ML20154C707
| ML20154C707 | |
| Person / Time | |
|---|---|
| Site: | Wolf Creek  |
| Issue date: | 09/29/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20154C700 | List: |
| References | |
| 50-482-98-12, EA-98-274, NUDOCS 9810070006 | |
| Download: ML20154C707 (90) | |
See also: IR 05000482/1998012
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ENCLOSURE 2
U.S. NUCLEAR REGULATORY COMMISSION
L REGION IV
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Docket No.: 50-482
License No.: NPF-42
Report No.: 50-482/98-12
E A N o..98-274
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Licensee: Wolf Creek Nuclear Operating Corporation
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Facility: Wolf Creek Generating Station
Location: 1550 Oxen Lane, NE
Burlington, Kansas
Dates: March 23 through April 10 and June 22 through 25,1998
' inspectors: M. Runyan, Senior Reactor inspector
R. Nease, Senior Reactor inspector
P. Goldberg, Reactor inspector
R. Bywater, Reactor inspector
J. Hanna, Reactor inspector -j
D. Pereira, Reactor inspector j
Accompanying
Personnel: F. Baxter, Consultant
C. Jones, Consultant
Approved by: T. Stetka, Acting Chief, Engineering Branch
Division of Reactor Safety
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. ATTACHMENT: Supplemental Information
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9810070006 980929
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PDR ADOCK 05000482
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TABLE OF CONTENTS
EX ECUTIVE S U M MARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v
R E PO RT D ETAI LS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ............. 1
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l Ill. Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...................... 1 I
i E1 Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 l
E1.1 High Hea J lnjection System . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 !
E1.2 Class 1 E DC Powe r . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
E1.3 Contrcl Room Heating, Ventilation, and Air Conditioning . . . . . . . . . . 10
E1.4 Performance improvement Requests . . . . . . . . . . . . . . . . . . . . . . . . 13
E8 Miscellaneous issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 '
i E8.1 Engineering Backlog . . . . . . . . . . . . . . . . . . . ................. 14
E8.2 Pressurizer Safety Valve and Main Steam Safety Valve Test Data
R e vi e w . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...... 15
E8.3 Year 2000 Computer issue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
E8.4 (Closed) Violation 50-482/9621-06: Procedure STS BG-004 did not
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Specifically Require Operators to Tighten or Verify the Mechanical !
l Position Stops for Valves BGV-198, -199, -200, and -201. . . .. .. 16
, E8.5 (Closed) Violation 50-482/9621-05: Operability Determination Was Not
l Thoroughly Documented in the Shift Supervisor's Log as Required by j
Administrative Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
E8.6 (Closed) Violation 50-482/EA96-470-02014: Two Examples of
Inadequate 10 CFR 50.59 Safety Evaluations . . . . . . . . . . . . . . . . . . 18
E8.7 (Closed) Violation 50-482/EA96-470-01013: Five Examples Where the
Licensee Failed to identify and Correct Conflicts Between Technical
Specification Clarifications and the Technical Specifications . . . . . . . 20
E8.8 (Closed) Violation 50-482/EA96-470-01033: Quality-Related Document
instruction Was Not Appropriate to the Circumstances When the
Licensee Allowed the Reactor Coolant System to be Cooled Down With
One Inoperable Source Range Channel . . . . . . . . . . . . . . . . . . . . . . 24
l_ E8.9 (Closed) Violation 50-482/EA96-470-01023: Reactor Coolant Pump
Flywheel Inspection Integrity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
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E8.10 (Closed) Unresolved item 50-482/9808-01: Licensee Failed to Prepare
Performance Improvement Requests for 12 Updated Safety Analysis
Report Significant Discrepancies . . . . . . . . . . . . , , . . . . . . . . . . . . . . 27
E8.11 (Closed) Unresolved Item 50-482/97201-01: Cooldown Analysis . . . 30
E8.12 (Closed) Inspection Follow up Item 50-482/97201-02: Emergency Core
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Cooling System leakage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
! E8.13 (Closed) Unresolved item 50-482/97201-03: Residual Heat Removal !
Pump Operation in Minimum Recirculation Mode . . . . . . . . . . . . . . . 33
E8.14 (Closed) Inspection Followup Item 50-482/97201-06: Procurement of
Emergency Diesel Generator Relay . . . . . . . . . . . . . . . . . . . .... 34
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E8.15 (Open) Inspection Followup item 50-482/97201-07: Sizing of Class 1E
Batteries. ...... .... ... .......................... 35
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E8.16 (Open) Inspection Follow up Item 50-482/97201-08: Sizing of Class 1E
Batteries . . . . ........ . ...... ................ .35
E8.17 (Open) Inspection Followup Item 50-482/97201-09: Sizing of Class 1E
Batteries . . . . . . . . . . .. .. . ..... ............... .36
E8.18 (Open) Unresolved Item 50-482/97201-10: DC Load Flow and Voltage
Drop . . . ............ .......... ................ .. 37
E8.19 (Open) Unresolved item 50-482/97201-11: DC Load Flow and Voltage
Drop . . . . . . . . . . ........ ................... .. ..... 37
E8.20 (Open) Unresolved item 50-482/97201-12: DC Load Control . . . . . . 38
E8.21 (Closed) Unresolved item 50-482/97201-13: Acceptance Criteria for
Battery Test
(Closed) Unresolved item 50-482/97201-14: Corrective Action For
Battery Test . . . . . .............................. ...... 38
E8.22 (Closed) Unresolved item 50-482/97201-15: Refueling Water Storage
Tank Level Instrumentation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
E8.23 (Closed) Unresolved item 50-482/97201-16: Seismic Qualification . . 40
E8.24 (Closed) Unresolved item 50-482/97201-17: Nitrogen Bottle Installation
. . ........ . ..... ....... ..... ..... ....... ... 42
E8.25 (Closed) Unresolved Item 50-482/97201-18: Motor Operated Valve
Diff e re ntial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ......... .... 43
E8.26 (Closed) Unresolved item 50-482/97201-19: Component Cooling Water
Low Temperature . . . . . . . . . . . . . . . . . . . ............ ..... 44
E8.27 (Closed) Unresolved Item 50-482/97201-20: Corrective Action for
Component Cooling Water Operating Procedure . . . . . . . . . . . . . . . 45
E8.28 (Open) Unresolved Item 50-482/97201-21: Updated Safety Analysis
Report Discrepancies . .... .......... ........... ... .. 47
E8.29 (Closed) Inspection Follow up Item 50-482/9604-03: Safety-Related
Battery Replacement with AT&T Round Cells ......... ....... 52
E8.30 Reactor Engineering Problem Identification Reports . . . . . . . . . . . 52
IV. Plant Support ..... .. ......... ......... ................. .......... 56
F1 Fire Protection Program . , . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56
F2 Status of Fire Protection Facilities and Equipment ............. ..... .57
F3 Fire Protection Procedures and Documentation . . . . . ........ ...... . 59
F4 Fire Protection Staff Knowledge and Performance . . . . . . . . . . . . ..... .60
F5 Fire Protection Staff Training and Qualification . . . . . . . . . . . . . . . . . . . . . . 61
F6 Fire Protection Organization and Administration . . . . . . . . . . . . . . . . . . . . . . 62
F7 Quality Assurance in Fire Protection Activities . . . . . . . . . . . . . . . . . . . . . . . . 62
F8 Miscellaneous Fire Protection issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63
F8.1 (Closed) Violation 50-482/9519-01: Failure to Provide Adequate
Emergency Lighting for a Valve Needed for Safe Shutdown Manual Manipulation
(Closed) Licensee Event Report 50-482/95-005: Failure to Develop an
Adequate Fire Protection Program for Emergency Lighting
......... ......... ...... ......................... 63
F8.2 (Closed) Licensee Event Report 50-482/97-016, Revisions 0,1, and 2:
Use of Fire Protection Pumps for.Non-Fire Protection Purposes
Constituted a Significant Degradation of Fire Protection System
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F8.3 (Closed) inspection Followup Item 50-482/96023-04: Reactor Coolant
Pump Motor Lube Oil Collection System . . . . . . . . . . . . . . . . . . . . . . 66
' V. Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68
X1- Exit Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68 i
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EXECUTIVE SUMMARY
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Wolf Creek Generating Station l
NRC Inspection Report 50-482/98-12 l
Enaineerina
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The licensee made changes to Emergency Management Guidelines ES-12, " Transfer to
l Cold Leg Recirculation," that involved an unreviewed safety question, without prior
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Commission approval and without performing safety evaluations. This was identified as
l a violation of 10 CFR 50.59 (Section E1.1.2).
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The licensee's evaluations of discrepancies between the Updated Safety Analysis
Report and Emergency Management Guidelines ES-12, reported in Performance i
improvement Request 97-3483 were poorly performed, limited in scope, and ineffective
in determining the proper priority of the performance improvement request. This
resulted in untimely resolution of the issues (Section E1.1.2).
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The licensee's lack of resolve in minimizing emergency core cooliag system leakage and
the use of the filter cleaning handle in lieu of monitoring the filter pressure drop of the
centrifugal charging pump lubricating oil filter, was identified as a weakness l
(Section E1.1.2).
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The lack of design basis calculations to support the minimum battery room temperature
of 60 degrees F was identified as a weakness in the licensee's design basis l
documentation; however, available contingency actions were sufficient to address any
safety concerns related to this matter (Section E1.2.2).
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The failure to identify Calculation NK-E-003, Revision 0, as an affected document in two
design change packages, was identified as an example of a violation of 10 CFR Part 50,
Appendix B, Criterion V (Section E1.2.2).
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An inconsistency in the regulation specification for a battery enarger purchase reflected
weaknesses in the licensee's design and procurement processes (Section E1.2.2).
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Design Calculation NK-E-002, " Class 1 E Battery Sizing," Revision 3, was of poor quality.
It did not contain a visible load profile, the computer program was disorganized and the
conclusions were not well supported (Section E1.2.2).
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There was a failure to correctly translate the design basis for the service water flow rate
to the component cooling water heat exchangers. The design control measures did not
verify or' check the adequacy of Calculation E6-06-W. This was identified as an example
of a violation of 10 CFR Part 50, Appendix B, Criterion ill (Section E8.11).
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Design control measures did mi assure the adequacy of the design for residual heat
removal pump operation in the recirculation mode, in that the wrong initial water
temperature was used in the calculation. This was identified as an example of a
violation of 10 CFR Part 50, Appendix B, Criterion 111 (Section E8.13).
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The failure to develop appropriate acceptance criteria for station battery testing was
considered an example of a violation of 10 CFR Part 50, Appendix B, Criterion V
(Section E8.21).
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Design control measures did not assure that effect of density variations on the refueling
water storage tank level indication was considered in the tank level instrument
uncertainties. This was considered to be an example of a violation of 10 CFR Part 50,
Appendix B, Criterion Ill (Section E8.22).
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Design control measures did not properly verify or check the adequacy of the design
l basis differential pressure for component cooling water Motor-Operated
l Valves EG-HV-062 and 132. This was considered to be an example of a violation of
10 CFR Part 50, Appendix B, Criterion Ill (Section E8.25).
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Design control measures did not ensure that the effect of lower component cooling
water water temperatures on safety-related motor oil temperatures and on the spent fuel
pool reactivity were adequately verified or checked. This was considered to be an
l example of a violation of 10 CFR Part 50, Appendix B, Criterion 111 (Section E8.26).
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The failure to promptly correct a discrepancy regarding the component cooling water
cooling water flow isolation to the spent fuel pool heat exchanger during cooldown was
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identified as a noncited violation (Section E8.27).
Plant Sucoort
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The failure to include inspection and periodic replacement of the relays for the
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diese!-driven fire pump was identified as a weakness in the preventive maintenance
program (Section F2).
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There were only four fire protection impairment control and breach authorization permits
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that required a compensatory fire watch. This was identified as a strength (Section F2).
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A noncited violation was identified for failure to maintain the fire protection system in
accordance with the fire protection program as required by Operating License NPF-42,
Section 2.C (5)(a), in that the licensee used the fire protection system for nonfire
protection purposes, a practice that rendered the fire protection system temporarily
inopercble (Section F8.2).
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A noncited violation was identified, in that, on three occasions the licensee identified
leakage sites from the reactor coolant pump lobe oil system that were not provided a
collection system, as required by Operating License NPF-42, Section 2.C (5)(a)
(Section F8.3).
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REPORT DETAILS
111. Enaineerina
E1 Conduct of Engineering
E1.1 Hiah Head iniection System
E1.1.1 System Descriotion
High head injection is provided by two multistage centrifugal charging pumps (CCP). On
a safety injection signal, the CCPs are automatically aligned for suction from the
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refueling water storage tank and discharge through the boren injection tank to the
reactor coolant system (RCS). If the refueling water storage tank becomes depleted,
the CCP suctions may be remote-manual transferred by control room operators to take
a suction from the discharge of the residual heat removal pumps during containment
sump recirculation.
E1.1.2 Desian Review
l a. inspection Scope (93809)
The team reviewed 24 design calculations related to the high head injection system,
including original architect-engineer calculations and more recent computerized flow
l^ models. The team also reviewed the accuracy of statements in the Updated Safety
- Analysis Report. In addition, the team reviewed surveillance testing and operations of
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b. Observations and Findinas
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Calculations for the most part were adequate for the situation. Some problem areas
were identified and are discussed below.
Emeraency Core Coolina System Switchover Operations
l The team reviewed the actions required to switch the suction for the emergency core
cooling system pumps from the refueling water storage tank to the containinent sump as
described in the Updated Final Safety Analysis Report and in the Emergency
Management Guidelines ES-12, " Transfer to Cold Leg Recirculation," Revision 9.
Emergency Management Guideline, ES-12, " Transfer to Cold Leg Recirculation,"
l Revision 9, describes operator actions necessary to switch the suction of the emergency
core cooling system pumps, specifically the CCPs and safety injection pumps, from the
refueling water storage tank to the containment sump upon the receipt of a refueling
j water storage tank Low-Low-1 level alarm. This action is required to ensure that these
l pumps are not lost due to air binding, and will be available for long-term core cooling.
For this reason, the switchover is time critical. The suction path for the residual heat
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removal pumps automatically switches from the refueling water storage tank to the
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containment sump upon receipt of the refueling water storage tank Low-Low-1 level
alarm. Updated Safety Analysis Report, Table 6.3-8, describes five numbered steps and
one unnumbered step, which must be performed to accomplish switchover for the CCPs
and safety injection pumps. The most time critical outflow analysis of the emergency
core cooling system suction switchover, described in Updated Safety Analysis Report,
Table 6.3-12, was a large break loes-of-cociant-accident in conjunction with a failure of !
one of the refueling water storage tank to residual heat removal suction valves to close.
Updated Safety Analysis Report Table 6 3-12 provides a total of 4.41 minutes for those
steps to be performed, which includes times for operator actions and times for the
valves to reposition. l
The team noted some discrepancies between operator actions required in Emergency
Management Guidelines ES-12 and those described in the Updated Safety Analysis i
Report refueling water storage tank outflow analyses. In particular, operator actions !
required to realign component cooling water from the spent fuel pool heat exchanger to
the residual heat removal heat exchanger were required by Emergency Management
Guidelines ES-12 to be performed upon receipt of the refueling water storage tank
Low-Low-1 level alarm. However, Updated Safety Analysis Report Table 6.3-8 stated,
"(T)he operator initiates component cooling water to the residual heat removal heat
exchangers and terminates cooling water to the fuel pool cooling heat exchangers as
the level in the refueling water storage tank nears the Low-Low-1 level set point." In
addition, as a result of the team's review of all the revisions to Emergency Management
Guidelines ES-12, the team found that Revisions 3,4, and 7 added operator actions, I
which increased the time required for operators to complete the emergency core cooling I
system switchover as described in Updated Safety Analysis Report, Section 6.3. I
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10 CFR 50.59(a)(1) states, in part, that the licensee may make changes to the facility
without prior Commission approval as long as the changes do not involve an
unreviewed safety question.10 CFR 50.59(a)(2) states, in part, that a change is
deemed to be an unreviewed safety question if the probability of a malfunction of
equipment important to safety previously evaluated in the safety analysis report may
be increased.10 CFR 50.59(b)(1) states, in part, that the licensee must maintain i
records of all changes to procedure that constitutes a change in the facility as described
in the Updated Safety Analysis Report, and that these records shall include a safety
evaluation that provides the bases for the determination that the changes do not include
an unreviewed safety question.
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By adding operator actions to Emergency Management Guidelines ES-12, on three
occasions, the licensee increased the amount of time required for the operators to
complete the switchover. This increased the probability that the switchover would not be
completed prior to the refueling water storage tank level becoming lower than the
suction point for the emergency core cooling system pumps, resulting in the malfunction
of one or more emergency core cooling system pumps. The team determined that the
licensee made changes to Emergency Management Guidelines ES-12 which involved
an unreviewed safety question without prior Commission approval was not obtained.
This was a violation of 10 CFR 50.59 (50-482/9812-01).
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[ The licensee's process for performing modifications or changes to design bases ,
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i documents included an engineering screening to determine if a safety evaluation, as
l required by 10 CFR 50.59, was necessary. The team reviewed the engineering l
screenings for all revisions to Emergency Management Guidelines ES-12 and found that
the licensee failed to identify that Revisions 3,4, and 7 to Emergency Management
Guidelines ES-12 involved changes to the facility as described in the Updated Safety
Analysis Report and, therefore, did not perform safety evaluations for those revisions.
The licensee's failure to perform safety evaluations for changes to the facility as
described in the Updated Safety Analysis Report is part of the violation of 10 CFR 50.59
(50-482/9812-01).
The team requested that the licensee verify on the simulator that operators could j
perform the switchover actions required in Emergency Management Guidelines ES-12 in
the 4.41 minutes provided in Updated Safety Analysis Report, Table 6.3-12. The team
observed two attempts.' The first attempt was completed in approximately 9 minutes and
the second attempt was completed in approximately 11 minutes, both exceeding the l
4.41 minutes provided in the Updated Safety Analysis Report. The licensee then
performed an operability determination in accordance with Generic Letter 91-18 and
determined that in the event that the suction for the emergency core cooling system
pumps could not be switched to the sump, one residual heat removal pump (which
changes suction automatically) would provide sufficient cooling to the core to prevent
fuel damage. The team reviewed the operability determination and found it to be
reasonable.
The team found that the licensee had previously identified and uocumented this issue in
Performance Improvement Request 97-3483. This performance improvement request
was initiated on October 29,1997, to address discrepancies between Updated Safety
Analysis Report, Sections 6 and 9, and Emergency Management Guidelines ES-12 that
were found during the licensee's review of the Updated Safety Analysis Report. These
discrepancies involved whether component cooling water was realigned to the residual
heat removal heat exchanger before or after reaching the refueling water storage tank
Low-Low-1 level set point. The screening, performed on October 30,1997 to determine
the priority of the performance improvement request, indicated that there were no
operability or reportability concerns. Further evaluation of this performance
improvement request on April 1,1998, concluded that operators could perform the
switchover before the refueling water storage tank was depleted, assuming that the
additional steps to realign component cooling water to the residual heat removal heat
exchanger took 2 minutes. This assumption was flawed in that it took 100 seconds for
the valves to change state, leaving only 20 seconds for operator action. When
performed in the simulator at the team's request, it took apprcximately 3 minutes for
component cooling water to be realigned. Further evaluation dated December 22,1997,
concluded that component cooling water flow to the residual heat removal heat
exchanger occurs before receipt of the Low-Low-1 level set point, which conflicts with
Emergency Management Guidelines ES-12. The team found that the licencee's
evaluations of conditions reported in Performance improvement Request 97-3483 were
l poorly performed and limited in scope. In addition, the engineering screening and
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evaluation were ineffective in determining the safety significance of the condition,
resulting in the licensee assigning a low priority to the resolution of the performance
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improvement request. At the time the team arrived onsite in April of 1998, the licensee ;
had not correctly addressed the discrepancies between the Updated Safety Analysis
Report and Emergency Management Guidelines ES-12,5 months after identification. l
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Minimizina Emeraency Core Coolina System Leakaae Durina Emeraency Operations j
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The team observed that a leak in the safety injection pump suction piping had not been
corrected after almost 2 years folicwing discovery. The licensee issued Performance
t- Improvement Request 98-0841 in response to the team's concerns. The team
l concluded that the leak did not represent a safety concern, but considered the licensee's l
l' response to be lacking. !
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l The team reviewed the licensee's management of valve seat and packing leakage for l
l the valves in the containment sum,? recirculation flow path. The licensee provided a list l
of open corrective work packages as of April 1,1998. Of the more than 70 items on the i
list, the team found ons notable item involving cleaning of the CCP oil filter due to the
handle being hard to turn (discussed below) and several items involving packing or seat
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leaks. The team observed ilo sense of urgency on the part of the licensee to identify l
and expedite the repair of the emergency core cooling system leaks.
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l The team determined that the licensee's slow response regarding emergency core !
! cooling system system leakage was a weakness.
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CCP Lubricatina Oil System j
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The centrifugal charging pump technical manual specified that the normal pressure drop
across the lubricating oil filter was 3 to 10 pounds per square inch (psi). However, !
l pressure instruments did not allow operators to monitor the actual pressure drop across
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the oil filter. The filter was designed to be cleaned by the operator during operation by
- rotating a small handle on the top of the filter assembly, which caused debris to fall to )
the bottom of the filter bowl Based on guidance from the filter vendor, the licensee !
stated that the filter was not actually removed and cleaned until this handle does not turn '
easily. This guidance had recently been incorporated into the quarterly flow tests
(STS BG 100A/B, " Centrifugal Charging System Train Inservice Pump Test,"
Revision 19). The use of the handle feature in lieu of monitoring the filter pressure drop
L as recommended by the pump vendor has not been formally evaluated, and was
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identified as a weakness. The team did not have any safety concerns with the
j licensee's practice.
c. Conclusions
The licensee's management of the design basis of the high head injection system was
j observed to be generally satisfactory, with the following exceptions noted below.
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On three occasions, the licensee made changes to Emergency Management ,
Guidelines ES-12, " Transfer to Cold Leg Recirculation," (Revisions 3,4, and 7) that l
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involved an unreviewe'd safety question, without prior Commission approval. In addition, !
the licensee failed to perform safety evaluations for each of these changes. This was ;
identified as a violation of 10 CFR 50.59.
The licensee's evaluations of conditions reported in Performance improvement !
Request 97-3483 were poorly performed, limited in scope, and ineffective in determining
the proper priority of the performance improvement request. This resulted in untimely
resolution of the issues identified therein.
The licensee's lack of resolve in minimizing emergency core cooling system leakage and ;
the use of the filter cleaning handle feature in lieu of monitoring the filter pressure drop '
of the centrifugal charging pump lubricating oil filter, as recommended by the pump i
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vendor, was identified as a weakness, i
E1.1.3 System Walkdown
a. Insoection Scope
The team conducted a plant walkdown of portions of the emergency core cooling l
system.
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b. Observations and Findinas
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One item noted during this walkdown was a drip-collection funnel under a sump
recirculation path component, the Safety injection Pump B suction line spool piece. The
funnel's purpose was to collect leakage from one of the flanges. This drip collection
apparatus had been in place for more than a year. No performance improvement
request or root cause evaluation was in place or planned. The licensee issued
Performance Improvement Request 98-0841 in responde to the team's concerns.
c. Conclusions
During a walkdown of the high head injection system, minor system leakage was noted.
However, no significant findings were identified.
E1.2 Class 1E DC Power
E1.2.1 System Description
The de power system included power supplies such as batteries and battery chargers,
distribution systems such as switchgear, panels, and cables, anc safety-related train
load groups arranged to provide de electrical power to Class 1E systems and
equipment.
