IR 05000331/1998008
| ML20236V698 | |
| Person / Time | |
|---|---|
| Site: | Duane Arnold  |
| Issue date: | 07/28/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20236V685 | List: |
| References | |
| 50-331-98-08, 50-331-98-8, NUDOCS 9808040148 | |
| Download: ML20236V698 (17) | |
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U. S. NUCLEAR REGULATORY COMMISSION REGION 111 Docket No:
50-331 License No:
DPR-49 Report No:
50-331/98008(DRP)
Licenue:
Alliant, IES Utilities Inc.
200 First Street S.E.
P. O. Box 351 Cedar Rapids, IA 52406-0351 Facility:
Duane Amold Energy Center Location:
Palo, Iowa Dates:
April 29 - June 9,1998 Inspectors:
Laura Collins, Acting Senior Resident inspector M. Kurth, Resident inspector Approved by:
R. D. Lanksbury, Chief
. Reactor Projects Branch 5 l
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EXECUTIVE SUMMARY Duane Amold Energy Center NRC Inspection Report 50-331/98008(DRP)
This inspection report included resident inspectors' evaluation of aspects of licensee operations, engineering, and maintenance.
Operations
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Strict procedural adherence and effective management oversight contributed to operations personnel performing an error free startup following Refuel Outage 15 (Section 01.1).
Operations staffs performance improved from the first half of Refuel Outage 15.. The
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number of self-revealing events, human errors, c. communication problems, and scheduling and planning deficiencies, as detailed in Inspection Report 50-331/98004, decreased (Section 01.1).
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The inspectors assessed the drywell material condition following the primary containment
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closeout inspection by operations' personnel and determined that the licensee failed to adequately verify that the drywell general area was free of trash and debris. This resulted in a violation (Section O2.2).
Operation's personnel identified that one train of the standby gas treatment system
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exceeded 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> run time without Technical Specifications-required testing being
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l conducted. However, the 25 percent allowable extension to the surveillance interval was not fully used. The cause of the problem was an ineffective run time tracking mechanism. The required testing was performed and the licensee was in the process of revising the tracking procedure (Section O3.1).
During the refueling outage, two separate configuration control problems occurred which
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l resulted in two non-cited violations. A scram discharge drain isolation valve was likely l
l mispositioned due to operations personnel's unfamiliarity with the unique characteristics
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'of the valve and its positioning. A control rod drive cooling water riser valve and exhaust
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valve were likely mispositioned due to the lack of procedural specifics in restoring the l
valve lineup (Section 08.1).
I Maintenance I.
l The inspectors concluded that work activities were effectively performed and
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well-controlled (Section M1.1).
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The licensee was proactive in establishing a 'ist conductor / coordinator for the complex
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i and infrequently performed loss of off off-signt power-loss of coolant accident (LOOP -
LOCA) test. The test conductor / coordinator was responsible for performing verification of completion of steps as an additional measure to ensure proper test configuration.
l However, the mispositioning of a valve during the LOOP-LOCA test demonstrated a lack of attention to detail by the operator. Additionally, the test conductor / coordinator failed to
property perform his verification function by not reading the procedure steps himself and l
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O then verifying proper actions. The mispositioning was licensee identified and corrected during the conduct of the surveillance test (Section M1.2).
The licensee promptly resolved emergent equipment issues that were identified during
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the inspection period. All of these equipment problems were resolved within the I
associated TS allowable outage times (Section M2.1).
The licensee appropriately identified and corrected issues involving missed quality control
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' (QC) inspections during the refueling outage. The inspector determined that in only one of three cases was the QC inspection required per the goveming QC inspection procedure. Corrective action in that case resulted in re-performing the work with the proper QC involvement. Although QC inspections were not required by the administrative procedure, they were specified in the maintenance action request package and the failure to perform the inspections as specified indicated a lack of attention to detail. Because the licensee identified and resolved the issues, this was considered to be a non-cited violation (Section M7.1).
Inadequate post-maintenance testing resulted in the outboard recirculation sample valve
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. being inoperable for over 4 months. The primary containment function was still met with the inboard valve. This indicated a weakness in the post maintenance testing program and was considered to be a violation (Section M8.1).
