion entered this ccnfiguration in the past was not available.
The inspectors determined that system engineering was tasked with revising and issuing operating procedure SOI-63K to incorporate the design calculation results. This was to be done promptly to prevent the potential for undesired cross tieing of the 125 Vdc
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buses in the future. The inspectors determined that, even following the belated procedure change, operators were cross tieing the buses. Although engineering was informed of the cross ties, the responsible engineer was unaware that the operators were not declaring the buses inoperable during the cross tie evolution.
The issue of cross tieing the buses is considered unresolved, pending licensee corrective action end further NRC review. (50 295/97018 04(DRS);
50 304/97018-04(DRS))
c.
.ConclusloRS The inspectors concluded that the licensee had not incorporated the cross-tie design calculation results into station procedures in a timely manner. The inspectors further concluded that neither opertions or engineering appeared to cornpletely understand the ramifications of the design calculation results upon the plant.
E2.5 High Efficiency Particulate Air Filters Contalning Aluminum were Installed in Reaq1ot Containment Building Exceeding the Design Basis a.
Insoection Scoon The inspectors examined the circumstances and generic implications associated with high efficiency particulate air (HEPA) filters installed in containment, containing aluminum which exceeded the design basis limit established in the licensee's design specification and noted in the Updated Final Safoty Analysis Report (UFSAR).
b.
Observations and Findings On August 20,1996, Westinghouse alerted Comed via letter, CWE 96146, that some plants may have procured HEPA filters containing aluminum materials for safety related applications inside the containment building. The original HEPA filters furnished by Westinghouse in 1970 did not contain aluminum material. During design basis LOCA conditions, aluminum material will generate hydrogen gas when exposed to sodium hydroxide in the containment spray system, and alumi,ium will dissolve when exposed to boric acid.
The inspectors determined that the licensee failed to promptly evaluate the Westinghouse alert letter applicability to the Zion plant. An NTS item was not issued requiring a response with due date. Thn letter was given to the maintenance system engineer by his supervisor in October 1996, for information only. The engineer finally read the letter in March 1997, and identified that the concern applied to Zion, Units 1 and 2.
The original HEPA filters were in place in the containment charcoal filter units (CCFU)
until replaced (as corrective work to address decreasing filter deficiencies) between 1992 and 1994. The inspectors determined that the system engineer used an informal
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unapproved filter 1:st, from his file, to select the filters. The list conta!ned the incorrect
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part number for this application. The engineer and work analysts failed to verify that the new filter, which was not a like for like replacement, was appropriate for inside containments. Design drawings, the UFSAR, and Sargent & Lundy (S&L) design specifications and requirements were not reviewed, in addition, station procedures had not specified the prccess for determining parts.
The licensee planned to (1) replace the HEPA filters before the respective unit increased mode of operation, (2) review a sample of work performed since 1994 (3) specify a formal method to ensure parts replacement are in accordance with controlled documents and (4) train appropriate personnel on the formal parts identification process, c.
Conclualon The inspectors concluded that although the maintenance system engineer eventually identified this problem in March 1997, the !lcensee's outside correspondence review process failed to promptly and formally address this issue, in addition, the inspectors were concerned that measures were not established to control parts or components which do not conform to requirements in order to prevent their inadvertent use or Installation.
Failure to establish appropriate measures to control parts is considered an example of a violation of 10 CFR 50, Appendix B, Criterion XV (50 295/97018-05a(DRS);
50-304/97018 05a(DRS)).
E2.6 Ooeration of Comoonent CoolingJystem (CC) Outside the Normal Ooerating Range a.
In5Dection Scom The CC system was operated outside the temperature range identified in the precautions of the system operating procedure. The inspectors reviewed the evaluation performed to permit the expanded limits and any other actions the licensee was taking, b.
Observations and Findings On January 12,1997, the licensee documented in PIF 97 0290 that Zion Unit 0, CC system, was being operated below the 70'F temperature precaution of system operating procedure sol 6, Rev. 5, dated May 16,1996. In response, the system engineer informed operations that an evaluation dated March 9,1992, allowed the CC temperature to go as low as 40'F.