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E1.2.2 Design Review
a. Inspection Scoce (93809)
The inspection scope encompassed battery sizing calculations, de minimum voltage
calculations, the de short circuit study, dc protective device coordination, the design
change package for the battery replacement, the design change package for the swing
battery charger replacement, and associated drawings, specifications, and supporting
documents.
b. Observations and Findinas
Batterv Room Temperature Concerns
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The team identified two concerns related to the temperature in the battery rooms:
1. Updated Safety Analysis Report, Section 9.4.1.2, stated that the ambient
temperature in the battery rooms, under any mode of operation, is between
60 and 90 degrees F. Calculation NK-E-002, "Clacs 1E Battery Sizing"
Revision 3, used 60 degrees F as the design input for analyzing the limiting
capacity of the batteries. Based on these facts, the team asked the licensee to
provide calculations to support the minimum battery room temperature of
60 degrees F, assuming winter conditions and a single failure of one train of
heating ventilating and air-conditioning equipment. In response, the licensee
indicated that there was no calculation to document that the temperatures in the
battery room would not drop below 60 degrees F with a single failure.
Additionally, the licensee stated that the standardized nuclear unit power plant
system (SNUPPS) design basis assumed that heating systems for the control
building were nonsafety related. The team noted that application of the single
failure criterion usually required assuming credible failures of nonsafety-related
equipment, which would include, for example, the nonsafety-related heating
systems. The team reviewed control room logs of battery room temoeratures
over six randomly selected wintertime weeks. These logs indicated that battery
room temperatures as low as 62 degrees F had b . en experienced, but had never
dropped below the 60 degrees F minimum temperature. Based on the team's
questions, the licensee outlined operator actions that would be instituted in the
event the temperature fell to 60 degrees F or below. Based on these actions, the
team determined that if battery room temperatures of 60 degrees F or below
were experienced, these conditions would be limited in duration, and would not
degrade battery capacity. The team considered the lack of design basis
calculations to support the minimum battery room temperature of 60 degrees F to
be a weakness.
2. The second concern involved the battery room thermometers used by control
room operators to log battery room temperatures. The team noted that these
thermometers had scales of 0-300 degrees F, with 1 degree F increments. The
accuracy of the thermometers was *1 degree F. The team considered these
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thermometers to be adequate, but somewhat inappropriate for the condition
being monitored. Following the identification of this concern by the team, the
licensee issued Performance improvement Request 98-0998 to improve the
resolution and readability of the thermometers.
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Failure to identify Affected Controlled Documents
1
The team identified two concerns related to the licensee's failure to identify controlled
documents affected by a design change:
1. Design Change Package 05846, "NK Battery Replacement," Revisions 0
through 11, installed new AT&T round cell batteries. Though these batteries were
functionally similar to the existing batteries, they were of a different construction
and had different ampere-hour ratings and short circuit contributions. The
licensee stated that they had data indicating the new AT&T batteries had a lower !
short circuit contribution than the old batteries. Based on this information, the
licensee chose not to identify Calculation NK-E-003, " Class 1E 125 V DC
Batteries Short Circuit Study," Revision 0, as an affected document, since it was
assumed there would be no adverse impact.
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2. Design Change Package 05248, "NK System Swing Battery Charger
Installation," Revisions 0 through 9, was closed out in November 1997.
Knowledge of fault current levels at various locations within the ac and de
systems were essential to this design change package in order to correctly
specify the ratings of equipment to be procured. As such, Revision 0 of the
design change package correctly identified Calculation NK-E-003, " Class 1E 125
V DC Batteries Short Circuit Study," Revision 0, as the source document for dc
fault current data. However, subsequent to Revision 0 of the design change
package, the new AT&T batteries with changed fault contributions were installed.
This fact was not identified in Revisions 1 through 9 of the design change I
package. The licensee had data indicating that the new AT&T batteries had a
lower short circuit contribution than the old batteries, and therefore the licensee
did not revise Calculation NK-E-003, or identify it as an affected document.
The team determined that the short circuit contribution from the batteries should have l
been inc;uded in Calculation NK-E-003. Procedure AP 05-001 " Change Package
Planning and implementation," Revision 2, Section 6.2.3, required that all programs
requiring revision, such as calculations be identified. The inspectors did not consider l
this issue to involve a functional problem with the batteries, since the assumption of j
decreased short circuit contribution was considered to be correct. '
10 CFR Part 50, Appendix B, Criterion V, " Instructions, Procedures, and Drawings,"
states, in part, that activities affecting quality shall be prescribed by documented '
procedures and shall be accomplished in accordance with these procedures. The failure
to follow Procedure AP 05-001 and identify that Calculation NK-E-003 required a
revision as the result of Design Change Package C5246 and 05248 was identified as an
example of a violation of 10 CFR Part 50, Appendix B, Criterion V (50-482/9812-02).
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Purchase and Installation of Eauipment
Battery Chargers NK-21 through NK-25 were purchased under Specification E-051(O),
l " Battery Chargers for SNUPPS," Revision 5. Battery Charger NK-26 was purchased
under Specification E-051 A(O), " Swing Battery Chargers for WCGS," Revision 2. The
two spare Battery Chargers NK-25 and NK-26 were permitted by technical specifications
to function in place of the permanent Chargers NK-21,22,23, and 24. The Updated
Safety Analysis Report relating to Amendment 104 stated that the spare battery
l chargers were intended to be equivalent to the permanent chargers. However,
Specification E-051(O), (for Chargers NK-21 through NK-25) specified a regulation of
l i0.5 percent; whereas, Specification E-051 A(Q), (for NK-26) specified a regulation of
i1.0 percent. This difference in regulation requirements and its significance was not
evaluated in Design Change Package 05248, "NK System Swing Battery Charger
l_ Installation."
The data sheet from the battery charger vendor showed that the vendor had, in fact,
supplied a battery charger with *0.5 percent regulation even though this was not
l consistent with the purchase specification.
This was considered to be a weakness in the licensee's design processes.
Poor Quality Calculation
The team reviewed Calculation NK-E-002, " Class 1E Battery Sizing," Revision 3, and
found it to contain the following discrepancies:
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The calculation had no visible load profile. Part of the data used to represent the
load profile came from a computer program, and part from a manual tabulation,
and no explanation was provided on how the two sources were to be combined
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to define the load profile.
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The computer program was disorganized and was unable to sort, summarize,
and present data in a logical format needed to determine the load profile.
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The conclusions were unsupported by the calculation. The team needed
extensive explanations by the licensee in order to understand their derivation.
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Section 5.2.5 of the calculation indicated that to provide conservatism and extra
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margin, the calculation would utilize a minimum battery voltage of 1.8 V per cell.
i Nonconservative values of 1.788 V and 1,79 V were utili'ed in the worksheets
l and attachments to the calculation. The team considered this discrepancy to be
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minor in that it did not affect the overall battery profile.
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The licensee acknowledged the problems with this calculation after attempting to provide
the team with an overview of the calculation and its conclusions. The licensee issued
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Performance improvement Request 98-1007 to enhance the calculation. Based on i
review of other documents and discussion with the licensee, the team concluded that the i
batteries were properly sized. However, the poor quality of Calculation NK-E-002 was
identified as a weakness. An inspection followup item (50-482/9812-03) was identified
to review the calculation after it is enhanced by the licensee.
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Drawina Error
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l The team reviewed Drawing M-1G051, " Equipment Locations Control & Diesel Gen.
Bldg & Common Corridor Plan El. 2000'-0* & El. 2016'-0"," Revision 8, and found that it
i
did not show Battery Charger NK 21 on Plan Elevation 2016 feet 0 inches. All other
battery chargers at this elevation were correctly identified. The licensee stated that this
oversight would be corrected.
c. Conclusions
The team noted that calculations and other design products in the electrical area were of
inconsistent quality and contained errors. These problems appeared to stem from a lack
of attention to detail, a lack of a questioning attitude, and weak independent verification
of calculations and design change packages.
The lack of design basis calculations to support the minimum battery room temperature
was identified as a weakness in the licensee's design basis documentation. However,
available contingency actions were sufficient to address any safety concerns related to ,
this matter.
The failure to identify Calculation NK-E-003 as an affected document in the two design
- changes was identified as an example of a violation of 10 CFR Part 50, Appendix B,
Criterion V.
An inconsistency in the regulation specification for the purchase of a battery charger
reflected weaknesses in the licensee's design and procurement processes.
E1.2.3 System Walkdown
a. Inspection Scoce
The system walkdown consisted of detailed inspections of the battery rooms, the
batteries, the battery chargers, the spare battery chargers, the transfer switches
ar sociated with the battery chargers, and various de switchgea and control panels.
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b. Observations and Findinas
Seismic Qualification of Electrical Panels
During the walkdown, the team noted that Electrical Cabinets NK-77, NK-25, and NK-75;
NK-01 and NK-71; and NK-04 and NK-74 were connected to each other by 4-inch
diameter, short, rigid conduit. Electrical Cabinets NK-71, NK-74, NK-75 and NK-77 were ;
installed as a result of DCP 05248, "NK System, Swing Battery Charger installation," in !
November 1997. Cabinets NK-01and NK-25 weigh approximately 1800 lbs and were -
more flexible horizontally than the new cabinets (NK-71, -74, -75, and -77), which weigh
approximately 500 lbs. each and are considered to be horizontally rigid. The differences l
in height, plan dimensions, and mass distribution could result in different dynamic l
responses during a seismic event. Upon questioning the licensee regarding the ;
interaction between the cabinets, the team was infctmed that each cabinet was l
independently seismically tested and qualified, however no formal calculations to ]
address interaction between the cabinets had been performed. The licensee stated that j
the conduit had been installed in accoraance with drawing -1R8900, " Raceway Notes,
Symbols, and Details," paragraph 3.35 of Revision 15, dated January 2,1997, which I
stated, "Only flexible conduit shall be fastened to any equipment which requires seismic !
qualification except when the installation is such that the equipment and the last support i
for the conduit are attached to the same surface (plare). . . ." The licensee stated that I
the basis for this specification is that, during a seismic event, equipment connected via
rigid conduit and mounted on the same plane, is expected to initially react in the same
direction. The team agreed, but given the differences in mass and dimensions
questioned the interaction between the cabinets during tae entire seismic event. The
licensee initiated Performance improvement Request 98-0986 to perform a calculation
explicitly addressing the team's concerns. An inspection followup item (50-482/9812-04)
was identified to review the new calculation.
c. Conclusions
The seismic qualification of selected electrical panel was indeterminate. With the
exception of this seismic qualification issue, the walkdown did not identify problems with
the do distribution system.
E1.3 Control Room Heatina. Ventilation. and Air Conditionino
E1.3.1 System Description
The control room heating, ventilation, and air-conditioning system is an emergency
ventilation system and part of the control building ventilation system. The control room
emergency ventilation system consists of three subsystems: air conditioning, filtration,
j and pressurization. These three subsystems protect control room operators from
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receiving excessive doses of radiation during postulated accidents involving the release
of large amounts of radioactive materials, including fission products. Several automatic
isolation functions ensure that control room operators are protected during accident
conditions. The control room air-conditioning system also provides the control room with
a conditioned atmosphere during all modes of plant operation, including post-accident
operation.
E1.3.2 Design Review
a. Insoection Scope (93809)
The team evaluated the control room ventilation system post-accident design safety
features, the test program for those features, and the operatiens associated with those
features. During its review of the applicable sections of the technical specifications and
Updated Safety Analysis Report, the team identified 16 specific design topics or
requirements for the control room ventilation system.
The team reviewed 38 design calculations, surveillance tests, procedures, and related
documents for the contro:- n ernergency ventilation system, which includes 1
subsystems for temperatuw control, filtration, and pressurization. The related additional l
documentation primarily involved the charcoal adsorber testing program, including
changes applicable to laboratory analysis of charcoal samples. Design calculations
reviewed by the team included the effects of single failures, charcoal adsorber
specifications, the potential for carbon dioxide buildup during control room isolation, and
heat load changes due to equipment modifications.
b. Observations and Findinas
No significant issues were identified i' ie design review of the control room ventilation
system.
E1.3.3 Design Changes
a. Inspection Scope (93809)
The team reviewed three design changes affecting the control room ventilation system.
b. Observations and Findinas
Deletion of Relative Humidity Sencors
Proposed Modification Request (PMR) 03158, " Deactivation of RH [ relative humidity)
Sensors and Transmitters," Revision 2, was issued due to the unavailability of
replacement relative humidity sensors to control the intermittent operation of ventilation
system heaters, used to maintain the required 70 percent relative humidity of air into the
charcoal adsorber media. The heaters were modified for continuous operation
whenever the pressurization systems are in operation. The team considered this
modification to be acceptable since heater operational reliability was improved.
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By letters dated October 24,1995, and May 16,1996, the licensee requested revisions
to the technical specifications that allowed the rating of the control room ventilation
pressurization system heaters to be reduced from 15kW to SkW. The team reviewed
the supporting Calculation GK-474, " Control Room Pressurization System Filtration Unit
Heater Output," Revision 1, which showed that SkW was adequate to achieve the
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70 percent relative humidity required to ensure charcoal bed adsorption efficiency. This
request was consistent with PMR 03158, Revision 2, which resulted in continuous heater
operation when the system is in operation. The team considered that continuous
operation of 15kW heaters would add unnecessary heat to the control room ventilation
system.
The team considered the request to downrate the heaters to be the result of the original l
problem with maintaining or replacing the relative humidity sensors. Nevertheless,in l
view of the periodic charcoal drying operations performed by the licensee, the
continuous heater operation described above, the power supply conservatism noted in
the calculation, and the industry practice of using approximations in ventilation system
calculations, the team agread that the specified reduction in heater capacity was
acceptable.
Charcoal Laboratory Test Chanae
The sams technical specification revision request included changes to the laboratory i
methods used to test the efficiency of the charcoal adsorber media. The change was -
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made to address interference of test results from the moisture introduced by the test i
method. Since the charcoal is sensitive to moisture, the team was concerned that the l
efficiency of the installed charcoal beds may be compromised by condensation of water
vapor during regular operation. The licensee provided the team with further information
showing that the ventilation systems for the charcoal beds are periodically operated
specifically to ensure that moisture was not collecting in the charcoal. The team
reviewed the associated documentation and considered this approach to be adequate. l
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c. Conclusions
The three design changes reviewed were considered acceptable. l
E1.3.4 Technical Specification Surveillance Testing
a. inspection Scope (93809)
The team reviewed technical specification testing of the control room ventilation system.
Control room emergency ventilation system surveillances reviewed by the team included
visual, flow, pressurization, high efficiency particulate air filter efficiency, ;eakage, and
charcoal adsorber sample laboratory test results. The team also assessed the quality of
the documentation of the surveillance tests since 1994.
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b. Observations and Findinas
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While all of the surveillances reviewed by the team were performed adequately, the
team noted that the licensee closed out one charcoal filter surveillance without including
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the laboratory results. This was a surveillance in which the charcoal adsorber failed a
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concurrent leak test, which resulted in the licensee having to replace the charcoal. The
licensee discarded the old charcoal test results. Although it was not specifically
required, the team noted that it may be important to collect, review, and retain all
sampling results for safety systems, even when those results are of no immediate
operational value.
c. Conclusions
Technical specification surveillances of the control room ventilation system were
properly performed.
E1.3.5 System Walkdown
a. Insoection Scopo (93809)
The team walked down the control room emergency ventilation system.
b. Observations and Findinas
The system engineer was very familiar with the various components in the system and
was very knowledgeable regarding the associated surveillance testing programs. The
equipment appeared to have adequate clearance for maintenance and testing
operations, and the material condition of the major system components was good.
Maintenance of smaller components was good, with some minor exceptions resulting
from condensation and possible leaks in the air-conditioning equipment.
The team also visited the control room to assess the operational aspects of the control
room emergency ventilation system. The operators were very knowledgeable regarding
system operations and they stated that they were comfortable with the human factors
aspects of the eyeem control and indication panels.
c. Conclusions
The material condition of the control room ventilation system was good.
E1.4 Performance Imorovement Reauests
a. Inspection Scope (93809)
The team reviewed Procedure AP 28A-001, " Performance improvement Request,"
Revision 9, and 55 performance improvement requests associated with the high head
safety injection system, control room ventilation system, and the Class 1E dc distribution
system. The team discussed the performance improvement request process and some
of the performance improvement requests with appropriate licensee personnel.
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b. Observations and Findinas
The team determined that the performance improvement request process provided a
single method for documenting the evaluation and resolution of problems, concerns, or l
recommendations, l
As the result of this review, no problems were identified with the selected performance I
improvement equests,
c. Conclusions
The team found the licensee's disposition of performance improvement requests to be
appropriate.
E8 Miscellaneous issues (92903. 37550)
E8.1 Enaineerina Backloa
a. Inspection Scoce
The team reviewed the licensee's engineering backlog and the manner in which the
backlog was being trended and tracked. In addition, the team discussed the backlog
with appropriate licensee personnel.
b. Observations and Findinas
The team noted that the open performance improvement requests had an upward trend
over the past 2-year period. In January 1996 there were approximately 290 open I
performance improvement requests and in March 1998 there were approximately l
460 open performance improvement requests. The team also found that vendor j
technical documents increased from 74 open items in April 1997 to 435 open items in
April 1998.- In addition, the licensee's design change package closeout backlog
increased from 72 in December 1996 to 220 in Febmary 1998. The change mekage ;
closeout backlog consisted of a number of change packages awaiting engineering
closecut by design engineering or the configuration control group that were greater than
90-days old.
The team discussed the engineering backlog with the licensee and determined that, in
the summer of 1997, the licensee was authorized to hire contractors to reduce the
backlog. The team reviewed Material / Service Requisition DES 930023, dated March 24,
1998, which was initiated by the licensee to obtain contractors to provide engineering
services to manage and implement the backlog reduction project. The licensee stated
that the work scope would start in early May 1998 and be completed by the end of
December 1998. The team found that the backlog reduction project consisted of four
specific areas - change package backlog, performance improvement requests,
motor-operated valve backlog, and reverification of safety classification analyses. The
change package backlog scope was 268 change packages which consisted of 2065
documents that required review and revision. The performance improvement request
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backlog consisted of 165 documents that required investigation of predominately
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. auxiliary feedwater system, essential service water system, and component cooling )
water system hardware and documentation discrepancies. The motor operated valve '
backlog scope consisted of resolution of 54 items, which the licensee stated would take
approximately 4800 man-hours. The reverification of 532 safety classification analyses
l required independent review, validation and correction of previously performed safety
j classification analyses. The team was not able to draw any conclusions regarding the
backlog reduction project since the project had not yet started.
1
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The team determined that while there was an overall upward trend in the engineering i
backlog, the licensee was in the process of taking action to reduce the backlog by
[ initiating a backlog reduction program.
l E8.2 Pressurizer Safety Valve and Main Steam Safety Valve Test Data Review
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a. Insoection Scope
The team reviewed a few performance improvement requests associated with the main
steam safety valves and pressurizer safety valves. The team discussed some of these
. documents with appropriate licensee personnel.
b. Observations and Findinas
The team reviewed Performance Improvement Request 97-2539, dated August 19,
1997. The licensee issued this performance improvement request to document the i
failure to perform an internal visual examination, VT-3, on one of the pressurizer safety i
valves during the first 10-year. inspection interval of the inservice inspection program. l
The team determined that on August 19,1997 the licensee performed a VT-3 inspection I
on a pressurizer safety valve which was installed during the fall of 1997 outage. The
team noted that the VT-3 results were satisfactory, with no indication of degradation. In !
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addition, the licensee generated LER 97-015 to report the missed surveillance.
Additional corrective actions planned included revising Procedure STS MT-005,
" Pressurizer Code Safety Valve Operability," to specify that VT-3 examination was
required during disassembly of the pressurizer safety valves and revising the second ;
interval inservice inspection program plan to specify the required examinations in each
of the three periods within the second 10-year inspection interval.
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The team reviewed the set pressure inservice test results for the pressurizer safety
valves and main steam safety valves from March 1993 to February 1998. The team
- found that, during testing in June of 1993, two of the pressurizer safety valves exceeded
their set points. The technical specification set point requirement was 2485 psig
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+/ 1 percent. The two valves that failed, opened at -2.13 and -2.70 percent below the ,
! nominal set point. During the July 1996 testing, one of the pressurizer safety valves i
- opened at 2534 psig which was +1.97 percent above the nominal set point. During the
l February 1998 testing, one valve opened at -1.81 percent below nominal set point. The
licensee issued Performance Improvement Request 98-013 for these test failures on
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March 19,1998.
c. Conclusions !
! The team found that the licensee was appropriately identifying and resolving issues
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involving pressurizer and main steam safety valve testing.
E8.3 Year 2000 Comouter issue
a. Insoection Scooe
The team reviewed the adequacy of the licensee's Year 2000 (Y2K) program. The
purpose of this review was to provide a preliminary review of the licensee's year 2000
preparedness and not a detailed performance-based appraisa!.
b. Observations and Findinas
- The licensee has been closely following the guidance provided in NEl/NUSMG 97-07,
" Nuclear Utility Year 2000 Readiness." The licensee appeared to be on schedule, which
allowed a 6-month margin of error should difficulties arise during implementation. The
program was comprehensive, as evidenced by a wide spectrum of departments (ranging
from human resources and finance to operations) and computer applications (extending
from microchips and software to entire computer systems) that were included. Wolf
Creek Nuclear Plant's Project Plan covers a wide variety of contingencies (e.g., a
relevant vendor being out of business or not assisting with needed information or
service).
c. Conclusions
Although there were few objective criteria to evaluate the licencee's performance, it
appeared that the licensee was meeting their schedule on the Year 2000 computer issue
and was following commonly accepted industry guidance.
E8.4 (Closed) Violation 50-482/9621-06: Procedure STS BG-004 did not Specifically Require
Operators to Tighten or Verify the Mechanical Position Stops for "alves BGV 198, -199,
-200, and -201
a. Backaround
Procedure STS BG-004, " Chemical and Volume Control system (CVCS) Seal Injection
and Return Flow Balance," Revision 4, provided procedural guidance for setting the
positions of seal injection throttle Valves BGV-198, -199, -200, and -201, and performing
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Technical Specification Surveillance Requirement 4.5.2.g (verifying the correct position
of mechanical position stops) for these valves. However, Procedure STS BG-004 did
not specifically require operators to tighten the mechanical stops for these valves.
b. Inspection Followuo
The licensee stated that the root cause of the violation was inadequate procedural
guidance, since Procedure STS BG-004 failed to provide adequate instructions. The
procedure did not require the performers to tighten, nor verify tightened, the locknuts
(mechanical stops) on CVCS valves BGV-198,199,200, and BGV-201. The licensee
stated that a contributing factor was that Procedure AP 21G-001, " Control of Locked
Component Status," Revision 6, failed to define or give examples of a mechanical stop.
The inspection team reviewed the licensee's completed corrective actions to prevent
recurrence of the violation. These specific corrective actions included Revision 7 of
Procedure AP 21G-001, to clearly define what constituted a mechanical stop. In
addition, the licensee revised Procedure STS BG-004, with Revision 6, to incorporate
instructions to assure that the mechanical position stops are tightened or verified
tightened.
The team reviewed the corrective actions and concluded that they were appropriate to
prevent recurrence of the violation. In addition, the inspectors reviewed revised
Procedures AP 21G-001 and STS BG-004, and determined that the revisions
appropriately addressed the discrepancy.
E8.5 (Closed) Violation 50-482/9621-05: Operability Determination Was Not Thoroughly
Documented in the Shift Supervisor's Log as Required by Administrative Procedures
a. Backoround
While performing an operability determination, a shift supervisor relied on an out-of-date
Calculation, GN-MW-005, which assumed a flow rate of 4000 gpm for a cooler group
(i.e., two coolers), instead of determining the actual requirement for containment air
cooler group essential service water flow rate of 2000 gpm.
b. Inspection Followuo
The licensee stated that the shift supentisor made an operability determination without
following administrative guidance. However, the licensee's evaluation and root cause
anc / sis of the event determined that the shift supervisor was correct in the
determination that no operability or reportability concerns existed. The licensee stated
that the root cause was personnel error in that the shift supervisor did not meet the
procedural requirements of Procedure ADM 02-024 (since superseded by
Procedure AP 26C-004), " Technical Specification Operability," Revision 3, in that the
basis for the operability determination was not documented in the shift supervisor's log.
The team reviewd the licensee's completed corrective actions to prevent recurrence of
tne violation. These specific corrective actions included the following:
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1. Performance improvement Request 96-2737 was entered into operations
required reading to remind the shift supervisors of management's expectation
regarding detailed log entries and a questioning attitude.
