IR 05000331/1999004
| ML20195F225 | |
| Person / Time | |
|---|---|
| Site: | Duane Arnold  |
| Issue date: | 06/09/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20195F222 | List: |
| References | |
| 50-331-99-04, 50-331-99-4, NUDOCS 9906140228 | |
| Download: ML20195F225 (16) | |
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U. S. NUCLEAR REGULATORY COMMISSION REGION lli Docket No:
50-331 License No:
DPR 49 Report No:
50-331/99004(DRP)
Licensee:
Alliant, IES Utilities Inc.
200 First Street S.E.
P. O. Box 351 Cedar Rapids, IA 52406-0351 Facility:
Duane Arnold Energy Center Location:
Palo, Iowa Dates:
April 14 through May 25,1999 Inspectors:
P. Prescott, Senior Resident inspector M. Kurth, Resident inspector Approved by:
M. N. Leach, Chief Reactor Projects Branch 2 Division of Reactor Projects l
9906140228 990609
PDR ADOCK 05000331 G
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EXECUTIVE SUMMARY Duane Arnold Energy Center NRC inspection Report 50-331/99004(DRP)
This inspection report included the resident inspectors' evaluations of aspects of licensee operations, engineering, maintenance, and plant support.
Ooerations The inspectors determined that operations personnel were effective in performing an
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error-free shutdown to identify and repair an intermittent main generator field ground alarm (Section 01.1).
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l The inspectors noted a slight decline in the use of three-way communications and panel
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attentiveness by operators during routine operations. The licensee's initial corrective actions appeared effective (Section 01.1).
The inspectors noted that degraded equipment and instrumentation were evaluated
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monthly or quarteriy as required per procedures. One minor discrepancy was corrected
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by operations management after the inspectors found a degraded sticker on the control
. room panel gauge that had been previously repaired (Section O2.2).
Maintenance The "A" feedwater regulator valve positioner replacement was satisfactorily completed
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and in accordance with plant procedures. Maintenance personnel were effective in completing the work and post-maintenance testing (Section M1.2).
The licensee was effective in troubleshooting and repairing the intermittent main
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generator field ground alarm and the hydrogen / oxygen monitor trouble alarm (Section M2.1).
In May 1998, improper planning caused the licensee to replace the standby liquid
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control system explosive valves without performing the required post replacement testing. This was not identified until after the standby liquid control system was returned to service and the reactor coolant temperature reached 212 degrees Fahrenheit.
Therefore, a Non-Cited Violation resulted from the failure to properly restore or isolate the standby liquid control system explosive valves prior to reaching the reactor coolant i
temperature of 212 degrees Fahrenheit (Section M8.1).
Enaineering
System engineering staff were effective in ensuring flood control materials and i
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equipment were staged and available prior to the river water level reaching the flood i
stage (Section E1.1).
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Plant Sucoort
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The licensee was effective in determining several contributing factors that led to an
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job activity (Stsction R1.1).
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Report Details Summarv of Plant Status The licensee operated the plant at 100 percent power at the beginning of the inspection period.
On April 16,1999, the licensee initiated a planned reactor shutdown to investigate and repair the cause of an intermittent main generator field ground alarm. Following repairs and main
generator reassembly, operators commenced a reactor startup on April 29. Full power was reached on May 3.
On May 8, operators reduced power to 50 percent to replace the "A" feedwater regulator valve positioner. Operators returned the plant to full power on May 9.
I. Operations
Conduct of Operations
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01.1 Observations of Routine Activities and Planned Power Reductions and Ascensions a.
Insoection Scope (71707)
The inspectors conducted numerous reviews of ongoing plant activities. These reviews included observations of control room shift tumovers and operator performance during plant evolutions. The inspectors interviewed operations personnel regarding plant status and events and reviewed daily logs.
