IR 05000461/1998006
| ML20216C920 | |
| Person / Time | |
|---|---|
| Site: | Clinton  |
| Issue date: | 05/11/1998 |
| From: | Kozak T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20216C907 | List: |
| References | |
| 50-461-98-06, 50-461-98-6, NUDOCS 9805190438 | |
| Download: ML20216C920 (22) | |
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U.S. NUCLEAR REGULATORY COMMISSION REGION ll1 l
l Docket No: 50-461 l l License No: NPF-62 l
l Rr. port No: 50-461/98006(DRP)
Licensee: Illinois Power Company Facility: Clinton Power Station i
Location: lilinois Power Company Mail Code V-275 P. O. Box 678 )
Clinton, IL 61727 1 Dates: March 4 - April 14,1998 l
Inspectors: T. W. Pruett, Senior Resident inspector K. K. Stoedter, Resident inspector R. A. Langstaff, RegionalInspector D. E. Zemel, Illinois Department of Nuclear Safety Approved by: Thomas J. Kozak, Chief Reactor Projects Branch 4
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9805190438 980511 PDR ADOCK 05000461 G PDR
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J EXECUTIVE SUMMARY Clinton Power Station NRC Inspection Report No. 50-461/98006(DRP)
This inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers c cix-wook period of resident inspectio Operations
. The Division 11 Emergency Diesel Generator and Residual Heat Removal Systems B and C were retumed to an operable status. These systems had been declared inoperable but available in August 1997 (Plant Summary).
. A design deficiency, material condition iscues, and the failure of an operator to appropriately communicate plant condiuons to the control room resulted in a loss of service air and a subsequent manual reactor scram. The operations department's root cause investigation for this event was thorough and identified several actions to improve equipment and operator performance. Although one of these actions was initially disapproved by the engineering work review board, operations personnel took the initiative to overtum the decision and to ensure that a long-standing operator work-around .
was appropriately resolved (Section 01.1).
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. Contingency plans for the Division 11 Inverter outage and the reserve auxiliary transformer er.cavation work were thorough in that they were communicated to affected personnel and considered the potential for several events (Section 01.2).
Maintenance
. One example of good questioning attitude was identified when operations personnel stopped a surveillance to address the impact of a leaking equalizing valve on a flow instrument used during testin0 (Section M1.2).
. The visible condition of coatings inside the containment and drywell was considered good. The amount of coatings which were loose or flaking was negligible and did not present an appreciable source of debris which could clog the emergency core cooling system (ECCS) suction strainers (Section M1.3).
. Past correcDe actions to address degraded coatings were inadequate. As a result, degradation developed such that ECCS suction strainer clogging may have occurred under certain circumstances and ECCS operability was not assured (Section M8.2).
. Inadequate planning and work control resulted in two occasions where an available train cf standby gas treatment was not maintained (Section E1.1).
Enaineerina
. Engineering, operations, and work control personnel failed to appropriately implement the requirements of Technical Specification 5.5.7," Ventilation Filter Testing Program." As a result, testing of the HEPA filter and the charcoal adsorber bed for the standby gas
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treatment system was not performed following painting in a ventilation zone which directly communicated with the standby gas treatment system (Section E1.1).
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Engineering personnel inappropriately determined that the dry film thicknesses (DFT) for l containment coatings applied in November 1997 were acceptable without performing an ;
adequate evaluation of coatings with less than the minimum allowed DFT (Section E2.1).
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ELant Support
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Numerous emergency response personnel failed to respond several pager test l Specifically, only 1 of 6 pager tests had 100 percent response from emergency response personnel (Section P4.1).
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The fire brigade responded promptly during the performance of a fire drill (Section F5.1).
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Report Details Summary of Plant Status
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! The plant remained shut down during the inspection period. Major activities completed included I
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' the performance of repairs on the Division 11 Nuclear System Protection System (NSPS) Inverter
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and the restoration of the Division 11 Emergency Diesel Generator and Residual Heat Removal ,
Systems B and C to an operable status. The restoration of Division ll equipment was significant in that these components had been inoperable but available since August 199 . Operations 01 Conduct of Operations 0 Manual Scram Due To Loss of Service Air System ' inspection Scope (71707)
The inspectors reviewed the licensee's actions taken in response to a loss of the service air (SA) system and subsequent manual reactor scram. The licensee documented the event in Licensee Event Report 50-461/98-002, Observations and Findinas On January 23,1998, at 3:15 p.m., SA compressor 1SA01C tripped when the lube oil temperature exceeded 125'F. Standby SA compressor 2SA01C started on low SA header pressure but tripped at 4:00 p.m. due to high lube oil temperatcre. Operations personnel implemented Procedure 4004.01, " Instrument Air Loss," and initiated a manual reactor scram at 4:05 p.m. due to low SA/ instrument air pressure prior to receiving an automatic scram signal due to a high water levelin the scram discharge volume. Main control room operators restored service air within ten minute i
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The operations department performed a root cause investigation for this event and !