2. Procedure AP 26C-004, Revision 0 (formerly Procedure ADM 02-024), was
issued, with instructions that a detailed log entry will be made by the shift
supervisor to record a decision concerning operability. The detailed log entry will
include the basis for the operability decision.
3. Procedure AP 26C-004, Revision 1, subsequently added a " Technical
Specification Operability Screening Form" as an aid to the shift supervisor to
ensure thoroughness of evaluation and consistency in documentation.
-The team's review of the above completed corrective actions indicated that they were ,
y appropriate to prevent recurrence. :
E8.6 (Closed) Violation 50-482/EA96-470-02014: Two Examples of inadequate
10 CFR 50.59 Safety Evaluations
a. Backaround
The NRC identified that the licensee made changes to procedures described in the
Updated Safety Analysis Report without an adequate written safety evaluation which
provided the basis for the determination that the changes did not involve an unreviewed 1
safety question.
A. On December 13,1995, the licensee's screening for revisions to
Procedures STS PE-049C, "A Train Underground Essential Service Water
System Piping Flow Test," Revision 2, and STS PE-049C, "B Train Underground
Essential Service Water System Piping Flow Test," Revision 0, failed to indicate
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that Section 9.2 of the Updated Safety Analysis Report was affected by the
change. The procedure revisions reclassified the essential service water system
as nonredundant, whereas, the Updated Safety Analysis Report described this
system as redundant. As a result, the licensee failed to either (1) submit a
request for an alternative to the inservice inspection requirements or (2) process
a change to Section 9.2 of the Updated Safety Analysis Report and determine .
whether the change involved an unreviewed safety question. I
1
B. On March 26,1996, the licensee performed an unreviewed safety question l
determination regarding changing the main turbine overspeed protection test
frequency as stated in Section 16.3.2 of the Updated Safety Analysis Report
from every 7 days to every 92 days, without providing supporting documentation {
to conclude that an unreviewed safety question was not involved. The
i unreviewed safety question determination did not address the licensee's l
l Mxperience with the testing of these valves and did not contain any information as ;
to the acceptability, by the turbine vendor, of the decreased surveillance
frequency on the turbine valves. l
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-.-. . _ . . . . - - - . - - . -
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1
b. Insoection Followuo
The licensee stated that the reason for Example A to the violation was personnel error.
, The inservice inspection engineer utilized his code experience and knowledge to assure
l that the changes were within the boundaries established by ASME,Section XI. During
l the procedure change to implement the new testing method, the inservice inspection
engineer incorrectly concluded that the application of the code requirements (e.g.,
l considering each train of essential service water as a nonredundant system) did not
l conflict with the Updated Safety Analysis Report description.
l The licensee stated that the reason for Example B of the violation was failure to follow
the procedural requirements of Administrative Procedure AP 26A-003,"Unreviewed
Safety Question Determination," Revision 3. This procedure discussed the need
and responsibility for assuring the completeness and accuracy of the information
provided in the unreviewed safety question determination. The licensee stated that
Procedure AP 26A-003 was not followed correctly, in that information helping to justify
the acceptability of making the subject change was identified but not included in the l
unreviewed safety question determination.
The inspectors reviewed the licensee's completed corrective actions for both violations
to prevent recurrence of the violation.
The licensee's corrective actions for Example A included the following:
-
The licensee reviewed other plant systems that have buried components to
determine if changes to pressure test methodology resulted from incorrectly
defining the system as redundant or nonredundant. The licensee found no other
examples.
-
The licensee committed to the 1989 Edition of ASME,Section XI. As part of this
commitment, the inservice inspection program plan has been revised and
associated pressure test procedures were being revised to the new
requirements.
-
In order to implement the requirements for testing redundant and isolable
components, permission was requested from the NRC to utilize the ASME,
Section XI 1995 Edition with 1995 Addenda so that Subsection lWA-5244 may
be applied to the essential service water buried portions of piping. The request
to implement the 1995 Addenda requirements was made in letter ET 97-0040
dated April 24,1997, to the NRC, and was pending at the time of the inspection.
l
The licensee's corrective actions for Example B included the following:
-
The licensee counseled the preparer and approver of the unreviewed safety
question determination relative to the missing information.
19
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The licensee reviewed the content of all other unreviewed safety question
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determinations performed by the same preparer for similar errors. No other
examples were identified.
-
in July 1996, engineering implemented the work product evaluation process.
This process was used to reinforce management expectations involving complete '
documentation of work, attention to detail, and procedural compliance.
-
The chief operating officer and the plant manager met with the plant safety
review committee to reinforce expectations for thoroughness of review and !
review for completeness of documentation.
'
The licensee conducted leakage testing of the essential service water system
underground piping. Train A testing was performed on November 5,1997, and Train B
testing was performed on October 30,1997. Both service water system piping leakage
tests were performed satisfactorily, with no noted test deficiencies.
At the time of this inspection, the licensee was revising pressure test procedures
(approximately 70) to satisfy the new testing requirements. The update to the pressure
tests entailed a review of all system boundaries that require pressure testing. Updating 1
the pressure tests was requeed to be completed with performance of the tests at the l
completion of the first 40-month inspection period in accordance with 10 CFR 50.55a
and ASME,Section XI. The licensee stated that updating of the pressure tests would be
completed by Refueling Outage 10, scheduled for the spring of 1999.
The team reviewed 5 of 11 recently revised pressure tests. The team noted that the
revisions placed the tests in new and consistent formats and included changes
necessary to meet the requirements of the 1989 Edition of ASME Code. The applicable
signoffs on the data sheets were revised to require a review of the inservice inspection
engineer for acceptance.
The inspectors concluded that the corrective actions appeared to be comprehensive and
that the root causes were addressed to prevent recurmace of the violation.
E8.7 (Closed) Violation 50-482/EA96-470-01013: Five Examples Where the Licensee Failed
to identify and Correct Conflicts Between Technical Specification Clarifications and the
Technical Specifications
a. Backaround
On March 31,1994, the licensee's corrective actions in response to Quality Assurance
Audit K381 findings failed to identify and correct conflicts between technical specification
clarifications and the technical specifications. Specifically, the licensee's screening of
the following technical specification clarifications did not identify conflicts between the
technical specification clarifications and the technical specifications.
-
Technical Specification Clarification 009-85 conflicted with Technical
Specifications 3/4.5.3 and 3/4.5.4 (applicable in Modes 4 and 5, respectively) by
20
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allowing two centrifugal charging pumps to be available while in cold shutdown.
l
Technical Specifications 3/4.5.3 and 3/4.5.4 allowed only one centrifugal
charging pump to be availatAe during cold shutdown.
-
Technical Specification Clarification 010-85 conflicted with Technical
Specifications 3.5.3 and 4.5.2 by allowing daily containment closecut inspections
following multiple containment entries in 1 day. Technical Specifications 3.5.3
and 4.5.2 require a containment visualinspection for loose debris be performed
following each containment entry.
-
Technical Specification Clarification 033-85 conflicted with Technical
Specification 3.6.1.1 by allowing containment penetrations to be considered
operable if dedicated operators were assigned to close inoperable containment
isolation valves. Technical Specification 3.6.1.1 requires that all containment
penetrations be isolable by automatic isolation valves.
-
Technical Specification Clarification 004-86 conflicted with Technical
Specifications 4.5.1 and 4.0.3 allowing cold leg accumulators to be considered
operable upon receipt of level and pressure alarms if accumulator level and
pressure were within prescribed limits. Technical Specifications 4.5.1 and 4.0.3
require the accumulators to be considered inoperable upon receipt of these
alarms.
-
Technical Specification Clarification 005-94 conflicted with Technical
Specification 4.8.1.1.2.g.7 by allowing hot restart testing of an emergency diesel
generator to be performed any time before or after the 24-hour load test as long
as the hot restart test was performed within 5 minutes of a 2-hour diesel run.
Technical specification 4.8.1.1.2.g.7 specifies that a hot restart test be performed
within 5 minutes following the 24-hour test except that the hot restart test may be
done following a warmup run only if it previously failed the test immediately
following the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> test.
b. Insoection Followon
The licensee stated that the reasons for the violation included technical specification
clarification procedural issues and weaknesses in the corrective action program, which
allowed for a nonconservative interpretation of the regulatory requirements.
As background to this violation, the licensee identified in Quality Audit TE-50140-K381,
" Technical Specifications and License Condition Adherence," dated March 4,1993, that
some technical specification clarifications appeared to contradict the associated
Technical specification. As a result of this audit, Performance improvement
Request 93-0131 was written regarding the use of technical specification clarifications,
,
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and was classified as " nonsignificant." The performance improvement request initiation
statement did not specifically identify any violations of technical specifications. However,
the performance improvement request did state that certain technical specification
clarifications could result in implementation of technical specifications, or changes to the
technical specifications, that were not previously approved by the NRC as required by 10
l CFR 50.92 and 10 CFR 50.36.
'
Performance Improvement Request 93-0131 recommended several corrective actions
including: 1) a revision to the technical specification clarification procedure; 2) a 10 CFR
50.59 regulatory screening be performed for all open technical specification
'
clarifications, and 3) an additional review be performed on all open technical
i specification clarifications to look for adequate technical basis, continued applicability,
i
'
need for a license amendment, compliance with current NRC guidance, and
appropriateness. This review resulted in the deletion of 11 technical specification
.
clarifications, revision to 6 technical specification clarifications, and initiation of 1
l technical specification amendment. The corrective actions were completed and
Performance improvement Request 93-0131 was closed on April 15,1994. In addition,
,
the licensee performed an effectiveness review on Performance Improvement Request
93-0131 and determined that the corrective actions were effective.
,
On October 16,1996, Performance improvement Request 96-2610 was written to
, document that Technical Specification Clarification 009-85 was not identified and
deleted during the corrective action activities from Performance Improvement Request
93-0131. As a result of this oversight, licensee personnel performed another review of
I
technical specification clarifications and identified several other technical specification
, clarifications requiring deletion. The licensee identified 14 clarifications that could have
4
potentially caused a violation of the associated technical specifications. Of the 14, a l
- total of 6 technical specification violations were identified and Licensee Event
Reports 96-011-01 thorough 96-016-01 were issued.
4
The licensee's corrective actions to prevent recurrence of the violation included the
following:
.
-
In parallel to the review activities, the licensee chartered an incident
Investigation Team 96-004 on October 24,1996, to conduct a programmatic
investigation of technical specification clarification related processes and to
identify root causes for the issuance of technical specification clarifications that
caused or allowed technical specifications to be violated. As a result of incident
Investigation Team 96-004, Technical Specification Clarification Procedure,
AP 26C-003, " Technical Specification Clarifications," was evised on April 10,
1997, with Revision 1. This revision accomplished the following items:
-
Step 5.4.1.2 was revised to require that the Manager Operations assure
that each technical specification clarification receives a 2-year relevancy
review.
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A note was added prior to Step 6.1.2 to denote that a technical '
specification clarification may not change the intent, scope, wording or
meaning of a technical specifications.
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Reviews by the technical specification clarification subcommittee were !
required to be documented on Form APF 26C-003-02,"TSC Disposition !
Form." '
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Disapproval of a technical specification clarification by the technical
specification clarification subcommittee, plant safety review committee or i
plant manager was required to have written justification. l
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technical specification clarification 2-year relevancy reviews were
required to be approved by the techn; cal specification clarification
subcommittee chairman and the manager operations.
l
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technical specification clarification deletions were required to be I
recommended in writing and contain justification for deletion.
-
For compliance issues, the chief operating officer on February 28,1997,
completed sessions with all departments communicating management ;
expectations regarding the need for verbatim compliance with nuclear regulatory
requirements. An action plan for regulatory awareness training was completed l
on March 12,1997. The purpose of this training was to effectively establish the
'
culture of literal compliance with regulations through initial communications, as
well as, continued re-enforcement of management expectations through the
training process.
The corrective action program was modified to include the following:
-
A corrective action review board was formed and met for the first time on
November 11,1996. The corrective acation review board was chartered j
to take a critical and questioning approach to each significant
performance improvement request it reviews. The corrective acation
review board was tasked to question whether the root cause was
correctly identified, corrective actions were appropriate, and if the
generic implications of the identified condition were addressed.
-
Organizational changes were implemented. Each group within the plant
operations organizations have performance imprnvement request
coordinators, whose primary responsibility will be to support the
corrective action process.
-
Training was held for managers and performance improvement request
coordinators on root cause analysis and human error prevention.
The licensee's leadership and selected membership changes to the plant safety
review committee and the nuclear safety review committee (offsite) were made in
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order to provide consistency in executing management's expectations. Both
committees were taking active roles in providing leadership and instruction to site
personnel in the area of literal compliance.
'
The team reviewed the licensee's corrective actions and concluded that they
were appropriate to prevent recurrence of the violation.
E8.8 (Closed) Violation 50-482/EA96-470-01033: Quality-Related Document Instruction Was
Not Appropriate to the Circumstances When the Licensee Allowed the Reactor Coolant
System to be Cooled Down With One Inoperable Source Range Channel
a. Backoround
The NRC identified that Technical Specification Clarification 00194, conflicted with
Technical Specification 3.3.1, Table 3.3-1, Functional Unit 6.b, Action 5, by allowing the
reactor coolant system to be cooled down, an activity which involved a positive reactivity
change, with one inoperable source range channel of nuclear instrumentation.
b. Inspection Followuo
The licensee stated that the reasons for the violation included technical specification
clarification procedural issues and weaknesses in the corrective action program, which
allowed for a nonconservative interpretation of the regulatory requirements. The licensee
also stated that during the editing process for a license amendment to Technical
Specification 3.3-1, an ambiguity was created which affected the intent / meaning of an
action statement.
l Prior to Amendment 96, Action Statement Sa, read:
"With the number of OPERABLE channels one less than the minimum
channels OPERABLE requirement, restore the inoperable channel to
OPERABLE status within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or open the Reactor Trip Breakers,
and suspend all operations involving positive reactivity changes and
verify valves BG-V178 and BG-V601 are closed and secured in position
within the next hour."
License Amendment 96 changed the wording to the following:
"With the number of OPERABLE channels one less than the minimum
channels OPERABLE requirement, restore the inoperable r hannel to
OPERABLE status within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or open the Reactor Trip Breakers,
and suspend all operations involving positive reactivity changes within
the next hour."
This word change resulted in an incorrect interpretation that positive reactivity changes
l were permissible after the reactor trip breakers were opened. As implied by the wording
of the technical specifications prior to Amendment 96, m positive reactivity additions
could be made after the reactor trip breakers were opened.
24
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The team reviewed the licensee's completed corrective actions to prevent recurrence of
the violation. These specific corrective actions included the following:
-
. Technical Specification Clarification Procedure AP 26C-003, " Technical
Specification Clarifications," Revision 1, was issued on April 10,1997. This
revision revised several steps which included requiring the Manager, Operations l
to assure that each technical specification clanfication received a 2-year I
relevancy review, and adding a note stating that a technical specification l
clarification may not change the intent, scope, wording or meaning of a technical ;
specification. I
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WCNOC Interoffice Correspondence Letter OP 97-0009, " Deletion of Technical l
Specification Clarification 001-94," was issued on March 25,1997.
-
Essential Reading Assignment 97-0011 was issued on March 27,1997, to inform
all licensed personnel, prior to assuming watch, that Technical Specification
Clarification 001-94 was deleted.
-
License Amendment Request, ET 97-00/1, dated July 29,1997, revised the
wording of Action Statement Sa to Technical Specification, Table 3.3-1, " Reactor !
Trip System Instrumentation." The NRC issued Amendment 111 on
September 29,1997, which changed the wording of Action Statement Sa to
Technical Specification, Table 3.3-1. The amendment statement prescribed the
set of actions to be accomplished when a source range neutron detector was ,
inoperable with the plant shutdown. This proposed wording change clarified the I
times and order in which these actions were to be performed.
The team reviewed the licensee's corrective actions and determined that they were ,
appropriate to prevent recurrence of the violation. l
l
E8.9 (Closed) Violation 50-482/EA96-470-01023: Reactor Coolant Pump Flywheel Inspection l
Integrity
a. Backoround l
!
The NRC identified that the licensee, on January 11,1995, made a change to a
procedure described in the Updated Safety Analysis Report that involved a change to
the technical specifications, without prior Commission approval. Specifically, the
licensee changed the frequency for scheduled surface and ultrasonic examinations of
reac',r coolant pump flywheels, as described in Regulatory Guice 1.14, " Reactor
Coolant Pump Flywheel Integrity," which is described in Section 3A and 5.4.1 of the
Updated Safety Analysis Report. However, the licensee did not recognize that the
change also involved a change to the technical specifications, because the Regulatory
'
Guide's examination schedule was specified by reference in Technical ;
Specification 4.4.10 (which was superseded by Technical Specification 6.8.5.b on l
October 2,1995). l
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.
Technical Specification, Section 6.8.5.b, specified the following requirement for the
reactor coolant pump flywheel inspection program, "Each reactor coolant pump flywheel
shall be inspected per the recommendation of Regulatory Position C.4.b of Regulatory
Guide 1.14, Revision 1, dated August 1975."
l
Regulatory Guide 1.14. " Reactor Coolant Pump Hywheel Integrity," Revision 1,
Regulatory Position C.4.b states, in part, "In service inspection should be performed for
each flywheel as follows: (2) A surface examination of all exposed surfaces and
complete ultrasonic volumetric examination at approximately 10-year intervals, during
l the plant shutdown coinciding with the inservice inspection schedule as required by
Section XI of the ASME code." In February 1995, Updated Safety Analysis Report
Change Request 95-003 was implemented to add an exception to the commitment to
Regulatory Guide 1.14, Revision 1, to address the frequency of the flywheel inspection.
During the regulatory screening and 50.59 evaluation, it was not ident;fied as a change
to the technical specifications and, therefore, no prior approval from the NRC was
sought.
b. Insoection Followup
The licensee stated that the reason for the violation included technical specification
clarification procedural issues and weaknesses in the corrective action program, which
allowed for a nonconservative interpretation of the regulatory requirements.
The licensee's corrective actions to prevent recurrence of the violation included the
following:
-
A license amendment was submitted under WCNOC Letter ET 96-0097, dated
December 3,1996, requesting a revision to Technical Specification 6.8.5.b for
inspection of the RCP motor flywheel. The amendment requested
implementation of the alternative testing requirements previously accepted by the
NRC for the Westinghouse Owners Group.
-
Change Request 96-02 was incorporated into WCRE-10. "Second Interval
in-service inspection Program Plan," on January 9,1997. This change revised
the inservice inspection program plan to identify that the 10-year inspection of
the flywheels shall occur within the 10-year inspection interval.
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Updated Safety Analysis Report Change Request 96-137 was initiated for
correcting the changes made by Updated Safety Analysis Report Change
Request 95-003 for inspection frequencies of the flywheel Unreviewed Safety
Question Determination S6-0191 was approved by the plant safety review
committee on December 11,1996, for this change request.
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A review of the technical specifications (up to Amendment 102) was performed
by the licensee to identify references to regulatory guides. Subsequently, the
Updated Safety Analysis Report was then reviewed to determine if changes to
the Updated Safety Analysis Report were made regarding the commitments to
the regulatory guides and the impact on the technical specifications. It was
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datermined that those portions of the Updated Safety Analysis Report that were
revised included either a technical specification revision to reflect these changes
or that the technical specifications were not impacted by the revision.
-
For compliance issues, the chief operating officer on February 28,1997,
completed sessions with all departments communicating management
expectations regarding the need for verbatim compliance with nuclear regulatory
requirements. An action plan for regulatory awareness training was completed
on March 12,1997. The purpose of this training was to effectively establish the
culture of literal compliance with regulations through initial communications as
well as continued re-enforcement of management expectations through the
training process.
-
For corrective action program issues, the corrective action program was
modified to include the following:
-
A corrective acation review board was formed and met for the first time
on November 11,1996. Corrective acation review board was chartered
to take a critical and questioning approach to each significant
performance improvement request reviewed.
-
Organizational changes were implemented, such that each group within
the operations department have performance improvement request
coordinators whose primary responsibility will be to support the
corrective action process.
-
Training was provided for managers and performance improvement
request coordinators on root cause analysis and human error prevention.
The team reviewed and found the licensee's corrective actions to be appropriate
to prevent recurrence of the violation.
E8.10 (Closed) Unresolved item 50-482/9808-01: Licensee Failed to Prepare Performance
Improvement Requests for 12 Updated Safety Analysis Report Significant Discrepancies
a. Backaround
The licensee identified 12 significant discrepancies in the Updated Safety Analysis
Report, but did not initiate performance improvement requests to ensure corrective
actions were initiated. An Updated Safety Analysis Report review iatabase was
established by the licensee to document discrepancies identified during the review
process. Self-Assessment Plan SEL 97-044," Wolf Creek Generating Station Updated
Safety Analysis Report Fidelity Review," dated October 17,1997, assigned responsibility
for developing and maintaining a corrective action screening mechanism for Updated
Safety Analysis Report discrepancies. The plan required that all corrective actions
associated with the Updated Safety Analysis Report fidelity review be conducted in
, accordance with Procedure AP 28A-001, " Performance Improvement Request." The
!
method for identifying the input forms was based on the number of the Updated Safety
l
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Analysis Report chapter, section, paragraph, table, etc., that the discrepancy was being
written against. The licensee stated that a group met twice a week to conduct an initial .
screening of discrepancies identified since the previous meeting. The twice weekly
meetings limited the maximum time elapsed between discrepancy identification and
initial screening to four days. On March 5,1998, the NRC reviewed printouts from a
sample of input forms which designated all the discrepancies as significant. The NRC
.
identified 12 significant discrepancies that were older than one week for which the
licensee had not generated a performance improvement request. The NRC noted that
the discrepancies ranged from one week to five months old. The 12 discrepancies were
as follows:
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Discrepancy 3.3.2-3051, dated 10/10/97, addressed the new radwaste building
not being designed to preclude endangering safety-related structures or
components when subjected to tornado loading.
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Discrepancy Table 15.7-7 (Section 11)-4013, dated 11/12/97, addressed
atmospheric dispersion factors during the fuel handling accident, in which, the
potential existed for the control room dose to approach General Design Criteria
19 limits.
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Discrepancy 4.3.3.3-4787, dated 12/11/97, addressed a need for verification of
spatial few-group diffusion calculations for reload cores because it appeared that
some of the values were outdated.
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Discrepancy 6.2.1.1.2,c.-6484, dated 2/5/98, addressed a problem associated
with calculated reactor containment intemal pressures, temperatures, and
inadvertent operation of the containment spray system.
-
Discrepancy 15.0.3.3-5183, dated 2/6/98, addressed reactor core power
distribution and questioned whether the historical uncertainty factor was
appropriately factored into the nuclear enthalpy rise hot channel factor or the
radial peaking factor.
-
Discrepancy 16.7.2.1.1 (4.7.7), dated 2/6/98, addressed polar crane seismic
restraints not being included in surveillance test procedures.
-
Discrepancy 3.10(B).1-6936, dated 2/17/98, addressed apparent conflicts
between Regulatory Guide 1.100, IEEE 344-1975, and the Updated Safety
Analysis Report regarding seismic qualification criteria.
-
Discrepancy 3.10(B).2-6982, dated 2/17/98, addressed an apparent conflict
between Regulatory Guide 1.100, IEEE 344-1975, and the Updated Safety
Analysis Report regarding methods and procedures for qualification of electrical
equipment and instrumentation.
- Discrepancy 16.7.2.1 (3.7.8)-6550, dated 2/27/98, addressed limiting conditions
for operation with respect to polar crane snubbers and the fact that they had not
been appropriately inspected.
