IR 05000298/1998002: Difference between revisions

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{{Adams
{{Adams
| number = ML20236Y216
| number = ML20249A807
| issue date = 08/06/1998
| issue date = 06/11/1998
| title = Ack Receipt of Informing NRC of Steps Taken to Correct Violations Noted in Insp Rept 50-298/98-02. Implementation of Corrective Actions Will Be Reviewed During Future Insp to Determine That Full Compliance Have Been Met
| title = Errata to Insp Rept 50-298/98-02,dtd 980515.Changes Have Been Made to Fourth Paragraph
| author name = Gwynn T
| author name =  
| author affiliation = NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
| author affiliation = NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
| addressee name = Horn G
| addressee name =  
| addressee affiliation = NEBRASKA PUBLIC POWER DISTRICT
| addressee affiliation =  
| docket = 05000298
| docket = 05000298
| license number =  
| license number =  
| contact person =  
| contact person =  
| document report number = 50-298-98-02, 50-298-98-2, NUDOCS 9808120003
| document report number = 50-298-98-02, 50-298-98-2, NUDOCS 9806180267
| title reference date = 07-23-1998
| package number = ML20249A052
| document type = CORRESPONDENCE-LETTERS, OUTGOING CORRESPONDENCE
| document type = INSPECTION REPORT, NRC-GENERATED, TEXT-INSPECTION & AUDIT & I&E CIRCULARS
| page count = 4
| page count = 1
}}
}}


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g[ 'g UNITED STATES g  NUCLEAR REGULATORY COMMISSION L cj  REGION IV C & 611 RYAN PLAZA DRIVE. SUITE 400
    %, ,e  ARUNGTON. TEXAS 76011-8064
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AllG -61998 I
G. R. Horn, Senior Vice President of Energy Supply Nebraska Public Power District 141415th Street
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Columbus, Nebraska 68601 SUBJECT: NRC INSPECTION REPORT 50-298/98-02
 
==Dear Mr. Horn:==
Thank you for your letter of July 23,1998, in response to our letter and Notice of Violation dated May 15,1998. We have reviewed your reply and find it responsive to the concerns raised in our Notice of Violation. We will review the implementation of your corrective actions during a future inspection to determine that full compliance has been achieved and will be maintained.
 
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Sincerely, I
      " T oma I.# 'y . Director ivision or Projects p
Docket No.: 50-298 License No.: DPR 46 cc:
John R. McPhail, General Counsel Nebraska Public Power District P.O. Box 499 Columbus, Nebruka 68602-0499 J. H. Swailes, Vice President of    \
Nuclear Energy Nebraska Public Power District    ,9(
P.O. Box 98 Brownville, Nebraska 68321    ')
9808120003 980806  i
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PDR ADOCK 05000298 e  PDR
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Nebraska Public Power District -2-B. L. Houston, Nuclear Licensing a'id Safety Manager Nebraska Public Power District P.O. Box 98 Brownville, Nebraska 68321 Dr. William D. Leech MidAmerican Energy 907 Walnut Street P.O. Box 657 Des Moines, Iowa 50303-0657 Mr. Ron Stoddard Lincoln Electric System 1040 O Street P.O. Box 80869 Lincoln, Nebraska 68501-0869 Randolph Wood, Director Nebraska Department of Environmental Quality P.O. Box 98922 Lincoln, Nebraska 68509-8922 Chairman Nemaha County (3oard of Commissicwrs Nemaha County Courthouse 1824 N Street Auburn, Nebraska 68305 Cheryl Rogers, LLRW Program Manager Environmental Protection Section Nebraska Department of Health 301 Centennial Mall, South P.O. Box 95007 Lincoln, Nebraska 68509-5007 R. A. Kucera, Department Director of Intergovernmental Cooperation Department of Natural Resources P.O. Box 176 Jefferson City, Missouri 65102 Kansas Radiation Control Program Director i
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Nebraska Public Power District    -3-Atg _ g ggg bec to DCD (IE01)
bec distrib. by RIV:
Regional Administrator    Resident inspector DRP Director    DRS-PSB Branch Chief (DRP/C)    MIS System Branch Chief (DRP/TSS)    RIV File Project Engineer (DRP/C)
E DOCUMENT NAME: R:\._CNS\CN802AK.MHM To receive copy of document, indicate in box: "C" = Copy without enclosures "E" = Copy with enclosures "N" = No copy RIV:PE:DRP/C l/PN AC:ORP/C    D:DRP l ,  l l JFMelfi;df U  CSMarscha@ TPGwynn RBP 8/ f/98    8/ 6 /98 8/ln/98 OFFICIAL RECORD COPY
 