The inspectors determined that on February 22, W/, the licensee documented in PlF
- 971144 that Zion Unit 0 CC system was being operated below the 40'F allowed by the 1992 evaluation.
The cause of the low CC water temperatures was due to low temperature service water (SW) which was used to cool the CC water through heat exchangers (HX). Since the SW is balanced to deliver the proper flow to all the equipment it cools, the SW could not
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be throttled to a lower flow rate. By the current technical specification, the station was allowed to r. hut off SW flow to one of the three CC HX; however, this action was not enough to rnalntain the CC temperature in the appropriate range. The CC system engineer stated that the new standerdized technical specification would allow isolating SW flow to all three CC HX, which would alleviate the problem. The date for incorporating the new standardized TS change had not been determined.
The inspectors noted that PIFs 97-0290 and 971144, for these two events were closed via PIF 971089, dated February 22,1997 and that PlF was then closed. A commitment was also opened which vaguely described the problem and had a due date of June 6,1997. The co'nmitment did not require an evaluation of potential equipment damage caused by operating the CC system below 40'F. The system engineer indicated that the evaluation was being performed and would be complete by the commitment due date.
The 1992 evaluation contained iour compensatory measures for operating the system
down to 40*F.
1.
Lube oil sampling frequencies on pumps (residual heat reti oval, safety injection, vob.,me control, component cooling, and reactor coolant) should be increased to twice monthly when CC temperature drops below 60'F to check for signs of condensation in the lube oil reservolts.
2.
Indicators installed within the CC system, which have an indication range not inclusive of 40*F should be replaced with indicators having a minimum value of 40'F, or less, as time permits.
3.
The technical staff should obtain a written response from radiation protection regarding the failed fuelletdown radiation monitors prior to implementation of procedures which would allow 40'F CC water.
4.
When SW inlet temperature falls below 40'F, and the colculated CC heat exchanger * range'is less than 8'F, appropriate operator actions should be initiated to ensure CC system temperatures are maintained above 40'F.
These compensatory actions were never implemented, nor formally dispositioned; although the licensee used the operability evaluation to justify operating the CC system below 70*F The inspectors questbned the system engineer regarding why the compensatory actions were not implemented, in reponse, the engineer stated that, for the first item, oil sampling was done yearly, with no water being four'd, so it was not necessary to do increased sampling during low temperature conditions. The inspectors noted that water could be present during the low temperature perios but could dissipate
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before the next annual sample. The engineer did not have data to support his conclusion and had not documented his determination. For the third item, the engineer also noted that verbal confirmatico had been obtained regarding the CC radiation detectors; however, there was no written documentation. For the last itom, the engineer stated that a procedure change request was sent to the procedure groups; however, the
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9 engineer did not follow through on this action to ensure that it was completed. The inspectors were unable to determine why the second compensatory measure, replacement of the temperature Indicators, was never implemented.
The inspectors were concerned about the poor followup on the issue. The inspectors deemed that the failure to implement the compensatory measures may have contributed to the plant operating outside its design bases in January 1997, in that there was no procedural guidance to address operator actions when the CC temperature was found to be below 40'F. Although the licensee was able to demonstrate that the CC system was still operable, for the January case, the inspectors considered the licensee to have failed to take timely corrective actions to resolve the recurrent problem with maintaining the CC temperature at or above 70'F.
c.
Conclualona The inspectors concluded that the licensee failed to take appropriate corrective actions in a timely manner. Although the 1992 evaluation allowed operation of the CC system with temperatures down to 40'F,it also contained compensatory measures which were not followed.
This failure is considered an example of a violation of 10 CFR 50 Appendix B Criterion XVI (50-295/97018-03b(DRS); 50 304/97018-03b(DRS)).
E2.7 Operability Assessrnent of Pressurizar Power Ooerated Relief Valves (PORV)
Accumulators a.
Infinection Scone The inspectors reviewed the operability assessmer, to determine if all functions of the PORV accumulators were addressed in the assessment, b.