Enaineerina During the refueling outage, the licensee discovered that high pressure coolant injection
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(HPCI) peak room pressure during a postulated high energy line break would reach 6.3 psi and that one HPCI room wall could not withstand that pressure. This discovery was a result of the licensee conservatively broadening its assessment by including the HPCI room walls after its initial assessment of the HPCI room peak pressure on the HPCI room doors (Section E1.1).
During the refueling outage, the licensee discovered that HPCI peak room pressure
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during a postulated high energy line break would reach 6.3 psi and that one HPCI room wall could not withstand that pressure. The licensee took corrective actions as appropriate by strengthening the wall but failed to report this condition to the NRC in a licensee event report. Without intervention by the inspectors this issue would not have been reported. Failure to make a required report was a violation of 10 CFR
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Part 50.73(a)(2)(ii)(B) (Section E1.1).
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l Report Details Summarv of Plant Status The plant began this inspection period in a shutdown condition for refueling outage 15 (RFO 15).
Startup from RFO 15 was on May 18,1998, with full power reached on May 26,1998. On May 27,1998, power was reduced to approximately 55 percent for several days to repair a feedwater motor oil leak. The plant was restored to full power on June 1,1998. The plant operated at full power for the remainder of the inspection period.
l. Operations
Conduct of Operations 01.1. General Comments (71707 and 71711)
a.
Inspection Scope i
The inspectors followed the guidance of Inspection Procedures 71707 and 71711 and conducted frequent reviews of plant operations. This included observing routine control room activities, reviewing system tagouts, attending shift tumovers and crew briefings, i
and performing panel walkdowns. The inspectors also observed portions of the i
May 18-26,1998, startup from RFO 15.
l b.
Observations and Findinas Operations personnel performed an error free reactor startup following RFO 15. Shift management provided effective oversight of startup activities. Operations personnel used three way communications and exhibited strict procedural adherence during the i
startup. Control room staffing levels were appropriate and operations personnel were generally knowledgeable of plant conditions.
Operations staff performance improved from that of the first half of RFO 15. The number of self-revealing events, human errors, communication problems, and planning and scheduling deficiencies, as detailed in inspection Report 50-331/98004, decreased.
Noteworthy observations are described in more detail throughout the report.
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Operational Status of Facilities and Equipment j
O2.1 General Plant Tours and System Walkdowns (71707)
l The inspectors followed the guidance of Inspection Procedure 71707 in walking down l
accessible portions of several systems:
I High pressure coolant injection (HPCI) system
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Reactor core isolation cooling (RCIC) system
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Equipment operability, material condition, and housekeeping were acceptable in all cases. The inspectors did not identify any substantive concems as a result of these walkdowns.
O2.2 Primary Containment Closeout (71707)
a, inspection Scope On May 13,1998, the inspectors assessed the drywell material condition following the primarv containment closeout inspection by operations' personnel.
b.
Observations and Findinas The inspectors toured the drywell and identified loose debris that needed to be removed I
from the drywell general area prior to start-up. This was identified after the licensee l
performed a primary containment closecut inspection on May 13,1998, in accordance
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with Integrated Plant Operating Instruction (IPOI) 7, "Special Operations," Revision 51.
j The loose debris found included: tape rolled into balls, exposed fibrous insulation on a
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section of drywell cooling piping, tie-wrap pieces, nails, glass, a carpenter's ruler, and sheet metal screws and wiring used to fasten insulation covers. As detailed in the attached Notice of Violation, the failure to verify in accordance with IPO! 7, Attachment 2,
" Primary Containment Closeout," that areas within the drywell, including the drywell general area, were free of trash, tools, and loose articles is a vintation (050-331/98008-01(DRP)). The loose debris removed filled roughly one-quarter trash bag, which was less than the amount of debris assumed in the design loading factor for the emergency core cooling system suction strainers.
Subsequent to the inspectors' drywell tour, the licensee conducted another primary containment closecut inspection and removed additional loose debris that amounted to less than one-quarter of a trash bag. The inspectors conducted a second drywell tour and were satisfied with the material condition.