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Discrepancy 9.4.1.2.3-6349, dated 2/25/98, addressed a potential discrepancy ;
identified between Calculation MGK 370, Revision 2, and the Updated Safety
Analysis Report with respect to local hydrogen concentration in the control
building. I
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Discrepancy 9.4.1.2.3-6350, dated 2/25/98, addressed an additional discrepancy
identified between Calculation MGK-370, Revision 2, and the Updated Safety
Analysis Report with respect to maintaining hydrogen concentration levels below l
0.5 percent volume by dilution with air provided by the control room '
pressurization system.
l
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Disciepancy 16.7.2.1.2-6692, dated 2/24/98, addressed modifications to I
16 steam generator snubbers that might not be discussed appropriately in the
current Updated Safety Analysis Report.
The NRC considered the licensee's failure to initiate perforrnance improvement requests
and determine appropriate corrective actions for the 12 discrepancies to be an
unresolved item.
b. Inspection Followuo
i
The team reviewed Procedure AP 28A-001, " Performance Improvement Request,"
Revision 9, the list of discrepancies, Self-Assessment Plan SEL 97-044," Wolf Creek j
Generating Station Updated Safety Analysis Report Fidelity Review," and discussed this l
item with licensee personnel.
The team noted that Section 4 of Procedure AP 28A-001 stated that a performance
improvement request, used to document the evaluation and resolution of problems,
including conditions adverse to quality, nonconformances, deficiencies, and deviations, I
was required for equipment operation problems, program or procedure implementation
problems, or work activities that do not occur as required.
The team found that Self-Assessment Plan SEL 97-044 required all corrective actions
associated with the conduct of the Updated Safety Analysis Report fidelity review to be
performed in accordance with Procedure AP 28A-001. However, the team noted that
the intent of this referral to Procedure AP 28A-001 was to assure that discrepancies that
affected plant operation or safety were appropriately entered into the corrective action
process via the problem identification report. in addition, the team noted that SEL 97-
044 provided the procedure to disposition identified discrepancies. This disposition
required the discrepancies to be initially screened, followed by a detailed review of the
discrepancy, and then resolution of the discrepancy through the normal corrective action
process. As the result of these reviews and discussions, the team determined that SEL
97-001 and Procedure AP 28A-001 were being properly implemented.
The team noted that nine of the 12 discrepancies were less than one month old and that
l none of the 12 discrepancies involved issues that affected operability of plant systems,
l structures or components, nor did they affect plant safety. The team also noted that the
29
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licensee addressed the 12 discrepancies and either issued problem identification reports
<
or determined that the discrepancy was minor in nature. Furthermore, to improve i
timeliness of processing USAR discrepancies, the licensee revised SEL 97-044 to )
assure that any potentialidentified discrepancy is resolved or a PIR initiated within 15 i
days of identification.
E8.11 (Closed) Unresolved item 50-482/97201-01: Cooldown Analysis
a. Backaround
l
The NRC reviewed Westinghouse Analysis FSDA-C-365,"NSSS Uprating Analysis," i
Revision 1, which was performed for power uprate and which calculated the time
required to bring the plant to cold shutdown so that neither the Updated Safety Analysis
Report cooldown rate of 100 degrees per hour nor the cooldown time of 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> was
exceeded. The time required to bring the plant to cold shutdown was dependent on the
residual heat removal flow and the temperature of the component cooling water system.
The component cooling water system temperature was dependent on the essential
service water system temperature. The NRC determined from the analysis calculation
that the piant could be brought to cold shutdown in approximately 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br /> with both
residual heat removal pumps running. The NRC found that the calculation used reactor
coolant system, residual heat removal system and component cooling water system flow
l
rates that were consistent with the design bases. However, this calculation also used an i
essential service water flow rate of 13500 gpm to the component cooling water heat ;
exchangers which was higher than that used in other calculations. The NRC reviewed l
Calculation EG-06-W, " Determine Flow and Heat Load Requirement," Revision W3. ;
This calculation included flow reductions caused by plugging of up to 46 tube pairs to l
provide margin for the future should plugging of additional component cooling water heat l
exchanger tubes be necessary. The essential service water flow used in this calculation
was 8800 gpm. The NRC noted that the Westinghouse analysis higher flow rate did not I
assume tube plugging. The licensee stated that only two tubes in one heat exchanger )
were plugged at the time. The licensee performed a preliminary evaluation of cooldown j
rate and time with the 8800 gpm flow rate and the two plugged tubes. This preliminary i
evaluation indicated that the cooldown rate and time would meet the values snacified in i
the Updated Safety Analysis Report.
b. Inspection Followup i
The inspectors reviewed Performance improvement Request 97-4145, dated April 24, .
1998, which discussed calculations with respect to differences in service water flow, the I
decay heat curve used, future tube plugging, and the time to cooktown. On March 9, l
1990, the licensee completed Plant Modification Request 02149, which reduced the
service water flow rate to the component cooling water heat exchangers to 8800 gpm.
However, the licensee failed to review and revise the Westinghouse analysis to reflect
the new design flow rate of 8800 gpm. In addition, the inspectors reviewed Change
Package 07659, dated April 24,1998, which the licensee prepared to remove
unnecessary heat loads. To assure that the cooldown rate of 100 degrees F and time of
20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> would be met, the licensee deleted use of the primary and secondary
evaporators during cooldown. The inspectors noted that the evaporators were not
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required during cooldown and by deleting them, approximately 17 million BTUs/hr of
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heat load were removed. The inspectors determined that removal of the evaporator ,
heat loads provided additional margin to meet the cooldown rate and time with both l
trains of the residual heat removal system operating as designed. The licensee revised
a number of operations procedures to assure that the evaporators were not used during
a cooldown. The inspectors also reviewed Updated Safety Analysis Raport Change
Request 98-069 dated April 22,1998, and determined that the licensee also revised the
Updated Safety Analysis Report to correct a number of errors dealing with the heat
loads and cooldown time.- The inspectors determined that the licensee's corrective
actions, which included calculation and procedure revisions were comprehensive and
adequate to prevent recurrence.
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10 CFR Part 50, Appendix B, Criterion Ill, " Design Control," requires, in part, that
measures shall be established to assure that applicable design bases are correctly
translated into specifications, drawings, procedures, or instructions. It also requires that
design control measures shall provide for verifying or checking the adequacy of the
design, such as by the performance of design reviews.
In 1990, Plant Modification Request 02149 reduced the service water flow rate to the ,
'
component cooling water heat exchangers to 8800 gpm. The supporting calculation for
this design change, Calculation EG-06-W, Revision W3, dated July 6,1990, described ,
the service water flow rate to the component cooling water heat exchangers as 8800 l
gpm. However, Westinghouse Analysis FSDA C-365, Revision 1, which determined the
cooldown rate and time, used a service water flow rate of 13500 gpm to the component
cooling water heat exchangers. The design control measures did not properly verify or
check the adequacy of Calculation EG-06-W in that the assumed service water flow
rates to the component cooling water heat exchangers were lower than those stated in
the Westinghouse analysis. The failure to correctly translate the design basis into
specifications and procedures was considered to be the first example of a violation of
10 CFR Part 50, Appendix B, Criterion 111 (50-482/9812-05).
E8.12 (Closed) Inspection Follow up item 50-482/97201-02: Emergency Core Cooling System
Leakage
a. Backaround
The NRC determined that there was no leekage acceptance criteria established for the
emergency core cooling system as required by Regulatory Guide 1.139, " Guidance for
Residual Heat Removal (RHR) to Achieve and Maintain Cold Shutdown," and referenced
in Updated Safety Analysis Report, Table 5.4A-1. This issue was identified by the
licensee's Design Basis / License Basis review team on November 5,1997, and they
initiated Performance improvement Requests 97-3738,97-3138, and 97-3563 to resolve
the discrepancy
l The NRC also determined that Updated Safety Analysb Report, Table 5.4A-1, did not
t establish an acceptable leakag limit for residual heat removal operability. However, in
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Updated Safety Analysis Report, Section 18.3.4, and Technical Specification,
j Section 6.8.4, the licensee had established a program to reduce leakage from systems
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outside containment that contain highly radioactive fluids. Their program required
monitoring and correcting leakage.s identified during surveillance tests or routine plant
walkdowns. Their program met the requirement of item Ill.D.1.1 of NUREG-0737. The
licensee stated that the existing program met the intent of Regulatory Guide 1.139 and
the Updated Safety Analysis Report table would be revised appropriately.
'
The licensee's corrective actions included the following:
-
The licensee initiated Perforrnance improvement Requests 97-3138,97-3563,
and 97-3738 to resolve the discrepancy. The only licensing basis problems I
identified were:
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Quantitive acceptance criterion was not included in the program for
monitoring emergency core cooling system leakage outside of
containment. This wau a problem because a 1 gpm acceptance limit for
emergency core cooling system leakage outside of containment was
implied in the Safety Evaluation R ; port. The I.censee ststed that a 1
gpm acceptance limit is not and never was included in the technical
specifications, although Technical Specification 6.8.4.a does provide a
qualitative acceptance limit of "as-low-as-practical" as discussed in ;
Updated Safety Analysis Report, Section 18.3.4, and NUREG 0881,
Supplement 5.
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Upd%d Safety Analysis Report Table 5.4A-1 (Sheet 8 of 10) stated that
the licensee complicd with Regulatory Guide 1.139. Regulatory
Guide 1.139 included the statement, "The leakage limits at which an RHR
train is to be declared inoperable and isolated should be stated in the
Plant Technical Specifications." The Safety Analysis Report contained a i
similar statement in Section 15.4.5.1. Technical Specification 6.8.4
required a program to maintain emergency core cooling system leakage
outside of containment at as low as practical levels, but did not specify ,
any quantitative acceptance limits at which equipment was to be
declared inoperable and isolated.
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The licensee revised Procedure AP 25C-001,"WCGS Leak Reduction of Primary
Coolant Sources Outside Containment," with Revision 1, which required a
computation of total emergency core cooling system leakage with a 1 gpm
acceptance criterion.
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The licensee revised Updated Safety Analysis Report, Tabh 5.4A-1 (Sheet 8
of 10), to state that residual heat removal leakage was addressed in the reactor
coolant sources outside containment program as discussed in the technical
specification and Updated Safety Analysis Report, Section 18.3.4.
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The licensee revised Procedures STN EJ-001, " Leakage inspection of the RHR
System," STN EN-001, " Leakage Inspection of the Containment Spray System,"
STN EM-001, " Leakage Inspection of the Safety injection System," and
STN BG-001, " Leakage inspection of the Chemical and Volume Control System
(CVCS)." These new procedures required performance of leak measurements
with the applicable pumps running and quantification of allleaks. The new
procedures were issued on June 3,1998.
The licensee revised Procedures STN PE-023, " TEN 02B Tank Pressure Test,"
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Revision 3, STN PE-024, "TEJ01B Tank Pressure Test," Revision 3,
STN PE-025, "TEJ01 A Tank Pressure Test," Revision 3, and STN PE-026,
" TEN 02A Tank Pressure Test," Revision 3, on June 2,1E'8. These procedures
included a prerequisite requiring the performer to review Procedure AP 25C-001
requirements prior to starting the test. The liquid equivalent of the acceptance
criteria for these procedures was now considered existing emergency core
cooling system leakage that counts toward the 1gpm acceptance criteria
contained in Procedure AP 25C-001.
b. Insoection Followuo
The inspectors reviewed the revised procedures and revised Updated Safety Analysis
Report, Table 5.4A 1. The inspectors determined that the corrective actions were
appropriate to correct the discrepancy. The inspectors verified that the new procedures
required performance of leak measurements as appropriate to calculate the required
residual heat removalleakage. The acceptance criterion was 1 gpm. The inspectors
noted that the licensee provided a quantitive acceptance criterion that was consistent
with the "as-low-as-practical" requirement of the technical specifications.
E8.13 (Closed) Urnesolved item 50-482/97201-03: Residual Heat Removal Pump Operation in
Minimum Recirculation Mode
a. Backaround
The NRC determined that for a small break loss-of-coolant accident,the residual heat
removal pumps would start and operate on minimum recirculation flow for 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />
l before an operator action was necessary to either shut the pump down or initiate cooling
!
flow to the residual heat removal heat exchanger. The NRC noted that this period of 2.5
, hours exceeded the pump manufacturer's specified time limit of 30 minutes.
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The ' IRC reviewed Calculation EJ-M-018, "RHR Pump Recirc. Operation vs. Time of
Initiation of CCW flow to RHR Heat Exchanger," Revision 0. This calculation provided
justification that the pumps could reliably operate in excess of 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> while in the
- recirculation mode. However, the team also noted that this calculation assumed an
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initial water temperature of 90 degrees F, whereas, Updated Safety Analysis Report,
Table 3.11b, specified that the maximum residual heat removal water temperature was
104 degrees F. Based on the NRC finding, the licensee determined that sufficient
margin existed in the calculation to demonstrate that the pump operation for 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />
without any cooling water would not damage the pump with the 104 degrees F initial
water temperature.
The licensee documented the corrective actions in response to the unresolved item in
Performance Improvement Request 97-4150. The licensee's corrective actions included
reviewing and revising Calculation EJ-M-018 as Revision 1, which changed the initial
water temperature to 104 degrees F.
b. Insoection Followuo
The inspectors reviewed Calculation EJ-M-018, Revision 1, and noted that the
calculation was appropriately checked and verified. The inspectors also determined that
the licensee's conclusions that a residual heat removal pump could be run for greater
than 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> with 104 degrees F initial water temperature was valid.
The licensee's design control measures did not assure that specifications were correctly
translated into the design for residual heat removal pump operation in the minimum
recirculation mode. Calculation EJ-M-018 incorrectly assumed an initial water
temperature of 90 degrees F in the residual heat removal system instead of a maximum
design basis temperature of 104 degrees F to determine the adequacy of pump
recirculation operation. The failure to translate the design data into
Calculation EJ-M-018, was considered to be the second example of a violation of
10 CFR Part 50, Appendix B, Criterion lli (50-482/9812-05).
E8.14 (Closed) Inspection Followuo item 50-482/97201-06: Procurement of Emergency Diesel
Generator Relay
a. Backaround
The NRC reviewed three modification packages to evaluate the 10 CFR 50.59 safety
evaluations and component procurement practices. The 10 CFR 50.59 evaluation
conclusions were adequate, and the changes were consistent with the design basis.
The team identified a concern with Design Change Package 05588, which in part,
procured an over excitation relay for an emergency diesel generator. This component
was installed as a safety-related item through the commercial grade dedication process
conducted by the supplier. To maintain the relay's qualification, the team noted that
monitoring of relay degradation was required, as specified in Certificate of
Conformance 62152.1, to determine the extent of degradation and establish the relay
replacement frequency. Documentation of the methodologies used to meet these
requirements and the surveillance results could not be provided by the licensee during
the inspection. The licensee issued Performance Improvement Request 98-0085 to
address this issue.
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b. Insoection Follown
The inspectors reviewed the following documentation: Certificate of
Conformance 62152.1,1-ENG-014 (Electrolytic Capacitor PM Program), Performance
improvement Request 98-0085, " Material Code Inquiry 90702222," and assorted work
packages and test records associated with the component. The inspectors also
interviewed licensee personnel. The inspectors determined that the procedures an-
documentation existed at the time of the NRC inspection and adequately ensured t
design basis for the component. In addition, the inspectors reviewed the test
surveillances and determined them to be acceptable for ensuring operability of the
emergency diesel generator relay.
E8.15 (Ocen) Inspection Followuo item 50-482/97201-07: Sizing of Class 1E Batteries.
a. Backaround
When determining the load profile of the batteries in Calculation NK-E-002," Class 1E
Battery Sizing," Revision 3, the licensee made some errors and omissions related to the
magnitude and application of load currents in the load profile.
b. Inspection Followup
The licensee issued Performance improvement Requests 97-3988 and 97-4063 to
address these discrepancies. The team reviewed the performance improvement
requests and determined that they were responsive to the concerns raised. This item
will remain open pending completion of the corrective actions outlined in the
performance improvement requests and subsequent NRC review.
E8.16 (Ocen) Inspection Follow uo item 50-482/97201-08: Sizing of Class 1E Batteries
a. Backaround
The licensee replaced the existing square cell Gould batteries with AT&T round cell
batteries under Design Change Package 05846 in early 1996. Technical
Specification 4.8.2.1 specified a criterion of 80 percent capacity for replacement of the
Gould batteries, however, the inspectors were concerned that this criterion was not
appropriate for determining degradation in the AT&T round cell batteries. In addition,
inspectors noted that an aging factor of 1.25 in the formula used to determine battery
cell size (Calculation NK-E-002, " Class 1E Battery Sizing," Revision 3) was omitted. As
a result of this omission, the potential existed that the batteries we e not oversized by
1.25 as required to offset a 20 percent deterioration that occurs at end of life. These
issues were referred to the Office of Nuclear Reactor Regulation (NRR) for review.
b. Insoection Followuo
Section 8.3.2.1.2 of the Updated Safety Analysis Report indicates that the batteries will
be replaced when their capacity decreases below 80 percent of the manufacturer's
rating in accordance with IEEE 450-1975. This capacity is determined by subjecting the
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battery to a performance discharge test every 60 months pursuant to Technical
Specification 4.8.2.1.e, or every 18 months for a degraded battery pursuant to Technical
Specification 4.8.2.1.f. These technical specifications were developed based on the
operating characteristics of the Gould batteries. As a rule, rectangular cell batteries, I
such as the Gould batteries, are relatively stable throughout most of their life, but l
experience a gradual capacity loss with age, with replacement recommended at '
80 percent capacity. As such, the Gould batteries were sized using a 1.25 aging factor
to ensure continued operability of the batteries.
The operating characteristic of the AT&T round cell batteries currently installed at Wolf
Creek differ from the Gould batteries in that they experience a gradual capacity increase )
over time. As such, an aging factor of 1.0 is used when sizing the batteries in lieu of
1.25. Based on the above, the gradual decline in capacity that was expected for the
Gould batteries as they age would be abnormalif observed on the AT&T round cell
batteries. Therefore, a technical specification surveillance test acceptance criterion of
80 percent capacity is not appropriate for the AT&T round cell batteries, since a
reduction in capacity would be indicative of abnormal battery performance.
The licens3 indicated that it intends to pursue an update to the Wolf Creek technical l
specification through the standard technical specification conversion process to reflect l
appropriate acceptance criteria for the AT&T round cell batteries. NRR found this l
approach to be acceptable. I
1
In addition, Updated Safety Analysis Report section 8.3.2.1.2 states, " . . a margin of l
25 percent is applied to ensure that tne rated battery capacity is at least 125 percent of
that required. This margin is consistent with the 80 percent capacity battery
replacement criteria given in IEEE 450-1975. As a result of the above sizing, the WCGS l
batteries are selected from those larger sizes that are commercially available. The I
resulting final battery selection is in excess of 150 percent of the system requirements."
This issue remains open pending for further review of the licensee corrective actions.
E8.17 (Ocen) Inspection Followuo item 50-482/97201-09: Sizing of Class 1E Batteries
a. Backaround
The licensee replaced the existing square cell batteries with AT&T round cell batteries
under Design Change Package 05846. However, sized the new batteries based on the
25 percent margin stated in the Updated Safety Analysis Report. However,
Section 8.3.2.2 of the NRC's Safety Evaluation Report was based on a battery capacity
oversizing margin of 50 percent. This issue was referred tc NRR for review and
resolution.
! b. Inspection Followup
!
i In addition to correction factors for temperature and design margins, the Gould batteries
were sized using an aging factor of 1.25 to account for loss of battery capacity as they
age. The AT&T batteries were sized using a temperature correction factor of 1.085, a
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design margin of 1.25 and an aging correction factor of 1.0, since the round cell
batteries are not designed to lose capacity as they age.
- ' NRR reviewed the licensee's calculations for sizing the AT&T round cell batteries and
identified that battery NK11, the battery that possesses the least amount of margin, was
purchased with an additional margin 23 percent of system requirements. As such, NRR
concluded that the AT&T round cell batteries are adequately sized to perform their
safety function however it was noted that battery NK11 is not sized with 150 percent of
the system requirements as stated in the Wolf Creek Updated Safety Analysis Report.-
The licensee plans to revise Calculation NK-E-002, " Class 1 E Battery Sizing." This issue
remains open pending review of calculation NK-E-002 and the licensee's corrective
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actions.
E8.18 [Qo6n) Unresolved item 50-482/97201-10: DC Load Flow and Voltage Drop
a. Backaround
, . Calculation NK E-001, " Class 1E DC Voltage Drop,' Revision 1, made an assumption
that a minimum operating voltage of 100 V was used for components where a minimum
,
had not been specified by the manufacturer,
b. Insoection Followuo
The licensee issued Performance Improvement Requests 97-4180 and 97-4043 to
address the issue. Performance Improvement Request 97-4043 attempted to link all
components listed at 100 V minimum to ANSI and ICS Standards stipulating the same
. values based on SNUPPS requirements. The team was concemed that this resolution
, was too general since some of the components may not have been designed to the
referenced standards even though this was a SNUPPS requirement. The licensee
indicated that they were also utilizing an attemate approach that links components to the
standards by comparison of similar representative components, when implementing the
< performance improvement requests. The team considered the etternate approach to be
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satisfactory.
The item will remain open pending completion of corrective actions by the licensee.
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E8.19 (Open) Unresolved item 50-482/97201-11: DC Load Flow and Voltage Drop
a. Backaround
.
- In reviewing Calculation NK-E-001, " Class 1E DC Voltage Drop," Revision 1, and
Calculation NK-E-002, " Class 1E Battery Sizing," Revision 3, it was observed that the
calculations did not reflect the worst case minimum voltage for each battery.
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b. Inspection Followuo
The licensee issued Performance Improvement Request 97-4185 to address l
these discrepancies. The team reviewed the performance improvement request and
determined that it satisfactorily addressed the concerns identified. Calculation NK-E-001
will be revised first and data from this calculation will be entered in
Calculation NK-E-002.
This item will remain open pending completion of the licensee's corrective actions.
E8.20 (Open) Unresolved item 50-482/97201-12: DC Load Control ,
i
a. Backaround i
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In reviewing Procedure A1-05-006, " Electrical Load Growth," Revision 0, it was noted
that dc electrical load growth was not always maintained in accordance with the
requirements of the procedure, and that a number of discrepancies existed in the data
base.
b. Insoection Followuo
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The licensee issued Performance Improvement Requests 97-4123,97-4125, and l
97-3846 to address the identified shortcomings. The team reviewed the performance
improvement requests ai.d determined that they were responsive to the issues
identified.
This item will remain open pending completion of the licensee's corrective actions.
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E8.21 (Closed) Unresolved item 50-482/97201-13: Acceptance Criteria for Battery Test
(Closed) Unresolved item 50-482/97201-14: Corrective Action For Battery Test !
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a. Backaround
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The NRC reviewed surveillance procedures for the safety-related batteries. During this l
review it was found that the only acceptance critena for Surveillance Test
Procedure MT-021, " Service Test for 125 VDC Class 1E Batteries," Revision 10, was
that the test be successfully completed. Also it was noted that the surveillance test did
not incorporate the design basis requirements contained in Calculation NK-E-002, l
pertaining to whether the battery discharge current was consistent with the load profile ;
.ind whether the battery final terminal voltage was higher tha7 the minimum allowable !
design value for the battery being tested. Furthermore, the acceptance criteria for
Step 6.1 of Procedure MT-022 "5 Year 125 VDC Discharge Battery Test," Revision 9,
did not specify that a constant discharge rate be maintained until battery terminal
voltage fell to a value equal to the minimum specified average voltage pcr cell or i
105 volts for 60 cells. In addition, neither procedure provided the needed corrective
actions for test deviations from the acceptance criteria. ;
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b. LnLspection
r Followuo
The inspectors reviewed documents and procedures and iriterviewed personnel to
determine the adequacy and completeness of the licensee's corrective actions. The
licensee issued Performance improvement Requests 97-3989 and 3941 which '
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identified the need to revise and clarify Procedures STS MT-021 and STS MT-022.
The inspectors reviewed these performance improvement requests and Procedures
STS-MT-021, " Service Test for 125vde Class 1 E Batteries," Revision 11, STS-MT-022,
"Sorvice Test for 125vdc Discharge Battery Test," Revision 10, Calculations NK- E-001,
" Class 1E DC Voltage Drop," Revision 1, and NK-E-002, " Class 1 E Battery Sizing," 1
Revision 3. The revised calculations and the performance improvement requests were l
determined to be thorough and comprehensive. The inspectors also reviewed a
licensee performed analysis that determined that the battery met the technical
specification operability requirements. The inspectors noted that the acceptance
criteria, and corrective actions taken for test deviations were placed into the respective
battery tests. As the result of this review, the inspectors determined that no operability
problem with the batteries existed.