identified several concems. During normal operation, the SA Air Compressor Lube Oil l Cooler Outlet Valves 1CC245A, B, and C were manually throttled to allow the component cooling water (CC) system to maintain SA compressor lube oil temperature between 100'-110'F. Operations personnel identified that due to excess cooling capability intemal to the SA compressors and the low heat load present on the CC system due to "
the prolonged plant shutdown, valves 1CC245A-C had been throttled almost closed to ensure that the lube oil temperature would remain within procedural specifications. Since these valves were nearly closed, changes in CC temperature due to changes in heat load on the CC system were magnified and resulted in abnormalincreases in SA compressor lube oil temperatur Two material condition deficiencies also contributed to this event. Operations personnel usually maintained CC system temperature using CC Temperature Control Valves 1WS018A and B which regulated the amount of service water (WS) supplied to the tube side of the CC heat exchangers. In 1996, licenses personnel discovered that the temperature controllers for these valves were unable to properly control CC temperature, t
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The inability to automatically control CC temperature resulted in an operator work around since operations personnel were required to control CC temperature through the use of a manual bypass valve (for the purposes of this inspection report, an operator work around is defined as a degraded or non-conforming condition that complicates the normal operation of plant equipment and is compensated for by operator action). While the licensee performed work to resolve this material condition deficiency in 1997, use of the bypass valve continued due to the inability to perform post-maintenance testing because of plant conditions, The second material condition deficiency involved excessive air intrusion into the CC system. The combination of air intrusion and the throttled 1CC245A-C valves may have reduced the heat transfer between the compressor lube oil and the component cooling water, and contributed to the high lube oil temperature and the subsequent trip of the SA compressor During the event, an operator failed to meet plant management's expectations to promptly !
communicate to the control room the lube oil temperature problem that was ongoin Specifically, the area operator responsible for operation of the SA compressors left the compressor area to perform shift tumover activities prior to ensuring that lube oil temperature on the operating SA compressor was stable. This resulted in operations personnel being unaware that lube oil temperature was increasing until the operating SA compressor tripped on high lube oil temperatur In.Nediate corrective actions for this event included briefing operations personnel and requiring that any changes in CC system heat load be coordinated through the control room to ensure that equipment temperatures remained within specifications. As part of the long-term corrective actions, operations personnel proposed two engineering design changes to improve the operation of the SA compressor lube cooler outlet valves and the CC temperature control valves. On February 12, the engineering work review board (WRB) approved the design change for the SA air compressor lube cooler outlet valves but disapproved the design change for the CC temperature control valves since the plant conditions which required manual control of CC temperature seldom occurred, the use of engineering resources to address this concem were not justified, and the valves were not considered an operator work-around. Operations personnel disagreed with the WRBs position regarding the design change for the CC temperature control valves and successfully overturned the WRBs decision regarding the CC temperature control valves on March 2,1998. The actions taken by operations personnel to resolve this issue were considered an improvement in the efforts to appropriately address material condition issues which have resulted in operator work-around c. Conclusions A design deficiency, material condition issues, and the failure of an operator to appropriately communicate plant conditions to the control room resulted in a loss of service air and a subsequent manual reactor scram. The operations department's root cause investigation for this event was thorough and identified several actions to improve equipment and operator performance. Although one of these actions was initially disapproved by the engineering work review board, operations personnel took the initiative to overtum the decision and to ensure that a long-standing operator work-around was appropriately resolve i l
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01.2 !;oorovements in Operations Continaency Plannina (71707)
NRC Inspection Report 50-461/98004 documented the licensee's failure to perform outage safety reviews and appropriate contingency planning prior to taking the Division 11 NSPS maintenance bypass transformer out of service. In response to this finding, the licensee revised Procedure 1151.09, " Methodology for Outage Safety Reviews and Maintenance of Acceptable Shutdown Risk," to implement a new risk assessment too The risk assessment tool focused on providini defense in depth to ensure that the licensee maintained the ability to satisfy key safety functions such as decay heat removal, coolant inventory control, and electrical power availability. The procedure also provided guidance on identifying activities requiring contingency plans and ensuring contingency plans were properly developed and communicate The inspectors reviewed several work activities including the performance of a Division ll NSPS bus outage and excavation activities for the degraded voltage static var l compensator modification and determined that the use of risk assessment and contingency planning had improved. In each case, appropriate contingency plans were developed and communicated to all affected personne Miscellaneous Operations issues i
0 (Closed) Inspection Follow-up Item 50-461/95015-01: Continued personnel errors in l implementing the safety tagging program. The inspectors reviewed the licensee's safety tagging program in September 1997, and determined that corrective actions to improve personnel performance with respect to the safety tagging program had not been implemented. The licensee's failure to implement timely corrective actions to correct a condition adverse to quality resulted in a subsequent violation of 10 CFR Part 50, Appendix B, Criterion XVI (see NRC Inspection Report 50-461/97019). l 08.2 (Closed) Notice of Violation 50-461/97006-09: Four examples of inadequate procedures for performing emergency diesel generator (EDG) surveillance testing and local leak rate ;
testing for main steam line drain penetration MC045. In the first two examples, the inspectors identified potential preconditioning of the EDG fuel oil system due to operating a fuel priming push-button or performing excessive barring ovsr of the EDGs. As part of the corrective actions for this violation, the licensee revised all EDG procedures to remove any actions which were considered preconditioning. The licensee also performed a review of all surveillance procedures and identified three other preconditioning concems which were resolved prior to the next performance of the respective surveillances. The third example discussed the licensee's failure to declare the Division ll1 EDG inoperable when operating the EDG in the droop mode during surveillance testing. In response to this concem, the licensee revised procedures goveming the operation of the Division ill EDG to ensure that the EDG was declared inoperable during surveillance testing. The fourth example discussed the inability of operations personnel to bypass and reset a Group 1 isolation due to an inadequate procedure. The inspectors reviewed the revised procedure and determined that it contained appropriate information to bypass and reset a Group 1 isolatio .3 (Closed) Notice of Violation 50-461/97006-10: Improper storage of manuals in the main control room. The inspectors reviewed the licensee's corrective actions and determined that they sufficiently resolved this violatio .
