IR 05000254/1998019
| ML20198G293 | |
| Person / Time | |
|---|---|
| Site: | Quad Cities  |
| Issue date: | 12/18/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20198G287 | List: |
| References | |
| 50-254-98-19, 50-265-98-19, NUDOCS 9812290045 | |
| Download: ML20198G293 (60) | |
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. U.S. NUCLEAR REGULATORY COMMISSION REGIONlli
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' Docket Nos:
50-254; 50-265 L
License Nos:
50 254/98019(DRS); 50-265/98019(DRS)
l Licensee:
Commonwealth Edison Company i
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Facility:
Quad Cities Nuclear Power Station, Units 1 and 2 l
Location:
22710 206th Avenue North Cordova, IL 61242
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Dates:
October 19 through November 6,1998 Inspectors:
Rolf Westberg, Reactor Engineer, Rill Team Leader Mike Miller, Reactor Engineer Al Walker, Reactoi Engineer Patricia Lougheed, Reactor Engineer -
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Roger Mendez, Reactor Engineer
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Ron Langstaff, Reactor Engineer Gerry O'Dwyer, Reactor Engineer
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l Bob Winter, Reactor Engineer l
Approved by:
John Jacobson, Chief l
Lead Engineers Branch l
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9812290045 981218 PDR ADOCK 05000254 e
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EXECUTirE SUMMARY Quad Cities Nuclear Generating Station Units 1 and 2 Inspection Report 50-245/265 98019 The purpose of the inspection was to evaluate the effectiveness of the engineering and technical
support (E&TS) provided to the plant in performance of routine and reactive site activities
including identification and resolution of technicalissues and problems. The inspection focused on system engineering functions, modifications, technical problem resolution, and engineering support to other plant organizations. The criteria used to assess E&TS performance was understanding of plant design and involvement in preventing and solving plant problems. In addition, the effectiveness of the corrective action program in identifying, resolving, and l
preventing problems was evaluated.
Enaineerina The 24 modifications reviewed by the team were adequately designed, installed, and
tested. Justifications for delaying and canceling rnodifications were acceptable
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(Section E1.1).
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The 10 calculations reviewed were acceptable; however, the team considered changing
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the installed position of thermal overloads without a design review a weakness (Section E1.2).
l The 10 temporary modifications reviewed wem well controlled, of good technical quality,
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temporary modifications were installed abnormally long (for four years or longer with one temporary alteration originally installed in 1992). A no response violation was identified for failure to test the reactor building sump pumps to the requirements in the temporary alteration package (Section E1.3).
10 CFR 50.59 Screenings and Safety Evaluations
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The 50.59 screenings and evaluations were determined to be complete and comprehensive. (Section E1.1)
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Recent 10 CFR 50.59 screenings (26) and safety evaluations (23) were reviewed and found to be of good quality except for some minor errors. The program for ensuring that trained and qualified personnel prepared and reviewed 50.59 screenings and safety evaluations was acceptable (section E3.1).
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in response to the team's concem with respect to potential pre-conditioning of reactor core isolation cooling prior to surveillance testing, the licensee took thorough corrective actions to ensure no pre-conditioning due to venting would take place (Section E3.2).
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Overall, the team concluded that the surveillance results reviewed were within the l
required acceptance criteria; however, the acceptance criteria for the battery charger test
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procedures was weak, in that it did not require that voltage data be taken during the four-
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hour discharge test.
Service battery procedures allowed tightening of intercell connectors prior to testing,
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which potentially constituted pre-conditioning of the test; however, the team found no i
j evidence ti'at it had been done previously (Section E3.3).
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The ter.m considered the licensee's systematic approach to locating DC grounds to be a
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strength (Section E3.3).
The team concluded that the licensee had made adequate progress in the
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implementation of selected strategic reform initiatives (Section E6.1).
The corrective action methods in place were good and, in most cases, were effective in
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addressing corrective action issues. The Events Screening Committee and the
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Corrective Action Review Board functioned well and actions were thorough and effective.
(Section E7.2).
Management expectation for Problem identification Form (PIF) initiation was not being
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met by some staff members. The use of computers to initiate PIFs contributed to some individuals not generating PIFs. Other individuals did not have a clear understanding of i
management expectations of when a PlF should be written (Section E7.3).
Several individuals were concemed with punitive actions that resulted from PIFs and did
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not support the process; however, this did not appear to impact the overall effectiveness of the corrective action process. The licensee corrective actions for this issue were prompt and comprehensive. (Section E7.3).
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encouraged the corrective action process. In addition, the general feedback of PlFs and
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industry events to work groups appeared to heighten the groups awareness of potential
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l problems and how to avoid them (Section E7.4).
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The % Emergency Diesel Generator (EDG) crankcase over presmre indication issue
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and elevated water and sediment concentrations in the Unit 1 EDG fuel oil tank both posed potential problems for the EDGs. Tracking and prioritizing of these issues until j
some level of resolution was verified appeared weak (Section E7.5).
L Plant On-site Review Committee (PORC)
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PORC comments contributed to the technical quality of temporary modification, TA 98-2-028 - Leaking. Reactor Recirculation Sample Line Relief Valve (Section E1.3).
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l The PORC was functioning well. Reviews of items were thorough and additional corrective actions were required prior to committee approval for rejected packages
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(Section E7.6).
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The team concluded that previous reviews, as evidenced in the off-site review committee
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quarterly trend reports and monthly committee review reports, indicated good performance by off-site review in the identification of problems, weaknesses and trends.
However, since the quarterly trend reports and the monthly committee review reports had been discontinued since April,1998, the team was unable to assess current performance (Section E7.7).
The audit and assessment program was acceptable. The audit and assessments
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conducted by Nuclear Oversight appeared to be effective in identifying and correcting significant issues (Section E7.8).
The System Health Indicator Program was an excellent assessment process for
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evalua;ing system status and identifying problem areas to management. The reports were informative and provided good information to management on the status and availability of plant systems and components (Section E7.9).
Further examples of an earlier escalated violation related to inadequate design control
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resulted iri a violation being identified. However, for this violation, the NRC exercised discretion in accordance with the Enforcement Policy and refrained from issuing a citation (Section E8.11 A non-cited violation was identified for three cases of licensee identified, non-repetitive,
and corrected errors in the loss of.:oolant accident analysis (Section E8.37).
A no response violation was identified for failure to promptly evaluate a previously
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identified concern with the heat removal rate of the RHR heat exchangers and to take
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corrective actions in a timely manner (Section E8.38).
A no response violation was identified for failure to establish a test program for the RHR
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heat exchangers to demonstrate that they would perform satisfactorily in service (Section E8.39).
A no response violation was identified for failure to adequately translate or verify design
information into design documents in that, documentation of design bases information was inconsistent with actual plant design, and failure to verify and check the adequacy of design (Section E8.41,46,47,51, and 52).
A non-cited violation was identified for licensee identified, non-repetitive, and corrected errors in the EDG loading analysis (Section E8.42).
Discrepancies between plant as-found conditions and the plant licensing basis resulted
in a violation being identified. However, for this violation, the NRC exercised discretion in accordance with the Enforcement Policy and refrained from issuing a citation (Section E8.50).
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l Report Details
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l 111. Enaineerina E1 Conduct of Engineering E1.1 Review of Desian Chance Packaaes and Modifications OP 37550)
a.
Insoection Scope The team reviewed a sample of twenty-four modifications and ten temporary modifications to determine if Quad Cities designed, installed, and tested modifications appropriately and whether they adequately justified canceled or delayed modifications.
The team also reviewed whether Quad Cities insta!Ied and removed temporary modifications in accordance with established procedures. In addition, the team reviewed 10 CFR 50.59 evaluations for the modifications, temporary alterations and procedure changes.
b.
Observations and Findinas The sample of modifications reviewed by the team were adequately designed, installed, and tested. In addition the team found delayed and canceled modification adequately justified. Team observations on specific modification follow:
DCP 9600025 - Replace Gearina on 1-1001-18B This modificaL., planned to replace the gearing on the linit i train B residual heat removal (RHR) minimum flow valve, valve 1-1001-18B, to provide a larger thrust window for the valve. The geaiing change would result in an increased stroke time for the valve.
The RHR minimum flow valves were normally open and would close when sufficient flow was established. The licensee planned to install this modification during the
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November 1998 refueling outage, Quad Cities had already done similar modificati<ns for the other unit and the opposite train.
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The team noted that the licensee performed a 10 CFR 50.59 safety evaluation, (SE)98-090, dated August 25,1998, and addressed the increased stroke time for the valve.
The safety evaluation documented that existing accident analyses assumed that the valve would remain open. Consequently, the increased stroke time for valve closure did not present a concern.
The team verified that the licensee had performed in-service testing (IST) and had updated associated IST program documentation to reflect the increased stoke times for the opposite train valve, valve 1-1001-18A (documented in procedure QCOS 1000-09 performed April 25,1996, and procedure QCAP 0410-01, Attachment E, data sheet).
l The team verified that the licensee specified similar testing for valve 1-1001-18B as part l
of testing this modification.
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DCP - 9600062. Reolace the Existina 1-1101-16. (Crane 1-1/2" tvoe T) with a Rockwell Edward Model D36174 This modification planned to replace a lift check globe valve, valve 1-1101-16, in the standby liquid control (SBLC) system discharge line with a check valve of a different type. They were replacing the existing valve to improve local leak rate test performance.
The team noted that the licensee had performed a 10 CFR 50.59 safety evaluation under the guidance of an earlier program. The licensee performed a safety evaluation screening, screening SS-H-98-0151, dated September 9,1998, to validate the quality of the earlier safety evaluation. The eafety evaluation addressed both flow characteristics and reliability of the replacement valve. The team considered both the earlier safety evaluation and more recent screening to be acceptable The team reviewed the work package, WR 960003776, for a similar modification (i.e., replacement of the other check valve in the same line), and verified that appropriate inspection and testing had been performed. The team verified that this modification specified comparable inspection and testing.
DCP 9600358 - Install ECCS Suction Strainers This modification planned to replace the existing emergency core cooling system (ECCS) suction strainers in the unit 1 suppression pool. This modification addressed providing greater net positive suction head (NPSH) margin for ECCS pumps in response to NRC Bulletin 96-03, " Potential Plugging of Emergency Core Cooling Suction Strainers by Debris in Boiling Water Reactors," dated May 6,1996.
The team reviewed the 10 CFR 50.59 safety evaluation, SE 97-022, dated February 12, 1997, performed under the guidance of an earlier program. The licensee performed a
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safety evaluation screening, screening SS-H-98-0140, dated August 14,1998, to validate the quality of the earlier safety evaluation. The team noted that although NPSH margin would be increased (as documented by the safety evaluation), a negative margin of-0.9 feet would still exist for the core spray (CS) pumps. The CS pump NPSH margin had improved from the -4.3 foot margin calculated for using the old strainers. At the time of this inspection, the Office of Nuclear Reactor Regulation (NRR) was reviewing the issue of required NPSH and necessary containment over-pressure as documented by NRC letter from Robert M. Pulsifer to Oliver D. Kingsley dated September 22,1998.
During an inspection of the Unit 1 and Unit 2 reactor building basements, the team noted that additional support pieces required by the ECCS suction strainer modifications had been installed on Unit 2 and were in the process of being installed on Unit 1. The additional support pieces were consistent with drawing M-1630-03. The team also inspected the ECCS suction strainers planned to be installed on Unit 1 and verified that he strainers were constructed consistent with the fabrication drawings.
The team reviewed the completed test results for the Unit 2 ECCS suction strainer modification (" Unique Test, Design Change Package (DCP) No. 9600346, ECCS Suction
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Strainer Replacement," Revision 1) and confirmed that the test verified adequate flow through the replacement suction strainers. However, the team questioned why the test
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The team verified that licensee engineers had performed calculations to evaluate the
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i effects of dynamic loads on the replacement suction strainers. Additionally, the team
reviewed calculation QDC-1600-S-0464 for flange stresses and bolting for attaching the replacement strainers. The team noted that nut torquing values specified by the calculation were based on dry threads. However, the licensee planned to install the s
strainers underwater which would provide lubrication for the threads thereby affecting the <
torque values. Additionally, licensee personnel stated that for Unit 2, they had applied j
lubrication to the nuts and studs to prevent galling of the threads. The application of l
lubricant was consistent with the site's general bolting procedure, procedure QCMM j
1500-11. The team was concemed that the inconsistency between the condition
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assumed by the design calculation, i.e., dry, and the installed condition, either wet or lubricated, could lead to aq improper torque applied for the bolted connections.-
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Additionally, the installation torque specified on the installation drawing did not account
for instrumentation tolerances such as that for the torque wrench. Licensee personnel informed the team that the torque wrenches had a calibration tolerance of 4% in this
instance, the 175 ft-lb minimum torque specified by the installation drawing, drawing M-1630-04, could have allowed the torque to be less than the 173.8 ft-lb minimum torque specified.by the calculation when torque wrench tolerances were considered. However, l
the team recognized that the flange bolting and associated torquing were not critical because the flanged joint was not a pressure boundary joint for this application.
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.(Lo.nclusions:
The 24 modifications reviewed by the team were adequately designed, installed, and
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tested. Justifications for delaying and canceling modifications were acceptable. The team considered the 50.59 screenings and evaluations to be complete and comprehensive.
E1.2 Review of Calculations (IP 37551)
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Insoection Scope The team reviewed ten calculations to evaluate correctness and adherence to standard methodology.
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Observations and Findinas Calculation No 004-E-001 reviewed thermal overloads (TOLs) installed in power circuits of motor operated valves. The calculation made the assumption that the TOL utilized ibc A position as opposed to the B, C or D position; however, the team observed that 12 of 13 TOLs in the 250 volts direct current (Vde) motor control center (MCC) were not in the
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A position. Although the licensee stated that this was acceptable practice becc a the
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overload response characteristic difference between each position was minimal and they were maintaining protection (not necessarily optimum protection) to the motor, the team noted that the assumption made in the calculations did not state that the position of the TOL could be changed.. In addition, the calculations reviewed required maintaining electrical coordination.
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Conclusions
The 10 calculaticns reviewed were acceptable; however, the team considered changing the installed position of thermal overloads without a design review a weakness.
E1.3 Temporary Alteration (TA) Proaram Review (IP37550)
a.
'InsoectionEm.
The team reviewed implementation of the TA program required by QAP 0300-12,
" System Temporary Alterations," Revision 33, approved in September 1998 and QCTP
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1020-02, " System Temporary Alteration Review," Revision 3, dated February 25,1997.
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The team reviewed ten TAs.
b.
Observations and Findinos Quarterly Reviews Procedure QCTP 1020-02 required that the cognizant, design engineer perform en evaluation addressing the continued need for the alteration when the temporary alteration was installed for greater than ihme months. The licensee followed this requirement for temporary alterations that they installed during the first three-month period. However, the team noted that the procedure did not require the subsequent evaluations be performed on a scheduled frequency. The team believed that the procedure did not provide clear guidance, although evaluations were performed on an approximate yearly basis. The team noted that several TAs were installed for an abnormally long time period (for more than four years on one TA originally installed in 1992).
TA 92-2-140 - Reactor Buildina Sumo Pumo Quad Cities initiated TA 92-2-140 to install a submersible floor drain sump pump in the 2B reactor building. The authorization and technical review was completed in p
October 1992 and the reactor building samp pump was installed in December 1992. The I
licensee issued a work order and performed some initial testing but found that the pump rotated in the wrong direction. A second work order was issued to correct pump rotation.
The team discovered that Quad Cities had not tested the high level start and low level trip, although temporary alteration 92-2-140, issued on October 23,1992, required verification that the 2B reactor building floor drain sump pump start on high sump level
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and trip on low level. Additionally, Procedure QAP 0300-12 " System Temporary Alterations," Revision 33, required performing and documenting the post installation testing. _ Quad Cities Updated Final Safety Analysis Report (UFSAR), section 9.3.3.4,
" Reactor Building Floor Drains and Sumps," required that the reactor building floor drain sump pumps start on a high sump level signal and trip on a low level sump level signal.
On November 6,1998, the licensee issued PlF Q1998-04823 to initiate action to test the reactor building sump pumps to the requirements in the temporary alteration package and the UFSAR.
Failure to test the reactor building sump pumps to the requirements in the temporary alteration package was a violation of 10 CFR Part 50, Appendix B, Criterion XII," Test Control" (50-254/98019-01a(DRS); 50-265/98019-01a(DRS)). Licensee corrective actions as described above and documented in their respective corrective action documents adequately addressed correction of the specific issue and actions to prevent recurrence. Therefore, no response to this violation is required.
TA 98-2-028 - Leakina Reactor Recirculation Samole Line Relief Valve:
The licensee initiated temporary modification 98-2-028 to address a leaking rehef valve
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(valve 2-0220-238) inside the Unit 2 drywell (documented on PlF Q1998-02975). The relief valve was off the reactor re-circulation sample line between the inboard and outboard containment isolation valves. Quad Cities had installed the relief valve in response to Generic Letter 96-06, " Assurance of Equipment Operability and Containment Integrity During Design-Basis Accident Conditions," dated September 30, 1996. The original revision of the temporary modification replaced the relief valve with a blind flange, directed that the associated containment isolation valves be closed, the i
volume between the two containment isolation valves drained, and specified that the
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pressure between the containment isolation valves be monitored. Pressure monitoring
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was accomplished by attaching a gauge to the local leak rate test (LLRT) line and opening the LLRT valves. Revision 1 to the temporary modification maintained the blind flange in lieu of the relief valve, halted pressure monitoring, and directed that the associated containment isolation valves be normally open.