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Nebraska Public Power District      -3-AUG - 6 1998 WTodiDCb'llE01)2.J bec distrib. by RIV:
Regional Administrator      Resident inspector DRP Director      DRS-PSB Branch Chief (DRP/C)      MIS System RIV File I- Branch Chief (DRP/TSS)
Project Engineer (DRP/C)
I DOCUMENT NAME: R:\_CNS\CN802AK.MHM To receive copy of document, indicate in bor "C" = Copy without enclosures "E" = Copy with enclosures "N" = No copy RIV;PE:DRP/C l/7N AC:DRP/Cl      D:DRP l ,, l JFMelfi;df U  CSMarscha@l TPGwynn RBP 8/ f/98    8/ ( /98  8/l_n /98 OFFICIAL RECORD COPY 110003
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P.O. DOX B E NEB SKA 68321
steam flow required to maintain peak critical centerline temperature less than 1500*F for an uncovered core, (3) maximum time before peak centerline temperature exceeds 1500*F for an uncovered core referenced to POHGH equal 13.4 kw/ft,~ (4) the cold shutdown boron concentration requirements, and (5) the , hot shutdown boron
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Nebraska Public Power District    "iL%%C,''"
concentration requirement. The emergency operating procedure parameters ultimately L  ' effected by these concems were listed as the boron injection initiation temperature, cold L shutdown boron wait, peak capacity level limit, heat capacity temperature limit, hot shutdown boron weight, minimum alternate reactor pressure vessel flooding pressure, L  minimum core flooding interval, maximum core uncovery time limit, minimum number of safety relief valves required for emergency depressurization, minimum reactor pressure vessel flooding pressure, minimum steam cooling reactor pressure vessel water level, l  minimum zero reactor pressure vessel water level, peak centerline temperature,
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NLS980094
pressure-suppression pressure, and peak linear heat generation rate. The licensee had addressed only the top of active fuel parameter.-
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The licensee issued Problem identification Report 2-27287 to document that an apparent discrepancy existed with the 0-inch level assumed as the top of active fuel in the vesse The licensee noted that 150-inch fuel potentially extended to above the zero leve The licensee evaluated the safety significance of the 6-inch nonconservative bias.
July 23,1998        7 i ' 3. - '
li E g 2. O U.S. Nuclear Regulatory Commission Attention: Document Control Desk      '
Washington, D.C. 20555-0001 Gentlemen:
Subject:    Reply to a Notice of Violation NRC Inspection Report No. 50-298/98-02 Cooper Nuclear Station, NRC Docket 50-298, DPR-46 Reference:
1. Letter to (NPPD) from E.E. Collins (USNRC) dated May 15,1998,
      "NRC Inspection Report 50-298/98-02 and Notice of Violation" By letter dated May 15,1998 (Reference 1), the NRC cited Nebraska Public Power District (District) for being in violation of NRC requirements. This letter, including Attaciunent 1, constitutes the District's reply to the referenced Notice of Violation in accordance with 10 CFR 2.201. The District admits to the violations and has completed the corrective actions necessary to return Cooper Nuclear Station to full compliance.
 
Should you have any questions concerning this matter, please contact me.
 
Sincer  ,
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John H. Swailes Vice President of Nuclear Energy
/rss Attachment cc: Regional Administrator USNRC - Region IV        '
Senior Project Manager USNRC - NRR Project Directorate IV-1        l 33' I 8~7[a
 
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i NLS980094 July 23,1998
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Senior Resident Inspector USNRC NPG Distribution l
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Attachment I to NLS980094 Page1of11 REPLY TO MA ? 15,1998, NOTICE OF VIOLATION
 
COOPER NUCLEAR STATION  l NRC DOCKET NO. 50-298, LICENSE DPR-46 During NRC inspection activities conducted from March 8 through April 18,1998, two violations of NRC requirements were identified. The violations and the District's reply are set forth below:
Violation      l
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A. 10 CFR Part 50, Appendix B, Criterion V, requires, inpart, that activities affecting
 
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quality shall be prescribed by documentedprocedures and instructions of a type appropriate to the circumstances... Instructions, procedures shallinclude appropriate ,
quantitative or qualitative acceptance criteriafor determining that important activities have been satisfactorily accomplished Contrary to the above, 1. Procedure 7.2.63, "High Pressure Coolant Injection Stop Valve flydraulic Cylinder ~ Maintenance, " was inappropriate to the circumstances and did not have appropriate acceptance criteria, in that the required torque value was not given in work instructionsfor theflange bolts. The procedure directed theflange bolts be tightenedas opposedto beingfastenedwith the specific torque value. The bolts were tightened without acceptance criteria, leading ultimately to stripped threads and a control oilleakfrom the high pressure coolant injection turbine stop valve hydraulic actuator.
 
This is a Severity LevelIV violation (Supplement 1) (50-298/98002-02).
 
Ahnission or Denial to Violation The District admits the violation.
 