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08.4 (Closed) Notice of Violation 50-461/97011-01: Failure to follow procedures during control room chilled water valve operability test. The inspectors reviewed the licensee's ,
corrective actions and determined that they sufficiently resolved this violatio l 08.5 (Closed) Licensee Event Repori 50-461/96-011: Priming of the EDGs during the performance of certain surveillance tests determined to be preconditioning. Corrective actions for this issue were reviewed during the closeout of Violation Sn-461/97006-09, items #1 and #2 (see Section 08.2). The inspectors considered the ; ' ensee's corrective i actions appropriate for this issu ,
08.6 (Closed) Licensee Event Report 50-461/96-012: Failure to demonstrate operability of a offsite power sources within one hour during surveillance while Division 111 EDG govemor speed droop control was set to 50 percent due to inadequate procedures. Corrective actions for this issue were reviewed during the closeout of Violation 50-461/97006-09, Item #3 (ses Section 08.2). The inspectors considered the licensee's corrective actions appropriate for this issu .7 (Closed) Notice of Violation 50-461/97011-03: Failure to have several EDG valves in the locked valve program. The licensee's root cause evaluation determined that this violation occurred due to programmatic weaknesses in the locked valve program. Corrective actions included placing valves 1DG150 through 1DG165 (fuel oil and starting air valves)
in the locked valve program and revising procedure lineups to ensure these valves remained locked open. The licensee also initiated a review of the locked valve program and implemented program enhancements as needed. The inspectors considered the licensee's corrective actions appropriate for this issu .8 (Open) Licensee Event Report 50-461/98-002: Loss of service air results in unplanned f engineered safety function actuation and manual reactor scram. The details of this event I were provided in Section 01.1, however, this event report will remain open pending the licensee's implementation of planned modification .9 (Open) Non-cited Violation 50-461/98004-04: Failure to perform adequate risk assessment and contingency planning. Additionalinformation related to this issue was provided in Section 01.2 of this report, however, this non-cited violation will remain open pending a review by the NRC 0350 Pane II. Maintenance M1 Conduct of Maintenance M1.1 Residual Heat Removal (RHR) Water Lea Pumo Surveillance (61726)
The inspectors observed good procedure usage, peer checking, and three way communications during the performance of Surveillance Procedure 9053.07,"RHR B/C Pumps and RHR B/C Water Leg Pump Operability." Operations personnel demonstrated improved questioning attitude when they stopped the surveillance to address the potential impact of a leaking equalizing valve on the accuracy of flow instrument 1E12-F560 which was used to collect data during the surveillanc .
M1.2 Evaluation of Containment Coatinas Inspection Scope (62707)
The inspectors evaluated the work performed to improve the material condition of containment coating Observations and Findinas The inspectors performed walkdowns of accessible portions of primary containment. In addition to areas accessible from deck gratings, the inspectors examined poliions of the containment liner between the 755 foot elevation and the suppression pool. The inspectors noted that the amount of remaining coatings which were cracked and flaking identified during their walkdowns was estimated to be less then 0.5 ft2 , Similarly, the inspectors also performed a walkdown of accessible portions of the drywell and estimated the amount of loose coatings as less than 2 in2 . The inspectors observed that the reactor recirculation pumps had been recoated using qualified coaunga and that many areas inside primary containment and the drywell had degraded coatings removed and areas recoate The inspectors reviewed work records associated with containment coatings work performed from 1997 through March 19,1998, which was documented in maintenance work requests (MWRs) D75335 and D77850. Documented inspections by quality control personnel showed that surface preparation for coating sites were acceptable. The inspectors noted that recorded surface temperatures were at least 5 F above the dew point temperature as required by Procedure 8901.08, " Field Coatings," and specified by the coatings manufacturer. Additionally, recorded ambient temperatures were within the coating manufacturer's specified application temperatures of 50'F to 110 F. As discussed in Section M3.1, humidities were not consistently within the application conditions specified by the coatings manufacturer. In addition, engineering dispositions for applied coating thicknesses were not always appropriate (see Section E2.1). j I Conclusions Overall, the visible condition of coatings inside both the containment and the drywell was considered good. The amount of coatings which were loose or flaking was negligible and did not present an appreciable source of debris which could clog ECCS suction strainer Ambient and surface temperature requirements were reviewed for containment coatings work performed from 1997 through March 19,1998, and were considered acceptabl M3 Maintenance Procedures and Documentation M3.1 Coatinas Procedure issues Inspection Scope (62707)
The inspectors rev'awei Procedure 8901.08, " Field Coatings," to determine the requirements for r,oatin:) applications inside containmen .