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The team verified that required testing and inspection for the original revision of the j
temporary modification had been performed. Pressure monitoring was specified as a result of comments by the plant on-site review committee (PORC). The team considered the pressure monitoring to be necessary to ensure that the assumptions of a drained volume continued to exist. As such, the PORC comments that resulted in the pressure monitoring, were indicative of significant contribution by the PORC review. Performance of the pressure monitoring resulted in the licensee identifying that the inboard isolation valve was leaking, volume was no longer draimd, and the design assumptions for the temporary modification were no longer valid.
The team identified two concems with respect to the safety evaluation associated with the temporary modih on, SE-98-126, dated October 10,1998, performed for the original revision + tamporary modification:
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The evaluation did not consider the breaching of what was normally a
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containment pressure boundary for accomplishing the pressure monitoring, (i.e., the opening of the LLRT valves). However, the team subsequently determined that 10 CFR 50.59 would not have required such an evaluation because the LLRT valves were not described in the UFSAR as being nomially closed. The team reviewed the work request that had accomplished the monitoring (WR 980105983-01) and confirmed that a second individual verified closure of the LLRT valves. During pressure monitoring activities, the inboard containment isolation valve was shut and provided the containment pressure boundary.
The evaluation did not address the potential for a water hammer after draining
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the line. Although the containment isolation valves were tagged shut, the safety evaluation noted that the valves could be opened for post-accident sampling.
With the line drained, a water hammer could occur when the valves were opened.
Revision 1 to the temporary modification was initiated as a result of leakage through the inboard isolation valve (documented by PIF Q1998-04363). The team reviewed the operability determination associated with PIF Q1998-04363 and the 10 CFR 50.59 safety evaluation for Revision 1 of the temporary modification, SE-98-135, Revision 1, dated October 20,1998. The team did not identify any concems. The team noted that the licensee based acceptability of a revised configuration on preliminary analyses performed for similar piping for unit 1. Although using preliminary analyses was acceptable for an operability determination, the team noted that formal analyses would have to be completed to rete.in the revised configuration following the next refueling outage. The team verified that the licensee planned to complete their analyses before the next refueling outage.
TA 98-02-22 -Reactor Core isolation Coolina Discharae Valves:
Quad Cities performed this temporary modification to address a leaking Reactor Core isolation Cooling (RCIC) discharge valve,2-1300-49. The temporary modification changed the valve position of the leaking valve from normally closed to normally open and changed the valve position of another RCIC valve discharge valve in the same line, valve 2-1300-48, from normally open to normally closed.
The team noted that the 10 CFR 50.59 safety evaluation for the temporary modification, SE-98-086, dated July 17,1998, specifically identified the UFSAR section and wording affected by the change, identified procedures requiring revision as a result, addressed differences in valve timing between the two valves (which was negligible), and considered the increased pressure and temperature on some components. The team considered the evaluation to be thorough and to address potentialissues well. The team verified that both valves received the same opening and closure signals.
The team followed up on one procedure identified as requiring revision and verified that an interim procedure had been issued. Specifically, interim procedure 98-0098, dated June 9,1998, had been issued for procedure QCOS 1300-05, " Quarterly RCIC Pump
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. Operability Test." The team verified that the interM, procedure included appropriate
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changes to valve lineups that reflected the tec$orary modification.
c.
Conclusions
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The 10 temporary modifica%ns reviewed were well controlled and of good technical quality and demonstrated engineering's responsiveness to plant issues; however, some TAs were installed abnormally long. The plant on-site review committee comments contributed to tne technical quality of temporary modification, TA 98-2-028 - Leaking Reactor Recirculation Sample Line Relief Valve. A no response violation was identified for friiure to test the reactor building sump pumps to the requirements in the temporary citeration package.
E2 Engineering Support of Facilities and Equipment E2.1 Problem Identification and Evaluation Review
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a.
Inspection Scope The team reviewed twenty electrical related PIFs, including the cause determination
evaluations and corrective actions to evaluate the effectiveness of problem identification,
evaluations and corrective actions.
b.
Observations and Findinas
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i in October 1997, the licensee identified that they could not adjust the low voltage alarm
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setpoint into the acceptance criteria on the 126 VDC battery charger for unit 2. Licensee personnelissued PIF Q199704021 to document the problem. It was subsequently determined the low voltage circuit board was not working correctly; however, no
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corrective actions were taken because no circuit board replacements were on site.
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During the inspection, the team found that circuit board was not scheduled to be replaced untii December 1998. Although the risk significance of not immediately
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repairing the low voltage alarm was relatively minor, the team noted that the alarm was a
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design feature to provide an early waming to plant personnel of problems with the battery charger.
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Conclusions The team concluded that the PlFs received prompt corrective actions and root cause determinations. The team noted a minor problem related to slow corrective action on the battery low voltage alarm.
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E3 Engineering Procedures and Documentation l
E3.1 10 CFR 50.59 Proaram Review Around the end of 1997, Quad Cities identified problems with the thoroughness of 10 CFR 50.59 screenings and safety evaluations. Quad Cities management responded by implementing corrective actions. This inspection focused on the quality of the screenings and safety evaluations produced by the present program during the past six
months since the restart of the units after extended outages.
a.
Inspection Scope (37001)
The team reviewed the implementation of the 10 CFR 50.59 program including procedures for screening changes, tests, and experiments and preparing safety evaluations; the processes for maintaining records, updating the UFSAR, and reporting to the NRC; and the training and qualifications of 10 CFR 50.59 screening and safety evaluation preparers. In addition, the team reviewed fifty safety screenings or safety evaluations associated with significant procedure changes, facility changes, temporary modifications, negative applicability determinations, UFSAR editorial changes, and defacto changes to UFSAR. The team also reviewed 10 CFR 50.59 Safety Evaluations during the review of Design Change Packages, Modifications, and Temporary Modifications (See Section E1.1 of this report).
b.
Observations and Findinas 10 CFR 50.59 Proaram Quad Cities used nuclear station work procedure (NSWP) A-04, Revision 1-1, "10 CFR 50.59 Safety Evaluation Process," to perform 10 CFR 50.59 screenings and safety evaluations. The team reviewed NSWP-A-04 and verified that the guidance in this procedure was in conformance with 10 CFR 50.59 and NUREG-1606, " Proposed Regulatory Guidance Related to implementation of 10 CFR 50.59." The team concluded that NSWP-A-04 appropriately reflected 10 CFR 50.59 safety evaluation criteria and, if
, effectively implemented, would ensure that changes were performed in accordance with 10 CFR 50.59.
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10 CFR 50.59 Proaram Reportina Review The team selected a sample of sixty-four safety evaluations initiated in the first six months of 1998 and determined that all but eighteen were listed on the 1998 Summary Report of Changes, Tests, and Experiments sent to the NRC that covered from October 30,1997 to June 30,1998. The team found that the eighteen safety evaluations had valid reasons for not being on the report such as the change had been canceled or the change had not yet been completed therefore the safety evaluation would be included on a future report. The team verified that Quad Cities correctly included three older safety evaluations in the 1997 Summary Report.
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10 CFR 50.59 Proaram Trainina Review The team reviewed the materials used in the training course for personnel that prepared 10 CFR 50.59 safety evaluations and verified that the information presented in the course was consistent with corporate procedures and NRC guidance. This training course, which consisted of sixteen hours of lecture and exercises, appeared to be comprehensive and included several examples. The team noted that besides successful completion of the training course, individuals were required to have at least two years of commercial nuclear experience and to complete the advanced 50.59 training. The team concluded that the licensee had an acceptable program for ensuring that trained and qualified personnel prepared and reviewed 10 CFR 50.59 screenings and safety evaluations.
10 CFR 50.59 Safetv Evaluation Review The team reviewed a selected sample of 10 CFR 50.59 screenings and safety evaluations and determined that, overall, the screenings and safety evaluations were appropriately prepared and were consistent with licensee procedures. In particular, the team determined that the preparers reviewed appropriate documents during the preparation of 50.59 screenings and safety evaluations; the 50.59 screenings and safety evaluations adequately addressed the effects of the proposed changes on plant operations, interactions with other systems and components, any new failure modes, and the effects on accidents and transients; and the 50.59 safety evaluations adequately addressed unreviewed safety question criteria.
c.
Conclusions Recent 10 CFR 50.59 screenings (26) and safety evaluations (23) were reviewed and found to be of good quality. The program for ensuring that trained and qualified personnel prepared and reviewed 50.59 screenings and safety evaluations was acceptable.
E3.2 Reactor Core isolation Coolina Surveillance Procedure a.
Scope The team reviewed the quarterly RCIC surveillance procedure, QCOS 1300-05.
b.
Observations and Findinas The team reviewed procedure OCOS 1300-05 and noted that the procedure directed operators to vent the RCIC pump before running the pump as part of the quarterly surveillance test. After venting, the procedure directed operators to close the vent valves when they observed a continuous' flow of water. The team noted that the procedure dia not specify how much, if any, gas to be vented was acceptable nor did the procedure
require an evaluation if an excessive amount of gas was observed. The team was
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concerned that the lack of controls on the venting could allow a condition that affected operability, i.e. excessive gas buildup, not to be evaluated as part of the surveillance test.
In response to the team questions, the licensee initiated Problem Identification Form (PIF) Q1998-04528 to address the pre-conditioning issue. As part of the PIF, the licensee documented that a test (using procedure QCOS 1300-07) that did not specify venting had been successfully performed recently on both units. The team verified that procedure OCOS 1300-07 did not specify venting of the pumps. The licensee also documented that the RCIC system engineer had never observed any air being vented when he was present during venting of the pump casing. As a result of their review for the RCIC system, the licensee identified pre-conditioning issues associated with venting for other safety significant systems, i.e., the HPCI, RHR, and CS systems (documented by PlF Q1998-04601). The team reviewed the surveillance procedures associated with these systems (procedures QCOS 1000-06, QCOS 1300-10,
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QCOS 1400-01, and QCOS 2300-09) and verified that the procedu es had been revised during this inspection to monitor system venting and initiate corrective action if venting was excessive. The team also verified that the procedure OCOS 1300-05 had been revised to eliminate the venting of the pump prior to the surveillance. The team noted that the licensee notified other Comed stations via a Nuclear Operations Notification (NON), NON QC-98-121, *NRC Pre-Conditioning Issue with Venting of Pumps Prior to Surveillance." The team considered the licensee's corrective actions to be comprehensive and acceptable.
c.
Conclusions in response to the team's concem with respect to potential pre-conditioning of RCIC prior to surveillance testing, the licensee took thorough corrective actions to ensure no pre-conditioning due to venting would take place.
E3.3 Surveillance Procedure Review a.
inspection Scope The team reviewed 125 VDC and 250 VDC station battery and battery charger surveillance test procedures and results.
b.
Observations and Findinas 125 and 250 VDC Ground Detection The team reviewed the licensee's ground detection procedures QOP 6900-04,06,07 and 09. The team noted that the licensee's procedures outlined proceduralized methods for locating DC grounds in the station. The procedures discussed calculating the relative strength of the ground, isolating by opening the associated breakerif the ground was suspected in a particular circuit, and systematically going through the DC circuits until the ground was located. The actions outlined in the procedure appeared to facilitate and shorten the time required to locate DC grounds.
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Batterv Charaer Surveillances The team reviewed procedure QCTS 0210-02, * Battery Charger Testing for Safety Related 125 VDC and 250 VDC Batteries," Revision 3. The team believed that the procedure was weak because it only required that current readings be taken during the l
four-hour current discharge test but did not require voltage data or readings be taken.
The battery charger vendor manual stated that during equalize current, the voltage regulation was plus or minus 0.5 percent. In reviewing the test results, the team noted that although the licensee made some checks to determine voltage regulation before the start of the four-hour test, the voltage was not recorded during the four-hour test. The
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voltage was important because plant equipment may not operate properly when voltage i
is below nominal nameplate voltage during accident conditions. The licensee issued a
PlF and agreed this matter should be reviewed.
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l The team also noted that the battery service test procedures QCTS 0240-04 and QCTS 0230-01 had a requirement to tighten the inter-cell connectors if it was determined that the connector did not meet the acceptance criteria. The team considered this practice to be a form of pre-conditioning prior to the start of the battery discharge test. Although the l
procedures allowed that the connectors be tightened, the team did not find instances
where the connectors were tightened prior to any of the recent discharge tests. The licensee corrected this procedural weakness. The team also noted that these j
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procedures contained acceptance criteria that appeared ambiguous. Although sections of the procedure required that inter-cell resistance be taken, the licensee's TSs required a visual inspection or that the resistance be less than 150 micro-ohms or that the value
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be within 20 percent of the baseline reading, whichever is greater. The concem was that two of the options were less conservative than the other option, namely a visual inspection could be implemented or that the inter-cell resistance could exceed 150 micro-ohm value but would still be acceptable per TS. The licensee agreed to enhance
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the battery testing procedures to correct the pre-conditioning issue.
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Conclusions
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Overall, the team concluded that the surveillance results reviewed were within the required acceptance criteria; however, the battery charger test procedure QCTS 0210-02 was weak in that it did not require that voltage data be taken during the four-hour discharge test. Service battery procedures QCTS 0240-04 and QCTS 0230-01 contained operator actions that could potentially constitute pre-conditioning of the test. The team considered licensee's systematic approach to locating DC grounds to be a strength.
E6 Engineering Organization and Administration E6.1 Strateaic Reform initiative Review l
a.
Insosction Scope (IP 40500)
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l The team reviewed the implementation of the following strategic reform initiatives:
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NGG-3, Action Step 8:
Implement the System Health indicator Program.
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NGG-8, Action Step 3:
Define and issue common procedures for the IST,
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inservice Inspection, Maintenance Rule, Appendix R, and Generic Letter 89-13 programs.
NGG-8, Action Step 4:
Implement the engineering work management
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system.
NGG-13, Action Step 1:
Assess effectiveness of the Safety Review Board,
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Plant Onsite Review Committee, and departmental self-assessment processes. Also assess the effectiveness of other programs such as the Corrective Action Process and OPEX.
NGG-13, Action Step 4:
Implement a generic lessons-learned process.
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b.
Observations and Findinas The team reviewed the strategic reform initiatives identified above with cognizant licensee personnel and verified that the action steps were being implemented. No deficiencies were identified, c.
Conclusions The team concluded that the licensee had made adequate progress in the implementation of selected strategic reform initiatives.
E7 Quality Assurance in Engineering Activities E7.1 General Comments The team reviewed the licensee's assessment activities to evaluate the effectiveness of licensee controls in identifying, resolving, and preventing issues that degrade the quality of plant operations or safety. These controls included the corrective action and self-assessment programs, implementation of timely and effective resolution of technical issues, active involvement in ensuring the reliability of plant systems, and awareness of industry events and how they impact the plant.
The team selected a sample of issues / problems for detailed analysis to assess the licensee's ability to identify and correct problems. Additionally, the team evaluated the process for initial identification and characterization of the specific problems, elevation of the problems to proper levels of management for resolution, disposition of any operability /reportability issues and implementation of corrective actions, including evaluation of repetitive conditions. Items reviewed included:
(1)
Deficiencies requiring safety evaluations, root cause assessments or operability determinations.
(2)
QA audits and self-assessments.
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. Deficiencies tracked in the corrective action programs, including the evaluation of (
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deferred items, or interim resolutions.
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Results of licensee audits that evaluated the effectiveness of the associated corrective action programs.
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Interviews with seleAed individuals involved with the problem identification process to determbe the extent of the individual's understanding of the process 4-l and willingness to report problems.
a Documents reviewed are listed at the back of this report.
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E7.2 Corrective Action Process
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- Insoection Scoce (40500)
The team assessed the Corrective Action Process (CAP) through review of implementing
procedures, problem identification forms (PlFs), corrective action management reports,
corrective action effectiveness reviews, Corrective Action Review Board (CARB) and
- Condition Review Group (CRG) activities, and action taken for previously identified trends. Documents reviewed are listed at the end of this report. The team reviewed the corrective action process including implementing procedures as well as ten selected PIFs for adequate problem identification and the adequacy and priority of proposed
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. actions planned or completed. The team discussed the corrective action process with
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cognizant licensee personnel and also attended two CARB meetings.
b.
Observations and Findinos The team reviewed Procedures NSP-AP-1004, * Correction Action Program Process,"
Revision 1, NSP-AP-2004," Correction Action Program Process Roles and Responsibilities," Revision 1 and NSP-AP-4004," Correction Action Program Procedure,"
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Revision 0. These procedures described the methods used and the responsibilities for identifying and correcting problems. A PlF was the primary method used to document identified problems.
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After initiation, PlFs were routed to an Events Screening Committee (ESC) where the problem was evaluated and actions assigned as needed. Immediate actions were scheduled and taken. Priorities were usually established by the responsible system engineer. If a root cause investigation was required, then a root cause committee was I
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usually assigned for cause investigation and determination of proposed corrective actions. The issue was then brought to the CARB where the investigation results were reviewed, additional recommendations were considered and concurrence was provided on the actions to be taken.