Reason for Violation l
l The reason for this violation is inadequate corrective actions by Cooper Nuclear Station (CNS)
l to prevent over torquing and causing the high pressure coolant injection system (HPCIS) to become inoperable. Corrective actions to a previous Licensee Event Report (96-013-01) were insufficient in that the review for extent of condition missed one procedure that was identified by the resident inspector.
 
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Attachment 1 to NLS980094 Page 2 of 11 The CNS Licensee Event Report (LER) 96-013-01, " Inoperable High Pressure Coolant Injection System Due to Control Oil Leak on Turbine Stop Valve Actuator," was submitted to the NRC  4 because the HPCIS was declared inoperable as a result of a control oilleak caused by stripping of
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the threads on one of the four flange studs. The apparent cause for the failure of the stud is over- :
torquing. Procedure 7.2.63 directed the studs be " tightened" as opposed to being " torqued" to a  ,
specific value.
 
The corrective actions frr this event included revising Procedure 7.2.63 and a search of the maintenance procedures containing the word " tighten." This search was made to assess the  -
f adequacy of the maintenance procedures with respect to torquing rmuirements. The search using 7.2 series maintenance procedures identified 114 procedures. Irsptition Report 50-298/98-02, Section M8.1, indicates that the inspectors identified 12 additional procedures beyond the 114 identified by CNS. A review of these 12 procedures indicated that Procedure 7.2.34.9 was deleted on October 30,1997, and 10 procedures except Procedure 7.2.47 are consistent with the vendor's numuals. It was determined that Procedure 7.2.47 did not contain the word torque as included in the vendor manual.
 
The technique used for searching procedures containing the word " tighten" was inadequate.
 
Maintenance Management inappropriately directed that the search be limited to 7.2 series procedures and failed to provide the needed guidance for conducting the search. Results of the procedure search were not appropriately verified, resulting in the failure to identify the missed procedures. Maintenance Management overview of the corrective actions for LER 96-013-01 was inadequate.
 
Corrective Steos Taken and the Results Achieved Procedure 7.2.47, "MSIV Air Manifold Removal, Overhaul, Testing and Installation," has been revised reflecting the vendor reconunended torque values.
 
A review of all of the 114 maintenance procedures determined that use of the words " tighten" and
" torque" is consistent with the vendor manuals.


A training session for maintenance supervisors was held, and the Maintenance Manager's expectations to prevent recurrence of this problem, as well as global ramifications, were  j
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conveyed.
Vendor testing had found that fuel peak centerline temperatures of 1800*F would not be -
reached until vessel water level dropped below -70 inches (below top of active fuel). The licensee performed an evaluation which considered various instrument errors, including errors expected in a harsh equipment qualification environment. They found that the 1800'F limit would rot be reached even with the 6-inch nonconservative instrument bia The failure to incorporate the correct fuel length design requirements in plant emergency operating procedures is an example of a violation of 10 CFR Part 50, Appendix B, Criterion V, which requires, in past, that procedures be appropriate to the circumstances (50-298/98002-02).


, Department supervisors held training sessions with their groups to review consequences of not i
Additiona'l questions which remain to be resolved include: (1) Technical Specification interpretation 96-003 which documented that the fuel length indicated in Technical Specification was 144 inches, although the Updated Safety Analysis Report stated that active fuel length was 150 inches. The resolution associated with the interpretation
performing thorough procedure searches, and not verifying the vendor instructions during procedure reviews / revisions.
  - concluded that the conversion to improved Technical Specifications would remove the
 
!"  . ' associated figure which showed the top of active fuel relative to the 144-inch active fuel length. The recalculation of setpoints for improved Technical Specification would be done in accordance with General Electric setpoint methodology and instrument zero    j would be redefined as a fixed point above the fuel which will be defined for the purposes    '{
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of level monitoring as top of active fuel. The interpretation stated that the reference in   i the Technical Specification bases was not a basis for the limiting safety system setting .
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and that safety margin for transient and accident analysis was maintained through    I administrative controls such as higher trip setpoints and emergency operating 4 -  procedures; This Technical Specification request dated June 8,1996, stated that the safety limit was maintained regarding General Electric setpoint methodology, inspectors    i ADOCk r -
 
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l Attachment I to NLS980094 Page 3 of 11 Corrective Steos That Will be Taken to Avoid Further Violations    {
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Procedure 7.0.4, " Conduct of Maintenance" will be revised by August 11,1998, to provide directions that the torque values provided by the vendor are included in maintenance procedures.
 
A global search of CNS maintenance procedures, which have not been previously reviewed for
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the word " tighten," will be performed by October 1,1998, to ensure that these procedures are  l consistent with the vendor recommended torque values. l Date When Full Comoliance Will be Achieved The District is in full compliance regarding the identified violation.
 