On April 16,'1999, the inspectors observed licensee activities during a power shutdown to investigate and repair an intermittent main generator field ground alarm. Also, on May 8, a power reduction to 50 percent was observed for replacement of the "A" feedwater regulator valve positioner. This included observation of portions of operations shift activities, management and reactor engineering briefings, operators use of procedures, and cooperation between control room and in-plant operators. In addition, the inspectors observed startup activities after repair of the main generator field ground alarm. The following procedure was reviewed:
Administrative Control Procedure (ACP) 1410.1, " Conduct of Operations,"
Revision 21 b.
Observations and Findinas The inspectors observed that all operators were attentive to shift briefings and were involved in good exchanges of information. The briefings were focused and
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Operations personnel performed an error-free power shutdown on April 16 through April 17 1999. The inspectors noted good communications between operating crew members during the evolution. Also, on May 8, operators performed a well controlled plant power reduction to 50 percent for replacement of the "A" feedwater regulator positioner.
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During control room observations, the inspectors noted that operators were effective in using three-way communications during infrequently performed evolutions, such as power reductions or plant shutdowns. However, a slight decline in the use of three-way communications was observed during routine operations. Several examples of inconsistent three-way communications by control room operators and/or plant operators were noted:
On April 14,1999, during the conduct of Surveillance Test Procedure
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On April 22,1999, during the performance of STP NS490002, "LPCI Inject
Check Valve Full Flow Test"; and On April 29,1999, during the conduct of general work activities.
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The lack of three-way communications varied with individuals and operating crews, in addition, control room operators were, in general, alert and attentive to control room instrumentation during infrequently performed evolutions. However, when the plant was being operated in a sustained condition, such as at full power or in shutdown, a subtle decline in panel attentiveness was noted. One example occurred on April 27,1999, when the reactor water level slowly drifted upward due to the limited ability and sensitivity of the reactor water cleanup to radwaste dump valve to radwaste to control water level. During a panel walkdown, the inspectors observed the reactor water level had trended upward trend until the reactor water level high annunciator alarmed. During this observation period, operators were focused on completing other work activities and did not provide appropriate attention to this panel indication. After the alarm was received an operator took actions to reduce the water level and cleared the annunciator.
The three-way communications and panel attentiveness issues were discussed with licensee management. The licensee was receptive and active in initiating changes. The inspectors noted that operators' three-way communications and panel attentiveness had improved following the inspectors' discussions with licensee management.
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Conclusions Operators were effective in performing an error-free shutdown to identify and repair an intermittent main generator field ground alarm. The inspectors noted a slight decline in
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the use of three-way communications and panel attentiveness by operators during routine operations. The licensee's initial corrective actions appeared effective.
02 Operational Status of Facilities and Equipment O2.1 General Plant Tours and System Walkdowns (71707)
The inspectors followed the guidance of Inspection Procedure 71707 in walking down
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accessible portions of several systems. The systems chosen, based on maintenance work activities and probablistic risk significance, were:
125 Volt direct current system
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control rod drive 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.