The team attended two CARB meetings. The board thoroughly discussed the issues.
Appropriate questions were asked and answered. The issues were presented by a knowledgeable individual who adequately responded to board questions. After CARB
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approval appropriate actions were authorized to correct the problems and prevent problem recurrence, c.
Conclusions Based on the inspection results, the inspectors concluded that the corrective action methods in place at QCNP were good and, in most cases, were effective in addressing corrective action issues.- The Events Screening Committee and the Corrective Action Review Board functioned well and actions were thorough and effective.
- E7.3 PlF Initiation and Threshold for Writina PlFs a.
Insoection Scooe (40500)
The team interviewed individuals from several different departments to determine how the corrective action process was functioning during the initiation of PlFs b.^
Observations and Findinas Last year, computers were used for the first time to write PlFs. The team found that for the people who wrote PIFs on the computer, the system worked well. Once the PIFs were written, their immediate supervisor was required to review the PlF before it was entered in the system. This review did not appear to inhibit the writing of PIFs.
v However, of the 12 non-management individuals interviewed, only five had written as least one PlF in the calendar year.
The initiating of PlFs by non-management personnel appeared low and the team found three contributing factors which contributed to the low participation rate.
Some individuals appeared to be intimidated by using a computer to write PlFs.
- Individuals indicated they had received training last year but felt they would have trouble if they had to use the computer entry system. One individual indicated that he had initiated a PlF this year on a paper form, which was still a viable attemative. Several individuals stated that they took issues to their supervisor to let them write the PlFs, thereby circumventing the computer system.
l While some individuals knew when a PIF should be initiated, several individuals
did not appear to understand management's expectations on when a PlF should
be written. Radiation protection personnel had clear examples provided by
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management of when a PlF should be initiated. Electrical maintenance stated
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that surveillance procedures delineated what circumstances required a PIF to be l
written. Operations knew that the initiation of an action request on maintenance rule equipment required a PlF to be written. However, some individuals indicated that they typically took suspect issues to their supervisor and let the supervisor determine if a PlF should be written. They would then rely on the supervisor to write the PlF. These individuals had various thresholds for when they would
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bring an issue to their supervisor since they had not been provided with clear expectations.
The team found several individuals that did not support the corrective action
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process. They felt the process was punitive and refused to write or bring issues to their supervisors. The team was informed by one individual that he had found copies of PlFs in his personnel file. The individual had nel been informed that the PIFs were in his file and in two cases, was not even aware of issues described in the PIFs. He further did not know what effect the PlFs would have on him.
Licensee senior management was not aware that PIFs had been placed in personnel files. In the specific example, the PIFs in the personnel folder were over 4 years old. In response to the team concems, the licensee Human Resources Organization reviewed more than 400 personnel files and discovered that approximately 18 of the files contained copies of PlFs. The team was told that this practice would be discontinued and that all personnel files would be reviewed and any PlFs found in the files would be removed, in addition, supervisors were instructed to discuss this issue with their staff and notify them that the practice had been discontinued. The team was provided with an intemal memo to plant supervisors stating that the practice was to be discontinued.
Conclusions l
Management expectation for PlF initiation was not being met by some staff members.
L The use of computers to initiate PlFs contributed to some individuals not generating l
PIFs. Other individuals did not have a clear understanding of management expectations i
of when a PlF should be written. Severalindividuals were concemed with punitive actions that resulted from PIFs and did not support the process; however, this did i
not appear to impact the overall effectiveness of the corrective action process. The licensee corrective acthns for this issue were prompt and comprehensive.
E7.4 Individual Feedback to PlFs and Feedback on Industry issues a.
Inspection Scooe (40500)
The team interviewed individuals to determine what type of feedback they received on PlFs and how they were informed of industry events that related to their work activities.
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Observations and Findinas in 1998, the licensee started providing formal feedback to the initiators of PIFs. The interviewed individuals who had written PIFs this year, stated they received direct feedback when a PIF was initiated and when the corrective action was determined. In those cases, the individuals felt the responses to the issues were appropriate. Those l
l individuals further indicated that the corrective action process was a useful method for l
solving problems.
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-Most of the individuals interviewed indicated that all PIFs associated with their activities were discussed in daily or weekly meetings. The individuals indicated that the meetings helped increase their awareness of potential problems and prevent similar problems. A few individuals who specifically stated they did not support the corrective action process, also indicated that general feedback of relevant PlFs was not consistent. Some PlFs
- were discussed and oth3rs were never mentioned.
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events were routinely addressed in daily or weekly meetings. In additions, the station's daily news letter addressed events at other sites. Radiation protection personnel specifically pointed out that management encouraged discussions of relevant PIFs and outside events to improve the departments performance.
c.
Conclusions For personnel involved in writing PlFs, sp3cific feedback provided to individuals encouraged the corrective action process. In addition, the general feedback of PIFs and industry events to work groups appeared to heighten the groups awareness of potential problems and how to avoid them.
E7.5 Corrective Actions Associated With Emeroency Diesel Generators (EDG)
a.
Insoection Scope (40500)
The team reviewed PlFs associated with the emergency diesel generators and questioned the system engineer on the status of those issues.
b.
Observations and Findin_gg 1.
In 1994, the % EDG tripped on high crankcase pressure. The engine crankcase was designed to operate at a vacuum and positive pressure could cause a crankcase explosion and substantial damage to the engine. The problem was believed to have been caused by oil splashing onto the diaphragm of the crankcase vacuum switch, thus causing an inadvertent trip. Corrective actions included the installation of a crankcase vacuum monitoring instrument. Since that time, the EDG was overhauled and a manometer was used to verify the engine crankcase operated at a vacuum.
On July 7,1998, the % EDG crankcase pressure was noted to reach 4.5 inches
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' of water as read on the vacuum monitoring instrument. The issue was documented in a PlF and the system engineer was informed. An action request was written to check the instrument calibration and to take actions based on the results. When the team questioned the system engineer, the engineer did not know the status of the instrument calibration check. He assumed that the crankcase pressure was acceptable since the EDG had not tripped on over-pressure. This belief was based on the fact that the site had never frand a pressure trip switch out of calibration. The trip switch normally actuated
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between 1 to 2 inches of water. No attempt was made to use a manometer to verify the acceptability of the crankcase pressure.
A work request was generated to perform the calibration check and scheduled to be worked the next available maintenance window. However, scheduling conflicts interfered and as of October 28, the instrument had not been calibrated.
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Following the team's questions, the priority of the calibration check was raised.
On an October 10,1998, test of the % diesel a manometer was used to monitor the EDG crankcase pressure and the pressure remained at a negative two inches of water throughout the two hour run. Although there was no longer a concem about excessive crankcase pressure, the concem with proper priorities and timely corrective action on possible problems on important equipment continued to exist.
The inaccurate gauge had not been calibrated and, after the diesel run, the priority on the PIF, which was written on the problem, was returned to a
"C" priority from the "B" priority assigned when the team expressed concem.
Licensee personnel stated that the gauge had been installed to trend crankcase pressure and that the crankcase pressure trip set-point was reliable and was checked periodically during scheduled surveillances. Licensee personnel agreed that the gauge was not providing usefulinformation for trending and did raise questions as to the actual crankcase pressure. They agreed that action on the gauge calibration issue was untimely and that this issue had been discussed with appropriate personnel.
2.
In a second example, the Unit 1 EDG fuel oil had approached the water and sediment limit of 0.05%. The sample had been 0.02% water and 0.02% sediment resulting in a combined value of 0.04%. The problem was identified on September 2,1998, and sampling had been increased to every two weeks. Two previous PlFs and three previous action requests were written addressing this concern. The earliest dating back to April 1996.
The fuel oil tank was a buried fiberglass tank and the licensee believed that the water and sediment were entering the tank at a transition piece near the refuel pipe. The evaluation was based on the fact that the sediment was non-metallic and therefore had to be entering the tank rather than a problem with corrosion within the fuel system. A manway cover was not properly sealing over the access area and standing water was found around the refuel pipe. The first replacement cover did not fit and a second cover was ordered.
When the system engineer was questioned on October 22, he stated that he knew the cover was in place that day as he had just observed it before the interview. He could not provide the date it had been installed. The team questioned why the engineer would not have followed the issue closer. Following installation of the cover and verifying no standing water remained, fuel samples
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could confirm that the problem $ ad at least stabilized and therefore the intrusion point had been found. The work package had been closed on October 10,1998.
PIF Q1998-03878 was generated to document excessive water and sediment in the September fuel oil sample for the U-1 EDG Fuel Oil Tank. Water was thought to possibly be entering through a broken fiberglass cover. The cover was repaired and water and sediment were removed from the tank. An action plan was developed to address other possible sources of sediment and water. This plan required biweekly monitoring for water and sediment. If the problem continued then the corrective action plan would require continued increased monitoring and possible tank entry in the future. Planned actions were adequate.
c.
Conclusions The % EDG crankcase over pressure indication issue and elevated water and sediment concentrations in the Unit 1 EDG fuel oil tank both posed potential problems for the EDGs. Tracking and prioritizing these issues until some level of resolution was verified appeared weak.
E7.6 Plant Operations Review Committee a.
inspection Scope The team reviewed the implementing procedures and records for the PORC. T' team discussed the PORC functions, findings and actions with cognizant licensee personnel and attended two scheduled PORC meetings.
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Observations and Findinas The team reviewed Procedure NSP-AP-1002, " Plant Operations Review Committee,"
Revision 1. ' No problems were noted with the procedure.
The team attended two PORC meetings and reviewed the ten packages presented at the meetings. Packages were well prepared and well presented. Eight of the packages were approved by the committee and the other two packages were sent back for changes. The PORC meetings were good and presented items were thoroughly j
discussed.
c.
Conclusion The PORC was functioning well. Reviews of items were thorough and additional corrective actions were required prior to committee approval for rejected packages.
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' E7.7 Plant Off-Site Review Committee a.
Inspection Scooe The team reviewed the implementing procedures and selected records for the off-site review committee. The team discussed the committee functions, findings and actions with cognizant licensee personnel, b.
Observations and Findinas The off-site review function, required by the Comed Topical Report, had changed several times in the recent past and was expected to change again in the near future.
Until April,1998, off-site reviews were conducted by the Comed corporate organization in Downers Grove. In April, responsibility for off-site reviews was transferred to the Nuclear Oversight Group, which was physically located at the plant. This group reported to the Site Nuclear Oversight Manager who reported to Comed corporate management in Downers Grove. The team reviewed the controlling procedure, NO-16, " Conduct of Off-Site Review,:" Revision 9, which was issued for use on August 6,1998, and considered the procedure adequate for good control.
Off-site Review Committee records, reviewed by the team, included two quarterly trend reports for the fourth quarter of 1996 and the first quarter of 1997 and monthly reports of off-site review activities from May 1997 to April 1998. The team noted that the monthly off-site review reports not only summarized the items reviewed by the committee but also documented problems and concems identified during the reviews. This review and documentation of problems and concerns appeared to be good, however, the team noted that the monthly reports had been discontinued and that the procedure no longer required these reports.
Licensee personnel stated that, in the near future, the off-site review function would be performed by a newly developed Nuclear Safety Review Board utilizing rc:edure NSP-RA-3001, " Conduct of the Nuclear Safety Review Board." The team reviewed Revision 0 of this procedure, which was dated September 14,1998. No problems were noted with the procedure.
c.
Conclusion
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The team concluded that previous reviews, as evidenced in the off-site review committee quarterly trend reports and monthly committee review reports, indicated good performance by off-site review in the identification of problems, weaknesses and trends.
However, since the quarterly trend reports and the monthly committee review reports had been discontinued since April,1998, the team was ur..me to assess current performance.
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E7.8 Internal Audits and Assessments by Nuclear Oversiaht a.
inspection Scoce The team reviewed the implementing procedures used by the Nuclear Oversight (NO)
Department in performing internal audits and assessments of plant activities. The activities were discussed with cognizant licensee personnel within the department. In addition, selected intemal audits and assessment records were reviewed.
b.
Observations and Findinas Audit and assessments conducted at the plant usually were conducted on Quad Cities activities only. In some cases, however, combined audits or assessments of the Comed nuclear plants were conducted by the corporate oversight organization and a combined report was issued. In these cases, the team's reviews were limited to items related to the Quad Cities specific information. Problems were usually identified during the audits and findings or PlFs were written and issued. Actions were then taken through the
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normal corrective action process. Audit and assessments conducted by the Nuclear Oversight Organization were usually thorough and well performed. Significancy issues were being identified and corrected in a timely manner.
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Conclusion The audit and assessment program was acceptable. The audit and assessments conducted by NO appeared to be effective in identifying and correcting significant issues.
E7.9 System Health Indicator Proaram a.
Inspection Scoce The team reviewed the System Health Indicator Program (SHIP), including the controlling documents, the reporting process and selected SHIP reports. The information reviewed and the reporting process were discussed with cognizant licensee personnel.
b.
Observations and Findinas The process was described in Nuclear Engineering Standard (NES) G-07, " System Health Indicator Program (SHIP)," Revision 3. This was a corporate engineering standard and was required for all operating Comed nuclear plants. The program was applied to all systems scoped within the maintenance rule and was a measurement of the general effectiveness of plant systems. Each system was evaluated overall and in six different areas with the results presented in a colored pictorial form. The systems were evaluated for Performance, Physical Condition, Derating, Work Backlog, Operator Workarounds and Design. Input information was provided by assigr,ed systems engineers. Since the systems evaluated were not always of the same complexity and size, some additional considerations were made. The standard allowed the System
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Engineering Supervisor to override a color in order to more accurately reflect the state or
status of a system.
The team reviewed monthly SHIP reports for August and September of 1998. One hundred twenty nine systems were listed with a summary listing for all systems. In i-addition a SHIP trend graph for the color designators for the past five months was
included. Since the results presented in the report utilized colors, problem areas and j
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good areas for the systems could be easily identified.
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- Conclusion i
The System Health Indicator Program was an excellent assessment process for
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evaluating system status and identifying problem areas to management. The reports were informative and provided good information to management on the status and availability of plant systems and components.
E8
. Miscellaneous Engineering issues
E8.1 (Closed) Inspection Follow-uo item (IFI) 50-254-93004-02: Follow-up on Safety-Related Contact Test Program. The initial concern was that not all safety-related contacts were i
being tested during technical specification required surveillance tests. The licensee undertook a program to ensure that all safety-related contacts were completely tested.
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NRC evaluated the program as being adequate in the 1993 inspection report, but opened the IFl in order to track its completion. The team verified that the contact test program was completed in December 1993. This item is closed.
E8.2 (Closed) IFl 50-254-93024-01: 50-265-93024-01: Time Delay Relay Affected Fast Transfer. A time delay relay in the circuit between the reserve auxiliary transfonner and the unit auxiliary transformer delayed the fast transfer for 1.2 seconds, resulting in power t
being lost to a number of minor loads. The IFl was opened for the licensee to evaluate whether the relay should be removed. Engineering personnel completed the evaluation
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the windings on large motois. The licensee stated that protection of the large motors
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was significantly more important than having to restart minor loads which lost power, The team also learned that several fast transfers had occurred since this IFl was written,
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E8.3 (Closed)IFl 50-254-94004-40:50-265-94004-40: Equipment Vibration Concerns. This item discussed the diagnostic inspection team's (DET) concems regarding equipment vibration. Two systems experiencing extreme vibration were the RHR system and the RHRSW system. The licensee replaced impellers on the RHRSW pumps and added ll anti-cavitation trim to flow control valves in both systems. Anti-cavitation trim was also added to the core spray (CS) flow control valves. These actions considerably reduced the system vibrations. Inspection Report 50-254/265-94004 also discussed excessive vibration in the CS system. The licensee replaced the flow control valve internals with anti-cavitation trim internals and removed the downstream flow limiters. This resolved
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the vibtation problems in this system. The team concluded that the licensee's actions were adequate to resolve the DETs concerns. This item is closed.
E8.4 (Closed) IFl 50-254-94004-46: 50-265-94004-46: Operability Evaluation for RHR Spring Cans. The DET identified that no operability evaluation was performed for four RHR spring cans which were found to be out-of-tolerance in 1992, in response to this issue, the licensee evaluated the RHR spring cans and added some adjustable spring cans to provide better control of RHR system vibration. In conjunction with the other actions on this system, described in E8.3 above, this significantly reduced the system vibration.
The team concluded that the licensee's actions were adequate to resolve the DETs concems. This item is closed.
E8.5 (Closed) IFl 50-254-94004-50: 50-265-94004-@: Vulnerability Assessment Team (VAT)/ Systematic Evaluation Program (SEP) Items. The DET noted that the licensee had not completed all actions associated with the VAT or the SEP. This item was opened to track closure of the remaining items. At the time of this inspection, only the VAT concem and eight SFP items remained open. These items are discussed individually below. As all of the individual items are closed, the overall tracking item is closed.
a.
VAT Issues: The VAT issues remaining open at the time of the DET were mainly material condition issues. Over the last few the years, the licensee has made strides in improving the overall material condition of the plant. At the time of this inspection, four VAT items remained open, and were being tracked in the licensee's nuclear tracking system (NTS.) These were: reactor feed pump low suction trip logic (NTS 254123961308), PCB transformer replacements (25420196228601.02),
Generic Letter 96-01 contact testing (2541049600102) and fuse control program improvements (2541009601003). The first item is a plant improvement. The feedwater system was in the maintenance rule A-1 category; however, the low suction trip logic did not appear to be a contributor to the problems. The second issue is an environmental rather than a nuclear safety concem. The last two are ongoing programs which are being worked on a risk-significant priority basis. The fuse control program is also
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discussed in item E8.14. The team concluded that sufficient progress had been made, with the remaining items being tracked in the licensee's corrective action program, such that the issue could be closed.
b.