A. 2. On February 11,1998, Procedure 7.0.15, " Station Painting Guidelines, "
Revision 3c1 was not appropriate to the circumstances, in that it did not appropriately control the application ofwater-basedpaint with volatile organics in the reactor building. Procedure 7.0.15 allowedseveralgallons ofpaint to be drying in the reactor building which containeda sigmficantfraction ofether-based and acrylate-based compounds. These compounds coulddegrade the  '
standby gas treatment system.
 
This is a Severity LevelIV violation (Supplement 1) (50-298/98002-02).
 
Admission or Denial to Violation The District admits the violation.
 
l Reason for Violation      l l
The reason for this violation is the failure to incorporate controls for paint with a significant fraction of organics which had the potential to affect the standby gas treatment system. j Water-based paint was used for painting inside the secondary containment boundary, which communicates with the standby gas treatment (SGT) system. CNS Procedure 7.0.15 excluded the water-based paints from the limitations imposed on other paint types. This exclusion led painting personnel to believe that the levels of volatile organic compounds (VOCs) in the water-based paints were not a concern. CNS personnel responsible for station painting activities reviewed the  l material safety data sheet and identified the paint to be water-based; however, due to their misunderstanding of VOCs in the water-based paints, their review did not include a check of the VOC content and its impact on the plant equipment. Further, a discussion with the paint supplier  l I
 
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Attachment I to NLS980094 Page 4 of11 l
  (Keeler & Long) indicated that not long ago the water-based paint was commonly referred to as latex paint with no VOCs.
 
On February 11,1998, the NRC Senior Resident Inspector questioned the paint fumes in the reactor building. It was determined by CNS that the paint contained VOCs, which were causing the odor given off by the paint fumes. An engineering evaluation was performed to determine the potential adverse effect of the paint used on the SGT system activated charcoal filters.
 
In this evaluation, a worst-case scenario, including isolation of the normal reactor building ventilation system and all VOCs adsorbed in the SGT charcoal filter of one train was considered.
 
It was determined that a total loading of the SGT system could be as high as 9.1% (weight) of  I VOCs. The most recent iodine filtering efliciency tests of the charcoal in the SGT system were found to be 99.96% and 99.95% for trains A and B, respectively. Industry testing has found that a 10% (weight) loading of charcoal is equivalent to 1% (approximately) loss of filter efficiency5 .
The CNS Technical Specifications require a filter efliciency of equal to or greater than 99%.
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Based on this test information, and the conservative assumptions used in the engineering evaluation, it was concluded that, during and aller the painting activities, the SGT trains would
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have been operable had a design basis event occurred.
 
Subsequent to the painting activities inside the reactor building, laboratory tests were performed utilizing samples of the paint used at CNS and the charcoal similar to that currently installed in the SGT system. These tests determined that filter loading up to 16% VOCs (weight) resulted in an
 
undetectable loss of filter efficiency . The results of this test support the CNS conclusion of continued operability of the SGT system, under both accident and normal operating conditions.
 
i Corrective Steos Taken and the Resuhs Achieved All painting activities in the reactor building were suspended, and painting Procedure 7.0.15 was placed on administrative hold.
 
An operability evaluation of the SGT trains was performed. It was concluded that the SGT trains would have been operable had a design basis accident occurred during or following the painting activities.
 
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  "" Study of the Effect of Coatings Operation on Radiciodine Removing Adsorbents," by l  W. P. Freeman and J. C. Enneking,21st DOE /NRC Nuclear Air Clear.ing Conference, l  August 11,1990.      .
2 Determination of Radiciodine Efliciency of Nuclear Grade Carbon Exposed to incremental Mass Loadings of VOC's from Keeler & Long Aqua Kolor Enamel, NCS Corporation, dated May 27,1998.
 
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Attachment I to NLS980094 Page 5 of11 Corrective Stens That Will be Taken to Avoid Further Violations The painting Procedure 7.0.15 will be revised by August 26,1998, to include limitations /
restrictions for the use of water-based paints. The revised procedure will include the consideration of VOC contents regardless of the type of the paint to be used.
 
Date When Full Comnliance Will be Achieved The District is in full compliance regarding the identified violation.
 
A. 3. Emergency Operating Procedure 2A, " Containment Control, " listed reactor vesselparametersfor when operators shoulddepressurize the plant with the water level at top ofactivefuel and at a level in thefuel bundle to prevent exceeding 1800 *F. The water levelparameters were based on a levelthat was biased 6 inches in the nonconservative direction, as a result ofan increase it:fuellength.
 
I This is a Severity LevelIV violation (Supplement 1) (50-298/98002-02)  )
Admission or Denial to Violation
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The District admits the violation.
 
Reason for Violation The reason for this violation is failure to verify that the Emergency Operating Procedure (EOP)
calculation input values were consistent with the relevant design and licensing basis.
 