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Conclusions The inspectors assessed the drywell material condition following the primary containment closeout inspection by operations personnel and determined that the licensee failed to adequately verify that the drywell general area was free of trash and debris during the primary containment closeout inspection for RFO 15. This resulted in a violation.
O3 Operations Procedures and Documentation O3.1 Standby Gas Treatment System (SBGT) Operation Exceeded 720 Hours Without Testina (71707)
a.
Inspection Scope i
The inspectors reviewed the licensee's process of tracking SBGT run time and the Technical Specification (TS) requirements for testing (TS 3.7.L.2/4.7.L.2).
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b.
Observations and Findinas On May 20,1998, operations personnel determined that the train "A" SBGT system had exceeded 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> run time without the TS-required high energy particulate filter and charcoal absorber bank testing having been conducted. The SBGT system run time was actually 775 hours0.00897 days <br />0.215 hours <br />0.00128 weeks <br />2.948875e-4 months <br /> and 58 minutes.
Operators initiated Action Request (AR) 981462 and entered the 7-day limiting condition for operation action statement for one SBGT train being inoperable. Subsequently, the licensee concluded that the surveillance test interval had not been exceeded since the maximum allowable extension of 25 percent had not been fully used. The inspectors also reviewed the TS requirements and concluded that the surveillance intsrval with the extension had not been exceeded.
The licensee further reviewed the issue and found that the method for tracking SBGT system run time required operators to calculate run time only after the SBGT system was shutdown and therefore long run times could allow the interval to be exceeded. During shutdown periods, such as the time period during RFO 15, the licensee was susceptible to this problem since the OBGT system was run for long periods to purge the drywell atmosphere.
The licensee performed the required tests and the operations department was in the process of revising the run time tracking mechanism, c.
Conclusions One train of the SBGT system exceeded 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> run time without TS-required testing being conducted. However, the 25 percent allowable extension to the surveillance interval was not fully used. The cause of the problem was an ineffective run time tracking mechanism. The required testing was performed and the licensee was revising the run time tracking procedure.
Miscellaneosa Ope.retions issues (92700)
08.1 (Closed) Unresolved item (URI) 50-331/98004-03: Configuration Control Problems During Refueling Outage 15. On April 19,1998, during the conduct of Surveillance Test Procedure (STP) 43B007, " Scram Discharge Volume Valve Time Quarterly Test," the scram discharge volume drain isolation valves failed to close. Manual Jacking mechanisms were found in the open position rather than the required neutral position per Operating Instruction (01) 255, " Control Rod Drive Hydraulic System." The jacking mechanisms were repositioned and the valves tested satisfactorily. The licensee failed to determine the exact cause of the mispositioning but concluded that the likely cause was operator error during lineup activities. Corrective actions included initiation of a training request to review the proper operation of these unique valves and a procedure change to maintain the valve actuators locked in the neutral position. -The failure to properly implement 01255 was considered to be a violation of TS 6.8.1.1, " Plant Procedures" which required, in part, that nuclear safety system and component operating procedures be implemented (50-331/98008-02(DRP)). This non-repetitive, licensee identified and corrected violation is being treated as a non-cited violation, consistent with Section Vll.B.I of the NRC enforcement policy.
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An operator identified a second configuration control problem on April 26 when the cooling water riser (V18-0830) and the exhaust riser (V18-0741) valves for control rod hydraulic control unit 30-19 were found closed. Identification of this problem was fortuitous in that the operator noted the discrepant condition during other activities in the area. Based on followup investigation, the licensee determined that the most likely cause of the event was valve mispositioning during friction testing on April 24. Surveillance Test Procedure NS55004, " Control Rod Drive Friction Testing," required operation of the cooling water valve but not the exhaust valve. The licensee also determined that the exhaust valve must have been open during friction testing because the control rod successfully passed the tests. The inspectors reviewed the procedure and noted that no independent verification was required and that the procedure did not designate velves by number, but rather just specified in Step 7.9.1, that cooling water was restored.