SEP issue V-10.B: RHR Reliability b.1 Systematic Evaluation Proaram (SEP) Item 8. SEP Topic V-10.B. RHR Reliability -
Ensure procedures creclude carallelina of 125 and 250 Vdc. related to Safe Shutdown Analysis SEP ltem 13. SEP Topic Vll-3. Systems reauired for safe shutdown b.2 SEP issue Vil-3: Systems Required for Shutdown.
Because construction licensing basis documents minimally addressed safe shutdown, Quad Cities developed these SEP issues for additional review of the systems that would
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allow a plant safe shutdown. The team reviewed these two related SEP issues that asussed RHR reliability thmugh the adequacy of procedures to prevent paralleling the 125 Vdc system and the 250 Vdc system and the systems for safe shutdown used within
- 10 CFR 50, Appendix R design basis accidents. Areas of concern for the second topic were procedural restriction against paralleling the 125 Vdc system and the 250 Vdc system and procedural controls for the Normal-Normal alignment for emergency diesel gene.'ator (EDG) Normal / Bypass switches. The team reviewed the licensee's actions to assure procedural controis reduced single failure vulnerability. Based on reviews of the licensee's actions, procedures and discussions with cognizant licensee personnel, the team concluded that adequate controls were in place and the licensee had adequately addressed these two related issues. NRC reviews of SEP ltems 8 & 13, Topic ill-8.C and Vll-3, respectively, are considered closed.
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SEP issue VI-4: Control of Containm6ot isolation Test Connections. The original SEP ltem questioned the administrative controls applied to containment capped branch lines, test connections and veat lines. The licensee performed an analysis and determined that the existing administrative controls were sufficient. The team reviewed several local leak rate test procedures and walked down a representative sample of test connections and vent lines to confirm that the lines were isolated. In all cases the test connections had a minimum of two isolation barriers. The team concluded that the licensee's administrative controls were sufficient to ensure that the lines would be properly isolated.
This item is closed.
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SEP ltem 10. SEP Topic VI-7.C.1. Aooendix K - Electrical. Instrumentation and Control Reviews The team reviewed the Quad Cities actions addressing the Appendix K issue concerning single failure reviews for electrical, instrumentation and control systems. Electrical coordination related to 125 Vde,250 Vdc and 120 volts altemating current (Vac) systems was an issue of concem. For 125 Vdc system the licensee added fuses for improvement in coordination. Additionally, the licensee developed procedures to use manual action on breakers to compensate since the licensee no longer could take credit for 125 Vdc electrical control actuation under presently defined analytical methods for Appendix R accident conditions. Although they did not reach full coordination for the 250 Vdc system, the licensee reviewed calculation 8256-56-19-1, Revision 2, dated 9/28/93, and found that the circuit breakers installed in the 250 Vdc buses have adequate interrupting capability. The calculation review accounted for additional resistance from the thermal overload heater. In the 120 Vac system textbook they could not reach coordination because the vulnerability was a postulated instantaneous fault at the terminals of the breaker; however, the more probable fault location would allow credit for cable impedance and the lowered current allowed existing coordination to function. Because the licensee did not achieve complete coordination at these lower level voltages, they evaluated power source reliability from coordination at higher level electrical systems.
The licensee study (SL-4501, volume 1) showed the 4.16 kV safety-related bus
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coordination was adequate. All safety related 480 Vac breakers now have RMS-9 trip devices providing improved coordination at that level. The licensee developed a fuse coordination improvement plan that included an improved fuse list, an improved fuse
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control procedure and verification walkdowns. Procedural controls reduced the implications of an uncoordinated protection level propagating to unwanted areas of the electrical system through a potential path through tie breakers 1819 and 1918 for unit one and 2829 and 2928 for unit two. Basea on the review of the licensee's actions, procedures and discussions with cognizant licensee personnel, the team concluded that the licensee had adequately addressed this issue. NRC review of SEP ltem 10, Topic VI-7.C.1 is considered closed.
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SEP ltem 11. SEP Tooic VI-10.B. Shared ESF. Onsite Emeraency Power and Service Systems for multiole unit stations The team reviewed issues conceming potential vulnerabilities for shared engineered safety features (ESF), On-Site Emergency Power and service systems for multiple unit stations. The recommended actions were to address possible parallelin0 of batteries, EDG switch lineup, battery charger performance, fuel oil system, and EDG loading capacity. The station procedures had adequate controls to preclude paralleling batteries in the 125 Vdc system and the 250 Vdc system. The station procedures controlled the normal-normal alignment of the shared (1/2) EDG. Replacing the 250 Vdc chargers under modification M04-1-82-049 had addressed potential performance deficiencies in the battery chargers. The EDG fuel oil system previously had been reviewed and was found to be adequately sized and the EDG loading calculation showed adequate capacity. The team reviewed these actions to satisfy the SEP topic concerns and concluded that the licensee had adequately addressed this issue. NRC review of SEP ltem 11, Topic VI-10.B is considered closed.
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SEP ltem 12. SEP Tooic Vll-1.A. Isolation of RPS from non-safety related systems The team reviewed isolation issues relating to the adequacy of the Design Basis of the Startup Range Neutron Monitoring System designed to comply with Institute of Electrical and Electronic Engineers (IEEE) Std 279-1968, not the later issued IEEE Std 279-1971.
Although the Yokagawa recorders are not class 1E devices, the recorders used a photocoupler input stage that increased the isolation significantly from that of the original recorder. Licensee analysis concluded that isolation was sufficiently high for assurance that the neutron monitoring protective functions would still function. The team reviewed these actions and the analysis and concluded that the licensee had adequately addressed this issue. NRC review of SEP ltem 12, Topic Vll-1.A is considered closed.
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SEP issue Vill-2: Onsite Emergency Power (Emergency Diesel Generators (EDGs)).
The SEP concem was on the reliability of the EDGs, due to Quad Cities having one bank of air start motors, compared to the industry norm of two banks. The licensee evaluated this item, and decided that the improvement in reliability did not justify the cost adding additional air start motors. The team acknowledged that there was not any regulatory requirement, at the time that Quad Cities was licensed, to have two banks of motors.
However, the team noted that air start motor failures had contributed to past EDG reliability concerns (see inspection reports 50-254/265-96020 and 50-254/265-97010).
The team also noted that the EDGs were currently in the maintenance rule A-1 category for availability. Being in the A-1 category required the licensee to have an action plan to l
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improve performance; at the time of the inspection, the licensee's plan was to decrease the maintenance rule availability requirement from 98 to 96 percent. A maintenance rule l
team reviewed the proposed plan and concluded that it was acceptable, based on the licensee's commitments. Additionally, the licensee had performed testing at the vendor's that proved that one bank of air start motors would start the diesels with both air start
' motors abutted. The licensee was considering a modification to monitor air start motor performance more exactly, to determine the precise effect the motors had on EDG reliability. Inspection follow-up item 50-254/265-96020-04 remains open and will l
continue to monitor the larger issue of EDG performance; however, this SEP item is closed.
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SEP ltem 15. SEP Tocic Vill-3.B. DC Power System Bus Voltaae
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The team reviewed the adequacy of the original design of DC power systems relating to
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l Control Room alarms and indications. The original design generally met, but was not completely in conformance with IEEE Std 308-1974, issued after the Quad Cities units were in operation. Quad Cities design did not include some alarms and indications recommended under the later IEEE Std. Control Room alarms and indications of concem were a battery high discharge rate alarm for all de systems and having indication when the 24/48 Vdc systems battery breakers were open. The licensee
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initially considered modifications that would provide an annunciator alarm for high discharge current and use breakers with auxiliary contacts to show a breaker open condition. After further review the licensee concluded that indirectly existing i
instrumentation can monitor discharge current (e.g., undervoltage alarms for de bus circuits and battery charger trouble, battery voltage for 125 Vdc and 250 Vdc systems).
The undervoltage alarms for de bus circuits indirectly detected breaker position. The i
team concluded that the licensee had adequately addressed this issue. NRC review of SEP Topic Vill-4 is considered closed.
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SEP ltem 16. SEP Topic Vill-4. Electrical Penetrations of Rx Containment The team reviewed the adequacy of the overload device for the low voltago electrical penetrations. The licensee evaluation determined that the ups' eam molded case J
breaker provided protection for faults above 600 amperes. Quad Cities could only take l
credit for faults below 200 amperes for the thermal overload relay providing protection because the manufacturer's characteristics curve only provided information up to 200 amperes. The licensee performed further analysis and testing for primary protection for currents between 200A and 600A and for the following reasons the low voltage penetratior.was adequate to perform its intended function. Dresden station performed testing on a similar electrical penetration and the General Electric (GE) thermal overload relays within the time constraints of the thermallimits provided the overload protection over the range of 200A to 600A of the low voltage electrical penetrations (CHRON
- 0300252). Additionally, the Coax low voltage power electric penetration assemblies were purchased qualified to the requirements and objectives of IEEE Std. 317-1983 as documented in environmental qualificatior binder EQ-680. The team had no further l
concems and concluded that the licensee had adequately addressed this issue. NRC
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review of S'EP Topic Vill-4 is considered cloced.
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E8.6 (Closed) IFl 50-254-95004-03:50-265-95004-03: Axial Thrust Measurements on Vertical Pump Motors. The issue involved the licensee not including axial thrust measurements in the inservice testing program, as required by OMa-1988, Section 4.6.4.
The licensee incorporated the axial thrust measurements into the inservice testing program and revised the surveillance procedures to specify appropriate acceptance criteria for the measurements. The team confirmed that the appropriate procedures were revised. This item is closed.
E8.7 (Closed) IFl 50-254-95005-09:50-265-95005-09: Electrical Load Monitoring System
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(ELMS) Update. As part of the corrective actions to a 1994 violation, the licensee committed to implement a program to rebaseline ELMS and redo the degraded voltage
relay reset calculation. This program was originally scheduled to be completed in 1996; however, it was delayed for a number of reasons. The licensee stated that all required data had been collected, and that analysis of the data, revision of ELMS, and completion of the calculation should occur by mid 1999. This item is currently being tracked by the licensee's nuclear tracking system, item number 254-100-02001.06.01. Based on being captured by the licensee's corrective action system, this item is closed.
E8.8 (Closed) VIO 50-254-95007-04: 50-265-95007-04: Failure to Assure that Adequate Test Instrumentation Was Used. The concem was that the test instrumentation being used did not have an accuracy equivalent to that assumed in the instrument setpoint i
calculations. In response, the licensee reviewed the surveillance procedures against the calculations to ensure that the violation would not recur. The surveillance procedures were revised to specify the test instruments which could be used during the surveillance and which would satisfy the setpoint calculation requirements. The team verified that the j
surveillance procedures properly specified accuracy of the test instruments to ensure the
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design basis was maintained. The licensee chose to specify specific instruments as having adequate accuracy bands. The cognizant engineer noted that in early 1998 a review was done of the setpoint calculations against the surveillance procedures and existing test instrumentation. This review confirmed that the test instrumentation in use met the accuracy requirements used in the calculations. This item is closed.
E8.9 (Closed) LER 50-265-95003-00 (IFS Trackina Number 95-271): Shutdown Cooling Not Available Because Valve Tripped on Overcurrent. The event occurred because the shutdown cooling isolation valve had a " continuously closed" signal present. When the valve was manually opened, the close signal tried to reclose it, causing an overcurrent trip. The licensee revised the procedure for initiating shutdown cooling to ensure that the isolation valves had all previous isolation signals reset prior to opening the valves. The team verified that the corrective actions were taken. This item is closed.
l E8.10 (Closed) Unresolved item (URI) 50-254-96008-12: 50-265-96008-12: High Pressure injection Keep Fill Line Qualification. The team confirmed that the keep fill line had been seismically qualified and that a check valve was installed. This resolved the concern and l
the item is closed.
E8.11 (Closed) URI 50-254-96008-13:50-265-96008-13: Technical issues Related to Previous Escalated Enforcement Actions. This URI discussed a number of instances where the
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licensee discovered that the plant did not comply with the updated safety analysis report.
Although these would be further examples of a an earlier escalated violation (EA 96-114)
of 10 CFR Part 50, Appendix B, Criterion ill, " Design Control," the licensee identified the problems as part of its corrective actions to the escalated actions and took immediate actions to correct each problem, along with the programmatic actions to prevent recurrence of the overallissue. Therefore, in accordance with the enforcement policy, NUREG-1600, Revision 1, Section Vll.B.4, no violation will be cited.
i (50-254/98019-02(DRS); 50-265/98019-02(DRS)). The unresolved item is closed.
E8.12 (Closed) Violation (VIO) 50-254-96010-02: 50-265-96010-02: Failure to Follow Temporary Alteration and Root Cause Evaluation Procedures. The temporary alteration
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and root cause evaluation programs were evaluated during this inspection (see Section E1.3) and were found to be acceptable. The specific issues were corrected.
This violation is closed.
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E8.13 (Closed) IFl 50-254-96010-03: 50-265-96010-03: Fuse Control Prot. ems. This item was opened to track the few remaining fuse walkdowns that remained to be completed (from a 1991 open item). The team discussed the status of the fuse control program with the cognizant engineer and determined that, although the walkdowns were not 100 percent completed, sufficient controls were in place to ensure that fuse
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replacements were handled in accordance with the fuse control program. This item is closed.
E8.14 (Closed) IFl 50-254-96010-04: 50-265-96010-04: Breaker Coordination Modifications.
This item was opened because the licensee canceled the breaker coordination modifications which were credited in the 1994 closure of a 1991 unresolved item. Full breaker coordination was achieved only for the 250 Vdc loads. For the 120 Vac and 125 Vdc loads, the licensee evaluated the breaker coordination issues and determined that
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further changes would not be cost effective. The teum reviewed the status of the 120 Vac and 125 Vdc breaker coordination and concluded that it was adequate to protect the
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safety function of the equipment involved. Breaker coordination concerns were also discussed during the system operational performance inspection, 50-254/265-97022 (see item E8.26.) This item is closed.
E8.15 (Closed) IFl 50-254-96010-05: 50-265-96010-05: Battery Temperature Operability Limits. This item was opened because the team were not able to review a calculation for the battery temperature limits during the 1996 inspection. The team determined that the item involved a one time letter which was retracted following the team's concerns.
Instead, corrective actions were taken to ensure that the batteries remained within the technical specification limits. This item is closed.
E8.16 (Closed) IFl 50-254-96010-06: 50-265-96010-06: Faulty Electrical Penetration Pressure
Gauge. This item was written regarding a problem with a non-safety-related gauge not being entered in the work control system. The licensee performed a two-way review of deficiency tags against the work contrcl system and identified a number of tags which were not in the system. Following verification of the work status, the tags were either removed or work control entries were made. This item is closed.
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E8.17 (Closed) IFl 50-254-96010-07: 50-265-96010-07: Vendor Document Control. This was I
written about GE service information letter (SIL) 448, which dealt with breaker inspections. The licensee disagreed with two of the three recommendations in the SIL regarding timing of preventive maintenance and refurbishment of breakers. The licensee performed an assessment of the breaker inspection and refurbishment schedule and determined that the frequency of breaker preventive maintenance was acceptable. The responsible engineer noted that the SIL requirements were very conservative and that the vendor was reconsidering some of the recommendations. The team had no further questions and this item is closed.
E8.18 (Closed) URI 50-254-96011-05: 50-265-96011-05: Reactor Water Cleanup Pipe Break Evaluation. The issue involved a generic problem with boiling water reactor 3's and 4's regarding isolation following a break in the reactor water cleanup piping. As an laterim solution, ~the licensee revised procedures to ensure that operators would take immediate action to isolate a break, should it occur. As a long term solution, the licensee planned to install a modification to provide automatic isolation on high temperatures using existing temperature detectors. The licensee committed to install the automatic isolation by the 15th refueling outage. The team confirmed that the interim procedures were in place and that the modification was scheduled to be installed on Unit 1 during the November 1998 refueling outage. Although the Unit 215th refueling outage schedule was not yet finalized, there was an open item tracking the need to install the modification during that outage. This item is closed.
E8.19 (Closed) VIO 50-254-97010-01: 50-265-97010-01: Design Change Process Not Used for Altemate Parts Replacements. This violation, along with the following two (E8.20 and 21) and LER 97005 (E8.29), discuss problems that occurred following replacement of the
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EDG air start motors with non-like-for-like parts. The licensee increased its requirements for engineering review of vendor information about part equivalencies, increased its emphasis on defining critical characteristics of parts and provided additional training as to engineering involvement w!'en parts problems are encountered. The team reviewed these corrective actions and discussed the issues with cognizant individuals. No additional concems were identified. This item is closed.
E8.20 (Closed) VIO 50-254-97010-02: 50-265-97010-02: Failure to Perform Adequate Testing After Part Changes. This issue was evaluated as part of VIO 50-254-97010-01; 50-265-97010-01, above. No additional concerns were identified. This item is closed.