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b. Observations and Findinas Procedure 8901.08 specified that temperature restrictions for coating rpplications were to i
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be in accordance with the manufacturers instructions and that coatings were not be applied when surface temperatures were less than 5*F above the dew point temperatur Although Procedure 8901.08 specified that humidity be determined and recorded, the procedure did not restrict coating activities due to humidity conditions unless rain, snow, fog, or mist was presen ;
The manufacturers trade name for the coatings most extensively used inside !
containment from 1997 through March 1998, was Carboline' 890. The June 1996
- product data sheet for Carboline' 890 specified application conditions with a mPXimum j humidity of 90 percent. The inspectors contacted the coatings manufacturer and I discussed application conditions for Carboline' 890 coatings w;th a technical service I engineer. The technical service angineer stated that even if metal temperatures were greater than 5'F above the dew point temperature, condensation could still occur when j humidity exceeded the limits specified by the product data sheet. Such condensation !
could adversely affect adhesion of the coatings. Licensee engineering personnel ,
believed that having surface temperatures 5'F above dew point temperatures ensured !
adhesion regardless of humidity conditions provided no moisture was visible. The ;
technical service engineer also stated that the August 1997 product data sheet for l Carboline' 890 specified application conditions with a maximum humidity of 80 percent '
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(versus the 90 percent specified by the earlier product data sheet). In response to these issues, engineering personnel obtained an April 1,1998, letter from the coatings manufacturer which provided additional basis for the product data sheet guideline However, the obtained letter did not specifically address the acceptability of coatings applied when humidity exceeded 80 percen The inspectors reviewed the relative humidities documented in MWR D75335 for coating work performed inside containment during 1997. Coating work record "F" showed that the relative humidity was 95 percent for coeting work performed on June 9,1997, which consisted of painting signs on tanks inside containment. In addition, the inspectors identified numerous occasions where the recorded humidity was between 80 percent and 90 percent when coating work was performed. For example, coating work record "A" showed that the relative humidity was 82 percent for coating work performed on a portion of the containment liner on June 3,1997. The inspectors questioned the acceptability of coatings which had been applied when the manufacturers humidity limits had been exceeded. The licensee stated that they planned to obtain additional information from the manufacturer stating the application of coatings when humidity levels were exceeded was considered acceptable. This item is considered unresolved pending review of the additional information provided by the licensee (URI 50-461/98006-01),
c. Conclusions One unresolved item wa.: identified due to the practice of allowing the application of coatings to proceed inside containment when containment humidity exceeded the manufacturers recommendations. The licensee planned to provide the inspector with
, additional information to clearly show that the manufacture considered the licensee's j current practices acceptable.
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M8 Miscellaneous Maintenance issues l
M8.1 (Closed) Notice of Violation 50-461/97011-11: Inadequate procedure for control of l transient materials inside containment. lilinois Power revised Procedure 1019.05,
" Control of Transient Material," to provide a broader definition of " flexible material" which was to be controlled by the procedure. The revised procedure also established controls for flexible materials on the upper elevations of containment which were not properly secured. The inspectors considered the procedure revisions acceptable. The inspectors performed a walkdown of the accessible portions of containment and noted that materials intended to remain inside containment durir.g operation were properly secure Specifically, painted radiological signs were used in lieu of magnetic signs, loose labeling on electrical panels and conduit had been either removed or secured, and use of permanent caution tape and foam safety precaution materials had been greatly reduce Additionally, metal tags were used instead of paper tags inside containment. The inspectors consdered the corrective actions for materials intended to remain inside containment acceptable. Although the procedure for control of transient materials was improved, the inspectors noted that some tape and other loose debris not associated with ongoing work was inside containment. Although the amount of loose debris had been greatly reduced since April 1997, the debris found during walkdowns conducted during j this inspection appeared to be relatively recent and to be the result of poor housekeepin '
l M8.2 (Closed) Unresolved item 50-461/97015-06: Past equipment operability as a result of I degraded containment coatings was questioned. As discussed in Section M8.3, the licensee determined that the potential failure of degraded coatings could have rendered the ECCS pumps inoperable due to inadequate net positive suction head resulting from ECCS suction strainer cloggin In April 1997, the inspectors noted that a large quantity of degraded coatings existed inside containment. In response to questions by the inspectors, engineering personnel stated that no formal operability evaluation had been performed for the degraded coatings. At the time, engineering personnel believed that no operability concem existed because it was unlikely that the coatings would migrate to suppression pool, and if coatings did migrate, the majority of coatings would sink to the bottom of the pool away from the ECCS suction strainers. However, no engineering evaluation had been performed which supported the view that no operability concem existe On June 9,1997, the NRC issued Confirmatory Action Letter Rlil-97-006 regarding ECCS suction strainer operability. By letter dated June 12,1997, Illinois Power committed to assess whether ECCS operability was previously compromised due to degraded containment coatings and inadequate transient material controls. By letter dated July 16,1997, Illinois Power identified that a reportable condition existed because of the uncertainty associated with past ECCS operability due to potential ECCS suction strainer clogging (see Section M8.3).