Observations and Findings Operability Assessment ER9700134 was revised four times. Revision 1, dated January 30,1997, stated tha' PORV instrument air accumulators were only required to support the PORVs while low temperature over pressure protection (LTOP) was enabled. Revision 2, dated February 4,1997, acknowledged that the use of a PORV was also included in the steam generator tube rupture scenario. Revision 2 properly stated that the steam generator tube rupture scenario was bounded by the feed and bleed operation which was identified in the original operability assessment. The remaining revisions did not address any other additional scenarlos requiring the PORV accumulators.
The system engineer stated that his review of the PORV functions had been based on the Technical Specification (TS), the Updated Final Safety Analysis Report, and his personal knowledge. He did not review the emergency operating procedures and old not receive assistance from an operations perspective in identifying the full scope of
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scenarios which called upon the PORV accumulators. The engineer was not aware that emergency operating procedures (EOP) E 1 (Loss of Reactor or Secondary Coolant)
and E 3 (Steam Generator Tube Rupture) required the use of the PORVs prior to restoring instrument air to the containment and therefore PORV instrument air accumulators were needed to fulfill the step in the procedure, c.
ConclullQD The failure to identify all scenarios where the PORV instrument air accumulators would be called upon to operate the PORVs was considered a weakness. Since the system engineer did not have operations experience it was understandable how he missed the scenarios in the EOPs However, the inspectors were concemed that after four revisions of the assessment, someone with an operation's perspective did not identify the EOP references. The inspectors agreed with the system engineer that the EOP actions that call upon the PORV instrument air accumulators were bounded by the original assessment.
E2.8 Evaluation Performed by the Indeoendent Safety En9lDREIDg Groun (ISEG)
e, insoection Scooe The inspectors reviewed evaluation QVL 22 06-056, dated October 7,1996, for technical accuracy.
b.
Observation and Findings The ev61uation (OVL 22 96-056, dated October 7,1996) concerned a Zion Unit i reactor vessel level indication system decrease during a reactor coolant system drain down, in the evaluation, an attempt was made to quantify the available volume above the reactor vessel nonles where a gas bubble could collect before the bubble would migrate to cther sections of the primary system. The inspectors had significant concems with the calculation. The calculation attempted to determine tl e available volume by calculating the reactor head area as one half the volume of a sphere and the area between the reactor head flan 0e and the top of the reactor nonles as a cylindrical area. The following errors were noted, Based on the drawing used to make these calculations, the radius used for the o
sphere was 20% greater then the Inside height of the reactor head.
The formula for the cylindrical area was correct; however, the actual calculation e
used the diameter squared instead of the radlus squared, The engineer assumed the total area was available space for the gas to collect o
and did not acknowledge that the space was also occupied by the control rod drives and other structures.
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There was no signature of the person performing the calculation or a date on the calculation. The evaluation was signed by the engineer who performed the calculation and also signed by the supervisor of ISEG as reviewer. The supervisor stated that he did not fully review the calculation and was not aware of the problems until the inspectors raised questions. The supervisor stated that there was no procedure that governed the review process for ISEG evaluations.
The evaluation which contained significant errors of a basic nature was a signed and approved evaluation issued by the ISEG organization. The failure to perform an adequate design review and verify the adequacy of the design with respect to the gas bubble was considered a significant weakness within the ISEG organization, c.
Conclusion The quality of the ISEG calculation and design review process was poor. The mistakes should have been identified by a cursory review. The lack of review for this issue brings into question the quality of other ISEG products.
E2.9 Ooerability of Steam Generat0Is during Shutdown Conditions a.
Insocction Scope The inspectors reviewed the method in which the licensee addressed shutdown risk following the identification of a gas bubble in the Unit 2 reactor vessel.
b.
Observation and Findings On March 7,1997, the licensee identified the existence of a gas bubble in the Unit 2 reactor vessel. On March 8,1997, the licensee atuo identified that a gas bubble existed in the Unit i roactor vessel.