E8.21 (Closed) VIO 50-254-97010-03: 50-265-97010-03: Inadequate Corrective Actions on Replacement Parts Program. This issue was evaluated as part of VIO 50-254-97010-01; 50-265-97010-01, above. No additional concems were identified. This item is closed.
E8.22 (Closed) URI 50-254-97017-03: 50-265-97017-03: Acceptability of Reliability-Availability Balance. The team reviewed the licensee's " Quad Cities Nuclear Generating Station Maintenance Rule Periodic Evaluation, Evaluation Period July 1,1996 to April 30,1998,"
dated June 25,1998. As part of their periodic evaluation, the licensee concluded that there was an imbalance between the number of systems categorized as (a)(1) due to reliability versus availability. The licensee attributed the imbalance to overly restrictive
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performance criteria and inadequate preventive maintenance. Most of the functions for which the licensee had identified as having overly restrictive performance criteria were not explicitly modeled in the plant's probabilistic risk assessment. At the time of this inspection, the licensee had revised performance criteria for one function, function Z7800-04 (non-safety related 480 volt breakers), to provide less stringent performance criteria. The team noted that the revised reliability criterion was based on probabilistic risk analysis reliability assumptions and determined that the criterion was acceptable.
With regard to preventive maintenance, the licensee had identified that the cause of slightly over half of the systems not performing up to expectations was due to inadequate preventive maintenance. The team verified that follow-up actions had been identified to address the inadequate preventive maintenance program. The team concluded that the licensee's periodic ussessment was thorough, correctly identified problem areas, and provided useful recommendations for improvement. This item is closed.
E8.23 (Closed) VIO 50-254-97022-01: 50-265-97022-01: Inaccurate Procedure Steps Prevented Rapid Opening of the High Pressure Coolant injection Steam isolation Valve.
The violation concemed NRC discovery of several errors in an operating procedure which would have prevented operators from performing a safety function in a timely manner. In response to the violation, the licensee revised the procedure to specify the correct panellocations. The team confirmed that the procedure was revised. This item is closed.
E8.24 (Closed) VIO 50-254-97022-03: 50-265-97022-03: Modification Failed to Incorporate Loss of Offsite Power Time Delay When Determining Valve Closure Time. The modification failed to incorporate the 10-second time delay that would occur on loss of offsite power into a modification, increasing the time taken to close the high pressure coolant injection outboard steam line isolation valve. The licensee's corrective actions locluded improvements to the modification process and verification that the design basis valve closure times were still met. Modifications were evaluated during this inspection and are discussed in Section E1.1. Based on this review and on the specific issue being acceptable, this item is closed.
E8.25 (Closed) URI 50-265-97022-05: Temporary Alteration Safety Evaluation Screening Did Not Evaluate All Modes of Operation. This unresolved item was similar to the above to issues. The particular temporary alteration was closed and the overall program was evaluated as being acceptable. This item is closed.
l E8.26 (Closed) VIO 50-254-97022-06: 50-265-97022-06: Failure to Follow 10 CFR 50.59 l
Procedure Regarding Report Submittals. The violation addressed a failure to include some safety evaluations in the annual report on safety evaluations sent to the NRC. In response, the licensee reevaluated its program and expanded the scope to capture all safety evaluations. Verification of the annual 50.59 submittal is evaluated during routine engineering inspections. This issue is also addressed in Section E.3.1. This item is i
closed.
E8.27 (Closed) IFl 50-254-97022-07: 50-265-97022-07-Licensee Corrective Actions to Ensure UFSAR Updating. The IFl was to review the licensee's progress in keeping the UFSAR
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updated. This programmatic review is evaluated during a routine engineering inspection.
Therefore, there is no need for the IFl. This item is closed.
l E8.28 (Closed) LER 050-254-96022-01 (IFS Trackina Number 97-124): "B" Control Room j
Emergency Ventilation System Unable to Maintain 1/8" dP. 'The team reviewed the j
revised LER against the original LER closure and determined that no additional follow-up j
was necessary. This item is closed.
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E8.29 (Closed LER 50-265-97005-00 and 01 (IFS Trackina Numbers97-295 and 98-099): Unit j
Two and Unit Half EDGs Declared Inoperable Due to Parts issue. This issue was j
evaluated as part of VIO 50-254-97010-01; 50-265-97010-01 (see Section E8.21). No
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additional concerns were identified during review of the LER. This LER is closed.
i E8.30 (Closed)VIO 50-254-98005-01: Work Package Prepared Prior to Design Approval. The l
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licensee changed the nuclear work request and modification procedures so that both had
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the same requirements for processing at-risk modification work. The requirements
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j included that design inputs be checked and a safety evaluation be performed, as a
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minimum, prior to the work request being written. The team concluded that sufficient
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50-254-98005. This item is closed.
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E8.31 (Closed) URI 50-254-98008-01: 50-265-98008-01: Operability of Standby Gas l
Treatment System Due to Wiring Error. The licensee performad a root cause evaluation
and determined that the wir!ng error could not result in any credible single failure which
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would disable both trains of standby gas treatment. The team reviewed the licensee's evaluation and had no further questions. This item is closed.
l E8.32 (Closed) LER 50-254-97030-00 and -01 (IFS Trackina Numbers98-055 and 98-166):
instrument Line Excess Flow Check Valve Testing. The licensee discovered that a 4'
check valve test was performed at less than the nominal pressure. In response, the valve was retested at the proper pressure, and the procedure was revised to prevent j
recurrence. The licensee also reviewed other check valve tests to ensure that the
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proper testing pressure was specified. The team reviewed the licensee's actions and i
considered them acceptable. This item is closed.
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E8.33 (Closed) LER 50-254-98006-00 and -01 (IFS Trackina Numbers98-092 and 98-260):
j Reactor Building Post Loss of Coolant Accident (LOCA) Temperatures Higher Than i
Values Assumed in the UFSAR. During a design basis review, the licensee discovered j
that the post accident reactor building temperature exceeded the UFSAR value. The
licensee immediately con'irmed that the environmental qualification of the equipment inside the reactor buildiry was not affected and confirmed that technical specification
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instrument setpoints wtste not exceeded. In addition, the licensee evaluated the thermal overloads, and installed new overloads where necessary. The UFSAR was revised to j-reflect the new values. As long term corrective actions, the licensee still had to revise
the individual environmental qualification binders and the individual setpoint calculations.
These were being tracked by NTS items 25418098SCAQ0000605 and j
254180098SCAQ0000606. This item is closed.
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E8.34 (Closed) LER 50-254-98007-00 (IFS Trackina Number 98-093): The Reactor Building Superstructure Not in Literal Compliance With UFSAR Description Pertaining to Class I Loading Combinations. The licensee issued this LER based on the USFAR description of Class I loading combinations not including infrequent loading conditions such as use of the reactor building crane concurrent with a seismic event. Following issuance of the LER, the licensee evaluated the event and determined that all stresses were within allowable limits. Therefore, the licensee retracted the LER. The team reviewed the licensee's conclusions and agreed with the retraction. This item is closed.
E8.35 (Closed) LER 50-254-98013-00 (IFS Trackina Number 98-164): Insufficient Clearance Between the Unit One CS Test Retum Valve and the Torus May Have Caused Interference During LOCA Condidons. The licensee evaluated the clearances and determined that, under certain combined LOCA and earthquake loadings, that a pad on the valve would contact the torus. The pad was removed and sufficient clearances verified to exist. The team had no concerns on this issue. The LER is closed.
E8.36 (Closed) LER 50-254-98012-00 and -01 (IFS Trackina Numbers98-165 and 98-259):
Leak in the Unit One Reactor Bottom Head Drain Line. The team reviewed Revision 0 and Revision 1 of LER 254/98-012 and PIF # Q1998-01033. These documents described the problem and the actions taken to correct the leak in the drain line as well as the cause investigation and corrective actions. The actions taken were adequate.
Based on these actions the team have no further concerns in this area and this item is closed.
E8.37 (Closed) URI 50-254-98201-02: 50-265-98201-02: LOCA Analysis input Errors. In preparation for the Architect Engineer (A/E) inspection, the licensee reviewed the input parameters for the Quad Cities LOCA analysis and identified three cases where the LOCA analysis did not properly reflect expected ECCS performance. In each case, a PIF was generated and entered into the corrective action system (01998-00606,00688, and 00695).
Operability determination checklists were processed for the PlFs and the combined effects of the ECCS performance issues were evaluated. The evaluation dete..T.md that, when credit was given for existing RHR and CS pump performance, which exceeded TS minimum performance, the existing limiting licensing basis LOCA analysis results were not adversely impacted; that is, peak cladding temperature would not increase. The evaluation also concluded that a different limiting break size, break location, or single failure would not result. Therefore, the LPCI and CS systems met their functional requirements and were operable. The team reviewed the operability determinations associated with the PiFs with acceptable results.
This non-repetitive, licensee identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy (50-254/98019-03(DRS); 50-265/98019-03(DRS)). The unresolved item is closed.
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E8.38 (Closed) URI 50-254-98201-04: 50-265-98201-04: RHR Heat Exchanger Capacity.
In 1993, GE notified Quad Cities that based on their latest analysis, the RHR heat exchangers were not capable of reraoving heat at the original design heat removal rate of 105 million BTU /hr with the current design fouling. The analysis gave a heat removal rate of 97.7 million BTU /hr which was a 6.9% reduction. Based on this new hed removal rate, the two heat exchangers which had marginally passed their last test per the l
GL89-13 test program would now be considered to have failed their last test.
At the March 27,1998, exit meeting for the A/E inspection, the plant committed to the following: 1) Resolve the questionable RHR heat exchanger capacity by establishing communication with the current holder of the original design basis information; 2)
Confirm that the ongoing revision to the containment analysis would use the correct value; and 3) Establish administrative procedures based on reduced river temperatures to address the capacity deficit until final resolution is achieved.
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The heat exchanger manufacturer, Thermal Engineering International, re-analyzed the heat exchanger capacity using newer methods and concluded that the new heat exchanger data sheet maintains the same 105 million BTU /hr rating at the original design conditions by taking credit for some of the fouling margin j
and some of the additional tubes included in the design.
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Calculation No. QDC-1000-M-0698," Design Basis Analysis of RHR Heat Exctager Cooling Capability," was performed to supply input to the containment analp.a. A commitment, NTS 254-100-98-201-01, was generated '.o complete the new containment analysis.
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To track the administrative requirement that the plant not be operated with river water temperatures greater than 94* F, the following actions were completed.
A standing order was generated to closely monitor river water temperature during the months of June, July, August and September, NTS 254201198CAOD0121725.
A precaution was added to Procedure No. QAP 0300-32 stating that if the river temperature rises above 94 F the 1 A and 2A RHR heat exchangers may not be capable of removing the design heat load of 105 million BTU /hr,.NTS 254201198CAOD0121726.
Procedure No. OCOS-1000-29 was revised such that the acceptance criteria reflect the design capability of the heat exchangers, NTS 254201198CAQD0121727.
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Failure to promptly evaluate a previously identified concem with the heat removal rate of the RHR heat exchangers, a condition adverse to quality, and to take corrective actions in a timely manner was a violation of 10 CFR Part 50, Appendix B, Criterion XV!,
" Corrective Action"(50-254/98019-04(DRS); 50-265/98019-04(DRS)) However
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licensee corrective actions as describe (i above and documented in their respective corrective action documents adequately addressed corrective actions completed and implemented to prevent recurrence. Therefore, no response to this violation is required.
The unresolved item is closed.
E8.39 (Closed) URI 50-254-98201-05: 50-265-98201-05:
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Test instrumentation - the results of RHR 1 A heat exchanger testing dated September 16,1994, showed an energy mismatch of 28% between the tubes and shell side of the heat exchanger which translates to about 40% instrument loop uncertainty with regard to the overall heat removal capability. According to the calculated results, if the more conservative shell side values were used, the heat exchangers would have failed the acceptance criteria and could not be proven capable of the design heat removal rate of 105 million BTU /hr. Review of the tests results for the 2A heat exchanger dated February 27,1995, resulted in a similar conclusion.
The RHR heat exchanger thermal performance monitoring test procedure, QCOP-1000-35 was changed to a formal operating surveillance procedure, QCOS-100-29 with the following enhancements. The new procedures addressed instrument uncertainty issues covered by the 1989 EPRI Guidelines. Graftel RTDs were procured for the RHR heat exchanger thermal test with a t10 F accuracy. The surveillance was written such that the flow accuracy requirement of iS% was achievable, b)
Potential preconditioning - the heat exchanger thermal performance monitoring test procedure, QCOP-1000-35, identified that RHRSW system flow through the
' mat exchanger may be required to be realigned in the reverse flow direction to facilitate data collection. Reversing flow could flush out signs of biofouling and
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stroking the heat exchanger bypass valves could reseat the valves thereby reducing as-found heat exchanger bypass leakage.
To resolve this concem, the licensee reviewed their flushing practices. The heat exchangers were flushed at least once per month using the velocity developed by two RHRSW pumps and the flow path was reversed every quarter. Historically, low flows over a period as long as nine months have been needed to significantly affect thermal performance. Therefore, any improvement in thermal performance due to flow reversal would be insignificant. In addition, for all previous testing of RHR heat exchangers, performance was measured in an as-found condition with no reversal of flow.
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Acministrative controls for degraded equipment - PIF 96-0264 documelted that j
the 1B RHR heat exchanger was found to be at 85.7% of the design heat transfer l
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rate and it was accepted as an operable but degraded condition at river temperatures below 84.7 F.
At the time the PIF was generated, the unit was not operating; therefore, there was no need for standing orders to monitor river temperature or to take compensatory action.
Further, the heat exchanger was opened, inspected, and repaired during the outage which corrected the degraded condition prior to startup.
Fai!ure to establish a RHR heat exchanger test program that ensured that all testing to demonstrate that they would perform satisfactorily was identified and performed in accordance with written test procedures was a violation of 10 CFR Part 50, Appendix B, Criterion XI, " Test Control" (50-254/98019-01 b(DRS); 50-265/98019-01b(DRS)).
However, licensee corrective actions as described above and documented in their respective corrective action documents adequately addressed corrective actions implemented to prevent recurrence. Therefore, no response to this violation is required.
The unresolved item is closed.
E8.40 (Closed) IFl 50-254-98201-06: 50-265-98201-06: Torus Cooling Mode Single Failure Vulnerability. During normal plant operation with RHR operating in the torus cooling mode, the system could not automatically be realigned ints the low pressure coolant ir;jection mode in the event of a LOCA, assuming a single falure which resulted in the retum path valves to the torus remaining open. The A/E team considered this item to be a potential generic issue since it was similar to a finding at the Cooper Station. That issue was referred to the Office of Nuclear Reactor Regulation (NRR) staff for further review.
The Boin g Water Reactor Owner's Group (BWROG) held an Ad-Hoc committee n
meeting in June 1998 and decided there was sufficient generic implications of this issue throughout the industry to further pursue resolution. Since NRR and the BWROG are working on resolution of this issue and it is being tracked to completion by a Region IV finding, there is no need for this item to remain open to ensure resolution of this concern.
This item is closed.
E8.41 (Closed) URI 50-254-98201-07: 50-265-98201-01: Minimum Required Torus Water Level During Shutdown Conditions. The calculatsns that established the basis for the 7 ft value specificd in TS 3.5.C appeared to be non-conservative because the NPSH and vortex calculations were based on a flow rate of 4500 gpm from a single RHR or CS pump. However,4500 gpm was a throttled flow rate and it was possible that two or more RHR/CS pumps could initially start. In addition, the NPSH calculations used the old (incorrect) value for suction strainer head loss (1 ft at 10,000 rather than 5.8 ft at 10,000 gpm). The licensee initiated PIF Q1998-01341 to address these concerns.
Calculation No, ODC-1000-M-0687, Revision 1," Minimum Required Suppression Pool Level for the ECCS System During Cold Shutdown and Refueling Conditions," was completed to form the basis for the required torus water levet. Comed letter SVP-98-184 to NRC dated May 18,1998 applied for an amendment to the TS which proposed that TS 3.5.C.2, shutdown suppression chamber minimum water level be changed from 7 ft to
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8.5 Ft. Procedure No. QOS-0005-01, Revision 1," Minimum Required Suppression Pool Level for the ECCS System During Cold Shutdown and Refueling Conditions," was revised consistent with the proposed TS change. The change was in the conservative direction; therefore the revised procedure bounded the existing TS as well as meeting the proposed TS change.
Failure to adequately control design inputs in that documentation of design basis information was inconsistent with actual plant design was a violation of 10 CFR Part 50,
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50-265/98019-05a(DRS)). However, licensee corrective actions as described above and documented in their respective corrective action documents adequately addressed corrective actions completed and implemented to prevent recurrence. Therefore, no response tu this violation is required. The unresolved item is closed.
E8.42 (Closed) URI 50-254-98201-08:50-265-98201-08: EDG load calculations 9390-02-19-1,2,3 assumed a 5 second nominal value for the interval between load blocks and determined the time for the RHR pumps to start and get to rated speed (as less than 4.5 seconds). Per TS 4.9.A.8.k. the allowable values for each load sequence logic interval for RHR is 4.5-5.5 seconds and 9.5-10.5 for CS. If the RHR pump started at 5.5 seconds and the CS pumps started at 9.5 seconds, then there would be only allow 4 seconds for the RHR pump to get to rated speed which was less than the calculated required time.