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The Fuel Zone instruments LI-91 A,B,C are scaled so that zero scale corresponds to the top !
of active fuel (TAF) at 144" This instrumentation is used to indicate the reactor pressure vessel (RPV) water level following a loss of coolant accident, and to verify core reflood by the ;
emergency injection systems. The elevation of 352.56" above the vessel bottom, as defined in !
Technical Specification (TS) Figure 2.1.1, was not changed to 358.56" when the 150 inch fuel was introduced in Cycle 4. This was because the core reload reviews narrowly focused on the '
parameters that affected the core reload and setpoint analyses. The TAF is ..ot referenced in the core reload analyses.
 
The present EOPs were developed in 1991, following the issuance of Revision 4 of the Boiling
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Water Reactor Owners Group Emergency Procedure Guidelines (BWROG EPG). In these procedures, some of the calculations that formed the basis for the operator actions used 150" as the fuel length parameter. However, a decision was made to use 144 inches for three TAF related parameters - reactor water level, the mass of the reactor vessel and internals, and the volume of
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Attachment I to NLS980094 Page 6 of11      l reactor vessel and piping. This decision was based on Technical Specification Figure 2.1.1 and the conventional understanding that the active fuel length was the length of enriched fuel, not the full length that included the reflector, made of natural uranium.
 
The impact ofusing 144" of fuellength on EOPs was evaluated. It was determined that this condition does not invalidate the effectiveness of current EOP operator actions. The effects of initiating reactor depressurization with 6 inches less water with respect to the top of fuel are well ;
within the existing design margins.
 
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l The impact ofinitiating the operator actions with water level 6 inches lower was specifically evaluated, for fuel similar to that used at CNS by the BWROG Emergency Procedure Committee in EPG Issue 9704, in 1997. Affected action levels are Minimum Zero Injection RPV Water Level (MZIRWL) and Minimum Steam Cooling RPV Water Level (MSCRWL). MZIRWL is the lowest RPV water level at which the covered portion of the reactor core will generate sufficient steam to preclude cladding temperature from exceeding 1800 degrees Fahrenheit. MSCRWL is the lowest RPV water level at which the covered portion of the reactor core will prevent the temperature of the uncovered cladding from exceeding 1500 degrees Fahrenheit. The calculated EOP action levels are at -43.8 inches for MZIRWL and -31.2 inches for MSCRWL. The improved BWROG evaluation methodology, showed that for MZIRWL, the peak cladding temperature would not be reached until reactor water level dropped to approximately -69 inches on the fuel zone instrument.
 
Additional margin is available because of other assumed uncertainties. The BWROG addressed the instmment uncertainties in EPG Issue 9704. The calculated levels are rounded up to the nearest 10" because of scale graduation (-30" versus calculated -31.2" for MSCRWL and -40" instead of-43.8" for MZIRWL).
 
The additional issues included in the Notice of Violation are responded to as follows:
The LI-91 instrument errors and calibration tolerances were considered in the engineering evaluation performed by CNS. An accuracy of +/- 22.6" was used for LI-91 during initial development. This was specified over the -150" to +225" range of fuel zone instrument under !
accident conditions. In addition, CNS evaluation indicated conservatism (5-10") that results from l requiring the operators to use pressure correction when reading the fuel zone level. l The inspection report states that CNS did not address commitments to the NRC regarding implementation of the BWROG guidelines with respect to the 1800 degree Fahrenheit cladding temperature limit. CNS has determined that RPV water level of-6" for TAF does not warrant e.n immediate correction. CNS has committed, under the EOP maintenance program, to correct l identified deficiencies within 90 days, if the deficiency would render one of the success paths of l
 
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Attachment I to NLS980094 Pcge 7 of 11 the respective EOP Flowchart or Support Procedure unworkable under accident conditions.
 
The needed EOP revisions are being tracked under the prescribed procedures.
 
In addition, the report also states that the licensee did not properly address the parameters used in generic vendor calculations described in General Electric Service Information Letter 529, Supplement 1, dated March 14,1997. General Electric informed CNS that the generic fuel data supplied with the original Revision 4 of the EPGs still apply. No further action is required until CNS changes the present fuel design to 9X9 or 10x10 types.
 
CNS performed the calculations to determine the effect of 6" fuel length difference on minimum core flooding interval (MCFI). It was determined that MCFIincreased from 20.5 minutes for 144" fuel to 20.6 minutes for 150" fuel. This difference is indistinguishable to operators using the logarithmic scale graph.
 
The EOP parameters not adjusted for change in fuel length are not used in calculation associated with hot shutdown or cold shutdown boron weights. Both of these concentrations are calculated assuming that the reactor pressure water level is at the high trip setpoint. No credit was taken for water level control to TAF.
 
Corrective Actions Taken and Results Achieved CNS evaluated the impact of-6" TAF on EOPs. It has been determined that this condition does not invalidate the effectiveness of current EOP operator actions, or warrant immediate EOP changes.
 