The inspectors noted that the licensee had initiated inspections of containment coatings in 1990 in response to NRC Information Notice 89-79, " Degraded Coatings and Corrosion of Steel Containment Vessels," issued December 1,1989. From 1990 through 1996, the licensee performed five inspections which identified that the amount of degraded coatings inside containment had increased from 471 ft2 to 1426 ft2 , a three-fold increase. During the period of 1990 through 1996, some areas with degraded coatings inside containment
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had been repaired and recoated. However, the recoating effort had not kept pace with )
the amount of degradation which was identified. As a result of the increased amount of
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degraded coatings, the licensee was not able to determine that the ECCS was operable through 1996. However, by letter dated July 16,1997, the licensee informed the NRC that in June 1997 significant actions We taken to improve the material condition of the
- degraded containment coatings and tu test those coatings that would be left in place to ensure that the coatings would rernain intact under accident conditions. As discussed in Section M1.3, the overall visible condition of coatings observed during this inspection period was good and the inspectors considered remedial corrective actions to be acceptabl CFR Part 50, Appendix B, Criterion XVI, requires that conditions adverse to quality be l promptly identified and corrected. Criterion XVI also required that for significant l
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conditions adverse to quality, measures shall assure that the cause of the condition is determined and corrective action taken to preclude repetition. The failure to take ,
sufficient corrective action for degraded containment coatings from 1990 through 1996 to l ensure ECCS operability is a violation of 10 CFR Part 50, Appendix B, Criterion XVI,
" Corrective Action." However, because this violation was based upon activities prior to the events leading to the current extended plant shutdown and satisfies 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 50-461/98006-02).
M8.3 (Closed) Licensee Event Report 50-461/97-020: The potential failure of degraded '
coatings could have rendered ECCS pumps inoperable due to inadequate net positive suction head (NPSH) resulting from ECCS suction strainer clogging. As discussed in '
Section M1.3, the overall visible condition of coatings observed during this inspection period was good. Consequently, the inspectors concluded that the licensee's remedial corrective actions for removal of loose and degraded coatings were acceptable. Past operability concems are discussed in Section M8.2. The licensee planned to install new ECCS suction strainers prior to restart. The conceptual design for the new strainers was such that the potential for ECCS suction strainer clogging would be greatly reduce M8.4 (Closed) Licensee Event Report 50-461/97-023: Inadequate work instructions leads to potential over-greasing of motor bearings causing potential failure of various motor Following the identification of this issue, the licensee performed multiple motor inspections to determine whether the motors were over-greased and the amount of grease within each motor. The licensee determined that although a few of the motors inspected contained grease in inappropriate locations, the amount of grease was not significant enough to cause motor damage, the grease would not have prevented the motor from performing its safety function, and the over-gressing condition was not reportable under 10 CFR Part 50.73. The inspectors reviewed the licensee's actions and considered them appropriate for this issu l l
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Ill. Enaineerina E1 Conduct of Engineering )
E1.1 The Effects of Containment Paintino on Standbv Gas Treatment Ave!!ebility
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a. Inspection Scope (37551)
The inspectors reviewed several procedures to ensure that the exposure of ventilation systems to paint was appropriately controlled during the application of coatings inside containmen Observations and Findinas I
Appendix F of Procedure 8901.08, " Field Coatings," allowed 1.5 gallons of paint to be I applied in containment within a 24-hour period. Step a of Appendix F directed that the system engineer be contacted and that Technical Specifications (TS) - required filter testing be performed in the event that the standby gas treatment (VG) system initiated within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after stopping painting activities inside containmen l On December 15,1997, VG "A" was initiated within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after stopping painting activities inside containment which exposed the HEPA filter and the charcoal adsorber bed to paint. Condition Report 1-97-12-235 was written to document this even Technical Specification 5.5.7, " Ventilation Filter Testing Program," requires that a program be established to implement required testing of the engineered safety feature filter ventilation systems, including the standby gas treatment system, at the frequencies specified in Regulatory Guide 1.52, Revision 2. Regulatory Guide 1.52, Revision 2, Sections Sc and 5d, requires that testing be performed on ventilation systems containing HEPA filters and charcoal adsorber beds following painting in any ventilation zone communicating with the system. Procedure 9866.01, "VGNC HEPA Filter Leak Test,"
Siep 2.1.1.2.2, requires that the HEPA filter for the standby gas treatment system be tested following painting, fire, or chemical release in any ventilation zone communicating with the subsystem. In addition, Procedure 9866.02,"VGNC Charcoal Adsorber Leak Test," Step 2.1.1.2.2, requires that the charcoal adsorber bed for the standby gas treatment system be tested following painting in any ventilation zone communicating with the subsystem while the subsystem is in operatio On December 16, engineering personnel performed engineering evaluation 1-97-12-235 on VG "A" to determine if the charcoal adsorber bed was adversely impacted by exposure to paint. Engineering personnel concluded that the charcoal adsorber bed was operable because less than 1.5 gallons of paint had been applied prior to initiating VG "A." The inspectors reviewed the engineering evaluation and identified two concems:
1) engineering personnel did not provide a technicaljustification to support their conclusion that the application of 1.5 gallons of paint would have no effect on the charcoal adsorbers, and 2) engineering personnel failed to address the impact of paint on the operation of the HEPA filte The inspectors riiscussed their concems with engineering personnel and noted that an analysis fumished by Sargent and Lundy (S&L) entitled " Report on impact of Painting on
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Atmospheric Cleanup Systems at Clinton Power Station" stated that the application of 1.5 gallons of paint or less within a 24-hour period would not have an adverse impact on ventilation systems which communicated with the containment environment. The inspectors reviewed the report and were unable to determine the technicaljustification for
- the conclusion provided by S&L in that it did not provide information regarding the type of paint used to perform the analysis or the paint's VOC content. The licensee subsequently agreed to perform VG system testing since they were unable to support the conclusion given in engineering evaluation 1-97-12-23 Because the licensee initially believed that engineering evaluation 1-97-12-235 was technically valid,2.5 months were allowed to elapse prior to performing filter testing required by TS 5.5.7. On January 28,1998, the licensee attempted to perform testing of VG "A" to ensure that charcoal adsorber bed was not adversely impacted due to being exposed to paint. However, an error in work scheduling resulted in operations personnel testing the incorrect VG train. The inspectors considered this a weakness in attention-to-detail by both work control and operations personnel since an additional month was needed to perform testing on the correct VG train. On February 20, the licensee confirmed that the charcoal adsorber bed for VG "A" was not adversely impacted due to exposure to paint. However, the inspectors idemified that the licensee failed to test the HEPA filter. The inspectors discussed this with licensee personnel and additional testing on the HEPA filter was successfully completed on February 27,1998. The failure to perform testing on the HEPA filter and the charcoal adsorber for the standby gas treatment system following painting is considered a violation of TS 5.5.7. However, because this violation was based upon activities prior to the events leading to the current extended plant shutdown and satisfies 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 50-461/98006-03). j l
During the inspection period, a'l of the ECCS systems were considered inoperable but j available due to degraded voltage concems. Technical Specification 3.5.2, ECCS- '
Shutdown, requires that one VG train be restored to an operable status immediately when two or more ECCS systems were inoperable. Although the licensee was unable to restore a VG train to an operable status due to degraded voltage issues, no actions were taken to ensure that both VG trains remained available such that they could provide defense in depth for secondary containment integrity. The licensee's lack of action '
resulted in both VG trains being unavailable for 36 days. The failure to protect both VG trains to ensure that they were not made unavailable was considered a weakness in the i licensee's work control proces On February 27, the licensee re-commenced painting activities inside containment. The inspectors questioned the licensee's decision to perform painting activities since engineering personnel had not determined the amount of paint which could be applied in a 24-hour period and because no actions were taken to prevent the VG system from j communicating with the containment environment during system operation. This was j considered an additional weakness in the work control process. Subsequently, the i licensee stopped all painting activities and began taking actions to restore primary j containment integrity in order to prevent the VG system from communicating with the '
containment environmen .
O 4 Conclusions Engineering, operations, and work control personnel failed to appropriately implement the requirements of TS 5.5.7, " Ventilation Filter Testing Program." As a result, testing of the HEPA filter and the charcoal adsorber bed for the standby gas treatment system was not performed following painting in a ventilation zone which directly communicated with the standby gas treatment system for approximately 2.5 months. Two examples of poor work control were identified involving the failure to provide an available train of standby gas treatmen E2 Engineering Support of Facilities and Equipment E2.1 Inaooropriate Enaineerina Disposit on of Identified Coatina Deficiencies a. inspection Scope (37551)
The inspactors reviewed engineering dispositions of deficiencies associated with 1997 and 1998 containment coatings work performed as of March 19,199 b. Observations and Findinas The inspectors noted that Procedure 8901.08, " Field Coatings," specified a coating dry film thickness measurement of 4 to 6 mils (thousandths of an inch) for Carboline @ 890 coatings. During a review of MWR D77850, the inspectors noted that engineering personnel had accepted numerous dry film thiuness (DFT) measurements outside the rarige of 4 to 6 mits for coatings applied to metal substrate. Specifically, DFT
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measurements from 3.00 mils to 8.68 mils had been accepted for first coat application Additionally, for MWR D75335, engineering personnel had accepted DFT measurements of 6.73 and 6.84 mils for radiation protection signs inside containmen Modification A-155 was developed to perform testing necessary to support use of Carboline' 890 as a qualified containment coating. The inspectors reviewed the ,
modification test data and determined that the DFT for first coats applied to metal substrate rar:ged from 4.6 to 9.2 mils. - Based on review of the modification testing, the inspectors considered the engineering dispositions of DFT measurements greater than 6 mils to be acceptable. However, the inspectors noted that the modification testing did not support DFTs less than 4.6 mills. On March 26,1998, engineering personnel identified additional qualification test results, dated October 21,1993, which supported use of coating thicknesses down to 3.3 mils for first coats applied to metal substrat Based on review of the additional test results provided, the inspectors concluded that DFT ranges between 3.3 and 9.2 mills were acceptable. However, the licensee had not justified the acceptability of containment coatings applied on metal substrate in November 1997 which had a DFT measurement less than 3.3 mils (documented on coating work record "H").