On February 10,1998, the licensee identified in PlF Q1998-0709 that the TS allowed tolerance for the timing relays had been incorrectly interpreted and that the procedures and calculations might not ensure adequate values. The procedures allowed the RHR timers to be set at 3.3-5.5 seconds and the CS timers to be set at 9-11 seconds.
The following corrective actions were taken or planned:
OCTS 0310-01, " Unit 1 ECCS Logic Test," was revised to verify 4.5 to 5.5
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seconds time delay between the RHR pumps and the 2* RHR pump and the CS pump. This includes verification of the 9.5 to 10.5 second time delay between the start of the 1" RHR pump and the CS pump.
QCTS 0300-02, " A' Loop RHR Logic Test," was revised to use 4.5 to 5.5 second
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time delays.
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QCOS 1400-11(formerly QCTS 0300-05, "CS Logic Test"), was revised to use
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9.5 to 10.5 second time delays.
OCOS 1000-33 (formerly QCTS 0300-12, "'B' Loop RHR Logic Test") requires
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revision for the 4.5 to 5.5 second time delay. This item is being tracked to completion by NTS 254201198CAOD123201.
OCTS 0310-03, " Unit 2 Logic Test," requims revision to use the same criteria as
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QCTS 0310-01. This item is being tracked to completion under ER9801850.
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This non-repetitive, licensee identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy (50-254/98019-06(DRS); 50-265/98019-06(DRS)). The unresolved item is closed.
E8.43 (Closed)IFl 50-254-98201-09: 50-265-98201-09: EDG Long Term Loading. Manually controlled EDG loads were not well understood or effectively procedurally controlled.
During the A/E inspection, an evaluation of maximum EDG loading, SO40-OH-0440, dated April 1,1998, was performed using maximum brake horsepower values with instrument air compressors turned off. This confirmed that the kilowatt load required to be supplied to mitigate a design basis event was less than the 2860 KW rating of each diesel.
Three NTS items were generated to incorporate the results of the SO40-OH-0440 evaluation into existing calculations: 25420198CNAQ00892-02 to track incorporation into EDG loading calculations 9390-02-1,2,3; 25420198CNAQ00892-03 to track
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incorporation into the ELMS-AC balance of plant calculation; and 25420198CNAQ00892 to review the station blackout EDG loading to determine if the brake horsepower needed to be incorporated into these calculations. The team reviewed SO40-QH-0440 and verified the NTS commitments. This item is closed.
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l E8.44 (Closed) URI 50-254-98201-10: 50-265-98201-10: Pump Inservice Test j
Instrumentation. The A/E inspection report noted that, if plant equipment did not meet the ASME requirements, new test equipment would be procured, and procedures would be revised to comply with Code requirements for instrument accuracy. The team reviewed OlP 0100-19, " calibration of IST Instruments Used by Operations in Performing Their Surveillance Requirements," Revision 14, and ASME Code OMA-1988, Part 6, Paragraph 4.6.1.1 and Table 1. The team determined that the plant was meeting the
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Code requirements for instrument accuracy. This item is closed.
J E8.45 (Closed) URI 50-254-98201-11: 50-265-98201-11: Ultimate Heat Sink (VHS) Technical Specifications. TS 3.8.C.1, Ultimate Heat Sink Minimum Water Level, appeared to be inconsistent with the UFSAR in that the TS allowed for plant operation in all modes with a river level down to 561' with capability to support normal and accident cooldown and accident mitigation, while the UFSAR implied that the contour of the river bottom at the intake flume would prevent a direct flow of water between the main chantiel and the cribhouse. These elevation requirements came into effect through the TS Upgrade Program (TSUP). Prior to TSUP, there was no TS for the UHS and operating surveillance QOS 0005-01 required a river level of 570'. This was changed to 561' after the TSUP on December 10,1997.
Calculation ODC-4400-M-0697 dated May 1,1998, determined that the required river level measured in the intake bay regardless of the number of pumps operating was 567.53'. A TS amendment to TS 3.8.C.1 to raise the minimum water level from 561' to 568' was submitted on May 18,1998. Review of historical data documenting performance of QOS 0005-01 from September 29,1997 to February 20,1998, indicated that the lowest recorded river level in that period was 571'. This item is closed.
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E8.46 (Closed) URI 50-254-98201-12: 50-265-98201-12: Ultimate Heat Sink Dam Failure.
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UFSAR Section 2.4.4, Potential Dam Failure, stated that if Dam 14 were to fail, the river level at the station was assumed to drop to elevation 561' and that the natural river bottom between the river's edge and the main channel varied in elevation from 557' to 565' and prevented a direct flow of water from the main channel to the cribhouse during a dam failure. UFSAR Section 9.2.5 indicated that the contour of the river bottom would trap a large volume of water at elevation 561' in the intake fiume which, in conjunction with the discharge fiume, would be used as an evaporative heat sink with portable pumps of approximately 2000gpm capacity available on site for makeup requirements.
l The A/E team determined that in an evaporative mode, the trapped volume UHS would increase in temperature and during summer operation, could be driven well above the 95'F design temperature established for the RHR heat exchangers and could affect the performance of other safety related equipment including the EDG cooling water system, ECCS room coolers, RHRSW vault coolers, and control room ver.Clation, all of which receive water from the UHS. PlFs Q1998-00966 and Q1998-01282 were generated to track these concerns.
A hydraulic study of the Mississippi river at the plant was completed in April 1998 and the study predicted that the elapsed time after breach of dam 14 for the water intake to be lowered to 565' would be 90 hours0.00104 days <br />0.025 hours <br />1.488095e-4 weeks <br />3.4245e-5 months <br />. Four calculations were prepared to address the team's concerns as follows: 1) QDC-3900-M-0591," Water Volume of the Ultimate Heat Sink After Loss of the Normal Heat Sink," Revision 0. This calculation concluded that the total volume contained in the UHS on a loss of river with the intake fiume silted and with one crib house de-watered, was less than the 3.8 million gallons stated in the UFSAR.
However, actual plant condition based on a recent dredging of the intake fiume showed the total volume was more than the UFSAR value. Taking credit for the water volume contained in the RHR piping, a factor not considered in the UFSAR, increased the total water volume by an additional 413,957 gallons.; 2) QDC-3900-M-0692, " Ultimate Heat Sink Temperature Effect on Shutdown Capability," Revision 0, which concluded that the plant was capable of dual unit shutdown and maintaining acceptable temperatures at the RHR service water intake and in the to.us, with the use of three pumps taking suction from the river and delivering 5,100 gpm to the RHRSW intake. With use of the condenser for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after the initiation of shutdown, the maximum intake temperature was calculated to be 106.5'F; 3) QDC-5700-H-0695,"RHR and RHRSW Pump Cooling Following Failure of Lock and Dam 14," Revision 0, concluded that with a cooling water temperature of 107'F, temperatures in the RHRSW and EDG cooling water vaults would be maintained below 130*F. Similarly, RHR comer room temperatures would be l
maintained below 150'F; and 4) QDC-3900-M-0706," Ability of Rainbow Irrigation Pumps to Provide 1,700 gpm (each) During Loss of Lock and Dam 14," Revision 0, concluded that three portable pumps were capable of delivering 5,100 gpm to the RHRSW intake.
l A UFSAR change request was processed on May 18,1998, to clarify the description of the loss of lock & dam 14, including a timeline and credible failure mocles, to provide a
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description of analyses results regarding expected peak temperatures and times, to state
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event or accident, to revise the discussion of evaporation times, and to clarify the volume of me UHS.
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Failure to assure that the plant's design basis information was consistent with actual
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plant design was a violation of 10 CFR Part 50, Appendix B, Criterion Ill, " Design
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Control"(50-254/9801945b(DRS); 50-265/98019-05b(DRS)). However, licensee corrective actions as described above and documented in their respective corrective
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action documents adequately addressed corrective actions completed and implemented to prevent recurrence. Therefore, no response to this violation is required. The unresolved item is closed.
E8.47 (Closed) URI 50-254-98201-13: 50-265-98201-13: RHRSW Pump Brake Horsepower.
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The A/E team identified that the licensee didn't use the correct motor brake horsepowers.
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The licensee reviewed the brake horsepowers in the calculation and corrected them,
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including the CS and RHR pumps, as well as the RHRSW pumps. This was j
documented in nuclear design information transmittal ODC 98-092 "RHR/CS/RHRSW j
Pump BHP Input Values for Diesel Generator Loading Calculations." These corrected
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values were then used in the EDG electricalloading calculations, as described in Section E8.48.
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Failure to adequately control design inputs into calculations to ensure that they were
consistent with the design bases was a further example of a violation of 10 CFR Part 50, l
Appendix B, Criterion lil, " Design Control" (50-254/98019-05c(DRS);
50-265/98019-05c(DRS)). However, licensee corrective actions as described above and
documented in their respective corrective action documents adequately addressed
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corrective actions completed and implemented to provent recurrence. Therefore, no response to this violation is required. The unresolved item is closed.
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E8.48 (Closed) URI 50-254-98201-16: 50-265-98201-16: The bases for TS 3.5.C states that a
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Contaminated Condensate Storage Tank volume of 140,000 gallons provided the required NPSH for the CS and LPCI pumps, and ensured that at least 50,000 gallons of makeup water could be supplied to the reactor vessel. This statement was apparently in enor, since TS LCOs 3.5.B.1.a.2 and 3.5.C.2.c required 140,000 gallons available as a makeup source. TS amendment 181, Unit 1, and amendment 179, Unit 2, were j
implemented on October 8,1998, correcting the bases for TS 3.5.C. The unresolved item is closed.
1 E8.49 (Closed) URI 50-254-98201-17: 50-265-98.201-17: Reconstitution of the ability to meet UFSAR and other regulatory commitments with regard to the Alternate Shutdown Cooling Mode (ASCM). It was discovered during the A/E inspection that no procedure existed to specifically implement the ASCM of operation.
Procedure No. OCOP 1000-38, " Alternate Shutdown Cooling," Revision 0, was mplemented on April 30,1998. This item was reviewed in conjunction with E8.55 and is considered closed.
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E8.50 (Closed) URI 50-254/265-98201-18: This item encompasses numerous inspection findings involving discrepancies between plant as-found conditions and the plant licensing basis.
The discrepancies listed below are considered 13 examples of a failure to comply with a.
10 CFR 50.71(e) which constituted a violation of NRC requirements. The majority of the discrepancies were NRC identified before the licensee had implemented their Updated Final Safety Analysis Report (UFSAR) re-verification program. It is the inspectors view that the licensee would have identified the discrepancies in light of the defined scope, thoroughness, and schedule of the licensee's re-verification program. As part of an ongoing design basis initiative, the licensee has committed to performing a comprehensive re-verification of the UFSAR and Technical Specifications (TS) by verifying and validating design basis information and reconstituting essential design basis calculations. Commitment tracking item NTS-254-123-97-03502 (scheduled completion date of May 31,1999) was generated to verify and validate regulatory design j
basis information (10 CFR 50.2) contained in the UFSAR and TS. A line-by-line review
of the UFSAR was commenced April 1997 and completed September 1998. The project remained on schedule. The unresolved item and this violation 50-254/98019-07(DRS);
50-265/98019-07(DRS)) are closed and discretion is exercised to not issue a Notice of Violation regarding these issues.
UFSAR Table 6.2-7 which lists penetrations of primary containment and
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associated isolation valves (CIV) indicated that valves MO 1001-23A/B and MO 1001-34A/B were Type C leak rate tested in accordance with 10CFR50 Appendix J; however, a review of surveillance procedures identified that the leakage through the valves was not measured. The valves only served as boundaries for testing of other system valves. The justification for not leak rate l
testing these valves was that the RHR system maintained a qualified water seat, but this was not documented in the UFSAR. PlF Q1998-01455 was initiated to address this discrepancy. UFSAR change UFSAR-97-RS-085 documented the justification.
Valves MO 100118A/B in the RHR pump minimum flow bypass lines were not are
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listed as CIVs in UFSAR table 6.2-7. The licensee stated that other potential inaccuracies in UFSAR Table 6.2-7 were previously identified (reference PIFs Q1997-03217 and Q199704255), and actions to clearly define what is considered a CIV and revise Table 6.2-7 accordingly were in progress. These actions were being tracked in the licensee's NTS system. Table 6.2-7 was changed to included these valves by UFSAR change UFSAR-97-R5-085.
UFSAR Table 6.3-18 which shows the variation in RHR heat exchanger duty as a
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function of the number of RHR and RHRSW pumps operating included a notation regarding the number of emergency diesel generators operating that was potentially misleading because it implies (for Cases 1 and 2) that a single EDG
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can support the simultaneous operation of more than one RHR and one RHRSW
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pump. The licensee initiated PIF Q1998-01016 to address this discrepancy.
UFSAR change UFSAR-97-RS-076 removed the notation from table 6.3-18.
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UFSAR Figure 5.4-11, a schematic diagram of the RHR system, depicted valve
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41 as a normally open valve although the notation LC (locked closed) was also shown. This valve should be depicted as normally closed, consistent with the RHR system flow diagram, drawing no. M-39, Sheet 2, Rev. AW. This item was captured on PlF Q1998-00918. UFSAR change UFSAR-97-R5-085 revised figure 5.4-11 to show the valve in the closed position.
UFSAR Table 6.3-5 indicated RHR pump design parameters of 4,500 gpm flow at
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360 ft of head. Review of the certified vendor pump curves indicated that the total developed head should be about 400 ft at a flow rate of 4,500 gpm. This item was also captured on PlF Q1998-00918. UFSAR change UFSAR-97-RS-085 revised table 6.3-5 to indicate 400 ft of head at 4,500 gpm.
UFSAR Figure 6.3-12, a schematic arrangement drawing of the LPCIloop
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selection logic, depicted both recirculation loop equalizing valves as normally open, while only one of these valves is actually closed during normal plant operation. This item was also captured on PlF Q1998-00918. UFSAR change UFSAR-97-R5-085 revised figure 6.3-12.
The diesel generator kVA rating on single line drawing 4E-1301, Sheet 3,
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Rev. AF (3125kVA,2500kW) is not consistent with the value shown in Section 8.3.1.6.1 of the UFSAR (3200kVA,2600kW). The licensee documeated this deficiency under PlF Q1998-00747. CCR 98004 was issued to revise drawing 4E-1301, Sheet 3.
UFSAR Table 8.3-1 sheet 4 & 5 of 5 (4kV 8 480-V Bus Loads) states that: (Unit
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1 shown typical for Units 1 and 2 except Main Transformer or as noted). This note does not provide for divergences between Unit 1 and Unit 2. Several
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examples were not of differences between the units. PIFs Q1998-00725 and l
Q199800785 documented these deficiencies. UFSAR change i
UFSAR-97-R5-083 revised table 8.3-1.
Figure 8.3-1 of the UFSAR shows a flow of power from SWGR 14-1 to XFMR 18
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to SWGR 19. Similarly the figure shows SWGR 13-1 powering XFMR 19 and i
then SWGR 18. This was inconsistent with the design drawing, single line diagram 4E-1301, Sheet 3, Rev. AF. This deficiency was documented under l
PIF Q1998-00556. UFSAR change UFSAP,-97-RS-083 revised figure 8.3-1.
l The tia breaker positions shown on UFSAR Figure 8.3-1 appear to be
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inconsistent with design drawing 4E-1328 Rev. F, and the 4kV breaker identification numbers shown on UFSAR Figure 8.3-1 for buses 618 71 are not consistent with breaker numbers shown on key diagrams. The licensee
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documented this deficiency under PIF Q1998-00789. UFSAR change UFSAR-97-R5-083 revised figure 8.3-1.
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UFSAR Section 8.3.2.2, page 8.3-32 last paragraph states that 125 Vdc cross-tie
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exists between 4160-V switchgear 13-1 and 23-1 and is controlled by two manually operated circuit breakers that are lead sealed in the open position.
Plant walkdown did not identify lead seals on these breakers. Lead seals cannot be installed on these type of breakers. The licensee initiated PlF Q1998-00655 to revise UFSAR. UFSAR change UFSAR-97-R5-083 revised the description of the breakers.
UFSAR Section 8.3.2.2 states that the period the unit 2125 Vdc alternate battery
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is relied upon is less than 52 days per calendar year (based on the probability of a tomado missile strike) and that there are no limitations on the unit 1 125 Vdc alternate battery. However the TS 3/4.9.c D.C. sources - Operating states that each unit 125 Vdc normal battery may be inoperable for a maximum of seven l
days per operating cycle for maintenance and testing provided the 125 Vdc
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alternate battery is placed in service. If it is determined that a 125 Vdc normal battery needs to be replaced as a result of rr.aintenance or testing, a specific battery may be inoperable for an additional seven days provided the 125 Vdc altemate battery is placed in service. Contrary to the UFSAR statemeni, it is evident from the TS that both 125 Vdc attemate batteries have limitations on usage. The licensee documented this deficiency under PlF Q1998-01438. The differences between the UFSAR and the TS were the result of differences in the intent of each document. The TS was intentionally made more conservative.
Therefore, a UFSAR change was not required.