Corrective Stens That Will be Taken to Avoid Further Violations The Improved Technical Specification implementation team identified changes that are needed to correct TS Figure 2.1.1, which is being relocated to the USAR. These changes will be completed by September 16,1998, following relocation to the USAR.
 
Options for clarifying action levels on the fuel zone level instrumentation and defming TAF for the purposes of EOP implementation will be evaluated. The needed changes will be implemented by November 15,1998.
 
The station Emergency Plan and operating procedures will be reviewed to identify any TAF
! references and revised as necessary to reflect the 150" fuel by November 15,1998.  ,
i EOP calculations will be reviewed, in conjunction with Severe Accident Management implementation, to identify and correct any discrepancies introduced by the change in fuel length from 144" to 150" This will be completed by December 31,1998.
 
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Attachment I to NLS980094 Page 8 of 11 An EOP/ design basis review will be conducted by March 31,1999, as per Action 3.3.e of the
" Strategy for Achieving Engineering Excellence."    i
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l The organizational capabilities needed to support consistent access to and application of design l
uformation into EOPs will be developed. This development will be accomplished through
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implementation of the action plans for Action 1.1 of the " Strategy for Achieving Engineering Excellence."      l j
Date When Full Comoliance Will be Achieved The District is in full comp!iance regarding this violation.
 
B.        I 10 CFR Part 50, Appendix B, Criterion XVI, requires, inpart, measures shall be
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established to assure that conditions adverse to quality, such asfailures, malfunctions, deficiencies, deviations, defective materialandequipment, andnonconformances, are promptlyidentifiedandcorrected Contrary to the above, 1. The licensee statedin the response to the Notice of Violationfor Violation 298/97006-01, as corrective actionfor a condition adverse to quality, that a review of Technical Specipcations would be performed to identify all operability verifications requiredprior to a mode change, by September 2,1997, a ad that procedures would be revised by October 15,1997. On March 11,19.c8, the licensee identifed that this review did notfind that the average power range monitors had not been required byprocedures to be tested within a weekprior to placing the mode switch in the run position.
 
This is a Severity LevelIV violation (Supplement 1) (50-298/98002-03)
Admission or Denial to Violation The District admits the violation.
 
Reason for Violation The reason for this violation is that Cooper Nuc. lear Station's corrective actions failed to identify all Technical Specifications operability verification mquirements.
 
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Attachment I to NLS980094 Page 9 of 11 The NRC Inspection Report 50-298/97-06, Notice of Violation, consisted of twe examples of inadequate procedures. In the first example, no procedure allowed the use ofinstelled 24-inch
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valves for inerting. The second example involved Procedure 2.1.1, "Stanup Procedure," which allowed the operators to place the mode switch in the stanup/ hot standby position pcior to performing the daily jet pump operability check contrary to the Technical Specification'n 4.6.E requirement. P response to this violation, CNS committed to take two corrective actions to  {
i avoid further violations. The first corrective action was to perform a comprehensive revi: .v of the Technical Specifications to identify all operability verifications required prior to a mode change consistent with Technical Specification 1.0.J; and the second was to revise, as necessary, Procedure 2.1.1.2, " Technical Specifications Pre-Startup Checks," to incorporate all the operability verifications identified by Technical Specifications review.
 
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The CNS corrective steps to avoid further violations, as stated in the response to Notice of Violation 97-06, were inadequate. During the review of Procedure 2.1.1.2,23 changes were made to the procedure, and 67 surveillance tests for verification were added. The inadequate  {
average power Iange monitors (APRMs) change to Procedure 2.1.1.2 was not realized by Operations Support Group personnel generating the changes or by personnel reviewing the changes because of a lack ofrigor.
 
Corrective Actions Taken and Results Achieved Procedure 2.1.1.2 was revised on May 27,1998. Section 8.4 of this procedure now contains the APRM surveillance requirement prior to reactor startup (within a week).
 
A comprehensive review of procedures was performed to capture all operability verifications as per the Technical Specification 1.0.J requirements.
 
Corrective Steps That Will be Taker to Avoid Funher Violations Procedure 2.1.1 will be revised prior to next plant stanup to include: (1) mode change requirements in Procedure 2.1.1.2, Sections 8.4 and 8.6; and (2) a verification signature from the Surveillance Coordinator that s11 the surveillance requirements listed in Procedure 2.1.1.2 are complete and current for plant startup.
 
D_ ate When Full Comoliance Will be Achieved The District is in full compliance regarding this violation.    \
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Attachment I to NLS980094 Page 10 of 11 B. 2.
 
In response to Violation 298/96024-07, the licensee identified that improper changes were made to emergency operatingprocedures because no operations ;
review was required,for modifications, before 199L For this condition adverse to quality, the licensee 's actions were not comprehensive in that they did not  1 conduct reviews to determine ifotherprocedures had been adversely affected by earlier modifications.
 