Step 7.9.1 was initialed by the control room operator once the operator in the plant performed the valve line-up. At the conclusion of the inspection, the licensee had initiated a procedure change to STP NS550004. This change included valve position
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verification requirements and clearer means of tracking which valves were operated. The i
failure to properly implement STP NS55004 was considered to be a violation of TS 6.8,
" Plant Procedures"(50-331/98008-03(DRP)). This non-repetitive, licensee identified and corrected violation is being treated as a non-cited violation, consistent with Section Vll.B.I of the NRC enforcement policy.
I 11. Maintenance l
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M1 Conduct of Maintenance M1.1 General Comments a.
Inspection Scope (62707) (61726)
The inspectors observed and/or reviewed all or portions of the following work activities.
The inspectors also reviewed applicable portions of the TS and the Updated Final Safety Analysis Report (UFSAR).
Main steam line radiation monitor channel calibration, Corrective Maintenance
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Action Request (CMAR) A48425 Residual heat rernoval logic functional test, STP 3.3.5.1-15
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Emergency diesel generator overspeed trip test
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Reactor vessel hydro test, STP 46G022 j
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Manual scram functional test, STP 3.3.1.1-22
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l Scram discharge volume high water level calibration, CMAR A52438
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l 4 KV Emergency bus degraded voltage functional test, STP 3.3.8.1-01
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Automatic scram functional test, STP 3.3.1.1-22
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Observations and Findinas i
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Maintenance and surveillance activities were performed satisfactorily. The inspectors observed that work packages were complete, approved procedures were used, and activities were conducted using conservative maintenance practices. The inspectors did not identify any substantive concems as a result of these observations and reviews, i
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Conclusions The inspectors concluded that work activities were effectively performed and well-controlled. A concem with attention to detail during the performance of loss of offsight power-loss of coolant testing is described below.
M1.2 Licensee Identified Mispositioned Valve Durina Loss of Off Off-Sioht Power-Loss of Coolant Accident (LOOP - LOCA) Testina (61726)
a.
Inspection Scope On April 30,1998, inspectors observed the control room staff during portions of STP 3.8.1-07, Revision 0, " LOOP-LOCA Test."
b.
Observations and Findinas Operations personnel were conducting STP 3.8.1-07, " LOOP-LOCA Test," when the test conductor / coordinator, who was on shift as the shift technical advisor (STA), identified that the outboard torus cooling / spray valve, MO-2005, was mispositioned. Step 7.1.1. l.
required the valve to be in the open pos~ition and the valve was found in the closed position. The step had been initialed as completed by an operator and had been peer checked by the STA; however, during the completion of Step 7.4.32, which required a verification that the residual heat removal and core spray systems were lined-up to start and run on minimum flow, the STA found valve MO-2005 in the closed position. The surveillance test was complex and infrequently performed; therefore, the licensee had assigned the STA as a test conductor / coordinator. The STA was responsible, in part, to perform a peer check, or a proper verification of completion of steps, as an additional i
measure to ensure that the test configuration was correct. The peer check was not f
required per the surveillance test procedure. The surveillance testing was stopped and Action Request (AR) 981354 was written to document tne valve mispositioning.
Operations personnel subsequently verified that all valves associated with the STP were in the proper position.
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l The mispositioning was identified and corrected prior to initiating the LOOP-LOCA test signal; therefore, no adverse effects resulted from the mispositioned valve. Also, if the l
l mispositioning was not identified, Step 7.4.56, which would have been performed later in i
the surveillance test, required that the torus cooling test valve, MO-2007, be throttled open and flow data be recorded. if valve MO-2005 was closed, there would have been
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l no flow through valve MO-2007, and the test would have been stopped to determine the
cause.
I Several factors led to the valve mispositioning and the missed peer check. Steps 7.1.1.a.
through I. verified that eight valves were in the closed position, and that the ninth valve, MO-2005, was in the open position. The operator read out loud each step as he closed the valves. ' When he read Step 7.1.1.1. out loud for the ninth valve, he incorrectly stated that it should be closed and therefore, he positioned the valve closed. The operator's mind-set, due to the closing of the previous eight valves, was to close valve MO-2005.