The inspectors determined that the acceptance criteria for station battery surveillance
test procedures were not appropriate to the circumstances in that the procedure
acceptance criteria did not assure that battery discharge current was consistent with the
load profile, that the battery final terminal voltage was greater than the minimum l'
allowable design value, and that a constant discharge rate was maintained during
testing. This failure to implement appropriate acceptance criteria was considered to be
an example of a violation of 10 CFR Part 50, Appendix B, Criterion V (50-482/9812-02).
E8.22 (Closed) Unresolved item 50-482/97201-15: Refueling Water Storage Tank Level
Instrumentation
a. Backaround
The NRC reviewed Calculation SA 90-056, " Reactor Protection System ESFAS Channel
Error Allowances," Revision 0, which calculated the refueling water storage tank level
instrument loop uncertainty. As the result of this review, the NRC identified that the
licensee did not consider density variation due to temperature and boron concentration
in determining the refueling water storage tank level instrument loop uncertainties. As a
result, the Low-Low Level 1 switchover set point could reduce the available tank volume
by 3.24 percent, the Low alarm set point could be reduced 2.51 percent and the tank
empty alarm could drift down 14 inches to within 3 inches of the refueling water storage
tank suction line. These uncertainties would reduce the margi available to the
operators to respond to the event. The NRC reviewed Letter SLNRC 84-0089, dated
May 31,1984, which the licensee sent to the NRC justifying the use of indicated
readings without regard for instrument uncertainties to satisfy technical specification
surveillance requirements. The licensee could not find documentation of the NRC's
acceptance of the licensee's position. However, a preliminary evaluation performed by
l the licensee indicated that there was an adequate margin in the net-positive suction
j head analysis to compensate for level indication inaccuracies.
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The NRC reviewed Calculation BN-20, " Refueling Water Storage Tank Set Points,"
Revision 1, which assumed instrument inaccuracies of 1 percent for bistable and ;
3 percent for total loop error to establish the refueling water storage tank level set '
points. The licensee was not able to produce uncertainty calculations supporting these I
assumptions. However, as the result of the team's review of the licensee's preliminary ;
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analysis of these discrepancies, the team determined that no operability issue existed.
b inspection Followuo
The inspectors reviewed Performance improvement Request 973974, dated
December 4,1997, which the licensee initiated to review the density variation due to
temperature and boron concentration in the refueling water storage tank instruments.
The licensee identified that new calculations were required to determine total loop
uncertainty for the alarm set point, level indication and the computer point. The team I
reviewed the new Calculation BN-J-001," Refueling Water Storage Tank Level l
Transmitter Density Errors," Revision 0, which was prepared to determine the magnitude l
and direction of errors due to density variations in the borated water contained in the
tank. The team determined that the licensee was in the process of preparing two
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additional calculations to determine and document the inaccuracies for other bistables
and loop uncertainties, and set points for other functions. In addition, the licensee
stated that they would revise Calculation SA-90-056 to incorporate the density variation
due to temperature and boron concentration.
The inspectors reviewed the licensee's Letter SLNRC 84-0089 dated May 31,1984.
This letter discussed the use of indicated readings without regard for instrument
uncertainties to satisfy technical specification surveillance requirements. The subject
matter was discussed with the NRC program office. As the result of these discussions,
the inspectors determined that the NRC had accepted the licensee's position regarding
the use of indicated instrument readings without instrument uncertainties to satinfy
technical specification surveillance requirements.
Design control measures did not ensure that the refueling water storage tank level
instrumentation uncertainty Calculation SA-90-056, " Reactor Protection System ESFAS
Channel Error Allowances," Revision 0, which calculated the Low-Low Level 1 set point
for the refueling water storage tank, correctly translated errors from density variation due
to temperature and boron concentration in determining the refueling water storage tank
level instrument uncertainty. In addition, uncertainty calculations did not exist for the
instrument inaccuracies of 1 percent for bistables and 3 percent for total loop error which
were assumed in Calculation BN-20, " Refueling Water Storage Tank Set Points,'
i .e/ision 1. The inspectors determineo that the failure to incitde density variations due
to temperature and boron concentrations in the refueling water storage tank level
calculations and the failure to have calculations for the uncertainties associated with
bistable and totalloop error was the third example of a violation of 10 CFR Part 50,
Appendix B, Criterion 111 (50-482/9812-05). The licensee's planned corrective actions
appeared comprehensive and appropriate to prevent recurrence.
E8.23 LClosed) Unresolved item 50-482/97201-16: Seismic Qualification
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a. Backaround
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The NRC deterrnined that the licensee's design control measures appeared to not l
verify or check the adequacy of the residual heat removal pump suction Pressure
Gages PI-601 and PI-602, to ensure that these gages would operate satisf actorily l
during a seismic event.
In response to the NRC finding the licensee stated that their Ashcroft Model 1279 l
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pressure indicators (installed as PI-601 and 602) were supplied by Westinghouse along
with other indicators under their Specification Sheet 04610 in the mid-1980 time frame.
Furthermore, the licensee stated that items on this specification sheet were ;
manufactured by Ashcroft as commercial grade items with no unique nuclear l
requirements. Westinghouse supplied them to Wolf Creek under the program they had l
in place at the time. The program, as documented in a Westinghouse letter dated i
July 10,1989, included an engineering judgement by Westinghouse regarding the j
seismic and pressure boundary integrity of the indicators. j
During the latter part of the 1980's, the nuclear industry developed the concept of a !
" commercial grade" item and the documentation to be provided in the future to dedicate
such items for use in nuclear safety-related applications, such as residual heat removal
pump suction Pressure Gages PI-601 and PI-602. At this time, the licensee questioned
the documentation available onsite to substantiate the Westinghouse seismic integrity
engineering judgement for the Ashcroft indicators. The licensee stated that this was
strictly an effort to upgrade the information available onsite, and did not reflect any
concern that the indicators could not withstand a seismic event. In fact, the licensee
noted that other similar Ashcroft 1279 Pressure Indicators, that had been supplied by
Bechtel under their Specification J-515A(O), had been provided with a seismic
qualification report. Westinghouse provided the licensee with Letter RCS/ CIEL (89)-299,
dated July 10,1989, which provided the bases for the seismic qualification of the
pressure indicators.
In mid-1991, the licensee decided to have a review performed to compare the
Bechtel Specification J-515A(O) seismic qualification report envelop against the three
possible configurations supplied by Westinghouse (diaphragm seal only, snubber only,
neither diaphragm seal nor snubber). The licensee stated that this review was not done
because there was a concern as to the seismic acceptability of the pressure indicators,
but rather to address the use of dedicated commercial grade items. The review was
completed for Calculation XX-F-010, " Seismic Qualification of Ashcroft Model No.1279,"
dated August 29,1991, and formally issued on January 21,1998. The licensee stated
that this review supported seismic qualification and exceeded the requirements for
commercialitem dedication. The purpose of the calculation was to provide seismic
qualification and justification to indicate that the Ashcroft Model 1279 pressure indicators
in accordance with Specification Sheet 04610, Revision 1, supplied by Westinghouse,
were similar to those of Specification J-515A, supplied by Bechtel. The license stated
that this review included all the safety-related pressure indicators furnished under
Specification Sheet 04610, and not just the PI 601/602 pressure indicators.
b. Inspection Followuo
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The inspectors noted that the licensee considered the residual heat removal pump
suction pressure indicators to have both a pressure integrity and a seismic design safety
function. The inspectors reviewed the Calculation XX-F-010, and the documentation
concerning the two pressure indicators and determined that there was no measurable
difference between the two pressure indicators. The inspectors also verified that
Calculation XX-F-010, provided a seismic qualification of the Ashcroft Model 1279
pressure indicators. The licensee again indicated that they had no concern regarding
the seismic qualification of the Ashcroft Model 1279 indicators. This position was based
on the Westinghouse's letter of July 10,1989,and later by Calculation XX-F-010.
Furthermore, this was supported by Bechtel's seismic qualification report of Ashcroft
Model 1279 pressure indicators.
. E8.24 [ Closed) Unresolved Item 50-482/97201-17: Nitrogen Bottle Installation
a. Backaround
During a refueling outage, the NRC determined that nitrogen bottles, temporarily
installed in the residual heat removal heat exchanger rooms and fastened to steel
structures by No. 9 wire, were not seismically restrained and could cause a potential
missile hazard. The licensee stated that those nitrogen bottles were installed in
accordance with Procedure GEN 00-007, "RCS Drain Down Procedure," Revision 19, to
provide backup nitrogen for the residual heat removal heat exchanger outlet valve
operators (EJHCV-606 and 607) during the refueling outage. The NRC team identified
that a safcty evaluation was not performed in accordance with 10 CFR 50.59 to provide
a basis for determining that an unreviewed safety question was not involved for the
installation of nitrogen bottles in the residual heat removal pump rooms.
Since these bottles were removed at the end of the refueling outage, the licensee and
the NRC concluded that this condition did not constitute an operability concern. The
licensee documented the corrective actions to this issue using Performance .
Improvement Request 97-3961. The licensee revised Procedure GEN 00-007 and
developed a 10 CFR 50.59 safety evaluation. The licensee concluded that the nitrogen
bottle installation was not an unreviewed safety question.
b. Inspection Followup
The inspectors reviewed the safety evaluation and Procedure GEN 00-007, "RCS Drain
Down," Revision 28, dated April 1,1998. The inspectors observed that the licensee
changed the procedure to ensure that the appropriate restraints were used when
installing the nitrogen bottles. However, the inspectors also oLserved that the procedure
did not state where the bottles would be placed in the residual heat removal heat
exchanger rooms. The licensee re_ vised Procedure GEN 00-007 on June 23,1998, to
include the correct nitrogen bottle location.
The inspectors noted that neither this nitrogen bottle installation nor a procedure that
described the nitrogen bottle installation was described in the Updated Safety Analysis
Report. Since this change did not change the facility as described in the Updated Safety
Analysis Report, a 50.59 safety evaluation was not required.
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E8.25 (Closed) Unresolved item 50-482/97201-18: Motor-Operated Valve Different!al
Pressure
a. Backaround
The NRC evaluated the adequacy of the component cooling water containment isolation
valves to meet their design basis requirement by reviewing the motor-operated valve
design documents. These valves are required to close against reactor coolant pressure
resulting from a reactor coolant pump (RCP) thermal barrier break. During this review,
the team observed that during the design basis accident involving a rupture of the RCP
thermal barrier, the differential pressure against which Valves EG-HV-062 and -132
must close was calculated to be 1120 psid. This result was based on a nonconservative
assumption that the downstream pressure used in the calculation was an average of the
pressure before and after closure. This caused the downstream pressure to be
unrealistically high and consequently the experienced differential pressure to be low.
The team determined that the downstream pressure would be 22 psig (based on the
static nead of the component cooling water surge tank) and the differential pressure for
closure would be 2228 psid. The licensee initiated Performance Improvement
Request 97-4054 to resolve this issue. The licensee also performed a review and
determined that the only other valves affected were Valves BB-HV-0013/14/15/16.
However, these valves are closed on limit switch control in lieu of torque switch control
and therefore did not have a similar problem.
b. Inspection Followuo
The inspectors reviewed documents, procedures, and interviewed personnel to
determine the adequacy and completeness of the licensee's corrective actions. The
inspectors specifically reviewed the following documents: Performance improvement
Request 97-4054, Calculations EG-M-006, -007, and -012 (bounding conditions for
motor-operated valves), all Revision 3. The NRC determined that
Calculation E-025-00007(O)-W10, "MOV Design Configuration Document,"
Revision 9W, incorrectly identified the differential pressure to close component cooling
water Valves EG-HV-062 and -132 as 1120 psid ;.. stead of 2228 psid. The reason for
the error was due to assuming a nonconservative downstream pressure of 1130 psig
instead of 22 psig based on the static head of the component cooling water surge tank.
The inspectors noted that there was no operability concern because the licensee's
analysis demonstrated that the motor-operated valves had sufficient thrust to close the
valves against the required differential pressure.
While the inspectors agreed with the licensee's conclus.ons and corrective actions for
this item, the inspectors determined that the licensee's design control measures did not
assure that the component cooling water motor-operated valve design bases were
correctly translated into the design calculations. The failure to translate the required
design basis differential pressure specified for the component cooling water motor-
operated valve was the fourth example of a violation of 10 CFR Part 50, Appendix B,
Criterion lli (50-482/9812-05). The licensee's corrective actions appeared to be
comprehensive and adequate to prevent recurrence.
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E8.26 (Closed) Unresolved item 50-482/97201-19: Component Cooling Water Low
Temperature
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a. Backaround
The NRC reviewed Design Change PMR 4380, " Component Cooling Water
Temperature Change," Revision 2, and its associated safety evaluation. The NRC
noted that this design change revised the allowable component cooling water
, temperature from 60 to 32 degrees F. The design change assumed that the component
cooling water system was at the same temperature as the lake water when the lake was
at 32 degrees F. The NRC identified that two items were not adequately addressed in
the design change package or in the safety evaluation.
The NRC determined that the lower component cooling water temperature caused lower
lubricating oil temperature for several motors, resulting in higher power requirements.
The increased emergency diesel generator loading was not addressed in either the
modification or the safety evaluation. However, the NRC concluded that there was no
operability concern since the loading increase was small and the diesel generator had a
large loading margin.
The NRC also determined that the lower component cooling water temperature resulted
in a lower spent fuel pool water temperature. The lower spent fuel pool temperature
effect on reactivity was not addressed in either the modification or the safety evaluation.
The NRC noted that the minimum temperature for which the spent fuel pool reactivity
was analyzed was 60 degrees F. The licensee stated that the spent fuel pool
temperature could approach within 4 degrees F (i.e.,36 degrees F) of the component
cooling water temperature. The licensee issued On-the-Spot Change 97-0898 To
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Procedure CKL ZL-003, " Control Room Daily Readings," which placed an administrative
limit of 65 degrees F on the minimum spent fuel pool temperature until a reactivity
analysis at lower temperatures was completed. Subsequent to the inspection, the
l licensee completed an analysis which determined that lowering the spent fuel pool
temperature from 60 to 35 degrees F would reduce the reactivity in the spent fuel pool.
In addition, L licensee determined that the lower temperature had no adverse effect on
the solubility of boron because the spent fuel pool boron concentration of 2000 to
2500 ppm was well below the saturation curve at 35 degrees F.
The NRC determined that the licensee's safety evaluation did not completely verify the
absence of an unreviewed safety question since it did not address the effect of low
temperature on the spent fuel pool reactivity and did not evaluate the effects on the
l diesel generator loading caused by the lower component cooling water temperature.
!
i b. Inspection Followup
The inspectors reviewed Performance improvement Request 973978, dated
December 4,1997, which the licensee generated to resolve the issue of the increase in
power required to run the safety-related pumps when component cooling water
temperature was 32 degrees F. The licensee determined that the net increase on the
diesel generator load per train was 24 kW. The inspectors noted that the most limiting
a
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safety related load on the emergency diesel generator occurred during the recirculation
phase and was equal to 5260 kW. The maximum load of 5834 kW including safety and
nonsafety-related loads occurred during a station blackout event. The inspectors noted
that each generator was rated at 620 > A &ntinuous operation, therefore, no
operability concern was identified. The i CAs determined that there was adequate
margin to meet the additional demand. ~ ' - Joectors reviewed the revised 10 CFR
50.59 safety evaluation and found that the ' aee included a discussion of the increase
in power to run the safety-related pumps ano the effect on the diesel generator. The
inspectors noted that the licensee concluded that the lowering of the component cooling
water temperature which caused an increase in pcwer demand to run the safety-related
pumps was not an unreviewed safety question. The inspectors agreed with the
licensee's evaluation.
The inspectors reviewed Performance Improvement Request 974062, dated
December 12,1998, which was initiated to determine the effect of low component
cooling water temperature on the spent fuel pool reactivity. In addition, the licensee
prepared a 10 CFR 50.59 safety evaluation, dated January 14,1998, to determine the
acceptability of revising the Updated Safety Analysis Report to reflect allowing the spent
fuel pool temperature to go as low as 35 degrees F. The effects of the lower
temperature on reactivity and boron solubility were evaluated as a result of the change
to the Updated Safety Analysis Report. The inspectors found that the effect of the
temperature change on reactivity was that it added conservatism by resulting in a net
negative reactivity addition. Based on the increase in negative reactivity being added to
the spent fuel pool, the licensee stated there were no credible accidents created by the
change. The licensee further stated that the criticality analysis in the Updated Safety
Analysis Report was conservative in that this analysis assumed no boron in the water,
while the pool boron concentration was maintained at or above 2000 ppm.
While the inspectors agreed with the licensee's conclusions and corrective actions for
this item the inspectors determined that the licensee's design control measures did not
assure that the effects of the lower component cooling water water temperatures on the
spent fuel pool reactivity were correctly translated into design Change PMR 4380. The
failure to translate the lower component coolin, . vater water temperature. 'nto the
design bases was the fifth example of a violation of 10 CFR Part 50, Appendix B,
Criterion lli (50-482/9812-05). The licensee's corrective actions appeared to be
comprehensive and adequate to prevent recurrence.
E8.27 (Closed) Unresolved item 50-482/97201-20: Corrective Action for Component Cooling
Water Operating Procedure
a. Backaround
The NRC determined that the licensee's Updated Safety Analysis Report,
Section 9.2.2.2.3, stated that during a cooldown, component cooling water flow to the
spent fuel pool heat e' : anger was reduced or terminated within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after
shutdown. However, the licensee's operating procedures did not specifically inform the
operator to reduce component cooling water flow to the component cooling water heat
exchanger four hours after shutdown to assure adequate flow to the remaining
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equipment cooled by component cooling water. The licensee identified in performance
improvement request 95-1167 dated May 1995, that this design basis requirement was
not incorporated in Operating Procedures EJ-120, " Start of a Residual Heat Removal
(RHR) Train," Revision 32, and EJ 121, " Start of a RHR Train in Cooldown Mode,"
Revision 11.
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As corrective action to Performance Improvement Request 95-1167, the licensee l
changed the procedures to provide better agreement with the Updated Safety Analysis i
Report. In addition, the Updated Safety Analysis Report Section was revised to be ')
compatible with the paragraphs in Procedures EJ-120 and EJ-121. However, upon - !
review of these procedures, the NRC noted that the Updated Safety Analysis Report and
the affected procedures were still not in agreement. Specifically, the licensee's operating i
procedures did not inform or direct the operator to reduce the component cooling water
flow to the component cooling water heat exchanger four hours after shutdown. l
The licensee initiated Performance improvement Request 97-3887 on November 24,
1997, to readdress the issue of specifically directing operators to reduce the component '
cooling water flow to the component cooling water heat exchanger four hours after
shutdown. The licensee initially believed that the applicable residual heat removal
system procedures could be changed to reflect what the Updated Safety Analysis l
Report stated in regards to reducing the component cooling water flow after shutdown. l
After further review, the licensee determined that the need to reduce the component
cooling water flow was based on 90 degree F lake temperature. The licensee
considered that adding this Updated Safety Analysis Report requirement to the residual
heat removal system procedures could cause operator confusion due to the fact that
lake temperature seldom approaches 90 degrees F. The licensee determined that an
Updated Safety Analysis Report change should be made to clarify the Updated Safety
Analysis Report statement. The clarification would provide background information that
would aid in the operation of the component cooling water system. The residual heat
removal system procedures would be revised once the Updated Safety Analysis Report
change was finalized.
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- The licensee's corrective actions were as follows
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Updated Safety Analysis Report Change Request 98-048 and associated
unreviewed safety question were approved by the plant safety review committee
on April 22,1998, which clarified the Updated Safety Analysis Report on the
need to isolate the component cooling water flow to the component cooling water
heat exchanger. The Updated Safety Analysis Report was changed identifying
that if the component cooling water heat exchanger outlet temperature exceeded
120 degrees F during shutdown and cooldown, the component cooling water flow
to the component cooling water heat exchanger was to be reduced or
terminated.
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Procedure STS EJ-120, "Startup of a Residual Heat Removal Train," Revision 33
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added Step 4.10 to ensure component cooling water cooling was isolated to the
- component cooling water heat exchanger if component cooling water outlet
- temperature exceeded 120 degrees F.
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Procedure STS EJ 121, "Startup of a RHR Train in Cooldown Mode,"
Revision 12, added Step 4.9 to ensure component cooling water cooling was i
isolated to the component cooling water heat exchanger if component cooling I
water outlet temperature exceeds 120 degrees F. I
b. Inspection Followuo
I
In 1995, the licensee initiated Performance Improvement Request 95-1167 to identify I
that this requirement as stated in the Updated Safety Analysis Report, had not been 1
incorporated in Operating Procedures EJ-120, and -121. The licensee changed both
procedures and the Updated Safety Analysis Repoit, Section 9.2.2.2.3, but failed in
1995 to correct a discrepancy regarding specific isolation instructions for the component
cooling water heat exchanger.
The NRC identified that clarification of the Updated Safety Analysis Report,
Section 9.2.2.2.3, was needed to address consideration of the lake temperature to
determine when the component cooling water flow had to be reduced or terminated.
The licensee initiated Performance improvement Request 97-3887, to readdress this
issue. In addition, procedure changes in Procedures STS EJ 120 and -121 were
initiated which detailed new steps ensuring component cooling water cooling was
isolated to the component cooling water heat exchanger if component cooling water
outlet temperature exceeded 120 degrees F. The licensee also initiated Updated Safety
Analysis Report, Change Request 98-048, which clarified the Updated Safety Analysis
Report on the need to isolate the component cooling water flow to the component
cooling water heat exchanger on April 22,1998. The Updated Safety Analysis Report
was revised to identify that if the component cooling water heat exchanger outlet
temperature exceeded 120 degrees F, the component cooling water flow to the
component cooling water hea exchanger was to be reduced or terminated.
10 CFR Part 50, Appendix B, Criterion XVI, requires that procedures be established to l
assure that conditions adverse to quality are promptly identified and corrected. The
failure to promptly correct a discrepancy regarding the component cooling water cooling i
flow isolation to the component cooling water heat exchanger during cooldown was a
violation of 10 CFR Part 50, Appendix B, Criterion XVI. This licensee-identified and
corrected violation is being treated as a noncited violation, consistent with
Section Vll.B.1 of the NRC enforcement policy (50-482/9812-06).
E8.28 (Open) Unresolved item 50-482/97201-21: Updated Safety Analysis Report
Discrepancies
a. Backaround
The NRC team identified the following Updated Safety Analysis Report discrepancies:
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Different values were referenced for the refueling water storage tank water
volumes in the documents listed below.
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Updated Safety Analysis Report Section 6.3.2.2 (page 6.3-6) stated that
the minimum refueling water storage tank volume "available" or
" assured" for emergency core cooling system injection mode operation
was 394,000 gallons. Another paragraph in the same Updated Safety
Analysis Report section refers to " usable" volume. However, Technical
Specification 3/4.5.5 specified the 394,000 gallons as the minimum i
contained water volume. I
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Updated Safety Analysis Report Table 6.3-1 listed 419,000 gallons
as maximum volume,407,000 gallons as normal capacity, and
394,000 gallons as assured water volume. These three refueling water
storage tank volumes are also shown in Updated Safety Analysis Report,
Figure 6.3-7, and System Description M-10BN(O), Figure 1.
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Updated Safety Analysis Report Table 6.2.1-5 listed refueling water ,
storage tank water volurne of 370,000 gallons for containment analysts.
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Updated Safety Analysis Report, Table 6.3-10, listed 326,860 gallons as
refueling water storage tank volume for emergency core cooling system
cooling.