This is a Severity LevelIV violation (Supplement) (50-298/98002-03).
 
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Admission or Denial to Violation The District admits the violation.
 
Reason for Violation The reason for this violation is the failure to identify all the affected conditions during the translation of design information to Emergency Operating Procedures (EOPs). This failure represents a missed opportunity to identify the causes of the programmatic weaknesses. Instead, the reviews focused on design changes that may have affected the EOPs. A broader review of the EOPs against design criteria would have detected the issues identified in this report.
 
In 1997, during a review of DC 90-001, "RCIC Alternate Boron Injection," against the EOPs, it was recognized that the design change (DC) operational description was not distinctly reflective of EOPs. As a result, Step 6.5.6 was added to EOP 5.8.8, " Alternate Boron Injection and Preparation," to remind the operators to economize other sources ofinjection to maximize alternate boron injection rate and avoid potential reactor vessel overfill. Because of this change, Operations reviewed other EOPs and supporting procedures, and determined that no other procedures were affected. This review, however, was not formally documented. During the review performed in 1997, CNS missed an opportunity for a broader review of EOPs against the design criteria.
 
The response to the Notice of Violation 50-298/96024-07 stated that "the design change process was revised in 1991 to include an EOP review in the checklist used for the development of modification packages. Had this review been in place at the time DC 90-001 was reviewed and approved, the inconsistency introduced by its approval would have been detected." CNS has traditionally reviewed DCs against operating and supporting procedures. The documentation l prior to 1991 was a signature on " Station Modification Cover Sheet" by Operations. In,1991, a
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checklist was added to ensure that a more structured review would be conducted. In order to verify that CNS performed adequate reviews, a sample review of 188 DCs prepared during 1989 through 1991 was performed. It was found that five had impact on EOPs. These five DCs were
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. Attachment I to NLS980094 Page11 of11 reviewed against EOPs, and it was determined that these DCs were properly reflected in the EOPs.
 
Corrective Actions Taken and Results Achieved CNS has performed a comprehensive evaluation under Significant Condition Adverse to Quality (SCAQ) 98-0358 of the extent of condition review performed in 1997. No other conditions were identified to affect the EOPs as a result of the improper design change translation.
 
Corrective Steps That Will be Taken to Avoid Further Violations An EOP/ design basis review will be conducted by March 31,1999, as per Action 3.3.e of the
" Strategy for Achieving Engineering Excellence,"
Procedure 0.5, " Problem Identification and Resolution," will be revised by October 1,1998, to clarify the extent of condition requirements.
 
The effectiveness reviews of corrective actions implemented under previous evaluations of SCAQs will be developed and implemented by December 31,1999, as per Actions 3.3.h and 3.3.i of the " Strategy for Achieving Engineering Excellence."
 
Date When Full Comoliance Will be Achieved The District is in full compliance regarding the identified violation.
 
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,  l ATTACHMEST 3  LIST OF ERC COMMITMENTS l
Correspondence No:NLS980094
 
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The following table identifies those actions committed to by the District in this
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document. Any other actions discussed in the submittal represent intended or planned actions by the District. They are described to the NRC for the NRC's l  information and are not regulatory commitments. Please notify the NL&S Manager at l  Cooper Nuclear Station of any questions regarding this document or any associated regulatory connitments.
 
COMMITTED DATE COMMITMENT  OR OUTAGE Procedure 7.0.4,  " Conduct of Maintenance" will be revised l  by August 11, 1998 to provide directions that the torque  August 11, 1 998 l  values provided by the vendor are included in maintenance l  procedures.
 
A global search of CNS maintenance procedures which have not been previously reviewed for the word " tighten" will
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be performed by October 1, 1998, to ensure that these  October 1, 1998
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l  procedures are consistent with the vendor recommended l  torque values.
 
The Painting Frocedure 7.0.15 will be revised by
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August 26, 1998 to include limitations / restrictions for the use of water-based paints. The revised procedure  August 26, 1998 '
;  will include the consideration of VOC contents regardless of the type of the paint to be used.
 
The Improved Technical Specification implementation team identified changes that are needed to correct TS Figure  September 16, 1998 2.1.1, which is being relocated to the USAR. These changes will be completed by September 16, 1998, following relocation to the USAR.      {
l  Options for clarifying action levels on the fuel zone level instrumentation and defining TAF for the purposes  November 15, 1998 of EOP implementation will be evaluated. The needed changes will be implemented by November 15, 1998.
 
The station Emergency Plan and operating procedures will be reviewed to identify any TAF references and revised to  November 15, 1998 reflect the 150" fuel by November 15, 1998.
 
EOP calculations will be reviewed, in conjunction with Severe Accident Management implementation, to identify  December 31, 1998 and correct any discrepancies introduced by the change in fuel length from 144" to 150". This will be completed by December 31, 1998.
 
