ML20236Y216
| ML20236Y216 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 08/06/1998 |
| From: | Gwynn T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | Horn G NEBRASKA PUBLIC POWER DISTRICT |
| References | |
| 50-298-98-02, 50-298-98-2, NUDOCS 9808120003 | |
| Download: ML20236Y216 (4) | |
See also: IR 05000298/1998002
Text
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UNITED STATES
g NUCLEAR REGULATORY COMMISSION
L cj REGION IV
C & 611 RYAN PLAZA DRIVE. SUITE 400
%, ,e ARUNGTON. TEXAS 76011-8064
.....
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.
,
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
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Nebraska Public Power District -3-
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Project Engineer (DRP/C)
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DOCUMENT NAME: R:\._CNS\CN802AK.MHM
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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)
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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
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OFFICIAL RECORD COPY
110003
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P.O. DOX B E NEB SKA 68321
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Nebraska Public Power District "iL%%C,"
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NLS980094
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July 23,1998 7
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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 G.R. Horn (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 ,
[ ~
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
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i NLS980094
July 23,1998
! Page 2 cf 2
Senior Resident Inspector
NPG Distribution
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Attachment I
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Page1of11
REPLY TO MA ? 15,1998, NOTICE OF VIOLATION
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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
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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
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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 -
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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.
, Department supervisors held training sessions with their groups to review consequences of not
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performing thorough procedure searches, and not verifying the vendor instructions during
procedure reviews / revisions.
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Attachment I
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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 '
This is a Severity LevelIV violation (Supplement 1) (50-298/98002-02).
Admission or Denial to Violation
The District admits the violation.
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Reason for Violation l
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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
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(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
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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.
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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
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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.
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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
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
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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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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
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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. ,
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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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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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The organizational capabilities needed to support consistent access to and application of design
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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
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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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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 {
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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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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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4
, l ATTACHMEST 3 LIST OF ERC COMMITMENTS
l
Correspondence No:NLS980094
1
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The following table identifies those actions committed to by the District in this
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
,
be performed by October 1, 1998, to ensure that these October 1, 1998
l procedures are consistent with the vendor recommended
l torque values.
The Painting Frocedure 7.0.15 will be revised by
'
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
'
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
,
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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