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Also, the STA performed his peer check by listening to what the operator said and was not reading the STP steps; therefore, when the operator read that MO-2005 was to be closed, the STA peer checked that it was closed.
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The surveillance test was continued later the same day. Both the STA and operator were counseled prior to the survoihance test continuation. Additionally, the STA performed a peer check by reading the STP, then determining if each step we properly completed.
No errors occurred through the completion of the test.
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Conclusions The licensee was proactive in establishing a test ccnductor/ coordinator for the complex and infrequently performed LOOP-LOCA test. The test conductor / coo;dinator was responsible for performing verification of completion of steps as an additional measure to ensure proper test configuration. However, the mispositioning of a valve during the LOOP-LOCA test demonstrated a lack of attention to detail by the operator. Additionally, the test conductor / coordinator failed to properly perform his venfication function by nut reading the procedure steps himself and then verifying proper actions. The mispositioning was licensee identified and corrected during the conduct of the surveillance test.
M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Plant Material Condition a.
~ Inspection Scope (62707)
The inspectors reviewed several emergent work items to ensure appropriate operability evaluations were performed, TS were met, repairs were made, and root causes were determined where appropriate.
b.
Observations and Findinas The inspectors noted that there were several emergent equipment issues during the inspection period. The examples are listed below:
On May 26,1998, the "A" reactor feedwater motor developed an oil leak within
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several days after startup activities. A downpower was initiated and repairs were completed on May 29. The "A" feedwater pump was retumed to service and reactor power was increased to 100 percent.
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l On May 8,1998, the "C" main steam isolation valve (MSIV) failed its local leak
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l rate test; however, it satisfactorily passed the accumulative leak rate test. After further investigation by contract personnel, the licensee determined that the "C" inboard MSIV piston disk had a 180" through wall crack. Regarding past operability, the piston was extensively tested by contract personnel and was.
considered to have been able to perform its design function. Additional piston disks wnre examined and no through wall cracks were identified. On May 18, the contractor (Ralph A. Hiller Company) submitted a 10 CFR Part 21 notification to the NRC. The licensee replaced the cracked piston disk.
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Conclusions The licensee promptly resolved emergent equipment issues that were identified during the !nspection period. All of these equipment problems were resolved within the associated TS allowable outage times.
M7 Quality Assurance in Maintenance
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M7,1 Missed Quality Control Hold Points (61726)
a.
Inspection Scope The inspectors reviewed several action requests that documented missed quality control (QC) hold points and the various maintenance action requests associated with the work.
I The inspectors also reviewed several QC procedures. Below is a list of documents reviewed.
AR 9802329802321F206 had to be reopened for a missed QC closure
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i exam AR 981048981048Missed QC inspection point for reinstalling control
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rod drive (CRD) hatch AR 981050981050QC Hold Point missed during system closure
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CMAR A42132 Inspect / repair va;<e MO 1039
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CMAR A42133 Inspect / repair valve MO 1041
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Preventive Maintenance Remove and reinstall CRD Hatch
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Action Request (PMAR)
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PMAR 1104280 Replace filter 1F206
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Administrative Control Cleanliness Control Program
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Procedure (ACP) 1408.13 ACP 1415.2 Performance of Quality Control Inspection
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b.
Observations and Findinas On March 24,1998, maintenance workers replaced a filter in a radwaste system and failed to notify the QC inspector to perform the closure examination specified in the maintenance action request form.: Shortly after the filter housing was closed and bolted, the foreman recognized the missed QC cleantiaess inspection. The QC inspector was called, the filter housing was unbolted, and the inspection performed.