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NUREG-0881 (Wolf Creek), Section 8.3.2.1.2, refers to the same section in
NUREG-0830 (Callaway) for a discussion of the NRC staff's position on battery
capacity. That section of NUREG-0830 stated that the licensee revised the ,
Updated Safety Analysis Report in Revision 6 to state that batteries were sized in i
excess of the 50 percent margin required. Callaway Updated Safety Analysis
Report was revised, but the Wolf Creek's Updated Safety Analysis Report had
not been revised to reflect similar changes.
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Updated Safety Analysis Report Section 9.2.2.2.2 states, "The normally closed
parallel sets of containment isolation valves will allow the operator to establish
cooling water to the reactor coolant pumps and the excess letdown heat
exchanger under emergency conditions, with a single failure." However,
Updated Safety Analysis Report, Table 3-11(B)-3, listed the motor operators for
these valves as Category C, EO not required. The currently installed motor
operators are Class RH, that is, environmentally qualified and, therefore, there
was no operability concern.
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Calculation EG-06 W," Component Cooling Water System Calculation," Revision
W-3, determined that the component cooling water hc at exchanger heat transfer
coefficient was 190 Btu /hr-ft -F based on the revised essential service water flow
of 7150 gpm. The Updated Safety Analysis Report stated that the t.ransfer
coefficient was 193 Btu /hr-ft2-F.
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Calculation SA-89-017," Evaluation of CCW & RHR Heat Exchanger
Performance for the Extended Fuei Operating Cycle (18 Months)," Revision 0,
determined that component cooling water temperature reaches 126 degrees F.
However, Updated Safety Analysis Report, Table 9.2-11, was based on a
component cooling water temperature of 120 degrees F.
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Updated Safety Analysis Report Fig. 5.4-8 showed suction for residual heat
removal Pumps A and B as coming from RCS hot-leg Loop 4, whereas, System
Description M-10EJ(O) and P&lD M-12EJ01 showed Loop 1 for Pump A and
Loop 4 for Pump B.
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Updated Safety Analysis Report Section 6.3.5.3, " Flow Indication," stated that the
flow frorn each residual heat removal subsystem to the RCS cold legs was
recorded in the main control room. This contradicted Updated Safety Analysis
Report, Table 7.5-1, and P&lD M-12JE01 (Loop FT-988), which showed this
parameter as being indicated (instead of recorded) in the main control room.
The licensee issued Performance improvement Request 97-4179 to update the
Updated Safety Analysis Report.
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Updated Safety Analysis Report, Table 7A-3, showed a range of 0-60 psig for the
containment pressure gauge, whereas, the range of the installed gauge was
0-69 psig.
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Updated Safety Analysis Report, pages 6.3-6,9.2-43,9.2-45, and 9.2-48
incorrectly described the control function of the refueling water storage tank
auxiliary steam heating system with respect to winterization
Procedure STN GP-001.
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Updated Safety Analysis Report Section 8.3.2.1.2 stated that a Class 1E battery
was to supply the loads in Tables 8.3-2 and 8.3-3 for 200 minutes where it should
be for 240 minutes.
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Updated Safety Analysis Report, Section 7.4.1, states that the refueling water
storage tank level transmitters are required for safe shutdown. However,
Updated Safety Analysis Report, Table 3.11(b)3, does not list these transmitters
as required for hot or cold shutdown.
The above discrepancies had not been corrected and the Updated Safety Analysis
Report updated to assure that the information included in the Updated Safety Analysis
Report contained the latest material as required by 10 CFR 50.71(e).
b. Insoection Followuo
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The licensee initiated Performance improvement Request 97-4018 to address
the refueling water storage tank water volume inconsistencies in the Updated
.
Safety Analysis Report, technical specifications, and system description. The
! licensee will review and implement the appropriate document changes in
response to this issue.
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The licensee initiated Performance Improvement Request 98-0618 to address
the battery capacity issue. The licensee will review and implement the l
appropriate document changes in response to this issue following resolution of I
Unresolved Item 50-482/97201-09, Battery Sizing.
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The licensee documented the corrective actions for the component cooling water l
containment isolation valve qualification issue in Performance improvement l
Request 97-4126. The corrective actions included performing calculation, l
EG-M-032, "CCW Heat Exchanger Performance," Revision 0, to provide a basis
for revisions to the Updated Safety Analysis Report and component cooling water !
system description. The licensee implemented the Updated Safety Analysis
Report changes with Updated Safety Analysis Report Change Request 98-037.
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The licensee stated that the component cooling water heat exchanger heat
transfer coefficients were different because the 190 Btu /hr-ft -F value assumed
that the maximum heat exchanger tubes were plugged. This value was then
used to determine if the component cooling water water temperature going to the
components cooled by the component cooling water system was below the
maximum allowed value. The licensee determined that the water temperature
would be within the required limits.
The 193 Btu /hr-ft2 F value was used to determine the maximum heat load that
the component cooling water heat exchangers would discharge to the ultimate
hcat sink. The licensee determined that the ultimate heat sink would not exceed
any design temperature limits based on this heat transfer coefficient. Although
the two heat transfer coefficients were different, they were used as conservative
,
values in different calculations. No Updated Safety Analysis Report change was
i
required.
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The licensee documented the corrective actions for the component cooling water
heat exchanger outlet temperature discrepancy in Performance improvement
Request 97-4052. The licensee reperformed Calculation EG-M-032, "CCW Heat
Exchanger During Normal Operations, Shutdown @ Four Hours (and 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />),
and Post-LOCA Recirculation," Revision O. The calculated maximum component
cooling water heat exchanger outlet temperature was 126.8 degrees F, which
was below the allowed upper limit of 130 degrees F. The value of 130 degrees F
was then used as a basis in Calculation EG-06-W, " Component Cooling Water
System," Revision 4. Based on the results of the calculations, Updated Safety
Analysis Report, Table 9.2-11, was revised using Updated Safety Analysis
Report CR 98-069, to be consistent with the results of Calculation EG-M-032.
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The licensee documented the corrective actions for the residual heat removal
pump loop suction location discrepancies in Performance improvement Request
97-3823. The licensee determined that the residual heat removal Pump A
< suction was from Loop 1 and not Loop 4 as shown in Updated Safety Analysis
l Report, Figure 5.4-8. The licensee corrected the figure using Updated Safety
Analysis Report Change Request 98-010.
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The licensee documented the corrective actions for the residual heat remova!
system control room indication discrepancies in Performance Improvement
Request 97-4179. The corrective actions included reviewing the residual heat
removal system description, piping and instrument diagrams, and Updated
Safety Analysis Report, Section 6.3.5.3. The licensee determined that the only
discrepancy was that the paragraph title in Updated Safety Analysis Report, 1
Section 6.3.5.3, was incorrect which resulted in a misinterpretation of the i
Updated Safety Analysis Report. The titie was changed to "RHR Pump Cold Leg I
Injection Flow" from "RHR Pump Hot Leg injection Flow." The licensee corrected I
the paragraph title using Updated Safety Analysis Report Change I
Request 98-010. )
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The licensee documented the corrective actions for the difference in the I
containment pressure gage actual range and the range licted in Updated Safety l
Analysis Report Table 7A-3 in Performance improvement Request 98-0062. The I
licensee determined that the Updated Safety Analysis Report table was incorrect.
The licensee changed the Updated Safety Analysis Report table using Updated
Safety Analysis Report Change Request 98-010.
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On February 21,1997, the licensee documented the refueling water storage tank l
heating steam control function issue in Performance improvement Request
97-0547 when identified by the system engineer. On March 27,1997, the
licensee reviewed the issue and implemented changes to the affected
documents. In addition, on December 30,1997, the licensee approved Updated ,
Safety Analysis Report Change Request 97-044 to correct the heating steam
control function descriptions.
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The licensee initiated Performance Improvement Request 97-4190 to address
the battery load supply time issue. The licensee will review and implement the
appropriate document changes in response to this issue following resolution of
Unresolved item 50-482/97201-07, Battery Load Profile.
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The licensee documented the correctiv.:, metions for the refueling water storage
tank level transmitter issue in Performance improvement Request 97-3958. The
licensee determined that Updated Safety Analysis Report, Section 7.4.1 was
incorrect in stating that the level instruments were required to maintain a hot
standby under a non accident condition. The licensee corrected the Updated
Safety Analysis Report section using Updated Safety Analysis Report Change
Request 97-203.
This item remains open pending further NRC review of the licensee's Updated Safety
Analysis Report upgrade program.
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E8.29 (Closed) Inspection Follow uo item 50-482/9604-03: Safety-Related Batte y
F . placement with AT&T Round Cells ;
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a. Backarour,a
This item involved concerns that previous industry problems with the AT&T round cell
batteries were not sufficiently understood to provide assurance that they would not occur
at Wolf Creek.
b. Inspection Followup l
The team was familiar with problems encountered with AT&T round cell batteries at
other nuclear facilities involving the AT&T high specific gravity cells. The cells installed
at Wolf Creek, however, were of a different design, termed " low specific gravity cells."
AT&T had been manufacturing low specific gravity cells for over 20 years and supplying
them to commercial and telecommunication facilities. The cells penormed well and
battery capacity was noted to increase with age. When some nuclear facilities requested j
higher capacity batteries, AT&T raised the specific gravity of the cells in order to j
increase upacity. This was an extrapolation of their standard low specific gravity
technology, and one in which they had limited experience, which resulted in the noted
industry problems.
Since installation of the batteries at Wolf Creek in March 1996, they have performed I
adequately. The discharge test performed during Refueling Outage 9 demonstrated that i
the batteries maintained the ability to provide the required capacity.
E8.30 Reactor Enaineerina Problem Identification Reports
a. Insoection Scope (37550)
The team reviewed three performance improvement requests relating to reactor
engineerin;; 'ssues identified during the licensee's Updated Safety Analysis Report
Fidelity Review. The team's review of the performance improvement requests assessed
their safety significance and the licensee's corrective action plan and schedule for
resolution.
b. Observations and Findinas
Performance Imorovement Reauest 98-0169
This performance improvement request involved an apparent discrepancy between the
safety limits, as defined in the technical specifications, and the design temperature of
the reactor coolant system, as defined in the Updated Safety Analysis Report. The
performance improvement request was initiated on January 22,1998, and was
categorized as a nonsignificant, Level 111 performance improvement request.
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Table 5.3-2 of the Updated Safety Analysis Report identified that the design temperature
l of the reactor coolant system (with the exception of the pressurizer) was 650 degrees F.
The licensee's review identified that some plant operations allowed in accordance of
Safety Limit Technical Specification, Figure 2.1-1, resulted in a T-hot temperature in
excess of 650 degrees F. For example, for plant operation at 2250 psia,100 percent
reactor power, and 623 degrees F reactor average temperature, which is allowed by the
safety limits, the T-hot temperature exceeded the reactor coolant system design
temperature by approximately 5 degrees F.
The licensee recognized that this issue may be generic to Westinghouse nuclear steam
supply systems and initiated discussions with Westinghouse for additional evaluation.
The initiator of the performance improvement request recommended that: (1) the safety
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limit should not allow operation that permits T-hot conditions to exceed the reactor l
coolant system design temperature; (2) previous plant operation should be reviewed to l
determine if the plant has been operated within the allowed safety limit while exceeding I
the design temperature; (3) the Safety Limit basic should be revised to add
consideration of reactor coolant system design temperature; and (4) reactor protection
system set points should also be reviewed for impact.
The licensee performed a preliminary review of the performance improvement request
and concluded that excessive T-hot temperatures should be prevented by the reactor
protection system. Other additional actions proposed included performing a review of
the accident analyses to compare temperatures during the transient to the reactor
coolant system design temperature and determining additional actions based on the i
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recommendations of the performance improvement request initiator. A due date of
July 31,1998, for compbtion of these actions was established.
The team considered this a valid issue requiring further evaluation. The licensee's time
table for resolution appeared acceptable, given that abnormal plant operation would be
prevented by the reactor protection system. The licensee's evaluation of this issue will
be reviewed during a subsequent NRC inspection. This was identified as an inspection
followup item (50-482/9812-07).
Performance Imorovement Reauest 98-0179
This performance improvement request involved the identification of a discrepancy
associated with the assumptions for the fuel handling accident evaluation in the Updated
Safety Analysis Report. The performance improvement request was initiated on
January 22,1998, and was categorized as a nonsignificant, Level 111 performance
improvement request.
The fuel handling accident evaluation in the Updated Safety Analysis Report identified
that the analysis complied with Regulatory Guide 1.25, " Assumptions Used for
Evaluating the Potential Radiological Consequences of a Fuel Handling Accident in the
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Fuel Handling and Storage Facility for Boiling and Pressurized Water Reactors." l
Regulatory Guide 1.25 contained a note that stated that the assumptions were valid only l
if certain tuellimitations were not exceeded. The fuellimitations were: 1) Peak linear l
power density of 20.5 kW/ft for the highest power assembly discharged; 2) Maximum l
center-line operating fuel temperature less that 4500 degrees F for this assembly; and 3) l
Average burnup for the peak assembly of 25000 MWD / ton or less (this corresponds to a l
peak local burnup of about 45000 MWD / ton).
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The initiator of the performance improvement request identified that fuel currently in use
exceeded the limitations identified in 2) and 3) above. Section 4.2.1.2.a of the Updated
Safety Analysis Report identified that a calculated fuel centerline temperature of
4700 degrees F had been selected as an overpower limit to ensure no fuel melting.
Therefore, there was a 200 degrees F discrepancy in maximum allowed fuel centerline
temperature. Also, the current operating cycle contained a limitation of 33500 MWD / ton
core average burnup and 60000 MWD / ton peak local burnup, both of which exceeded
the fuel handling accident assumption. The impact of these discrepancies were that the
dose consequences contained in the fuel handling accident evaluation were
nonconservative.
The licensee completed a preliminary evaluation of the performance improvement l
request. With respect to the fuel centerline temperature criterion, the licensee
concluded that the peak centerline fuel temperature would not exceed 2000 degrees F
during normal power operation. After the team identified that this conclusion was
incorrect, the licensee reperformed their evaluation and ide J'ied that 2000 degrees F
was the fuel average temperature and that the maximum ic : centerline temperature
was less than 3600 degrees F. This was consistent with the Updated Safety Analysis
Report. With respect to the fuel burnup, the licensee identified that NUREG/CR-5009,
" Assessment of the Use of Extended Burnup Fuelin Light Water Power Reactors,"
stated that increasing fuel enrichment to 5.0 weight percent U-235 with a maximum
burnup of 60000 MWD / ton increases the doses for a fuel handling &ccident by a factor
of 1.2. However, the licensee also identified that increasing the results by 20 percent
would still keep dose rates remain below the regulatory limits.
The licensee identified additional actions to be taken. These included performing a ;
formal review of NUREG/CR-5009, revising the fuel fission product activity based upon l
this review, performing new analyses for the fuel handling accident and other accidents
with the revised source term, and revising the Updated Safety Analysis Report. The
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licensee identified a completion date of December 31,1998, for these actions.
The team considered that fuel may have been handled ducing the last several outages
that may have contained a radiological source term that exceeded the assumptions and
- potential consequences of a fuel handling accident. This consideration will be reviewed
further by the NRC and was identified as an inspection followup item (50-482/9812-08).
Performance Improvement Request 98-0179 also referred to related Performance
Improvement Request 97-2783. This performance improvement request was initiated
on September 11,1997, and was categorized as nonsignificant, Level Ill. The team
reviewed this performance improvement request, which identified that the dose
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consequences analysis of record may not be bounding for the duration of the current
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operating cycle. The performance improvement request identified that the Updated
Safety Analysis Report dose calculations referenced WCAP 13447, "3579 MWt NSSS
Rerating Engineering Report," which had been completed to support the licensee's
rerating project. The analysis in WCAP 13447 supported a core average cumulative
burnup of approximately 33500 MWD / ton; however, the projected burnup for the end of
the current operating cycle was expected to be approximately 34430 MWD / ton. The
burnup was expected to exceed the WCAP 13447 limitation at approximately 472
effective full power days. The team questioned the licensee regarding when it identified
this discrepancy, at what time was the core expected to exceed the burnup limitation,
what controls were in place to prevent exceeding the burnup limitation, and what l
corrective actions were being taken to resolve the issue. l
The licensee informed the team that with nominal plant operation, the core was l
expected to achieve 472 effective full power days of operation in March 1999. No formal
administrative controls were determined to be necessary by the licensee to restrict
operation beyond this time because the reactor engineering staff were aware of the
issue and were in close communication on a daily basis with the control room operators. I
The licensee informed the team that a plan was in p! ace to complete the revised '
analyses well before that time. The team identified the review of the licensee's
implementation and completion of these analyses as an inspection followup item
(50-482/9812-09).
Performance improvement Reauest 98-0412
This performance improvement request involved the identification of a discrepancy
between the as-measured limit for the enthalpy-rise hot channel factor, F-Delta-h,
identified in the core operating limits repon, and the limit for F-Delta-h identified in the
technical specifications safety limits. The oerformance improvement request was
initiated on February 16,1998, and was categorized as a nonsignificant, Level lli
performance improvement request.
The safety limit for F-Delta-h was 1.65 and included an allowance of 4 percent for
measurement uncertainty. The core operating limits report for the current operating
cycle specified a limit of 1.59. Accounting for 4 percent measurement uncertainty, the
maximum allowed measured value of F-Delta-h was approximately 1.5865, which was
nonconservative compared to the core operating limits report. The initiator of the
performance improvement request recommended that a review be performed to verify
that the as-measured values of F-Delta-h did not result in exceeding the safety limit
when the 4 percent measurement uncertainty factor was prvperly included. Also, the
initiator recommended that an evaluation be performed to determined if the core
operating limits report limit for F-Delta-h should be reduced to 1.58.
The licensee's initial evaluation confirmed that application of the 4 percent measurement
uncertainty factor to the safety limit resulted in a 1.5865 limit for unadjusted F-Delta-h.
The evaluation also identified that this value was rounded to 1.59 in the core operating
limits report. The licensee provided justification for this by identifying that the additional
digits were nonsignificant figures for a measurement uncertainty of 4 percent. Also, the
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propagation of other additional uncertainties applied to the F-Delta-h value for departure
from nucleate boiling analyses in the Updated Safety Analysis Report provided
additional assurance that using the core operating limits report measured limit of 1.59
was acceptable. The licensee closed the performance improvement request on
March 5,1998. The team concurred with the conclusion of the licensee's assessment.
Safety Sianificance Classification
The team reviewed Procedure AP 28A-001, " Performance improvement Request,"
Revision 9, to determine if it had correctly classified the above performance
improvement requests. The team noted that Level I and 11 performance improvement
requests were classified as "significant conditions adverse to quality," required a formal
root cause evaluation, and corrective actions to prevent recurrence. Level lli
performance improvement requests were classified as " conditions adverse to quality,"
and did not require a detailed root cause evaluation or corrective action plan. The team
noted that Procedure AP 28A-001 did not explicitly identify the area of engineering
calculations or safety analyses for inclusion in the performance improvement request
process, although the procedure did state that performance improvement requests were
used to document the evaluation and resolution of problems, concerns, or
recommendations. There were no instructions or examples in the procedure for how
calculation errors shou ld be assessed for significance or addressed for resolution. The
team was concerned that this could result in the misc!assification of issues. Although
none of the performance improvement requests resulted in an immediate operability
concern, the team considered the lack of including safety analyses and other
engineering calculations in its performance improvement request procedure a weakness
that could result in misclassification of issues.
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c. Conclusion
The team did not identify any immediate operability concerns as a result of its review of
the above performance improvement requests. However, a future operability concern
existed with respect to the burnup limitations of the safety analyses for operation late in
the current operating cycle and a potential reportability issue existed for handling fuel
, that may have exceeded dose consequence analysis assumptions. The team identified
l a weakness in the licensee's procedure for performance improvement requests in that
the procedure did not address the significance or processing of problems with safety
analyses or engineering calculations.
IV. Plant SupppLrt
a. Inspection Scope (64704)
Tne team inspected the licensee's fire protection program to verify that the licensee had
, properly implemented and maintained the fire protection program required by the
- operating license. The team reviewed fire protection procedures, administrative
controls, quality assurance audit rcgorts, fire brigade qualifications, fire brigade staffing,
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and fire watch staffing in accordance with the approved fire protection program. The
team also conducted walkdowns and tours of the facility to verify licensee
implementation of the approved fire protection program.
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l b. Observations and Findinas ,
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During the inspection, the team noted that most administrative controls were properly j
l implemented and that most administrative control procedures were adequate. In
l addition the fire brigade and fire watch personnel were qualified, plant housekeeping for ,
control of transient combustible materials was very good, the number of component '
l impairments / breaches was very low, and station fire response equipment was generally
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well maintained. However, the team noted instances where the fire protection program
had not been adequately implemented. These included: 1) offsite fire brigade training
and drills had not been conducted annually as required; 2) the fire water suppression ;
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system had historically been used for nonfire protection purposes without evaluation of '
the effect on fire suppression capability; 3) a preventive maintenance program did not
exist for electrical relays in the diesel-driven fire pump start circuitry; and 4) the reactor
coolant pump lube oil collection system requirements were not evaluated properly when
a deviation was identified. These items are discussed in other sections of this report.
l The team noted that some of the fire protection program implementation problems had
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occurred in the past, were self-identified or self-revealing, and any performance
l concerns were corrected. The fire protection and quality assurance organization staff
l had identified areas for improvement and the fire protection organization appeared
committed to maintain an effective fire protection program.
c. Conclusions
l The team considered the implementation of the fire protection program to be good,
although some examples of problems were identified.
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, F2 Status of Fire Protection Facilities and Equipment
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a. Insoection Scoce (64704)
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l The team performed a walkdown of accessible areas of the facility containing safe
! shutdown equipment. The team also visually inspected fire protection equipment
located throughout the facility, including fire suppression and detection equipment, fire
l barriers, and fire brigade and operator emergency response equipment located in
equipment storage areas.
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! The team also randomly selected components required for post-control room fire safe
shutdown by Procedure OFN RP-017, " Control Room Evacuation " Revision 11, which
could be required for safe shutdown during a control room fire, to verify that they were
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accessible, well iabeled, and had adequate emergency lighting to perform required
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tasks.
. b. Observations and Findinas
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The team observed that most fire response equipment was well maintained, accessible,
within calibration, and in good working order. All valves observed by the team in the fire
suppression systems were in their proper position. Preventive maintenance of fire
protection equipment was performed in accordance with approved procedures.
However, during the week of March 30,1998, the licensee performed the annual
preventive maintenance of the diesel-driven fire pump in accordance with Procedure
STN FP-410, " Diesel Engine Inspection." During post-maintenance testing per
Procedure STN FP-211, " Diesel Fire Pump Operability and Fuel Level Check," on
April 2,1998, the engine failed to start on demand. The licensee identified that the
cause of the failure was a failed relay in the engine start circuitry. After replacement of
the failed relay, and other relays in the engine start circuitry, the pump was returned to
an operable condition.
The licensee determined that its preventive maintenance program did not include
inspection or replacement of relays in the engine start or alarm circuitry. Performance
improvement Request 98-0964 was initiated to document this event and it was
categorized as a significant condition adverse to quality requiring a root cause
evaluation. The licensee also determined that this event required evaluation as a
maintenance preventable functional failure per the maintenance rule. The team
considered the licensee's failure to include inspection and periodic replacement of the
relays for the diesel-driven fire pump a weakness in the preventive maintenance
program. The licensee informed the team that periodic inspection and replacement of
relays would be added to the program as part of the corrective actions for the
performance improvement request. The review of the licensee's corrective actions in
response to this failure was identified as an inspection followup item (50-482/9812-10).
The team noted that all fire brigade response equipment in the fire brigade storage
areas was well maintained and ready for immediate use with the exception of two carbon
dioxide fire extinguishers. The team identified that these two fire extinguishers did not
have current monthly inspection tags and that one of them was empty. The fire
extinguishers were identified by a sign that stated, "For Emergency Use Only," but the
team learned that they were extra equipment available for brigade use in addition to the
minimum equipment required by the fire protection program. The last monthly fire
extinguisher inspection, completed on March 7,1998, per Work Package 126378, did
not include a requirement to inspect the subject extinguishers. The licensee initiated
Performance Improvement Request 98-0871 to correct the deficiency.