The inspectors reviewod an outage risk approval form dated March 31,1997. The document addressed how the plant was going to deviate from an administrative guideline for shutdown risk. Normally while in mode 5 (cold shutdown), the equipment
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hatch to the containment was not removed when the reactor coolant system pressure boundary was not intact. The personnel hatch doors could be open as long as closure was a hlevable within the time it would take if shutdown cooling was lost and the time the reactor coolant would reach saturation (time to boil). During the evolution, secondary containment was operable.
This document originally took credit for the steam generators being operable. The document stated that after a loss of all shutdown cooling, the time to boll was "at least 3.75 hours8.680556e-4 days <br />0.0208 hours <br />1.240079e-4 weeks <br />2.85375e-5 months <br />" and the time to core uncovery was "at least 33 hours3.819444e-4 days <br />0.00917 hours <br />5.456349e-5 weeks <br />1.25565e-5 months <br />." Early In April, the residert inspectors questioned the effect of gas in the steam generators. On April 6, the document was revised to assume no credit foi the steam generators. Under the new assumption the time to boll decreased to "at least 60 minutes" and the time to uncover the core decreased to "at least 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />."
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Copies of the Risk Assessment Evaluation Form were not required to be retained and were typically purged after approximately 30 days. From the remaining documentation the inspectors found that the licensee stopped taking credit for the Unit 2 steam generatom on April 8,1997. The latt form available for Unit 1 was dated April 12,1997.
At that tlme period no credit was being taken for the steam generators on Unit 1.
c.
Conclusions Whlie no violations of NRC requirements occurred with respect to taking credit for the steam generators, NRC Intervention was ne:essary to get the steam generator issue addressed. Based on the significant difference in risk caused by not taking credit for the steam generators, the licensee should have identified the issue without NRC intervention.
E2.10 Non seismically Quahfied Solenoids Found in Starting Circuitrv of 1C and 2C Diesel Containment Sorav Pumos a.
Insoection Scong The inspectors investigated licensee identified nnn seismically qualified starting solenoids that were installed in the starting circuitry of the 1C and 2C diesel containment spray pumps.
b.
Obiervations and Findings Non seismically Oualified Solenoids (Unit 2)
On April 28,1997, while replacing the 2C Diesel Containment Spray (CS) Pump starting solenoids as preventative maintenance (PM) under Work Package (WP) No. 970022320 01, an electrical maintenance worker noticed that the two solenoid replacement parts had different part numbers. Subsequently, on Apill 29,1997, PlF 97 2129 was issued, This PlF identified that two starting solenoids had been installed on the 2C CS pump that may have been non-seismically qualified. Subsequently, it was found that only one of the two solenoids on the 2C CS pump was not qualified, in 1987, a new system engineer had incorrectly determined that the replacement solenoid P/N 3055737 did not require a seismic report. As a result of this evaluation, the replacement solenoid was not required to be seismically qualified. A contributing cause of the nor":onformance was the assignment of the non seismically qualified solenoid to the same Si number as the original seismically qualified part (Sl No.
770A17). This resulted in both seismic and non seismic replacement solenoids having same Si number as the previous seismically qualified solenold.
The licensee was investigating the root causes under the PIF process for the one non-seismically qualified solenoid on the 1C CS pump. As of June 9,1997, the root cause investigation bad not yet been completed.
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Non seismically Qualified Solenoids Unit 1 i
On May 1,1997, based on the discovery of a non seismically qualified solenoid in the Unit 1 CS pump, the system engineer wrote PlF 97 2160. This PlF identified the installation of one non seismically qualified 1C containment spray pump starting solenoldi On February 21,1997, the 1C CS pump failed to start as documented in a previous II.spection report. As part of the troubleshooting for that event under WP 9/0020679 01, the pump starting solenolds and relays were replaced. The system engineer instructed the replacement solenoids to be SI No. 770A17.
