ML20236U538
| ML20236U538 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 07/23/1998 |
| From: | Swailes J NEBRASKA PUBLIC POWER DISTRICT |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| 50-298-98-02, 50-298-98-2, NLS980094, NUDOCS 9807300256 | |
| Download: ML20236U538 (15) | |
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i P.O. 00X NEB SKA 68321 Nebraska Public Power District
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NLS980094 July 23,1998 U.S. Nuclear Regulatory Commission i
Attention: Document Control Desk Washington, D.C. 20555-0001
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Gentlemen:
Subject:
Reply to a Notice of Violation NRC Inspection Report No. 50-298/98 02 l
Cooper Nuclear Station, NRC Docket 50-298, DPR-46 i
Reference:
"NRC Inspection Report 50-298/98-02 and Notice of Violation" I
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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 Attachment 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.
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John H. Swailes Vice President ofNuclear Energy
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Senior Project Manager USNRC - NRR Froject Directorate IV-1 9907300256 980723 PDR ADOCK 05000298 !
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Senior llesident Inspector USNRC NPG Distribution l
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t Attachment I fo NLS98dO94 Page1 of11 REPLY TO MAY 15,1998, NOTICE OF VIOLATION COOPER NUCLEAR STATION NRC DOCKET NO. 50-298, LICENSE DPR-46 During NRC inspection activities conducted from March 8 through April 18,1998, two viohdions of NRC requirements were identified. The violations and the District's reply are set fonh below:
l Violation A.
10 CFR Part 50, Appendix B, Criterion V, requires, inpart, that activities affecting 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 Hydraulic Cylinder Maintenance, " was inappropriate to the circumstances and did not have appropriate acaptance criteria, in that the required torque value was not given in work instructionsfor theflange bolts. Theprocedure directedtheflange bolts he tightenedas opposed to beingfastened with the specific torque value. 7he bolts were tightened without acceptance criteria, leading ultimately to stripped l
threads anda control oilleakfrom the high pressure coolant injection turbine stop valve hydraulic actuator 7his is a Severity LevelIV violation (Supplement 1) (50-298/98002-02).
l Admission or Denial to Violation The District admits the violation.
l Reason for Violation The reason for this violation is inadequate corrective actions by Cooper Nuclear Station (CNS) 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 r
insufficient in that the review for extent of condition missed one procedure that was identified by the resident inspector.
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I The CNS Licensee Event Report (LF't) 96-013-01, " Inoperable High Pressure Coolant Injection System Due to Control Oil Leak on Turbine Stop Valve Actuator," war abmitted to the NRC l
because the HPCIS was declared inoperable as a result of a control oil leak caused by stripping of 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 j
specific value.
The corrective actions for 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 adequacy of the maintenance procedures with respect to torquing requirements. The search using l
7.2 series maintenance procedures identified 114 procedures. Inspection Report 50-298/98-02, i
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 l
vendor's manuals. It was determined that Procedure 7.2.47 did not contain the word torque as I
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 I
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 Stens Taken and the Results Achieved Procedure 7.2.47, "MSIV Air Manifold Removal, Overhaul, Testing and Installation," has been
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revised reflecting the vendcr recommended torque values.
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A review of all of the 114 maintenance procedures determined that use of the words " tighten" and
" torque"is consistent with the vendor manuals.
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l A training session for maintenance supervisors was held, and the Maintenance Manager's J
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expectations to prevent recurrence of this problem, as well as global ramifications, were conveyed.
Department supervisors held training sessions with their groups to review consequences of not performing thorough procedure searches, and not verifying the vendor instructions during procedure niews/ revisions.
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i to NLS980094 Page 3 of11 Corrective Steos That Will be Taken to Avoid Funher Violations 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 the word "t ghten," will be performed by October 1,1998, to ensure that these procedures are i
consistent with the vendor recommended torque values.
Date When Full Comnliance Will be A.chieved 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 of water-basedpaint with volatile organics in the reactor building. Procedure 7.0.15 allowedseveralgallons ofpaint to be drying in the reactor building which contained a significantfraction of ether-basedandacrylate-basedcompounds. 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.
Reason for Violation The reason for this violation is the failure to incorporate controls for paint with a significant fraction of organics which had the potential to afTect the standby gas treatment system.