The team reviewed the list of active fire protection equipment impairments and breaches I
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for which compensatory measures had been implemented, and accompanied a fire
watch performing a tour of the affected areas. There were snly four fire protection
impairment control and breach authorization pwmits that required a compensatory fire
watch. The team considered this low number cf impairments to be a strength. However,
the team noted that one of the inoperative components, the control room pantry
automatic door closer, had been inoperable since March 1996. The original design of
the system was for the door to automatically close and isolate the control room from the
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pantry in the event of a fire in the pantry. However, when a new fire detection system
was installed in 1996, the new system was unable to control the door closer. Therefore,
Temporary Modification Order 96-017-KC was implemented on March 18,1996, to
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defeat the autoclosure capability of the door until a permanent modification was
designed and installed. Additionally, on March 17,1997, the pantry ionization detector
was made inoperable due to frequent nuisance alarms during routine cooking activities.
Hourly fire watch patrols of the pantry (which was next to the continuously manned j
control room) were properly implemented as compensatory action for both of these !
impairments.
The licensee informed the team that a permanent modification was planned to replace
the ionization detector with a thermal detector and restore the automatic door closure
capability. The modification was scheduled for implementation per Plant Modification
Request 04519 during the week of May 4,1998. The control room pantry was used by
operators for meal preparation and cooking activities and the team cons dered that i
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these activities represented a potential fire hazard. The team considered that although
the area was provided with a compensatory hourly fire watch patrol and that the
adjacent control room was continuously manned, the length of time Temporary
Modification Order 96-017-KC was excessive.
c. Conclusions j
Fire protection equipment required for program implementation was generally well
maintained and available for immediate use. The team concluded that the self-revealing
failure of the diesel driven fire pump to start during a post-maintenance test indicated
that a weakness existed in the preventive maintenance program for the start circuitry.
The low number of impairments was identified as a strength.
F3 Fire Protection Procedures and Documentation
a. Insoection Scope (64704)
The team reviewed the licensee's approved program as defined in the Updated Safety
Analysis Report for the facility. The team reviewed the procedures listed in the
attachment to this report to verify that the procedures adequately implemented the
licensee's approved program.
b. Observations and Findinas
The team found that, with the exception of the item noted below, the procedures
adequately implemented the approved fire protection program.
Section 9.5.1.7.5.2.1.5 of the Updated Safety Analysis Report stated that over each
2-year period following initial qualification, fire brigade members receive periodic
refresher training such that all training subjects are completed within the 2-year period
and must complete all of the refresher training to maintain active status. The team
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identified that Procedure AP 10-105, " Fire Protection Training Program," Revision 1,
Change 98-060, allowed a 31-day grace period for brigade members to complete
qualification requirements prior to being removed from active status. During a review of
training attendance records of 13 randomly selected brigade members and leaders, the
team identified that 5 individuals had exceeded the 2- year requalification cycle for
training, but completed their training requirements within the procedurally-allowed grace
period. l
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The team informed the licensee that its fire protection program did not allow the grace ;
period contained in Procedure AP 10-105 and that brigade members had inappropriately l
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used the grace period to complete their requalification training requirements. The team
did not have a safety concern regarding fire brigade member knowledge or performance
because of the short period of time in excess of 2 years that elapsed before the brigade
members received their training. The team considered the failure to complete fire
brigade requalification training within 2 years to be a violation of the fire protection
program.
Ooerating License NPF-42, Section 2.C.(5)(a) requires that the licensee shall maintain in
effect all provisions of the approved fire protection program as described in the Final
Safety Analysis Report and as approved in the NRC Safety Evaluation Report.
Section 2.C.(5)(b) allows the licensee to make changes to the approved fire protection
program without prior approval of the NRC only if those changes would not adversely l
affect the ability to achieve and maintain safe shutdown in the event of a fire. This ;
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failure to maintain the fire protection program as documented in the Updated Safety
Analysis Report constitutes a violation of minor significance and is not subject to formal
enforcement action. The licensee initiated Performance Improvement Request 98-0995
to correct this discrepancy and informed the team that it intended to perform the proper l
evaluation to support changing its fire protection program to allow implementation of the ,
grace period. This minor violation is addressed in this report to document that grace l
periods are not applicable in fire protection training and scheduling and that the
licensee's corrective actions were complete.
c. Conclusio. ..
With exception of the minor violation addressed above, the team determined that the fire
protection program procedures adequately implemented the approved fire protection ;
program.
F4 Fire Protection Staff Knowledge and Performance
a. Inspection Scope (64704)
The team reviewed the adequacy of the fire protection staff by conducting interviews
and plant walkdowns with staff members. The team also accompanied fire watch
L. personnel on fire watch patrol.
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b. Observations and Findinas
Discussions with the fire protection staff indicated that they understood NRC
requirements for the fire protection program and the National Fire Protection
Association, National Fire Code requirements. They also demonstrated a detailed
understandmg of fire hazards associated with the facility and a detailed knowledge and
understanding of the systems, testing, and analyses associated with the fire protection
program.
During an accompaniment with a fire watch on patrol of the facility, the fire watch
demonstrated thorough knowledge of his duties and a conscientious attitude to the
identification of potential problems. The team observed that the fire protection
personnel had a very good working relationship with other onsite organizations.
c. Conclusions
The plant had a qualified fire protection staff which had a very good working relationship
with other station organizations. The fire watch program was effectively implemented.
F5 Fire Protection Staff Training and Qualification
a. sc%ection Scope (64704)
The team reviewed the readiness of onsite fire brigade personnel to fight fires and ability
of fire watch personnel to perform compensatory measures for fire protection
component impairments and fire barrier breaches. The team reviewed the fire brigade
composition, qualifications (including medical), and training records to determine if the
fire brigade met the requirements of the fire protection plan. The team also reviewed a
quality assurance audit finding regarding the offsite fire brigade.
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b. Observations and Findinas
The 1997 quality assurance audit of the fire p.utection program identifii that offsite fire
brigade training and drills had not been performed in accordance with the fire protection
plan. Specifically, offsite fire brigade training had not been conducted since 1993 and
. the offsite fire brigade had not participated in a fire drill since 1994. The licensee .
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initiated Performance improvement Requests 97-3726 and 97-3972 to address these
items, respectively.
Section 9.5.1.7.5.2 of the Updated Safety Analysis Report .dentified that training for the '
offsite fire department is required annually and that the offsite fire department is required
to participate in a fire drill annually. The team also reviewed the February 5,1996,
" Agreement for Fire Protection," between the licensee and offsite fire department. The
Agreement identified that drills and training were to be conducted on at least an annual
basis.
Operating License NPF-42, Section 2.C.(5)(a) aquires that the licensee shall maintain in
effect all provisions of the approved fire protection program as described in the Final
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Safety Analysis Report and as approved in the NRC Safety Evaluation Report.
Section 2.C.(5)(b) allows the licensee to make changes to the approved fire protection
program without prior approval of the NRC only if those changes would not adversely
affect the ability to e.chieve and maintain safe shutdown in the event of a fire, The failure
of the licensee to conduct offsite fire brigade training and drills with offsite fire brigade
participation on an annual basis is a violation of the fire protection program. The
licensee implemented corrective actions including conducting training for the offsite fire
department on March 11 and 25,1998, and scheduling a fire drill with offsite fire
department participation for May 16,1998. Since the facility was designed to be
self-sufficient with respect to onsite fire fighting capabilities, no credit is taken in the fire '
protection system design for offsite fire department response. Therefore, the team
considered that this constituted a violation of minor sa . / significance and is not subject
to formal enforcement action. This minor violation is wressed in this report to
document that if changes are made to the fire protection program, changes to
associated documents must also be made,
c. Conclusions
The team considered the licensee's onsite fire protection staff training to be adequate to
meet fire protection program requirements with one minor exception. A noncited
violation was identified for the licensee's failure to conduct annual training and drills for
the offsite fire brigade.
F6 Fire Protection Organization and Administration
a. Insoection Scoce (64704)
The team reviewed the fire protection program organization designated to implement the
b, Observations and Findinos
The fire protection organization was described in Procedure AP 10-100, " Fire
Protection," Revision 1. This procedure constituted the Fire Protection Manual, as
described in the Updated Safety Analysis Report, and detailed staffing and
responsibilities for the implementation of the program. The team noted that
implementation was consistent with the approved program
c. Conclusions
The team found that the fire protection organization and administration was
implemented in accordance with the fire protection program.
F7 Quality Assurance in Fire Protection Activities
a. Insoection Scope (64704)
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The team reviewed the 1996 and 1997 quality assurance audits to verify that the audits
met the requirements of the approved fire protection program.
b. Observations and Findinas
The 1996 audit was the triennial audit, required by Technical Specification 6.5.2.8.f. The
audii included a particularly detailed review of the licensee's fire barrier penetration seal
program and Darmatt fire barrier installation project (for replacement of Thermo-Lag fire
barrier material).
The 1997 audit was the biennial audit, required by Technical Specification 6.5.2.8.e.
The audit included a particularly detailed review of plant modification packages.
The audits were comprehensive in scope and performed an in-depth evaluation of the
fire protection program at the facili'y. Some of the problems identified by the audits 1
included engineering review of plant change packages for impact on the fire protection !
program, offsite fire brigade training, and programmatic controls on Darmatt fire barrier
installation. Issues identified in the audits were formally presented to the line i
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organization and the line organization developed an audit response plan to evaluate the
issue, identify corrective actions, and track tua item to closecut.
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c. Conclusions
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The team found the fire protection program audits to be in compliance with the ;
requirements of the program. The audits were effective and resulted in meaningful
findings.
F8 Miscellaneous Fire Protection Issues (92903,93809) l
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F8.1 (Closed) Violation 50-482/9519-01: Failure to Provide Adequate Emergency Lighting for l
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a Valve Needed for Safe Shutdown Manual Manipulation
[ Closed) Licensee Event Report 50-482/95-001 Failure to Develop an Adequate Fire l
Protection Program for Emergency Lighting
a. Backaround
The NRC inspectors identified that a valve required for manual operation to achieve safe ;
shutdown following a control room fire did not have adequate emergency lighting (
available. During its followup of this violation, the licensee unducted plant walkdowns l
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by engineering and operations personnel with normal and standby lightina turned off,
and identifieci .ditional examples of locations where emergency lighting was
inadequate. ine licensee reported this event to the NRC in Licensee Event
Report 50-482/95-005. l
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b. Inspection Followuo
The team reviewed the licensee's corrective actions as identified in the response to the
violation and the licensee event report. The licensee evaluated the deficiencies
identified in its plant walkdowns and added or adjusted emergency lights to ensure that
adequate emergency lighting was provided for operation of safe shutdown equipment
and for access and egress routes to that equipment. The team verified that the licensee
had implemented interim compensatory actions which included initiating an order that all
operators carry flashlights, increasing the priority for maintenance on emergency lights,
and installing temporary backup lighting if necessary. The licensee revised its
procedure MPE BA-010, " Preventive Maintenance on Teledyne Emergency Lighting," to
include the additionallights and revised aiming instructions. The team concluded that
the licensee's actions in response to this violation and licensee event report were
acceptable.
F8.2 (Closed) Licensee Event Reoort 50-482/97-016. Revisions 0.1. and 2: Use of Fire
Protection Pumps for Non-Fire Protection Purposes Constituted a Significant
Degradation of Fire Protection System
a. Backaround
During a review of uses of the fire protection system, the fire protection engineer
identified that the system had repeatedly been used over the life of the plant for nonfire
protection purposes including cleaning and maintenance activities. The licensee
determined that there was insufficient evaluation of the impact of these activities on fire
protection system operability. Further, the licensee identified that the fire protection
system could have been significantly impaired and unable to provide required pressure
and flow at the location of a fire.
The licensee initiated Performance improvement Request 97-2687 and conducted a root
cause and significance evaluation of this condition. The licensee determined that the
fire protection water supply system piping and pumps were sized and installed to supply
3300 gpm at 80 psig at the furthest interface point. This design basis was chosen to
accommodate the greatest suppression system flow demand (2300 gpm, which was
located in a nonsafety-related area) and a 1000 gpm hose stream backup capability.
The Fire Hazards Analysis identified that the largest suppression system demand for a
fire in a safety-related area was 1035 gpm. The licensee performed a historical review
of fire water usage for nonfire protection purposes, conducted a test of the fire
protection system on September 19,1997, and determined that the maximum nonfire
protection demand on the system was approximately 2140 gpm. Therefore, enough
l margin was available to provide water to the maximum fire suppression system demand
in a safety-related area and still maintain the ability to achieve and maintain safe
shutdown. H&ever, manual hose stream backup capability would not have been
available. Foi nonsafety-related areas, the maximum nonfire protection demand on the
fire protection system would have exceeded the capability of the fire protection system
to meet the largest fire suppression demand.
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The licensee concluded that root causes for this event included: 1) that fire pm'etion
program management was not adequate to ensure that all uses of the fire prot. ..
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pumps were thoroughly evaluated, and 2) personnel were not adequately trained with !
respect to system operability requirements such that nonfire protection uses of the
system had become the accepted norm.
The licensee implemented immediate corrective actions by issuing Special Order SO-07, l
"Use of Fire Protection System for Non-Fire Protection Purposes," on October 1,1997,
which prohibited nonfire protection use of the fire protection system without engineering
evaluation and approval of the plant manager. Other corrective actions included
reviewing and evaluating operations procedures to identify those that used fire
protection system water in supporting other activities, and developing a procedure to
govern use of the fire protection system pumps.
b. Inspection Fol!owuo
The team reviewed the event reports and performance improvement request
documentation. The team also reviewed Calculation KC-413," Determine the Flow
Requirements of the Fire Pump," Revision 0, and the Fire Hazards Analysis that
supported the licensee's' determination that sufficient water supply would have been
available for the largest water suppression system demand in a safety-related area.
However, the team noted that Calculation KC-413 also identified that the fire protection
system water supply was designed to provide an additional 1000 gpm for yard hydrants
(or hose streams). This additional margin would not have been available during many of
the instances the system was used for nonfire protection purposes.
The licensee was required to comply with its approved fire protection program. The fire
protection program required that the fire protection system be capable of supplying a
maximum system demand of 2300 gpm at 80 psig, plus simultaneous flow of 1000 gpm
for outside hose streams. On many occasions over at least a 10-year period, the
licensee used the fire protection system for nonfire protection purposes. The licensee
determined that the largest demands on the fire protection system for nonfire protection
purposes occurred during the fall of 1996 through the spring of 1997, and were as high
as 2140 gpm.
Operating License NPF-42, Section 2.C.(5)(a) requires that the licensee shall maintain in
effect all provisions of the approved fire protection program as described in the Final
Safety Analysis Report and as approved in the NRC Safety Evaluation Report. The
team concluded that since the fire protection system was not maintained in accordance
with the fire protection program, the fire protection system was inoperable when it was
used for these nonfire protection purposes and that this was a violation
(50-482/9812-11). However, this licensee-identified and corrected violation is being
treated as a noncited violation, consistent with Section Vll.B.1 of the NRC Enforcement
Policy. The team reviewed Special Order SO-07, Procedure SYS FP-293, " Fire Pumps
Manual Operations,' Revision 7, which had been revised to govern the administrative
control of all fire pump manual operations, and interviewed fire protection and operations
staff. The team concluded that the licensee's evaluation of this event was thorough and
that it had established acceptable measures to prevent recurrence.
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F8.3 (Closed) Inspection Followuo item 50-482/96023-04: Reactor Coolant Pump Motor
Lube Oil Collection System
a. Backaround
During the NRC inspection, the inspectors reviewed the licensee's followup of industry
information relating to reactor coolant pump lube oil fires. The licensee documented in
Performance Improvement Request 96-3133, on December 2,1996, that it had not
tracked a recommendation from an earlier industry operating experience evaluation to i
conduct further reactor coolant pump lube oil leakage inspections and install additional '
oil drip pans if leakage continued to occur. The inspectors initiated this item to track the
resolution of this issue. ,
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b. Insoection Followuo
The team reviewed the licensing basis for reactor coolant pump lube oil collection at the
facility, the licensee's operating experience evaluations, and resolution to oil leakage v:a l
engineering evaluation and plant modification.
Operating License NPF-42, Section 2.C.(5)(a) requires that the licensee shall maintain in
effect (A provisions of the approved fire protection program as described in the Final
Safety Analysis Report and as approved in the NRC Safety Evaluation Report.
Section 2.C.(5)(b) allows the licensee to make changes to the approved fire protection
program without prior approval of the NRC only if those changes would not adversely l
affect the ability to achieve and maintain safe shutdown in the event of a fire. Generic
Letter 86-10, " Implementation of Fire Protection Requirements," provided guidance to
the industry regarding the analysis required by the licensee to support changes to the '
approved fire protection program including the applicability to the provisions of
The licensee initiated Industry Information Program Report 02805, "NRC Information
Notice 94-58: Reactor Coolant Pump Lube Oil Fire (Haddam Neck, Millstone), on
September 15,1994. The approved fire protection program at that time, contained in
the Updated Safety Analysis Report, identified that the licensee was committed to the
requirements of 10 CFR Part 50, Appendix R, Section 111.0, and NRC Branch Technical
Position CMEB 9.5-1 for reactor coolant pump lube oil collection systems. The
requirement, in part, was that the "... collection system shall be capable of collecting lube
oil from all potential pressurized and unpressurized leakage sites in the reactor coolant
pump lube oil systems... Leakage points to be protected shall include lift pump and
piping, overflow lines, lube oil cooler, oil. fill and drain lines t nd plugs, flanged
connections on oil lines, and lube oil reservoirs where such features exist on the reactor
coolant pumps . . " The licensee documented in Industry information Program Report
02805 that it had identified minor oil leakage from RTD terminal box conduit
l compression fittings on the reactor coolant pumps during Refueling Outage 7 (1994).
l The engineering evaluation summarized the leaks as minor and that ignition of a fire
could not be expected. Maintenance was performed to tighten the leaking fittings. The
report identified a recommendation that if oil leaks from the fittings or similar leaks
continued, then localleak collection devices should be installed. The report did not,
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however, document an evaluation regarding the licensee's compliance with the
regulatory requirements for oil collection, nor did it evaluate the potential impact of oil
leakage from these leakage points during the next operating cycle.
The licensee initiated Performance improvement Request 96-3133 on December 2,
1996, to perform an evaluation of the Arkansas Nuclear One reactor coolant pump fire.
This item identified that the 1994 recommendations for monitoring and installing oil
collection devices were not completed or tracked. The licensee completed Reportability
Evaluation Report 97-022 on March 27,1997, to evaluate the oil leakage history of the
reactor coolant pump motors. The report documented that lube oil leakage from the "A"
reactor coolant pump motor was identified by control room operators on August 7,1995, i
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during the operating cycle following Refueling Outage 7. The leakage was evaluated as
acceptable by the engineering staff and operation continued. The licensee did not
document a fire protection evaluation of the leak at that time. With the unit shutdown on
January 30,1996, an inspection was performed and the licensee identified that the RTD
fitting on the "A" motor had leaked. Approximately 5 gallons was added to the oil
reservoir to refillit. The licensee's evaluation of the impact of the leak concluded that
based upon its magnitude and path of travel, its location relative to insulation and hot
pipe, and the ignition characteristics of the oil, the leakage was not a combustibility
hazard. The licensee concluded that at no time would the oilleakage have resulted in a
loss of function for any safety-related equipment, a potential for degradation of
safety-related equipment, nor was it a condition outside the design basis of the plant.
Therefore, the event was considered to be not reportable to the NRC per 10 CFR 50.72
or 10 CFR 50.73.
Reportability Evaluation 97-022 also documented that the licensee was not in
compliance with regulatory requirements and that the adequacy of the lube oil collection
'
system and any necessary design changes would be evaluated and implemented during
the closecut of Performance Improvement Request 96-3133. The licensee intended to
implement design changes to eliminate any potential uncontained lube oil leakage paths.
During the licensee's evaluation of options during resolution of Performance
improvement Request 96-3133, the licensee caded to install a modification to the
reactor coolant pump motor upper reservoir RTD conduit boxes to prevent oil leakage.
Modification DCP 07280, "RTD Conduit Seals," was prepared and consisted of a plan to
install a new sealed conduit design with leak tight littings on the RTD conduit boxes to
prevent or minimize lube oil leakage. The licensee's unreviewed safety question
determination concluded that oil leakage would be eliminated or negligible, bounded by
the evaluation for a 5 gallon oil leak, and would not represent a fire hazard. Therefore,
no collection drip pan was included as part of the design for this potential leakage path.
As allowed by License Section 2.C.(5)(b), the licensee changed the fire program
documentation contained in the Updated Safety Analysis Report based on its conclusion
that the deviation between the existing NRC-approved program and the as-built,
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as-operated configuration of the lube oil collection system did not adversely affect the
ability to achieve and maintain safe shutdown in the event of a fire, nor constitute an
unreviewed safety question. The revised fire protection program identified that, "The
RTD conduit boxes were not provided with drip pans, however, conduit seals and leak
tight fittings are used to minimize lube oilleakage. Oilleakage at the RTD conduit box
does not represent a fire hazard."
The licensee installed DCP 07280 during Refueling Outage 9 (fall 1997) and revised
Procedure MPE M7120-02, " Reactor Coolant Pump Motor inspection," Revision 8, to I
include an inspection of the RTD conduit boy.es for oil. The team also verified that lube
oil reservoir level monitoring and alarm capability existed in the control room and that I
during the current operating cycle there had not been any unusual reduction in lube oil
inventory that may indicate a leak.
Operating License NPF-42, Section 2.F, requires, in part, that the licensee shall report l
any violations of the requirements contained in Section 2.C of this license within 24
hours to the NRC via the Emergency Notification System (ENS) with written followup l
within thirty days in accordance with the procedures described n 10 CFR 50.73(b), (c), j
and (e). Operating License NPF-42, Section 2.C.(5)(a), requires that the licensee j
maintain in effect all provisions of the approved fire protection program as described in l
the Updated Safety Analysis Report for the facility. The Wolf Creek Updated Safety
Analysis Report, Table 9.5E-1, states, in part, that the reactor coolant pump shall be
equipped with an oil collection system and that such collection systems shall be capable
of collecting lube oil from all potential pressurized and unpressurized leakage sites in the
reactor coolant pump lube oil systems. On September 15,1994, December 2,1996,
and March 27,1997, the licensee identified that reactor coolant pump lube oil was
leaking from sites that were not provided with a lube oil collection system. This was a
violation of Operating License Section 2.C.(5)(a). However, this licensee-identified and
corrected violation is being treated as a noncited violation, consistent with
Section Vll.B.1 of the NRC Enforcement Policy (50-482/9812-11). After discussions
with the team, the licensee reported this violation to the NRC in accordance with
,
Operating License, Section 2.F. An ENS notification was made on April 9,1998, and
LER 50-462 s8002 was issued on May 11,1998. The team reviewed the LER and the
licensee's corrective actions taken and planned to correct the violation and prevent
recurrence, and found them to be adequate.
. V. Manaaement Meetinas
X1 Exit Meeting Summary
The team met with licensee representatives on April 10,1998, and on June 26,1998, to
conduct a technical debrief prior to leaving site. Following additionalin-office review and
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telephonic discussions of the team's findings, an exit interview was conducted by j
. telephone on May 19 1998. Following additional review of documents and conference
!
" telephone calls, a supplemental exit meeting was conducted by telephone on July 20,
.1998. The licensee acknowledged the team's findings.