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UFSAR Section 6.3.2.1.2 third paragraph says that power required for each
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pump is approximately 850 HP, whereas, the nameplate data indicates that the pumps are rated at 800 HP. The licensee documented this deficiency under PIF Q1998-00714. UFSAR change UFSAR-97-R5-085 revised Section 6.3.2.1.2 to include a discussion of the 800 HP nameplate value, b.
(Open) URI 50-254/265-98201-18: UFSAR Tables 8.3-2 & 8.3-3 (Diesel Generator Loading), labeled as " Original Design Basis", reflect the original design basis loading values. These values indicate individual load brake hersepower (BHP) and total diesel generator BHP /kW loading, including 2000 hour0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br /> kW loading. The listed loads and the total IWing do not reflect the current configuration and are not diesel generator specific.
The liw see documented this deficiency under PlF Q1998-00764. The practice of changing the UFSAR original design basis values to " original design basis" has previously been deemed unacceptable by the NRC. This item will be reviend in conjunction with Unresolved item 50-254/265/97013-02 and remains open E8.51 (Closed) URI 50-254-98201-19: 50-265-98201-19: The team identified six examples of where control of calculations was inadequate.
Battery sizing calculation 7318-32-19-1 referred to Duke calculations 0597-050-E-=014 and 016 as input documents; however, the referenced calculations were not in the electronic work order system (EWCS) database. The calculations were added to the
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EWCS database and tracked by NTS 254-100-98-20119 which was closed on September 16,1998.
Two active calculations documented the same SRV setpoint for PC1(2)-0203-3A-E, Calculation 64.4200.0405 dated November 5,1982, and NED-I-EIC-0043 dated 1991.
Calculation 64.4200.0405 was superseded by NED-I-EIC-0043. EWCS was undated to reflect this action and track by NTS 254-201-98-CAOD0074601 which was closed on August 25,1998.
The following examples are being tracked by NTS 254-201-98-CAOD00659, due June 25,1999; NTS 254-201-98-CAOD0054501 due March 30,1999; NTS 254-201-98-CAOD0081701 due June 1,1999; and NTS 254-201-98-CAOD0081301 due June 10, 1999.
Diesel generator loading calculations Nos. 7318-33-19-1,7318-33-2, and 7318-33-19-3 were found to be inactive; however, they were shown in the electronic work control system as active. The active calculations for the emergency diesel generator loading were 9390-02-19-1, 2, and 3.
Breaker settings for 480V switchgear 18,19,28, and 29 were changed without revising or superseding Calculation No. 792342-19-1 to remove obsolete settings.
Motor replacements for RHR motor-operated valves 2-1001-4A and 4B were "like for like" in that each were rated at 60 ft-lb; however, the new motors had a higher full load current. Thermal overload sizing calculation No. 004-E-031 and voltage drop calculation No. 004-E-005-1001 were not revised to reflect this higher full load current. Additionally the electricalload monitoring system (ELMS) data was not updated with correct full load and locked rotor currents, in addition PIF Q1998-02162, " Trend PlF for Design Calculation Problems," was generated on April 27,1998. The results of this trending PlF indicated that the majority of calculation problems were tied back to older calculations that were generated during the construction and early operating phases. Corrective actions that resulted from this investigation included an evaluation of the EWCS database for entries with empty fields, generation of PlFs for specific EWCS discrepancies, training for engineering personnel on " Good Calculations," course number N-EGCAL, and issuance of a letter dated June 19,1998, to remind personnel that additional care and attention to NEP 12-02,
" Preparation, Review, and Approval of Calculations," shall be used when creating new or revising existing calculations.
Failure to ensure that the design basis was correctly translated into specifications, drawings, procedures, and instructions was a violation of 10 CFR Part 50, Appendix B, Criterion lil, " Design Control" (50-254/98019-05d(DRS); 50-265/98019-05d(DRS)).
However, licensee corrective actions as described above and documented in their respective corrective action documents adequately addressed corrective actions planned
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to prevent recurrence. Therefore, no response to this violation is required. The l
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E8.52 (Closed) URI 50-254-98201-20: 50-265-98201-20: Inputs used in RHRSW and DGSW j
vault cooler calculations and core spray cooler calculations were non-conservative.
A Nuclear Design information Transmittal was drafted and the calculations were planned to be revised, using the corrected input, by February 28,1999. As part of the 1998 Management Action Plan, key objective S.16.B, missing calculations were planned to be reconstituted. This initiative will be completed by February 28,1999, which appears to be an appropriate time frame. Failure to ensure that the design basis was correctly translated into specifications, drawings, procedures, and instructions was a violation of 10 CFR Part 50, Appendix B, Criterion 111, " Design Control" (50-254/98019-05e(DRS);
50-265/98019-05e(DRS)). However, licensee corrective actions as described above and documented in their respective corrective action documents adequately addressed corrective actions planned to prevent recurrence. Therefore, no response to this i
l violation is required. The unresolved item is closed.
E8.53 (Closed)IFl 50-254-98201-21: 50-265-98201-21: EDG Fuel Oil Tank Level Instruments.
Procedures did not include level instrument uncertainties in ensuring a minimum usable I
volume of 10,000 gal (66% level) in EDG fuel oil tanks 1-5201, W5201, and 2-5201 after performance of surveillances OCOS 6600-01, Revision 2,6000-19, Revision 10, and
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6600-20, Revision 11.
Per instrument uncertainty calculations NED-I-EIC-0142, Revision 2, and QDC-5200-1-0031, Revision 0, the instrument uncertainty was between i 6% (level instrument 2-5241-11) and i 7.11 percent (levelinstruments 1-5241-11 and W5241-12)
of full scale. This equated to an uncertainty between 1037 and 1066 gallons. The Operators' Surveillance / Turnover Sheets for Unit 1 and Unit 2, QOS 0005-S12 and OOS-0005-S18, verified storage tank level between 81% and 95% each shift,12799 -
14320 gal for 1-5201 and 12971 - 14669 gal for W5241 and 2-5241. These levels more than compensated for the instrument uncertainties. The surveillance procedures were revised in August 1998 to include instrument uncertainties. This item is closed.
E8.54 (Closed) LER 50-265-98003-00 (IFS Trackina Number 98-328): Unit Two Main Generator Trip and Subsequent Reactor Scram. The generator trip and subsequent scram was caused by a loose connection on a current transformer. The licensee
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planned to perform periodic checks on the current transformer connections to prevent recurrence. The team had no concerns with this event. This item is closed.
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V. Manaaement Meetinas X1 Exit Meeting Summary The team presented the inspection results to members of licensee management at th'e conclusion of the inspection on November 6,1998. The licensee acknowledged the findings presented.
The team asked the licensee whether any material examined during the inspection should be considered proprietary. No proprietary information was identified.
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PARTIAL LIST OF PERSONS CONTACTED Licensee Personnel Comed C. Alguire, Design $ngineering K. Betherd, Regulatory Assurance W. Bohke, Engineering Vice President R. Bozarth, Engineering Administration D. Craddick, System Engineer S. Darin, Engineering-J. Dimmette, Site Vice President K. Gladrosich, Nuclear Oversight Manager B. Harris, Assistant Site Vice President R. Heyn, Engineering J. Hoeller, CAP manager E. Karpe, Rad Protection Manager
.G. Larsen, Engineering Programs Supervisor P. Lawless, Project Manager D. McCullough, System Engineering A. Misak, Reactor Engineering Supervisor W. Pearce, Quad Cities Station Manager D. Peters, Nuclear Oversight Assessor C. Peterson, Regulatory Affairs Manager W. Porter, Design Engineering Supervisor
'J. Purkin, System Engineering Manager
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M. Richter, Site Engineering M. Santil, System Engineering C. Schumacher, System Electrical Supervisor.
S. Short, E/l&C Design Supervisor J. Steele, Engineering Administration Supervisor
~J. Trettin, System Engineering J. Williams, Project Engineer, NGG Engineering D. Wozniak, Engireering Manager MidAmerican Enerav Comoany D. Tubbs, Senior Engineer-Nuclear NRC J. Jacobson, Branch Chief, DR.S K. Walton, Resident inspector, Quad Cities IDNS R. Ganser, IDNS Resident Inspector, Quad Cities
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ACRONYMS AND'INITIALIZATIONS A/E Architect Engineer -
- Automatic Depressurization System CARB:
Corrective Active Review Board
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i CFR:
Code of Federal Regulations
CS-Core Spray
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DCP Design Change Package l
ECCS:
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EDG Emergency Diesel Generator ELMS Electrical Load Monitoring System ESF
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Engineered Safety Features
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EWCS Electronic Work Order System.
GE General Electric GL Generic Letter i
IEEE-Institute of Electrical and Electronic Engineers IN information Notice IST -
In Service Testing LER Licensee Event Report-MCC Motor Control Center MOV Motor-Operated Valve NES-Nuclear Engineering Standard NO
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Nuclear Oversight NPSH Net Positive Suction Head
'NRC
- Nuclear Regulatory Commission
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'NRR-
~ Nuclear Reactor Regulation PlF -
Problem Identification Form l-PORC Plant Operations Review Committee l
RCIC Reactor Core Isolation Cooling-RHR Residual Heat Removal l
RHRSW Residual Heat Removal Service Water System L
.SEP.
Systematic Evaluation Program SHIP System Health Indicator Program
-TOL-Thermal Overload.
TS Technical Specification l
'UFSAR Updated Final Safety Analysis Report URI Unresolved item
.Vac'
Volts Altemating-current VAT Vulnerability Assessment Team l-Vde'
Volts Direct Current
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INSPECTION PROCEDURES USED -
IP F/001:
10 CFR 50.59 Safety Evaluation Program IP37550:
Engineering
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IP40500:
Effectiveness of Licensee Controls in Id tifying, Resolving, and Preventing Problems IP 92700:
Onsite Follow up of Written Reports of Non-Routine Events
- IP 92703:
Follow up - Engineering PARTIAL LIST OF DOCUMENTS REVIEWED Pfocedures and Surveillances:
NEP-04-01 Plant Modifications, Revision 6 QCAP 0460-01 Quad-Cities Nuclear Station Plant Design Change Process, Revision 8 QCEMP 0400-02 Inspection, Repair and Maintenance of DC Operated Cutler-Hammer Motor Controllers, Revision 10 QCIS 0200-06 Low-Low Reactor Water Level Calib' ration and Functional Test, Revision 14 QCOP 6900-19 Documenting 125/250 VDC Grounds, Revision 6 QCOP 6900-25 Transfer of Unit One 125 VDC Bus Between Normal and Alternate Battery, Revision 4 QCOS 6900-02.
Station Battery Quarterly Surveillance, Revision 5 L QCTS 0210-02 Battery Charger Testing for Safety Related 125 VDC and 250 VDC Batteries, Revision 2 QCTS 0230-01 Unit 125 VDC Service Test Normal Battery, Revision 4 QCTS 0240-04 Unit One Service Test 250 VDC Safety Related Battery, Revision 4 QCTS 0310-01 Unit One Emergency Core Cooling System Simulated Automatic Actuation and Diesel Generators Auto-Start Surveillance, Revision 3
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. OCTS 0310-03 Unit Two Emergency Core Cooling System Simulated Automatic Actuation and Diesel Generators Auto-Start Surveillance, Revision 3 QAP 0300-02 Conduct of Shift Operations, Revision 51
QARP 1500-01 Safe Shutdown Procedure, K2, Revision 12 QCAN 901(2)-74 014125 VDC Switchboard 6A (7A) Voltage Low Alarm, Revision 1
- QCAN 1(2)-8350-C-1 Non-Essential 250 VDC Battery High Discharge Rate, Revision 0 QCAN 1(2)-8350-C-2 Non-Essential 250 VDC Battery Charger A and B" Output Breakers
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Open, Revision 0 l
QCEM 0100-03 125/250 Vdc Battery Replacement (Out of Service), Revision 2 QCEM 0100-05 24/48 Vdc Battery (Out of Service), Revision 3 QCOA 6100-03 -
Loss of Offsite Power, Revision 4 QCOP 6600-04 Diesel Generator % Preparation for Standby Operation, Revision 12
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- QCOP 6900-24 Transfer of Unit two 125 Vdc Bus between Normal and Altemate Battery, Revision 2 QCOP 6900-25 Transfer of Unit one 125 Vdc Bus between Normal and Alternate Battery, Pevision 4
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- ' - QCOP 1000-29 Shutdown Ciooling Startup and Operations from Outside the Control-L-
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Room, Revision 3
- QCOS 6600-07 Quarterly.% Diesel Generator 125 VDC Control Power Auto-Transfer J
Switch Test, Revision 3
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QOA 0010-05 Plant Operation with the Control Room Inaccessible, Revision 14
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QOP 6900-02 125 VDC Electrical System, Revision 18 -
QCOS 1300-05 Quarterly RCIC Pump Operability Test, Revision 19 l-QCOS 1300-07 RCIC Manual Initiation Test, Revision 11 QCOS 1300-10 -
RCIC Monthly Vent Verification, Revision 5 QCOS 2300-09.
HPCI Monthly Vent Verification, Revision 5
i QCOS 2300-05 Quarterly HPCI Pump Operability Test, Revision 26
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QCOS 1300-05 Quarterly RCIC Pump Operability Test, Revision 20 l
. OCOS 1000-06 Quarterly RHR Pump / Loop Operability Test, Revision 17 L
- QCOS 1400-01 Quarterly Core Spray Pump Flow Rate Test, Revision 9 l:
QCOS 1000-09 Quarterly RHR Power Operated Valve Test, Revision 4 L
QCMM 1500-11 Torquing Requirements for Fasteners, Revision 4
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- QCAP 0500-1 -
Processing 10 CFR 50.59 Safety Evaluations and Screenings, Revision l
6-j QCAP 1000-05 Qualification of 10 CFR 50.59 Participants and Operability
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Determination Reviewers, Revision 7 NSWP -A-04 Revision 1-1,4/9/98,10 CFR 50.59 Safety Evaluation Process.
Standard NES-G-07 System Health Indicator Program (SHIP), Revision 3.
L N.O. - 07 Conduct of intemal Audits, Revision 4.
N.O. - 16 -
Conduct of Off-site Review, Revision 9.
NSP-AP-1002 Plant Operations Review Committee, Revision 1.
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NSP-AP-1004 Correction Action Program Process, Revision 1.
NSP-AP-2004 Correction Action Program Process Roles and Responsibilities, Revision 1.
NSP-AP-4004 Correction Action Program Procedure, Revision 0.
l NSP-RA-3001 Conduct of the Nuclear Safety Review Board, Revision 0.
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NSP-WC-3001 Work Screening and Classification, Revision 0.
CWPI-NSP-AP-1-12 Corrective Action Program Process Manual of Common Work Practice i
l Instructions, Revision 0.
Problem Identification Forms (PIFSh 1997-58 U2 SBO battery room reached 66 degrees
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l 1997-292 Unit 2 battery ambient temperature dropped due to problems with ventilation 1997-299 Low ambient temperature caused battery electrolyte temperature to be low L
1997-302 UPS battery cell found out of tolerance 1997-1044 Ambient temperature in Unit 2 alternate 125 VDC battery area L
1997-1255 Unit 1 battery spc-t'c gravity found out of tolerance l
? D1998-04924 250 VDC discovet uu at 290.4V on equalize charge l<
D1998-05045-SCRs installed backward during Unit 2 250 VDC battery charger maintenance
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D1998-05141 Excessive noise and vibration with U2 250 VDC charger D1998-05151 U2 250 VDC battery charger arcing at firing module Q1998-03323 Untimely routing of requests for.50.59 reviews.
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Q1998-03389 Untimely ERs requesting 50.59 screenings or SEs.
Q1998-03323 Untimely routing of ERs for 50.59 screening.
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Q1998-03389 Untimely ERs requesting 50.59 screenings or SEs..
Q1998-03904 OOS Surveillance not complete on due date.
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Q1998-03975 Inadequate Screening for MSOP Lube Oil Trip.
Q1998-04299 Safety Evaluation Third Party Review Transfer, t
Q1998-04441 Potential High Pressure Setpoint Surveillance Frequency Problem.
Q1998-04444 SSFI id'd screening's failure to require a SE for Toxic Gas.
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Q1998-02975 Unit 2 Increasing Drywell Pressure.
Q1998-04363 Unit 2 Recirc Sample Line pressure.
Q1998-04601 Potential Preconditioning of HPCI, RHR, and CS Pump Operability Surveillances.
Q1998-04528 NRC E&TS INSPECTION ISSUEl Possible pre-conditioning of RCIC
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Pump During Surveillances.
Q1998-01033 Leak on Unit 1 Reactor Bottom Head Drain Line Q1998-03753 Inadequate Out of Service Boundary on % B Fire Diesel Q1998-03878 U-1 EDG Fuel Oil Tank - High water and sediment in Sept. Sample Q1998-03893 Spill of Radioactive Water during the change out of a heater in the Floor Drain Surge Tank Building
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Q1998-04237 1D3 High Level Alarm Q1997-03801 Conflicts with Appendix R safe shutdown analysis Q1997-04021 Unable to adjust low voltage setpoint Q1997-04735 Level 3 ground on unit 1125 Vdc system Q1998-01371 125/250 volt battery and charger tests inadequately planned Q1998-02415 Level 3 ground on unit 2125 Vdc system Q1998-02604 incorrect breaker installed in 125 Vdc bus 1B-1 Cub CO2 Q1998-02915 125 Vdc chanyF failed the four hour discharge test Q1998-03077 Division 2 AT&S DC power supply breaker tripped during ground checks Q1998-03531 Failed to calibrate battery charger per procedure Q1998-03609 Unit 2 B channel scram discharge valve (SDV) low voltage condition 10 CFR 50.59 Safety Evaluations:
SE-96-027 Reactor Recirculation Pump A Suction Piping Weld Overlay.