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 p-ints from the limitations imposed on other paint types. This exclusion led painting personnel to believe that the levels ofvolatile organic compounds (VOCs) in the water-based paints were not a concern. CNS personnel responsible for station painting activities reviewed the 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. Funher, a discussion with the paint supplier l
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to NLS980094 Page 4 of1I (Keeler & Long) indicated that not long ago the v. ter-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 VOCs. The most recent iodine filtering efliciency tests of the charcoalin the SGT system were found to be 99.96% and 99.95% for trains A and B, respectiveif Industry testing has found that a 10% (weight) loading of charcoal is equivalent to 1% (approximately) loss of filter efliciency'.
The CNS Technical Specifications require a filter etliciency of equal to or greater than 99%.
Based on this test information, and the conservative assumptions used in the engineering evaluation, it was concluded that, during and after the painting activities, the SGT trains would 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 efliciency. The results of this test support the CNS conclusion of 2
continued operability of the SGT system, under both accident and normal operating conditions.
Corrective Stens Taken and the Results Achieved All painting activities in the reactor building were suspended, and painting Procedure 7.0.15 was placed on administrative hold.
l 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.
'" Study of the Effect of Coatings Operation on Radiciodine Removing Adsorbents," by i
W. P. Freeman and J. C. Enneking,21st DOE /NRC Nuclear Air Cleaning Conference, 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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l Attachment I to NLS' 86094 9
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 Comoliance Will be Achieved i
i The District is in full compliance regarding the identified violation.
A.
3.
Emergency Operating Procedure 2A, " Containment Control, " listedreactor vesselparametersfor when operators shoulddepressuri:e theplant with the water level at top of activefuel and at a level in thefuel bundle to prevent exceeding 1800 F. The water levelparameters were based on a level that was biased 6 inches in the nonconservative direction, as a result of an increase infuellength.
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This is a Severity Level IV violation (Supj>lement 1) (50-298/98002-02)
Admission or Denial to Violation The District admits the violation.
Reason for Violation 1
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.
The Fuel Zone instruments LI-91 A,B,C are scaled so that zero scale corresponds to the top i
of active fuel (TAF) at 144" This instmmentation 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 not referenced in the core reload analyses.
The present EOPs were developed in 1991, following the issuance of Revision 4 of the Boiling I
Water Reactor Owners Group Emergency Procedure Guidelines (BWROG EPG). In these l
procedures, some of the calculations that formed the basis for the operator actions used 150" as
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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
e to NLS'986094 Page 6 of11 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 inciuded the reflector, made of natural uranium.
The impact of using 144" of fuel length on EOPs was evaluated. It was determined that this condition does not invalidate the effectiveness of current EOP operator actions. The effects of initiatic.g reactor depressurization with 6 inches less water with respect to the top of fuel are well within the existing design margins.
The impact ofinitiating the operator actions with water level 6 inches lower was specifica!b 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 : ore 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 MZlRWL and -31.2 inches for MSCRWL. The improved BWROG evaluation methodology, showed that for MZIRWL, the peak cladding l
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 instrument 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.
The inspection report states that CNS did not address commitments to the NRC regarding l
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 an immediate correction. CNS has committed, under the EOP maintenance program, to correct identified deficiencies within 90 days, if the deficiency would render one of the success paths of f
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1 Attachment I to NLS' 86094 9
Page 7 of 11 the respective EOP Flowchart or Support Procedure unworkable under accident conditions.
l The needed EOP revisions are being tracked under the prescribed procedures.
A 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 j
supplied with the original Revision 4 of the EPGs still apply. No further actic,n 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 MCFI increased 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 I
assuming that the reactor pressure water level is at the high trip setpoint. No credit was taken for l
water level control to TAF.
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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 Steos 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.
I Options for clarifying action levels on the fuel zone level instmmentation and defining 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.
EOP calculations will be reviewed, in conjunction with Severe Accident Management implementation, to identify and correct any discrepancies introduced by the change in fuel
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length from 144" to 150" This will be completed by December 31,1998.
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Attachment I to NLS980094 Page 8 of11 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."
The organizational capabilities needed to support consistent access to and application of design information into EOPs will be developed. This development will be accomplished through implementation of the action plans for Action 1.1 of the " Strategy for Achieving Engineering Excellence."