The team leader noted that team personnel had reviewed pro'prietary documentation
during the course of the inspection. Proprietary documentation was not divulged in this jl
report. The licensee acknowledged the team's findings. ;
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ATTACHMENT
SUPPLEMENTAL INFORMATION
PARTIAL LIST OF PERSONS CONTACTED
Licensee
D. Alford, Licensing Engineer
D. Claridge, Senior Licensing Engineer
T.~ Garrett, Manager, Design Engineer
T. Harris, Supervisor, Licensing
R. Holloway, Design Engineering
D. Jacobs, Manager, Support Engineering
D. Knox, Manager, Maintenance
B. McKinney, Plant Manager
R. Muench, Vice President, Engineering
C. Rich, Jr, Supervisor, Electrical and Instrumentation and Control
C. Reekie, Licensing
B. Selbe, Project Engineer
R. Sims, Manager, System Engineering
B. Smith, Supervisor, Design Mechanical
L. Solorio, Design Engineering
L. Stevens, Supervisor, Nuclear Safety Engineering
J. Yunk, Senior Engineer, Licensing
NRC
F. Ringwald, Senior Resident Inspector
B. Smalldridge, Resident insp -.ctor
INSPECTION PROCEDURES USED
37550 Engineering
92904 Followup- Plant Support
92903 Followup Engineering
61704 Fire Protection Program
,
93809 Safety System Engineering Inspection (S'EI)
,<
ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
50 482/9812-01 VIO Failure to Receive NRC Approval of a Change That Created
an Unreviewed Safety Question as Required by 50.59
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Opened
50-482/9812-02 VIO Failure to Follow Design Control Procedures and to have
Adequate Design Control Procedures
50-482/9812-03 IFl Review Revised Battery Sizing Calculation NK-E-002
50-482/9812-04 IFl Review Revised Electrical Cabinet Seismic Qualification
Calculation
50-482/9812-05 VIO Failure to Translate the Design Basis into Specifications and
to Verify and Check the Adequacy of Design Specifications
50-482/9812-06 NCV Failure to isolate the Spent Fuel Pool Heat Exchanger During
Plant Cooldown
50-482/9812-07 IFl Review the Resolution of the Discrepancy Between the l
Technical Specification Safety Limits and the Design
Temperature of the RCS
50-482/9812-08 IFl Review the Dose Consequences for a Fuel handling Accident
50-482/9812-09 IFl Review the Licensee's Analysis for Extended Core Operation
50-482/9812-10 IFl Review the Corrective Actions to Assure that the Diesel Driven
Fire Pump Relays are Placed in the PM Program
50-482/9812-11 NCV Failure to Declare the Fire Protection System inoperable
When the Fire Pumps are Used for Non-fire Protection
Activities and Failure to Assure that the RCP Oil Collection
System was in Accordance with Ucense Conditions
Closed
50-482/9621-06 VIO Procedure STS BG-004 did not Specifically Require
Operators to Tighten or Verify the Mechanical Position Stops
for Valves BGV-198, BGV- 199, BGV-200, and BGV-201
50-482/9621-05 VIO Operability Determination was not Thoroughly Documented in
the Shift Supervisor's Log as Required by Administrative
Procedures.
VIO Two Examples of inadequate 10 CFR 50.59 Safety
50-482/EA96-470- Evaluations.
02014
VIO Five Examples Where the Licensee Failed to identify and
l 50-482/EA96-470- Correct Conflicts Between Technical Specification
, 01013 Clarifications and the Technical Specifications.
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Closed
50-482/EA96-470- VIO Quality Related Document Instruction was not Appropriate to
01033 the Circumstances when the Licensee Allowed the Reactor
Coolant System to be Cooled Down with One Inoperable
Source Range Channel.
50-482/EA96-470- VIO Reactor Coolant Pump Flywheel Inspection Integrity.
01023
50-482/9808-01 URI Licensee Failed to Prepare Performance improvement
Requests for Twelve Final Safety Analysis Report Significant
Discrepancies
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50-482/9604-03 IFl Safety Related Battery Replacement with AT&T Round Cells
50-482/9519-01 VIO Failure to Provide Adequate Emergency Lighting for a Valve
Needed for Safe Shutdown Manual Manipulation )
50-482/95-005 LER Licensee Event Report Failure to Develop an Adequate Fire
Protection Program for Emergency Lighting
50-482/97-016, LER Use of Fire Protection Pumps for Non-Fire Protection
Revs 0,1, and 2 Purposes Constituted a Significant Degradation of Fire
Protection System
50-482/96023-04 IFl Reactor Coolant Pump Motor Lube Oil Collection System
1
50-482/97201-01 URI Cooldown Analysis
50-482/97201-02 IFl Emergency Core Cooling System Leakage
50-482/97201 03 URI Residual Heat R3moval Pump Operation in Minimum
Recirculation Mode
50-482/97201-06 IFl Procurement of EDG Relay
50-482/97201-13 URI Acceptance Criteria for Battery Test
50-482/97201-14- URI Acceptance Criteria for Battery Test
50-482/97201-15 URI Refueling Water Storage Tank Level Instrumentation
SL -432/97201-16 URI Seismic Qualification
50-482/97201-17 URI Nitrogen Bottle Installation
50-482/97201-18 URI Motor Operated Valve Differential Pressure
50-482/97201-19 URI Component Cooling Water Low Temperature
l 50-482/97201-20 URI Corrective Action for Component Cooling Water Operating
ProcedJre
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50-482/9812-06 NCV Failure to isolate the Spent Fuel Pool Heat Exchanger During
Plant Cooldown i
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50-482/9812-11 Failure to Declare the Fire Protection System inoperable
l When the Fire Pumps are Used for Non-fire Protection f
Activities !
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50-482/9812 12 NCV Failure to Assure that the RCP Lube Oil Collection System ,
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Was in Accordance with License Conditions
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Discussed
50-482/97201-07 IFl Sizing of Class 1E Batteries
50-482/97201-08 IFl Sizing of Class 1E Batteries
50-482/97201-09 IFl Sizing of Class 1E Batteries
50-482/97201-10 URI DC Load Flow / Voltage Drop
50-482/97201-11 URI DC Load Flow / Voltage Drop
50-482/97201-12. URI DC Load Control
50-482/97201-21 URI Updated Safety Analysis Report Discrepancies
LIST OF ACRONYMS USED
CFR Code of Federal Regulations
gpm gallons per minute
HEPA high efficiency particulate, air
LER licensee event report
LPSI low pressure safety injection
PCT peak clad temperature
psi pounds per square inch
psia pounds per square inch absolute
psig pounds per square inch gage
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PARTIAL LIST OF DOCUMENTS REVIEWED i
PROBLEM IDENTIFICATION REPORTS l
PIR SUBJECT DATE
NUMBER
940204 performance improvement request was initiated due to conditions August 1,1994
that may have existed for the main steam safety valves being
outside of the Technical Specification tolerance for set points
950726 Over 45 Wrs had been generated to address concerns with the March 31,1995
battery monitor
950938 Safety related excess letdown valve failed IST stroke time test April 21,1995
and remained inoperable for approximately 2.5 years
950972 Three valves were found to be mounted slightly out of plumb with April 27,1995
perfect verticalin the field
951453 Replace gauges for discharge suction and oil pressure on chiller June 2,1995
units due to high failure rate
951627 Corrective action plan in Performance improvement Request June 25,1995
950241 failed to prevent an inoperability determination of CCP
during a surveillance test
I
951810 Appendix R Emergency Ughts
951838 Pressurizer safety valve did not have two as-found set point tests July 24,1995 l
within ASME Code tolerances
952270 Three pumps identified as still having temporary startup strainers September 14,1995
installed
952321 performance improvement request initiated to determine why a September 20,1995
nonsafety related component was installed on safety related
equipment
952582 Control room experienced a loss of water from the CVCA system October 26,1995
when flow was introduced through the demin vessel
952880 Hydromoter for a valve would not properly control the '/alve while December 1,1995
in the closed posilon
~960088 A vent valve was shovm on drawing as normally coen whea the January 10,1996
valve should be shown as normally closed
% 0190 Plant had a significantly higher amount of component 'ailures of January 23,1996
indicators, recorders, and gauges than the rest of the agency
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960282 Emergency Lights j
960314 During a test reactor coolant system pressure dropped below 325 February 5,1996
Psig
960801 Metal bellows type flexible hoses on the ccps were replaced with December 18,1996
neoprene hoses
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960863 performance improvement request implemented to track March 15,1996 l
corrective actions for the flexible tube oil system tubing during l
normal maintenance activities
961418 Capillary tube attached to the high pressure side of the oil May 17,1996 l
pressure switch was broken and alloled a high pressure oil leak ;
961423 Broken lug was found of an inlet damper which prevente the May 20,1996
damper closure
961530 During maintenance bonr'et was removed from a valve and a June 5,1996
small amount of water sprayed from the valve
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961648 During testing the noise of the air whistling past the control room June 25,1996 i
doors was noted to be louder than previously noted with the i
control building supply fan secured l
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961804 A conflict existed between drawings and procedures regarding July 15,1996
the temperature limit of the charging pumps bearing oil
962085 Note on drawing incorrectly stated that two valves were locked August 23,1996
closed refueling operations
962128 A cyclic noise every 25 seconds was heard on the control building August 30,1996
supply fan
963051 Flow through the control room pressurization system filter November 26,1996
absorber unit was outside Technical Specifications
963123 During the clam treatment on the essential service water system November 29,1996
the control om AC cooler did not appear to be receiving the
properleve f treatment
963133 Reactor Coolant Pump Motor Lube Oil Collection
963301 Control room essential drawings were not correct December 17,1996
970232 Compressor motor to SGK05A unit tripped off line January 27,1997
970253 Equipment SGK09 could not add enough humidity to the air in the January 29,1997
control room
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PIR SUBJECT DATE
NUMBER i
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970351 Gages were being damaged by pulsation and vibration February 4,1997 l
970519 During the performance of a test, valve BGV-0148 could not be February 20,1997
closed l
! 970873 Temperatures in the class 1E switchgear and battery rooms were March 21,1997
trending higher than normal
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971391 Initiated to address ineffective corrective actions while performing May 12,1997 )
work on a valve !
971491 performance improvement request initiated to evaluate corrective June 12,1995
actions Callaway completed by closing off their normal air exhaust i
registers ;
972289 CVCS Train A exceeded its maintenance rule unavilability July 29,1997
performance criteria
972396 Control room HVAC units were declared inoperable in order to August 8,1997
replace the lower seal on the main control room door
972529 Snubbers were removed from pipe support for one month to August 19,1997
prevent damage to snubbers. Operability of system was
questioned
972539 Failure to perform VT-3 test on pressurizer safety valve body for August 19,1997
the inservice inspection program
972687 Non-Fire Protection Use of Fire Pumps
972783 Accident Analysis Fuel Burnup Assumptions
973292 ped ~mance improvement request initiated to track engineering October 20,1997
test results that determined that the required control building
pressurization was maintained
973533 Seal injection filter high differential pressure alarm was received October 31,1997
in the control room
973726 Offsite Fire Brigade Training
973767 System engineer discovered that the air supply valve and air November 15,1997
pressure regulator indicator for the reactor coolant system
letdown to regenerative heat exchanger were damaged
973972 Offsite Fire Brigade Drill Participation
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980145 Seal injection line to the chemical and volume control system January 19,1998
! boron thermal regeneration system chiller pump was leaking
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~ PIR SUBJECT DATE !
NUMBER !
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980169 Safety Limit / Updated Safety Analysis Report Fidelity i
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- 980179 Fuel Handling Accident Analysis Updated Safety Analysis Report
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Fidelity - '
980412 Safety Limit / Updated Safety Analysis Report Fidelity
980443- Found a 30 amp fuse installed instead of a 3 amp January 23,1998
980735- Fire Protection Audit issues
s
980743-' performance improvement request initiated to perform a root March 18,-1998
cause evaluation and determine corrective actions for pressurizer ;
safety valve failures
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980758 performance improvement request initiated due to an evaluation 4
or a non-conformance report was not issued for pressurizer )
safety valve as-found set point failures during 1996 j
980871 - Two Carbon Dioxide Fire Extinguishers Not inspected
980964 Failure of Diesel-Driven Fire Pump to Start
980995- Fire Brigade Training Time Allowance
REPORTABILITY EVALUATION REQUESTS
.
- RER SUBJECT - REV. OR DATE i
NUMBER
95-015 RER initiated to evaluate the reportability of a pressurizer safety May 30,1995
valve failing it's surveillance test
97-022, Reactor Coolant Pump Motor Oil Leakage
- 98-010 RER initiated to evaluate the reportability of pressurizer safety March 4,1998
valves failing surveillance tests98-011. RER initiated to evaluate the reportability_of pressurizer safety . March 4,1998
valves failing surveillance tests98-013 RER initiated to evluate the reportability of pressurizer safety March 19,1998
valves failing surveillance tests
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' PROCEDURES- I
- PROCEDURE NO. TITLE REV.
AP 05-001 Change Package Planning and Implementation", 2
AP 05-002 " Dispositions and Change Packages" 3- H
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AP 05-008 Fire Protection Review 0 l
AP 10-100 Fire Protection 1
OTSC 97-015 .;
AP 10-101 Control of Transient Ignition Sources 3 i
~AP 10-102 Control of Transient Combustible Materials 3
AP 10-103 Fire Impairments. 5
OTSC 98-124 -
' AP 10-104 Breach Authorization 7
OTSC 98-049 !
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- AP 10-105 Fire Protection Training 1 ;
OTSC 98-060 l
l AP 10-106 - Fire Preplans 1
~ AP 10-107 Fire incident Investigation and Reporting 1
AP 10-108 Fire Prevention Inspections 1
,
AP 28A-001 Performance improvement Request 9
OFN RP-016 Control Room Evacuation 11-
STS BG 100A . Centrifugal' Charging System "A" Train Inservice Pump Test 18,19
STS PE-001 - - Filter /Adsorber Visual Inspection - Safety Related Units 4'
' STS PE-002 Charcoal Adsorbent Sampling for Nuclear Safety Related-
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Units
STS PE-004- Auxiliary Building and Control Room Pressure Test 9
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[ : STS PE-005 ' HEPA Filter in Place Leak Test, Safety Repated Systems 4.
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L . STS PE-C06 1 Charcoal Adsorber In Place Leak Test, Safety Related Units-- 7 l
-. STS PE-009 Control Room Ventilation Systems Flow Rate and Combined 5
- Pressure Drop Test ~
- STS PE-009-BAC Control Room Ventilation Systems Flow Rate and Combined 5
L - Pressure Drop Test , .
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Pump Suction Header Pressure Test
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PROCEDURE NO. TITLE REV.
STS PE-0421D . CVCS CCP "A" Discharge Header Pressure Test 2
STS PE-042E ' CVCS CCP "B" Discharge Header Pressure Test 2
STS PE-042F ' CVCS Pumps Discharge Pressure Test 3
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STS PE-042K : Chemical and Volume Control System Misc. Pressure Test 4
STS PE-044. . Auxiliary Building and Control Room Pressure Test
STS PE-044At High Pressure Safety injection System Pressure Test 5
STS PE-044C . High Pressure Safety injection System Pressure Test 2
STS PE-044D High Pressure Injection System Pressure lest 2
STS CV-210B ' ECCS Si and residual heat removal inservice Check Valve 3
Test i
i SYS' NK-201 Transferring Between NK Battery Chargers . 0
. SYS BG-120 _ CVCS Startup 24
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I SYS FP-293 Fire Pumps Manual Operations 7
SPECIFICATIONS
SPECIFICATION NO. TITLE REV ;
f E-050A(O) Class 1E Batteries for WCGS 5
L E-051(O) Battery Chargers for SNUPPS . 5
E-051 A(O), Swing Batte'ry Chargers for WCGS 2
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E-051B(O Electrically Operated Manually Controlled Transfer Switches 0
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. E-1 R8900 . Raceway Notes, Symbols, and Details 1
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i DRAWINGS
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DRAWING - TITLE REV
j. N'JMBER
' E-11 NK01 ' Class 1E 125 V DC System Meter & Relay Diagram 5
g . E-11NK02 Class 1E 125 V DC System Meter & Relay Diagram 4
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l E-11010 DC Main Single Line Diagram 4
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I~ M-1G051 Equipment Locations Control & Diesel Gen. Bldg & Common Corridor Plan 8
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i. M-1G050 ~ Equipment Locations Control Bldg & Common Corridor Plan 2
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I' DRAWING TITLE . REV !
NUMBER i
1 M-12KC01 Fire Protection Turbine Building 5 I
M-12KC02 Fire Protection System - 6
M-12KC03 Fire Protection System 2'
' M-12KC04 - Fire Protection Halon System 1
. M-12KC05 Fire Protection System 00
M-12KC06 Fire Protection Halon System 00
M-12KC07 ' Fire Protection Halon System 00 2
-CALCULATIONS
NUMBER TITLE . REV.
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1-BCB-W-1 Minimum Wall Violation; F025, FW321, FW691 and FW690 0
2 ECB Pipe Class ECB 0
AN-95-021 Determination of the ECCS Flow Rates During the Recirculation 0
Phases l
AN-96-074 RWST water level to supply adequate NPSH for the ECCS 0
Pumps (Setpoint L-04)
BG-FW-004 Piping Stress Analysis of CVCS - Normal and Altemate Charging 1
System l
BN 6 Pressure Drop Calc for Line 08-HCB-8" (RWST Disch Hdr to O
CVCS Pump "B" Suct HDR) from Line 07-HCB-24" to Line !
BG-265' l
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BN 7. . Pressure Drop Calculation for Line 07-HCB-24" (RWST Disch 0 i
Hdr Line) from Branch Line 09-HCB-8" to Branch Line
BN-20 RWST Level Set Points 1 l
E-3 Class 1E Battery System 0
, E-3-W : Class 1E Battery System W-0
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ECCS-5 Calculate Head Loss to Assure Adequate NPSH to.CCP "A" 0
during Cold Leg Recirculation in Accordance with PFD-RD-285-4.
The area of concern is from 'r esidual heat removal Sump "B" thru
ECCS-7 CCP "A" NPSH During Hot Leg Recirculation 0
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NUMBER TITLE REV.
ECCS-45 Verify Adequate Resistance Exists in RCP Seal Injection Line to 0
Limit Runout of CVCS Centrifugal Charging Pumps during ECCS
Injection
ECCS 46 - CC Pumps NPSH from RWST 0
EM-17 Pressure Drop Calculation for 75-BCB-CVCS to Boron Injection 0
Tank
EN-20 Minimum Post-LOCA Recirculation Times 0
EQAL-SAP, Auditable Link Report for Wolf Creek Unit 1 4 i
M-751-00003
EQWP AE-2 AE followup item, Performance Improvement Request 98-0037 1
GK-02-W Control Room Ventilation System 1
GK-02-W Safety Related Control Room . y ilVAC Capabilities During 2
Accident Conditions (SGK04A/B and SGK05A/B)
GK-03-W Control Room A/C System Temp vs. CFM Curve 1 i
GK-03-W Temp vs CFM Curve 1 i
GK-04-W Failure of One Train 0
GK-91 Control Room Pressurization System: Determine Control Room A
Inleakage Characteristics
GK-112 HVAC - Control Building - Wintor Operations A
GK-230 Control Room Habitability: CO2 Buildup 0 )
GK-386 Control Building Ventilation - Normal Operation 3
GK-474 Control Room Pressurization System Filtration Unit Heater 1
HE-5 Mode C Delta P; Determine the pressure Drop from the Recycle 0
Evaporator Package to the Boric Acid Tanks (Mode C pts 16-17)
HE-7 Mode A Operation - Pts 1-29, Delta P from CVCS to the RHTs. 1 l
KC-413 Fire Protection - Fire Pump Flow Requirements 0
KC-452 Fire Protection System - Water Supply Adequacy 0
M-CX-386 Control Building HVAC - Normal Operation 3
MEO-M-72' -1 Environmental Qualification 6 I
NK-E-001 Class 1E DC Voltage Drop 1
NK-E-002 Class 1E Battery Sizing 3
NK-E i'?:s Class 1E 125 V DC Batteries Short Circuit Study 0
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NUMBER TITLE REV.
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P 139 Snubber Reduction for CVCS - Normal Charging (Reactor 0
Building)
PB BG 30 ' Pipe Break Analysis 0 ,
PB 1125 - Room No.1125 P/T Volumes & Vent Areas O
SA 91-016 ECCS Design Basis Injection Flowrates Re-Analysis in 0
Supporting of the WCGS Power Re-Rating Project -
SA-92-056 CCP & Si Pumps Runout Flowrates During the Recirculation 0
Phase
SBG-3 ' Centrifugal Charging Pumps A
- PLANT MODIFICATIONS
i^ MODIFICATION NUMBER TITLE ,
j- DCP 03702 Reactor Coolant Pump Oil Fill Lines
PMR 04519. Upgrade Fire Detection System i
DCP 05248 . NK System Swing Battery Charger Installation, Revisions 0 - 11
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DCP 05846 NK Battery Replacement, Revisions 0 through 11
DCP 07280 Reactor Coolant Pump RTD Conduit Seals :
TEMP MOD /TMO 96-017-KC Control Room Pantry Fire Protection Equipment
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- . PREVENTIVE MAINTENANCE AND SURVEILLANCE ACTIVITIES
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MPE BA-010, Revision 6. Preventive Maintenance on Teledyne Emergency Lighting
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- MPE M7120-02, Revision 8 Reactor Coolant Pump Motor Inspection
l STN FP-410 Diesel Engine inspection
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STN GP-009, Revision 25 Emergency Radio and Equipment Check and Inventory
STN FP-211 Diesel Fire Pump Operability and Fuel Level Check
' TMP 95-ENG-190, Revision 0 Emergency Lighting Walkdown
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MISCELLANEOUS DOCUMENTS
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Number Title REV. OR DATE l
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l . Agreement for Fire Protection Between Wolf Creek Nuclear Februay 5,1996
Operating Corporation and Coffey County Fire District #1
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Wolf Creek Updated Safety Analysis Report
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Wolf Creek Technical Specifications !
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Safety Evaluation Report Related, Amendment No.104 February 10,1997 l
! AP 29-003 Component Cyclic or Transient Limits . February 20,1998 l
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l Bechtelletter Control Room Doses October 30,1987
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CKL ZL-001 Auxiliary Building Reading Sheets February 17,1998
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CKL ZL-004 Turbine Building Reading Sheets February 20,1998
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DG WCN06-76 Design Guide for Overcurrent Protection Coordination 0,1
EMG ES-12 Transfer to Cold Leg Recirculation November 1,1996 j
EOWP AE-2 Large Pump Motors (Outside Containment) August 3,1983 l
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Adopted ASTM D3803-1989 as the laboratory testing standard September 4,1996
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License -
Amendment for charcoal samples; downrated the heater capacity from 15
No.102 kw to 5 kw.- ;
MEO-M-721-1 Centrifugal Charging Pump Environmental Qualification August 2,1996 !
NRCIR Wolf Creek Generating Station Design inspection February 23,1998
50-482/97-201 1
NUREG-0830 Safety Evaluation Report, Callaway October 1981
PMR 03158 Deactivation of RH Sensors and Transmitters June 10,1993
PMR 04380 ' Changes design documentation to allow components served by September 1,1993
CCW to operate with the temperature as low as 35F
QA AUDIT Fire Protection Program December 6,1996
REPORT
K15-002, K-468
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QA AUDIT - Fire Protection Program March 19,1998
' REPORT
Report 02805 Industry Technical Information Program Report,"NRC
Information Notice 94-58: Reactor Coolant Pump Lube Oil Fire
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! Number Title REV. OR DATE
SLT 83-0045 SNUPPS Vortex Analysis: Containment Recirculation Sump April 27,1983
Testing
Special Order Use of Fire Protection System for Non-Fire Protection Purposes 12:00 a.m.
TIN FB Training Lesson - Fire Extinguishers and Extinguishing Agents January 2,1900
1231406
TIN FO Training Lesson - Training for Coffey County Fire District #1 January 1,1900
1235500
WC 14624 Calibration Data Sheet for Controlotron 990, Serial U1207 October 12,1992
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WC 14625 Calibration Data Sheet for Controlotron 990, Serial U1206 October 20,1992
WCRE-08 WCGS Approved Fuse List January 5,1900
WP 115686, PEM01 A has a leak on the suction flange.
WP 126378 Fire Extinguisher Monthly Sun /eillance
WP 126598 Appendix R Emergency Lights in the Turbine and Diesel
Generator Buildings Annual
l ' WP 128669-1 Oil leak on "B" CCP (PBG05B) March 31,1998
l WR 00800-92- Component Cooling Water System Low Temperature December 22,1992
Evaluation - Post-LOCA
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