On April 23, during the review of completed PMAR 1100325 which was used to remove I
and reinstall the CRD hatch, the project lead identified that QC required inspections of the o-ring and the o-ring seating surface had not been performed. Once discovered, work was stopped, the hatch removed, and new QC inspected o-rings were installed.
l On May 1, the quality assurance organization identified that QC cleanliness inspections were not performed after the replacement of Valves MO-1039 and MO-1041. These valves are steam drain valves to the condenser from piping upstream of the turbine stop valves. Maintenance Action Requests A42132 and A42133 specified a system closure inspection by QC but the inspection was performed by the craftsperson performing the
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work. After the AR was written to document the issue, QC personnel concluded that the
closure inspection was not mandatory because the system was designated as cleanliness Class D. Administrative Control Procedure (ACP) 1408.13, " Cleanliness Control Program," required that all systems designated as cleanliness Class B or C receive a closure inspection, but the inspection was optional for cleanliness Class D. The procedure also stated that cleanliness inspections should be performed by QC personnel and/or the work group in accordance with the requirements and guidelines of the i
procedure.
l The inspectors reviewed QC procedures and concluded that although the maintenance planner designated QC inspections in all three cases, actual quality control involvement was required for only one work activity, the replacement of o-rings during reinstallation of the control rod drive hatch. In this case, the failure to implement ACP 1415.2,
" Performance of Quality Control inspection," as specified by CMAR 1100325 was considered to be a violation of 10 CFR Part 50, Appendix B, Criterion X, " Inspections,"
(50-331/98008-04(DRP)). However,' identification of the discrepancy and corrective action ultimately resulted in the required inspection being completed..This non-repetitive, licensee identified and corrected violation is being treated as a non-cited violation, l
consistent with Section Vll B.l of the NRC enforcement policy.
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Conclusions The licensee appropriately identified and corrected issues involving missed QC inspections during the refueling outage. The inspector determined that in only one of three cases was the QC inspection required per the governing QC inspection procedure.
Corrective action in that case resulted in re-performing the work with the proper QC involvement. Although QC inspections were not required by the administrative
procedure, they were specified in the maintenance action request package and the failure J
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to perform the inspections as specified indicated a lack of attention to detail. Because the licensee identified and resolved the bsues, this was considered to be a non-cited
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l M8 Miscellaneous Maintenance issues (92903)
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M8.1 - - (Closed) URI 50-331/98004-05(DRP): Inadequate Post-Maintenance Testing. On
Amit 3,1998, the primary containment isolation system (PClG) Group i relay (A71B-K057)
fer the recirculation sample line outboard valve failed to perform its intended function and deenergize afterinitiation of a PCIS Group Iisolation signal; Therefore, the associated recirculation sampie line outboard valve did not close. The redundant inboard isolation valve did close as required. The licensee determined that mechanical binding prevented the relay from dropping out. The mechanical binding was due to improper retainer
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replacement during corrective maintenance and the reassembly of the relay on i
December 16,1997. Therefore, the recirculation sample line outboard valve was considered inoperable by both the inspectors and the licensee from December 16,1997, until April 3,1998. The relay was replaced on April 3,1998.
The April 3,1998, engineered safety feature actuation occurred after corrective j
maintenance was performed on the relay. Management Directive (MD) 24 provided instructions to be used by shift supervisors, and maintenance coordinators, olanners, and l
supervisors in specifying and reviewing post-maintenance testing. As detr.iled in the
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a attached Notice of Violation, the failure to verify that the relay was able to perform its intended function following maintenance was a violation of TS 6.8.1.5, MD 24, " Post-Maintenance Testing Program,"(50-331/98008-05(DRP)).
Although the recirculation sample outboard isolation valve failed to close, the primary containment isolation was accomplished by the closing of the redundant inboard isolation valve, CV-4639. During RFO 15, the results of the containment leak tightness surveillance testing demonstrated that CV-4639 was well within leak tightness limits.
Once the failure of the PCIS Group i recirculation sample line outboard valve was recognized, the licensee took the appropriate action. In accordance with TS 3.7.B.2, immediate corrective actions were taken to isolate the affected penetration. The suspect relay was replaced. The licensee tested the intended functions of all relays that had been worked on for relay coil replacements. The relays tested satisfactorily. Long term corrective actions were to provide additional training to engineers and operators regarding post-maintenance testing requirements.