The organizational capabilities needed to support consistent access to and application of design  Per Action 1.1 of o
information into EOPs will be developed. This development will be accomplished through implementation  Afhie g Engineering
[  of the action plans for Action 1.1 of " Strategy for  Excellence" l  Achieving Engineering Excellence."
 
Procedure 2.1.1 will be revised prior to next plant startup to include: (1) mode change requirements in  P r to mext plant l
l Procedure 2.1.1.2, Section 8.4 and 8.6; and (2) a  sa f either a verification signature from the Surveillance Coordinator  .
forced outage or RFO- i
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that all the surveillance requirements listed in  18, whichever comes Procedure 2.1.1.2 are complete and current for plant  first startup.
 
An EOP/ design basis review will be conducted by March 31, 1999, as per Action 3.3.e of the " Strategy for Achieving  March 31, 1999 Engineering Excellence."
 
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l ATTACHMENT 3
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LIST OF NRC COMMITMENTS l
Procedure 0.5, " Problem Identification and Resolution,"
will be revised to clarify the Extent of Condition requirements.
 
October 1, 1998 The effectiveness reviews of corrective actions  December 31, 1999 implemented under previous evaluations of SCAQs will be developed and implemented by December 31, 1999, as per Action 3.3.h and 3.3.1 of the " Strategy for Achieving Engineering Excellence."
 
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l PROCEDURE NUMSER 0.42 l REVISION 11 UMBER 6 l PAGE 9 OF 13 l
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Latest revision as of 14:33, 30 January 2022

Errata to Insp Rept 50-298/98-02,dtd 980515.Changes Have Been Made to Fourth Paragraph
ML20249A807
Person / Time
Site: Cooper Entergy icon.png
Issue date: 06/11/1998
From:
NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20249A052 List:
References
50-298-98-02, 50-298-98-2, NUDOCS 9806180267
Download: ML20249A807 (1)
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steam flow required to maintain peak critical centerline temperature less than 1500*F for an uncovered core, (3) maximum time before peak centerline temperature exceeds 1500*F for an uncovered core referenced to POHGH equal 13.4 kw/ft,~ (4) the cold shutdown boron concentration requirements, and (5) the , hot shutdown boron

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concentration requirement. The emergency operating procedure parameters ultimately L ' effected by these concems were listed as the boron injection initiation temperature, cold L shutdown boron wait, peak capacity level limit, heat capacity temperature limit, hot shutdown boron weight, minimum alternate reactor pressure vessel flooding pressure, L minimum core flooding interval, maximum core uncovery time limit, minimum number of safety relief valves required for emergency depressurization, minimum reactor pressure vessel flooding pressure, minimum steam cooling reactor pressure vessel water level, l minimum zero reactor pressure vessel water level, peak centerline temperature,

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pressure-suppression pressure, and peak linear heat generation rate. The licensee had addressed only the top of active fuel parameter.-

The licensee issued Problem identification Report 2-27287 to document that an apparent discrepancy existed with the 0-inch level assumed as the top of active fuel in the vesse The licensee noted that 150-inch fuel potentially extended to above the zero leve The licensee evaluated the safety significance of the 6-inch nonconservative bias.

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Vendor testing had found that fuel peak centerline temperatures of 1800*F would not be -

reached until vessel water level dropped below -70 inches (below top of active fuel). The licensee performed an evaluation which considered various instrument errors, including errors expected in a harsh equipment qualification environment. They found that the 1800'F limit would rot be reached even with the 6-inch nonconservative instrument bia The failure to incorporate the correct fuel length design requirements in plant emergency operating procedures is an example of a violation of 10 CFR Part 50, Appendix B, Criterion V, which requires, in past, that procedures be appropriate to the circumstances (50-298/98002-02).

Additiona'l questions which remain to be resolved include: (1) Technical Specification interpretation 96-003 which documented that the fuel length indicated in Technical Specification was 144 inches, although the Updated Safety Analysis Report stated that active fuel length was 150 inches. The resolution associated with the interpretation

- concluded that the conversion to improved Technical Specifications would remove the

!" . ' associated figure which showed the top of active fuel relative to the 144-inch active fuel length. The recalculation of setpoints for improved Technical Specification would be done in accordance with General Electric setpoint methodology and instrument zero j would be redefined as a fixed point above the fuel which will be defined for the purposes '{

of level monitoring as top of active fuel. The interpretation stated that the reference in i the Technical Specification bases was not a basis for the limiting safety system setting .

and that safety margin for transient and accident analysis was maintained through I administrative controls such as higher trip setpoints and emergency operating 4 - procedures; This Technical Specification request dated June 8,1996, stated that the safety limit was maintained regarding General Electric setpoint methodology, inspectors i ADOCk r -

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