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O2.2' Review of Control Room Dearaded Instrumentation
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Inspection Scope (71707)
The inspectors performed a detailed walkdown of control room instrumentation to identify all degraded instruments. Results of the walkdown were compared to the licensee's control room degraded indication log. An audit of existing caution tags in the control room was also performed. The inspectors reviewed the following procedures and logs:
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Operations Department Instruction (ODI)-12. " Degraded Control Room
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Instrumentation," Revision 4 Test Procedure OP-001, " Quarterly / Monthly Tagout, Temporary Modification and
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Degraded Control Room Instrumentation Audit" ACP 1410.5, "Tagout Procedure"
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Degraded Control Room Instrumentation Log
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Tagout Log
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- Observations and Findinos During the walkdowns conducted in the control room, the inspectors noted that all '
degraded instrumentation was properly identified.- The operators were following the guidance in ODI-12 in identifying and labeling control room indication judged to be operable but in a degraded condition. The inspectors performed an audit of the current Degraded Control Room Indication Log. One deficiency was noted. The main generator field amperage Gauge iT3602 had been repaired and the control room
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I degraded instrument sticker removed, however, this activity was not cleared in the degraded instrument log. Once identifiex1, this was promptly corrected by the onshift
-- shift supervisor At the time of the inspectors' review, there were 14 active control room degraded indication tags. The inspectors noted that eight of the degraded indication tags were older than 6 months. The inspectors determined that Action Requests (AR)
were written, as required, identifying that the degraded instrumentation tags had exceeded a 6 month duration time limit. The last monthly audit of the Degraded Control Room Instrumentation Log had been performed as required by Procedure OP-001, and the results of the audit were forwarded to the operations supervisor. The inspectors also noted that there were 15 caution tags on components in the control room. The caution tags were used to indicate circuit or equipment conditions or provided instructions for equipment operations. Caution tags were generally used for equipment that was also degraded in some manner (e.g., pumps whose hand-switch could not be used for remote operation or a pump with high vibration that should only be operated if absolutely necessary). The caution tags were filed in the Tagout Log and reviewed on a quarterly basis per Procedure OP-001,
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Conclusions The inspectors noted that degraded equipment and instrumentation were evaluated monthly or quarterly as required per procedures. One minor discrepancy related to log keeping was corrected by operations management after the inspectors found a degraded sticker on the control room panel gauge that had been previously repaired.
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Miscellaneous Operations issues (92901)
08.1 (Closed) Licensee Event Report (LER) 50-331/98001-00: On January 9,1998, control room staff was below a Technical Specification (TS) minimum requirement. In accordance with TS Table 6.2-1, a shift technical advisor (STA) was required to be
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onsite during power operations. For 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and 11 minutes an STA was not onsite due i
to a family medical emergency. Operations management was aware of the circumstances and allowed the STA to leave knowing another STA was en route to the j
site. As of August 1998, the licensee has implemented improved TS which allows a two hour grace period to allow for extenuating circumstances, such as in this example. This was considered to constitute a violation of minor significance and is not subject to formal enforcement action in accordance with the NRC enforcement policy. This item is closed.
The Severity Level IV violations listed below were issued in Notices of Violation prior to the March 11,1999, implementation of the NRC's new policy for treatment of Severity Level IV violations (Appendix C of the Enforcement Policy). Because these violations would have been treated as Non-Cited Violations in accordance with Appendix C, they are being closed in this report.
08.2 (Closed) Violation (VIO) 50-331/98006-01: Inadequate operating log entries for work on reactor manual control (RMC) system. This violation was in the licensee's corrective action program as AR 980769980769
08.3 (Closed) VIO 50-331/98008-01: Failure to verify drywell clean of trash. This violation was in the licensee's corrective action program as AR 12751.
II, Maintenance M1 Conduct of Maintenance M1.1 General Comments a.
Inspection Scope (62707 and 61726)
The inspectors observed all or portions of the surveillance test activities and work request activities listed below. The applicable test or work package documentation was reviewed. Specific tests and work request activities observed are listed below:
Maintenance Activities Corrective Maintenance Action Request (CMAR) 1108136: Position Modulator a
Replacement for CV-1579 ("A" feedwater regulator valve)
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Corrective Work Order (CWO) A48846: Main Generator Field Circuit Testing
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Plan CWO A43723: Disassembly and Testing for Main Generator Field Ground
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CWO A40172: "A" Standby Diesel Generator Lube Oil Strainer Leak Repair
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Surveillance of Activities STP 3.1.4-01, " Scram Insertion Time Test"
STP 3.3.1.1-12, " Discharge Volume High Water Level Calibration"
STP 3.5.1-09, "HPCI System Post Startup Operability Test"
STP 3.8.1-06, " Standby Diesel Generators Operability Test"
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STP 3.8.1-07, " LOOP-LOCA Test"
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NS490002, "LPCI Inject Check Valve Full Flow Test"
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Observations and Findinas The inspectors noted that, in general, licensee personnel conducted the work associated with these activities in a professional manner. Technicians were i
knowledgeable of their assigned tasks and work document requirements. Comments
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on specific items are detailed in the proceeding sections.