Date When Full Comnliance Will be Achieved The District is in full compliance regarding this violation.
B.
10 CFR Part 50, Appendix B, Criterion XVI, requires, inpart, measures shall be established to assure that conditions adverse to quality, such asfailures, malfimctions, 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 Specifications would be performed to identify all operability verifications requiredprior to a mode change, by September 2,1997, and that procedures would be revised by October 15,1997. On March 11,1998, the licensee identified 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 runposition.
This is a Severity LevelIV violation (Stq)plement 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 Nuclear Station's corrective actions failed to identify all Technical Specifications operability verification requirements.
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Page9 of I1 The NRC Inspection Report 50-298/97-06, Notice of Vio'ation, consisted of two examples of inadequate procedures. In the first example, no procedure allowed the use ofinstalled 24-inch valves for inerting. The second example involved Procedure 2.1.1, "Startup Procedure," which allowed the operators to place the mode switch in the startup/ hot standby position prior to performing the daily jet pump operability check contrary to the Technical Specification 4.6.E requirement. In response to this violation, CNS committed to take two corrective actions to l
avoid further violations. The first corrective action was to perform a comprehensive review of the Technical Specifications to identify all operability verifications required prior to a mode change i
consistent with Technical Specification 1.0.J; and the second was to revise, as necessary,
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Procedure 2.1.1.2, " Technical Specifications Pre-Startup Checks," to incorporate all the operability verifications identified by Technical Specifications review.
l 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 j
average power range 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 of rigor.
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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 I
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 Taken to Avoid Further Violations Procedure 2.1.1 will be revised prior to next plant startup 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 all the surveillance requirements listed in Procedure 2.1.1.2 are complete and current for plant startup.
Date When Full Comoliance Will be Achieved The District is in full compliance regarding this violation.
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Page 10 of 11 B.
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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 conduct reviews to determine if other procedures had been adversely affected by earlier modifications.
This is a Severity LevelIV violation (Supplement) (50-298828002-03).
Admission or Denial to Violation 1
The District admits the violation.
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Reason for Violation The reason for this violation is the failure to identify all the afTected 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 90 901 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 prior to 1991 was a signature on " Station Modification Cover Sheet" by Operations. In 1991, a 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 1
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Attachment I to NLS'98dO94 Page11of11 reviewed against EOPs, and it was determined that these DCs were properly reflected in the EOPs.
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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 Steos 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.c 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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ATTACHMENT 3 LIST OF NRC COMMITMENTS l
l Corres,pondence No:NLS980094 l
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 information and are not regulatory commitments.
Please notify the NL&S Manager at Cooper Nuclear Station of any questions regarding this document or any associated regulatory commitments.
COMMITTED DATE COMMITMENT OR OUTAGE Procedure 7.0.4, " Conduct of Maintenance" will be revised August 11, 1998 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 the word " tighten" will be performed by October 1, 1998, to ensure that these October 1, 1998 procedures are consistent with the vendor recommended torque values.
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 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.
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.
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EOP calculations will be reviewed, in conjunction with i
Severe Accident Management implementation, to identify and correct any discrepancies introduced by the change in December 31, 1998 fuel length from 144" to 150".
This will be completed by December 31, 1998.
The organizational capabilities needed to support Per Action 1.1 of consistent access to and application of design o8 information into EOPs will be developed. This Achiev g Engineering development will be accomplished through implementation Excellence" of the action plans for Action 1.1 of " Strategy for Achieving Engineering Excellence."
Procedure 2.1.1 will be revised prior to next plant startup to include: (1) mode change requirements in Prior to next plant startup from either a Procedure 2.1.1.2, Section 8.4 ana 8.6; and (2) a verification signature from the Surveillance Coordinator forced outage or RFO-l 18, whichever comes i
that all the surveillance requirements listed in first Procedure 2.1.1.2 are complete and current for plant startup.
An EOP/ design basis review will be conducted by March 31, March 31, 1999 1999, as per Action 3.3.e of the " Strategy for Achieving Engineering Excellence."
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l ATTACHMENT 3 LIST OF NRC COi@!ITMENTS l
' Proeddu're 0. 5, " Problem Identification and Resolution,"
will be revised to clarify the Extent of Condition October 1' 1998 requirements.
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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REVISION NUMBER 6 l
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