On December 12,1997, engineering personnel reviewed the DFT measurements and inappropriately determined that DFT measurements less than 3.3 mils were acceptable even though the specific measurements (3.00 and 3.15 mils) were not supported by qualification testing. As a result, no corrective actions had been taken to appropriately l resolve the DFT measurements at the conclusion of the inspection.10 CFR Part 50, I
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I Appendix B, Criterion XVI, requires that measures be established to assure that j conditions adverse to quality such as deviations and nonconformances are promptly ,
identified and corrected. The failure to correct nonconformances associated with the DFT l measurements for containment coatings applied on November 17 or 18,1997, was considered a violation of 10 CFR Part 50, Appendix B, Criterion XVI. However, because this violation was based upon activities prior to the events leading to the current extended plant shutdown and satisfies 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 50-461/98006-04), Conclusions Engineering personnel inappropriately determined that the dry film thickness (DFT)
measurements for containment coatings applied in November 1997 were acceptable. As a result, appropriate corrective actions to resolve the inadequa'e DFT measurements had not been taken at the conclusion of the inspectio E8 Miscellaneous Engineering issues j E (Closed) Inspection Follow-up Item 50-461/96006-04: Magne-Blast breaker issues not l addressed until raised by the inspectors. NRC Inspection Reports 50-461/97003 and 50-461/97018 identified significant weaknesses in the licensee's maintenance program for safety and non-safety-related breakers. The licensee's actions to resolve deficiencies
.regarding Magne-Blast breakers will be reviewed as part of the follow-up Confirmatory Action Letter 97-00 E (Closed) Notice of Violation 50-461/97006-01: Failure to provide an adequate procedure for testing the containment ventilation system. The inspectors verified that the licensee revised applicable procedures to include a double verification signature for installing upstream and downstream sample lines for test equipment. The inspectors determined that the corrective actions sufficiently resolved this violatio E (Closed) Notice of Violation 50-461/97006-06: Failure to perform reactor pressure vessel hydrostatic test at the required pressure. As stated in inspection Report 97015, the inspectors compared the instructions given in Procedure 9059.01, " Reactor Coolant System Leakage Test," with ASME Code requirements and determined that all code requirements, including the required test pressure, were appropriately implemented. No additional concems were identifie IV. Plant Support R8 Miscellaneous Radiation Protection issues R (Closed) Notice of Violation 50-461/96009-09: Failure to wear protective clothing when crossing a contamination boundary. The inspectors reviewed the licensee's corrective actions and determined that they sufficiently resolved this violatio .
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P4 Staff Knowledge and Performance in EP P Performance of Emeroency Response Oraanization (ERO) Paoer Testina Inspection Scoce (71750)
Following the declaration of an Alert on February 13,1998, the inspectors and the licensee identified weaknesses in the ERO's ability to respond and activate ERO facilities within one hour, in response to this finding, the licensee initiated several pager tests to improve the ERO's performance and to emphasize the importance of emergency response activities. The inspectors reviewed the results of the pager tests to evaluate the responsiveness of on-call ERO personne Observations and Findinas Of the six pager tests conducted between March 24 and April 7,1998, only one test was considered acceptable with 100 percent of the ERO responding Performance during the remaining five pager tests was considered unacceptable in that multiple members of the ERO failed to respond to the pager test in a timely manner. For example, the results of a pager test performed on March 24, determined that 36 percent of the on-call ERO personnel failed to respond to their pagers. The results of two additional tests identified that key ERO positions may not have been fille Following each pager test, the licensee questioned on-call ERO personnel to determine why they had not responded to the pager test. The licensee identified that some individuals had reasonable excuses for not responding to their pagers. However, most ERO personnel failed to respond to the tests due to leaving their pagar at home, not having their pagers tumed on, not having their pager within hearing distance, or because they had not replaced a dead battery. Several personnel stated that they received a busy signal when they called the number given on the pager and then forgot to keep callin The failure to respond to an ERO pager drill due to any of the above reasons was considered unacceptable by plant management and symbolized the individual's insenMtivity to the emergency response functio The on-call ERO's failure to appropriately respond to pager tests was considered significant in that it called into question the licensee's ability to adequately staff and activate the emergency response facilities as described in the emergency plan. In response to the ERO's poor performance, the senior vice president sent a memorandum to all nuclear program employees clearly delineating the expectations for ERO respons Emergency planning personnel planned to perform additional unannounced, off-hours, ERO pager drills to monitor ERO performanc Conclusions Numerous personnel failed to respond _ to several pager tests. Specifically, only 1 of 6 pager tests had 100 percent response from emergency response personne ,
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l P8 Miscellaneous Emergency Response issues P (Open) Inspection Follow-up Item 98003-14: Activation of the Technical Support Cents Additional information regarding this issue is provided in Section P F5 Fire Protection Staff Training and Qualification F Performance of Fire Drill Inspection Scope (71750)
On March 26,1998, the fire protection group simulated a fire in the radwaste solidification room. The inspectors responded to the scene to monitor the performance of fire brigade personne Observations and Findinas Fire brigade members responded promptly to the scene of the simulated fire and demonstrated a good questioning attitude when they inquired about radiation levels due to a potential resin transfer taking place in the radwaste solidification room. The inspectors noted that many of the brigade members did not perform a negative pressure mask-to-face fit test after donning a self contained breathing apparatus (SCBA) to ensure that the SCBA mask formed a proper seat. The inspectors considered this a weakness since the failure of an SCBA to form an adequate fit could result in the fire brigade member inhaling hazardous or radioactive materials. The inspectors discussed this contem with licensee management from fire protection, operations, and radiation protection and leamed that employees who use SCBAs were trained to perform a negative pressure fit test prior to performing work in an area which required using an i SCBA, but not as part of fire brigade training. The licensee agreed to review negative pressure fit testing for fire brigade member ; Conclusions The fire brigade responded promptly and demonstrated gcod questioning attitude during the performance of a fire drill on March 26. One weakness regarding the performance of SCBA negative pressure fit tests was identifie V. Manaaement Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on April 14,1998. The licensee acknowledged the findings presente The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identifie .