SE-97-190 UFSAR Change: UFSAR-97-R5-075, MSIV Test Revision.
SE-97-022 ECCS Pump Suction Strainer NPSH Safety Evaluation.
SE-98-072 UFSAR Change: UFSAR-97-R5-055, Service Water Drawing Revision.
SE-98-008 Unit 2 SBO DCS Bypass SE-98-086 Unit 2 RCIC System Valve Lineup Change.
SE-98-090 increased Stroke Time for RHR Valve SE-98-107 UFSAR -97-R5-075, UFSAR Change for MSIV Testing.
SE-98-126 SRV 2-0220-238 Removal.
SE-98-131 UFSAR Change: UFSAR-97-R5-088, RCIC Pump Type Revision.
SE-98-134 Reactor High Pressure Scram Setpoint Change.
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SE-98-135 Temporary Modification 98-2-022, Rev.1.
SE-98-105 Safety Evaluation for DCP 9700324 -- Replace Obsolete Unit 1 Control Room Recorders SE-98-112 Safety Evaluation for DCP 9600434 (addendum)-- New RWCU automatic system isolation on RWCU high area temperature SE-98-115 Safety Evaluation for DCP 9700455 - Replacement of Narrow Range Reactor Level Transmitter LT 1-0646-B SE-98-134 Safety Evaluation for DCP 9800268 (Unit 1) and 9800269 (Unit 2) -
Increase High Reactor Pressure Scram Setpoint to avoid Spurious Scrams.
SE-98-137 New Safety Evaluation for Containment Over Pressure issue to address a potential unreviewed safety issue 1997-01-006 Revise UFSAR to Address 125 VDC Battery Qualified Life E12-2-96-205 Replacement of the U2 HPCI Gland Seal Leak-off Condenser Hotwell Drain Pump Motor, dated 3/12/96 1997-01-065 Place and Maintain 24/48 VDC Battery Charger in Equalize Mode 1998-01-058 Change TS Basis 3/4.9A to Reflect that the Unit Auxiliary Transformers Are Additional Sources of Offsite Power 1997-01-056 SBGT System Dampu Thermal Overload Setpoint Change 1997-01-006 Revise UFSAR to Address 125 kOC Battery Qualified Life 10 CFR 50.59 Safety Screeninas:
SS-P-97-0002 RCIC Minimum Flow Valve Test Changes.
SS-P-98-0022 Secondary Containment Capability Test Changes.
SS-P-98-0030 RCIC isolation Upon SBLC Startup Test Changes.
SS-P-98-0041 Unit 2 Station Blackout Diesel Fuel Oil Pump Test Changes.
SS-P-98-0080 Torus Cooling Operation Procedure Changes.
SS-P-98-0219 QCOP 1100-03, Rev. 4 Procedure Changes.
SS-P-98-0278 RCIC lsolation Valve Test Changes.
SS-P-98-0434 Earthquake Response Procedure Changes.
SS-F-98-0270 Update Service Water System P&lD to As-built condition.
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SS-F-98-0273 Control Switch Labeling Changes.
SS-F-98-0280 Operations Control of Unit 2 Inerting Valves.
SS-F-98-0283 DCP 9800039, Replacement of Radwaste Valves.
l SS-F-98-0284 Tagging Shut Radwaste Valves 1(2)-1001-20 and 21.
SS-F-98-0286 Tagging Shut RHR Valves 1(2)-1001-47.
SS-F-98-0288 OOS 98-6682 on C1 heater extraction steam instrument air.
SS-F-98-0297 Add Stiffener to HPCI Valve Junction Box Mounting Bracket.
SS-F-98-0298 Impression Current Cathodic Protection System Connection.
SS-F-98-0299 incorporate DCR 9600251 Design Drawing Revisions.
SS-F-98-0302 Evaluate Reactor and Turbine Building Sample Panel Flowrates.
SS-F-98-0304 Condensate Pipe Support 1-3405-R3 Drawing Revision.
SS-F-98-0309 Level Indicator Ll-03341-77A EWCS Listing Revision.
SS-H-98-0140 Screening to Validate ECCS Pump NPSH Safety Evaluation.
SS-H-98-0151 Screening to Validate SBLC Valve Replacement Safety Evaluation.
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SS-F-98-0305 Safety Screening for DCPs2 9800277 (Urut 1) and 9800278 (Unit 2)--
Change in Calibration Requirements for the Fuel Pool Radiation Monitors Safety Screening for Revision 7 of Procedure QAP 1170-17, Fire Protection Program.
Safety Screening for Revision 0 of Procedure QCAP 0230-22, TMOD Exclusion Tracking Calculations:
NED-E-EIC-0065 Thermal Overload Heater Sizing for DC Motor Operated Valves (MOVs)
NED-EIC-MOV-DR0007 Valve Actuator Motor Terminal Voltage Calculation E-001-2301 MOV Terminal Voltage Calculations DRE96-0026 Flange Calculation for HPCI Discharge Line No. 2-2304-12-DX DRE96-0040 Breaker and Thermal Overload Heater Sizing for Replacement Breaker 2-83250-2AD2 DRE96-0126 Motor Terminal Voltage Calculation for Dresden 250 VDC MOVs NED-I-EIC-0017 Reactor High Pressure Scram Setpoint Error Analysis, Revision 2.
ODC-1600-S-0464 Evaluation of Existing and New Flanges on ECCS Suction Strainers, Quad Cities Unit 1, Revision 1 28.0201.0232.23 Model Q102 Non Mark I Loads, Revision 1 QDC-1600-S-0465 Model Q1.02 Submerged Structure Loads on ECCS Suction Strainers, Revision 0 Modifications:
DCP E-12-3-96-225 Unit 3125 VDC Battery Charger Anchorage DCP 9600434 (addendum) New RWCU automatic system isolation on RWCU high area temperature DCP 9700324 Replace Obsolete Unit 1 Control Room Recorders DCP 9700455 Replacement of Narrow Range Reactor Level Transmitter LT 1-0646-8 DCP 9800268 increase Unit 1 High Reactor Pressure Scram Setpoint to avoid Spurious Scrams.
DCP 9800269 increase Unit 2 High Reactor Pressure Scram Setpoint to avo d Spurious Scrams.
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DCP 9800277 (unit 1)
Change in Calibration Requirements for the Fuel Pool Radiation Monitors DCP 9800278 (unit 2)
Change in Calibration Requirements for the Fuel Pool Radiation Monitors DCP 9600334 Breaker Replacement for 2A 125 VDC Battery Charger DCP 9700347 Modify Turbine Trip Logic on Low Pressure to 2 of 2 Logic DCP 9800243 Install ADS Inhibit Switch DCP 9800245 Rewire Reactor Feedwater Pump to Ensure Trip on High Level DCP 9800253 Install Chart Recorders Across the Channel Scram Relay Logic Contacts DCP 9800254 Connection of the impressed Current Cathodic Protection System to the Diesel Generator Metallic Fuel Tanks
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Temoorarv Alterations TA 92-2-140 install Submersible Pump in 2B Reactor Floor TA 94-1-006
- Install Pump in Discharge Bay to Composite Sampler Piping
. TA 94-1-084 Install Makeup Mobile Demineralizer System TA 94-1-121 Install Thermocouples to Monitor Area Temperature of the Unit 1 RVLIS drywell Legs TA 96-1-111 Block Open Backdraft Dampers for Drywell Coolers
' TA 98-2-028 Leaking Reactor Recirculation Sample Line Relief Valve:
TA 98-02-22 Reactor Core isolation Cooling (RCIC) Discharge Valves:
Temocrary Modifications 98-2-022 Revision 0, approved June 9,1998 98-2-028 Revision 0, approved October 10,1998 98-2-028 Revision 1, approved October 19,1998 Correspondence:
CHRON #0300252 SEP Topic Vill-4 Electrical Penetrations of Reactor Containment:
Overload Protection of Penetrations between 200A and 600A, May 16,1994 Reports:
SVP-98-328 Summary Report of Changes, Tests, and Experiments Completed issued October 30,1998, OEAG May 1998 Report -
Rev. O, dated June 8,1998.
OEAG June 1998 Report Rev. O, dated July 16,1998.
QEAG July 1998 Report Rev. O, dated August 12,1998.
QEAG August and September Report,1998, Rev. 0, dated October 6,1998.
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' Lesson Plans:
NSWP A-0410 CFR 50.59 Safety Evaluation Training Lesson Plan, Rev. 3, Module -
GSETI.
10 CFR 50.59 NSWP A-04 Workshop Lesson Plan, Rev. 3, Module 5059WKSP (N-E5059W)
Licensee Event Reports:
254/98-012 Leak in the Unit One Reactor Bottom Head Drain Line.
UFSAR Chanoes:
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' UFSAR-97-RS-055 UFSAR Change: Service Water Drawing Revision.
I UFSAR-97-RS-075 UFSAR Change: MSIV Testing.
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l QCAP 410-01 CGE Attachment E, IST Valve Surveillance Acceptance Criteria '
I Summary Sheet, for procedure QCOS 1000-09, dated April 25,
1996
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l Work Reauests:
l WR 980105983-01 Measure 2-0220-44/2-0220-45 Vclume Pressure for Leakage
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WR 980105614-01 Place Blind Flange on Relief Valve for Support of LLRT l,
WR 980076523-01 Valve to Relieve Pressure Between AO-2-0220-44 and AO-2-0220
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WR 960003776-01 Replace SBLC Check Valve with Rockwell-Edwards Spring
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Drawinos:
M-1630-03 ECCS Suction Header Penetration Reinforcement Installation i
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Drawing, Quad Cities Station Units 1 & 2, sheet 1, dated January
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14,1998 l
M-1630-03 ECCS Suction Header Penetration Reinforcement installation Drawing, Quad Cities Station Units 1 & 2, sheet 2, dated January 14,1998 M-39 Diagram of Residual Heat Removal (RHR) Piping, Quad Cities Station Unit 1, sheet 1, dated April 27,1998 i
M-39 Diagram of Residual Heat Removal (RHR) Piping, Quad Cities Station Unit 1, sheet 2 M-1630-04 ECCS Suction Strainer Installation Drawing, Quad Cities Station Unit 1 & 2, dated January 20,1998 M-89 Diagram of Reactor Core Isolation Cooling (RCIC) Piping, sheet 1, dated May 23,1998 M-77 Diagram of Nuclear Briier & Reactor Recirculating
L QCU1-ECCS-8004-1100-Quad Cities Unit-1, Sure-Flow Strainer, ECCS Sump Strainer l
Assembly - 4 Required, revision 1, dated November 6,1997 l
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e-ITEMS OPENED, CLOSED, OR DISCUSSED i
Ciosed 254/93004-02 IFl Follow-up on Safety-Related Contact Test Program 254/265-93024-01 IFl Time Delay Relay Affected Fast Transfer 254/265-94004-40 IFl Equipment Vibration Concerns 254/265-94004-46 IFl Operability Evaluation for RHR Spring Cans 254/265-94004-50 IFl VAT /SEP ltems 254-95004-03 IFl Axial Thrust Measurements on Vertical Pump Motors 254/265-95005-09 IFl ELMS Update 254/265-95007-04 IFl Failure to Assure that Adequate Test instrumentation Was Used 254/265-96008-12 URI High Pressure injection Keep Fill Line Qualification 254/265-96008-13 URI Technical issues Related io Previous Escalated Enforcement Actions 254/265-96010-02 VIO Failure to Follow Temp Alt and Root Cause Evaluation Procedures 254/265-96010-03 IFl Fuse Control Problems 254/265-96010-04 IFl Breaker Coordination Modifications 254/265-96010-05 IFl Battery Temperature Operability Limits 254/265-96010-06 IFl Faulty Electrical Penetration Pressure Gauge 254/265-96010-07 IFl Vendor Document Control iM!265-96011-05 URI Reactor Water Cleanup Pipe Break 264/265-97010-01 VIO Design Change Process Not Used for Alternate Parts Replacements 254/265-97010-02 VIO Failure to Perform Adequate Testing After Part Changes 254/265-97010-03 VIO Inadequate Corrective Actions on Replacement Parts Program 254/265-97017-03 URI Acceptability of Reliability-Availability Balance 254/265-97022-01 VIO Inaccurate Procedure Delayed HPCI Steam Isolation Valve Opening 254/265-97022-03 VIO Failure to incorporate LOOP Time Delay in Modification l
265-97022-05 URI Safety Evaluation Screening Did Not Evaluate All Modes of Operation I
254/265-97022-06 VIO Failure to Follow 10 CFR 50.59 Procedure Regarding Submittals 254/265-97022-07 IFl Licensee Corrective Actions to Ensure UFSAR Updating
254-98005-01 VIO Work Package Prepared Prior to Design Approval 254/265-98008-01 URI Operability of Standby Gas Treatment System Due to Wiring Error 254/265-98201-02 URI LOCA Analysis input Errors 254/265-98201-04 URI RHR Heat Exchanger Capacity 254/265-98201-05 URI RHR Heat Exchanger 89-13 Testing i
254/265-98201-06 IFl Torus Cooling Mode Single Failure Vulnerability 254/265-98201-07 UR Minimum Required Torus Water Level During Shutdown j
Conditions
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254/265-98201-08 URI EDG Short Term Loading 254/265-98201-09 IFl EDG Long Term Loading 254/265-98201-10 URI Pump Inservice Test Instrumentation 254/265-98201-11 URI Ultimate Heat Sink Technical Specifications
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l 254/265-98201-12 URI Ultimate Heat Sink Dam Failure
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254/265-98201-13 URI RHRSW Pump Brake Horsepower l
254/265-98201-16 URI CCST Water Level to Provide Suction for RHR/CS
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254/265-98201-17 URI Altemate Shutdown Cooling Mode l
254/265-98201-18 URI. UFJAR Discrepancies
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254/265-98201-19 URI Inadequate Control of Calculations 254/265-98201-20 URI-Non-conservative Calculation inputs
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254/265-98201-21 IFl EDG Fuel Oil Tank Level Instruments l
254/265-98019-01 VIO Inadequate Test Control.
l 254/265-98019-02.
NCV Enforcement discretion for further examples of an earlier escalated violation.
l 254/265-98019-03 NCV Three cases of licensee identified, non-repetitive, and corrected
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L errors in the LOCA analysis.
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' 254/265-98019-04 VIO Inadequate Corrective Action.
254/265-98019-05 VIO Inadequate Design Control.
254/265-98019-06 NCV Licensee identified, non-repetitive, and corrected errors in the
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EDG loading analysis.
254/265-98019-07 VIO Enforcement discretion for UFSAR discrepancies 265-95003-00 LER Shutdown Cooling Not Available Because Valve Tripped on Overcurrent (IFS Tracking #95-271)
254-96022-01 LER
"B" Control Room Emergency Ventilation System Unable to Maintain 1/8" dP. (IFS Tracking #97-124)
~ 265-97005-00 LER Unit Two and Uait Half EDGs Decised Inoperable Due to Parts issue (IFS Tracking #97-295)
265-97005-01 LER Unit Two and Unit Half EDGs Declared Inoperable Due to Parts Issue (IFS Tracking #98-099)
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254-97030-00 LER Instrument Line Excess Flow Check Valve Testing (IFS Tracking
- 98-055)
254-97030-01 LER instrument Line Excess Flow Check Valve Testing (IFS Tracking l
- 98-166)
254-98006-00 LER Reactor Building Post Loss of Coolant Accident (LOCA)
Temperatures Higher Than Values Assumed in the UFSAR (IFS Tracking #98-092)
254-98006-01 LER Reactor Building Post Loss of Coolant Accident (LOCA)
Temperatures Higher Than Values Assumed in the UFSAR (IFS Tracking #98-260)
254-98007-00 LER Reactor Building Superstructure Not in Literal Compliance With UFSAR Description Pertaining to Class I Loading Combinations (IFS Tracking #98-093)
l 254-98012-00 LER Unit One Reactor Bottom Head Drain Developed Leak (IFS Tracking #98-165)
254-98012-01 LER Unit One Reactor Bottom Head Drain Developed Leak (IFS Tracking #98-259)
254-98013-00 LER Insufficient Clearance Between U1 CS Test Return Valve and
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Torus May Have Caused Interference During LOCA Conditions (IFS Tracking #98-164)
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265-98003-00 LER Unit Two Main Generator Trip and Subsequent Reactor Scram (IFS Tracking #98-328)
Ooened 254/265-98019-01 VIO Inadequate Test Contro!.
254/265-98019-02 NCV Enforcement discretion for further examples of an earlier escalated violation.
254/265-98019-03 NCV Three cases of licensee identified, non-repetitive, and corrected
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errors in the LOCA analysis.
254/265-98019-04 VIO Inadequate Corrective Action.
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254/265-98019-05 VIO Inadequate Design Control.
254/265-98019-06 NCV Licensee identified, non-repetitive, and corrected errors in the
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EDG loading analysis.
j 254/265-98019-07 VIO Enforcement discretion for UFSAR discrepancies
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