111. Enaineerina E1 Conduct of Engineering l
E1.1 HPCI System Hioh Eneroy Line Break (37551)
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Inspection Scope
The inspectors reviewed action requests and calculations associated with a postulated HPCI system high energy line break (HELB). Below is a list of documents reviewed.
l Calculation (CAL) -
Strength of doors 204,219, and 220
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M-93-038 CAL-M98-045 Pressure / Temperature Response to HPCI and RCIC
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l HELBs CAL-C-98-001 HPCl/RCIC Room Pressurization Capability I
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Design Basis HELB Outside Containment j
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Document (DBD)
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AR 970842970842HPCI HELB Analysis
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AR 97084297084201 HPCI and RCIC room doors do not meet pressure j
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requirement AR 97084297084202 Track completion of CMARs A47507, A47599, and A47598
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(Replace hinges on doors 204,219, and 220)
AR 97084297084203 Strength of corridor wall outside HPCI room has inadequate i
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" design margins" for HELB event AR 97084297084204
"Past operability" evaluation of HPCI room wall
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UFSAR 3.6 Postulated Piping Failures in Fluid Systems Outside
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l Containment
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b.
Observations and Findinas On April 3,1998, AR 97084297084201 was written which documented that the HPCI room door hinges had been installed incorrectly. The inspectors reviewed the licensee's actions to resolve the issue described in the AR, which stated, "During the investigation, it was determined that supports were required to provide the margin necessary for designing as left design margin for the HPCI room wall along the corridor to the RCIC room." An addendum AR was written on May 5 to document this problem and track corrective
' actions. During the refueling outage, the licensee replaced the door hinges and strengthened the HPCI room wall. The inspectors questioned the deportability of this issue under the criterion of 10 CFR 50.73(a)(2)(ii)(B), any event or condition that resulted in the nuclear power plant being in a condition that was outside the design basis of the plant.
The document describing how the HPCI and RCIC room door issue was resolved referenced two calculations, CAL C98-038, which documented the strength of the doors and the hinges, and CAL-M98-045, which documented the HPCl/RCIC HELB analysis.
The results of the HELB analysis, dated May 9,1998, indicated that peak conditions in the HPCI room were approximately 300*F,6.3 psi, and 100 percent humidity. The RCIC room peak conditions were 286*F,3.5 psi, and 100 percent humidity. Previous calculations showed lower peak pressures (e.g.,2.91 psi for the HPCI room). The inspectors briefly reviewed the calculations and determined that the change in peak conditions was due to advanced technological modeling and calculations and was not due to calculational errors in the original equations. Based on the results of the door strength analysis, the licensee concluded that while the door hinges had been installed incorrectly, the doors would withstand the recalculated peak pressures.
As a result of the higher portulated pressures, the licensee took a conservative approach and broadened its assessment by performing an analysis of the room walls. The results of the analysis, as stated in CAL-C98-001, concluded that all walls were acceptable except for the HPCI room hallway wall. This wall required additional structural steel reinforcing along the top of the wall. With the addition of the reinforcements, the wall was calculated to withstand 6.6 psi. The licensee initially estimated the failure pressure of the wall without the supports to be from 4.2 to 4.9 psi. Subsequent calculations showed the failure pressure to be 4.35 psi.
The inspectors reviewed the UFSAR, Section 3.6, and concluded that prior to recent upgrades of the HPCI wall, the plant had been outside the design basis in that the HPCI compartment (room; would have been overpressurized. Specifically, the inspectors relied upon the following portions of the UFSAR.
UFSAR 3.6.1.2.4.5 described the compartment pressure analysis model and
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stated, "The analyses conducted yielded pressure versus time relationships that were used to determine if the structures surrounding the affected compartments
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UFSAR 3.6.1.2.3 described the substantial concrete walls in the plant as an
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inherent safety feature in that these walls, required for radiation shielding
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physical separation between the high energy lines and other equipment.
UFSAR 3.6.1.3.3 stated that HPCI and RCIC steam lines were analyzed per
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l Generic Letter 87-11 and were postulated to break only at the terminal ends.
Thus only the steam tunnel and HPCI and RCIC equipment rooms are affected.