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X3 Management Meeting Summary (
On March 17,1998, an 0350 Panel meeting between the NRC and Illinois Power was held in the !
Region ill Office. Topics of the meeting included improvements in the conduct of operations, the response to the February 13,1998, Alert, and corrective action program improvement ,
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l PERSONS CONTACTED Licensee W. MacFarland IV - Senior Vice President G. Hunger, Jr. - Plant Manager W. Romberg, Manager- Nuclear Station Engineering Department R. Phares, Manager - Nuclear Safety and Performance improvement G. Baker, Manager - Quality Assurance ;
J. Goldman, Manager - Work Management V. Cwietniewicz, Manager - Maintenance W. Maguire, Director - Operations M. Tacelosky, Supervisor - Operations Services ,
D. Smith, Director - Security / Emergency Planning l J. Place, Director - Plant Radiation and Chemistry i J. Sipek, Director - Licensing j l
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INSPECTION PROCEDURES USED IP 37551: Engineering IP 61726: Surveillance Observations IP 62707: Maintenance Observations IP 71707: Operations IP 71750: Plant Support >
IP 92901: Operations - Followup IP 92902: Maintenance - Followup IP_92903: Engineering - Followup IP 92904: Plant Support - Followup ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-461/98006-01 URI Review of additionalinformation regarding allowable humidity levels during application of containment coating /98006-02 NCV Enforcement Discretion: Failure to take corrective actions for degraded containment coatings resulted in ECCS strainer inoperabilit /98006-03 NCV Enforcement Discretion: Failure to test HEPA filter and charcoal absorber bed in standby gas treatment system following exposure to pain /98006-04 NCV Enforcement Discretion: Failure to take appropriate corrective actions to resolve deficiencies in dry film thickness measurements for containment coating Closed 50-461/95015-01 IFl Continued personnel errors in implementing safety tagging progra /97006-09 VIO Inadequate procedures for surveillance testing due to preconditionin ,
50-461/97006-10 VIO Improper storage of manuals in the main control roo /97011-01 VIO Failure to follow procedure during control room chilled water valve operability tes /96-011 LER Priming of the EDGs during surveillance testing determined to be preconditionin /96-012 LER Failure to demonstrate operability of offsite sources while operating the Division 111 EDG in the droop mod I 20 l l
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50-461/97011-03 VIO Failure to have EDG valves in the locked valve progra /97011-11 VIO Inadequate procedural controls for the control of transient materials ,
inside containmen j 50-461/97015-06 URI Operability of ECCS suction strainers due to degraded containment coating /97-020 LER Potential failure of containment coatings could render ECCS pumps inoperable due to inadequate net positive suction head
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resulting from ECCS strainer cloggin /97-023 LER inadequate work instructions leads to potential over-greasing of motor bearings causing potential failure of various motor !
50-461/96006-04 IFl Magne-Blast breaker issues not addressed until raised by the l
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inspectors, l 50-461/97006-01 VIO Failure to provide an adequate procedure for testing of the containment ventilation syste I 50-461/97006-06 VIO Failure to perform reactor pressure vessel hydrostatic test at the required pressur /96009-09 VIO Failure to wear protective clothing when crossing a contamination boundar Discussed 50-461/98-002 LER Loss of service air results in unplanned engineered safety features actuation and manual reactor scra /98004-04 NCV Failure to perform adequate risk assessment and contingency plannin /98003-14 IFl Activation of the Technical Support Center l
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l LIST OF ACRONYMS l
CC Component Cooling Water l
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DFT Dry Film Thickness ECCS Emergency Core Cooling System EDG Emergency Diesel Generator ERO Emergency Response Organization HEPA High Efficiency Particulate Air MWR Maintenance Work Request NPSH Net Positive Suction Head NSPS Nuclear System Protection System RHR Residual Heat Removal S&L Sargent and Lundy SA Service Air SCBA Self Contained Breathing Apparatus TS Technical Specifications VG Standby Gas Treatment System VOC Volatile Organic Compound WRB Work Review Board WS Service Water l l
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