As part of the WP, Zion Generating Station Maintenance Procedure Electrical Troubleshooting Guidelines E/G-002, Section F. Limitations and Actions, step 3.
required that " replacement parts shall be verified to ensure they are like for like, properly evaluated or correctly red tagged." During this replacement work, the worker verified that the first solenoid of two replaced was like for like with the original solenold.
However, he did not verify that the second solenoid had the same part number.
Consequentially, the second solenold replaced was not selsmically qualified, in addition, part numbers for the solenoids with Sl No. 770A17 were not documented on G.
01 Ex. C, Bill of Material, with this WP.
On May 20,1997, test results were completed as part of the licensee root cause
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investigation. The test results showed that the non seismically qu;,;ified solenoid part met seismic qualification standards, c.
Conclusion Failure to establish methods for the identification and control of parts and prevent the use of nonconforming parts and components is considered an example of a violation of 10 CFR 50, Appendix B, Criterion XV,(50-295/97018-05b(DRS);
50-304/97018-05b(DRS)).
V. Management Meetings X1 Exit Meeting Summary The lospectors presented the inspection results to members of "censee management at the conclusion of the inspection on July 30,1997. The licensee acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary Information was identified
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PARTIAL LIST OF PERSONS CONTACTED l
i Licensee J. Mueller, Site Vice President R, Starkey, Plant Manager R. Godley, Regulatory Assurance Manager J. Lewis, Radiation Protection Manager T. Luke, Engineering Manager F. Gogliotti, Desigrogineering M. Weis, Support hc vices Director R. Zyduck, Site Qaality Verification Director T. Cromeans, Materials Management Supervisor E. Falb, Maintenance Support Supervisor D. Giernoth, Shift Manager C. Allen, Regulatory Assurance D. Beutel, Regulatory Assurance.
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.HRC A. Vogel, Senior Resident inspector D. Calhoun, Resident inspector E. Cobey, Resident inspector LIST OF INSPECTION PROCEDURES USED lP 37550: Engineering IP 37551: Onsite Engineering IP 37700: Engineering Modifications IP 40500: Effectiveness of Licensee Controls in Identifying, Resolving and Preventing Problems
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l ITEMS OPENED, CLOSED, AND DISCUSSED Ooened 50 295/304/97018-01 URI Steam Generator Pressure Transmitters Inoperable (Section E 2.1)
50 295/304/97018-02 URI insufficient Voltage to Energize SR breaker coils (Section E2.2)
50-295/394/97018-03a VIO Failure to incorporate design req's into the procedure in a timely manner (Section E 2.3)
50-295/304/97018 03b VIO Failure to incorporate timely corrective actions for operating the CC system below 70'F. (Section E 2.6)
50 295/304/97018-04 URI 125 V Cross tie configuration concerns (Section E 2.4)
50 295/304/97018-05a VIO HEPA filters containing alumimum were installed in reactor containment building. (Section E 2.5)
50-295/304/97018-05b VIO Non seismically qualified solenolds were installed in the starting circuitry of 1C and 2C diesel containment spray i
pumps (Section E 2.10)
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LIST OF ACRONYMS USED i
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CC Component Cooling CS Containment Spray I
DRS-Division of Reactor Safety i
EDSFl
Electrical Distribution System Functional Inspection EOP Emergency Operat!ng Procedures
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EQ Environmental Qualifications j
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HEPA High Efficiency Particulate Air HX Heat Exchanger IDNS lilinois Department of Nuclear Safety
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IN Information Notice
IP Inspection Procedure
ISEG Independent Safety Engineering Group
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LOCA Loss of Coolant Accident LOOP Loss of Offalte Power LTOP Low Temperature Overpressure Protection _.
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MSLB Main Steam Line Break NFS Nuclear Fuel Services
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NRC Nuclear Regulatory Commission NTS Nuclear Tracking System PIF Problem Identification Form PM Preventive Maintenance-PORV Power Operator Relief Valve SGFP Steam Generator Feed Pump S&L Sargent and Lundy SW Service Water TS Technical Specifications UFSAR Updated Final Safety Analysis Report URI Unresolved item VIO Violation WP Work Package
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