Based on these UFSAR statements, the inspectors determined that the plant had been outside the design basis in that the HPCI room wall was not capable of withstanding the
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pressurization due to the HELB event. As a result, a licensee event report was required within 30 days of discovery of the condition. The AR documented the discovery on
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May 5,1998. Therefore, the failure to submit the required licensee event report as of (
June 5 was determined to be a violation of 10 CFR Part 50.73(a)(2)(ii)(B)
(50-331/98008-06(DRP)).
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The licensee did not initially consider the discovery of this condition as reportable and t
began an analysis to determine the environmental effects of a postulated failure of the HPCI room wall. That analysis concluded that other portions of the reactor building would not be adversely affected (i.e., would not become a harsh environment and threaten safe
. shutdown of the plant) by the release of steam from the room.
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Conclusions During the refueling outage, the licensee discovered that HPCI peak room pressure during a postulated high energy line break would reach 6.3 psi and that one HPCI room wall could not withstand that pressure. The licensee conservatively broadened its assessment by including the HPCI room walls after its initial assessment of the peak pressura on the HPCI room doors. The licensee took appropriate corrective actions by strengthening the well but failed to report this condition to the NRC in a licensee event report. Without intervention by the inspectors this issue would not have been reported.
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This was a violation of 10 CFR Part 50.73(a)(2)(ii)(B).
V. Mananoment Meetinos X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on June 9,1998. The licensee acknowledged the findings presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.
X3 Management Meeting Summary On May 19,1998, a management meeting was conducted in the Region ill office to discuss a number of self-revealing events that occurred during the first several weeks of RFO 15 due to human errors, communication problems, planning and scheduling deficiencies, and poor procedural adherence.
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PARTIAL LIST OF PERSONS CONTACTED Licensee -
J. Franz, Vice President Nuclear G. Van Middlesworth, Plant Manager R. Anderson, Manager, Outage and Support J. Bjorseth, Maintenance Superintendent D. Curtland, Operations Manager R. Hite, Manager, Radiation Protection i
M. McDermott, Manager, Engineering K. Peveler, Manager, Regulatory Performance j
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INSPECTION PROCEDURES USED IP 37551:
Onsite Engineering IP 61726:
Surveillance Observation IP 62707:
Maintenance Observation IP 71707:
Plant Operations IP 71711:
Plant Startup From Refueling IP 92700:
Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92903:
Followup - Maintenance ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-331/98008-01 VIO Failure to verify drywell clean of trash, tools, and loose articles.
50-331/98008-02 NCV CRD cooling water valve found out of position.
50-331/98008-03 NCV CRD hydraulic system valves found out of position.
50-331/98008-04 NCV Failure to implement quality control procedures.
50-331/98008-05 VIO Inadequate post maintenance testing.
50-331/98008-06 VIO Failure to report condition outside of the design basis.
Closed 50-331/98004-03 URI Configuration control problems during RFO 15.
50-331/98004-05 URI Inadequate post maintenance testing.
50-331/98008-02 NCV CRD cooling water valve found out of position.
50-331/98008-03 NCV CRD hydraulic system valves found out of position.
' 50-331/98008-04 NCV Failure to implement quality control procedures.
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LIST OF ACRONYMS USED I
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ACP Administrative Control Procedure AR Action Request CAL-Calculation CMAR Corrective Maintenance Action Request CRD.
Control rod drive DAEC.
Duane Amold Energy Center DBD Design Basis Document HELB High Energy Line Break HPCI High Pressure Coolant injection IPOl Integrated Plant Operating Instructions l
LOOP-LOCA Loss of off-sight power-Loss of coolant accident MD Maintenance Directive MSIV Main SteamLline Drain NOV Notice of Violation
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NRC Nuclear Regulatory Commission O!
Operating instruction PCIS
- Primary Containment isolation System r
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PSI Pounds per Square Inch (
PSIG Pounds per Square Inch Gauge
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QC Quality Control RCIC Reactor Core Isolation Cooling RFO Refuel Outage SBGT-Standby Gas Treatment System STA Shift Technical Advisor STP Surveillance Test Procedure TS Technical Specification UFSAR Updated Final Safety Analysis Report URI Unresolved item VIO Violation
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