M1.2 Feedwater Reaulator Valve Positioner Reolacement l
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Insoection Scope (62707)
The inspectors observed the position modulator replacement for the "A" feedwater regulator valve. The work activities were provided in CMAR 1108136. Interviews were conducted with technicians performing the work activities.
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Observations and Findinas
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On May 8,1999, instrument technicians conducted a pre-job briefing to replace the
"A" feedwater regulator positioner. The work planners and technicians thoroughly defined responsibilities of test support personnel and discussed all aspects of the maintenance during the briefing. Instrument and calibration (l&C) engineers directed
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j the maintenance and provided effective insights on the positioner replacement. The
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l&C technicians were knowledgeable and proficient in completing the maintenance activities. Good coordination was noted between maintenance and engineering in completing the maintenance. The post-maintenance testing results were satisfactory and the "A" feedwater system was returned to service that same day.
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Conclusions The "A" feedwater regulator valve positioner replacement was satisfactorily completed and in accordance with plant procedures. Maintenance personnel were effective in completing the work and post-maintenance testing.
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M2 Maintenance and Materiel Condition of Facilities and Equipment
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M2.1 Plant Material Condition a.
Insoection Scope (62707 and 61726)
The inspectors reviewed several emergent work items to ensure that appropriate operability evaluations were performed, TS were met, repairs were made, and root causes were determined where appropriate.
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Observations and Findinas The emergent equipment issues followed by the inspectors during the inspection period were:
On April 17,1999, a plant shutdown was commenced to troubleshoot and repair
the intermittent main generator field ground alarm. The licensee identified a torn copper " leaf" used to connect the positive main terminal studs to the main generator field. On April 29,1999, the licensee commenced a reactor startup following repairs to the main generator.
On May 3,1999, operators, on occasion, noticed slight variations in the
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"A" feedwater flow control room instrumentation. Engineering and maintenance personnel developed a work package and on May 8,1999, instrument technicians removed and replaced the "A" feedwater regulator positioner.
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On May 5,1999, operators received a hydrogen / oxygen monitor trouble alarm.
The necessary 30 day LCO was entered and further investigation revealed that the terminal screw for a heat trace sample point was loose. Within three hours after receiving the alarm, the screw was tightened and the trouble alarm was -
cleared. The operators exited the LCO condition.
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Conclusions
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The licensee was effective in troubleshooting and repairing the intermittent main generator field ground alarm and the hydrogen / oxygen monitor trouble alarm.
M8-Miscellaneous Maintenance issues (92903)
M8.1 (Closed) LER 50-331/98006 00: Inadequate post replacement test on standby liquid control (SBLC) system explosive valves. In April 1998 improper planning caused the
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I licensee to replace the Code Class 2 SBLC explosive valves without performing a post VT-2 examination. Technical Specification 3.6.G.1 and 4.6.G.1 required that Code Class 2 components be maintained and tested in accordance with American Society of Mechanical Engineers (ASME)Section XI Code. If the condition was not met,
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TS 3.6.G.2 required that the affected component be restored to its structural integrity or isolated prior to increasing the reactor coolant system temperature above 212 degrees Fahrenheit. The reactor coolant temperature had reached 212 degrees Fahrenheit prior to the licensee identifying that the explosive valve testing had not conformed with TS 3.6.G.1. Therefore, with TS 3.6.G.1 not met, the failure to properly restore or isolate the SBLC explosive valves prior to reaching the reactor coolant temperature of 212 degrees Fahrenheit on May 18,1998, was a violation of TS 3.6.G.2 (50-331/99004-01(DRP)). This Severity Level IV violation is being treated as a Non-Cited violation consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as AR 12060. Upon discomry, the ASW Section XI Code examination (VT-2 test) was performed and no problems were icientified. This item is closed.
111. Engineerina
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Conduct of Engineering i
E1.1 Enaineerina Suooort to Emeroent issues a.
Insoection Scooe (37551)
The inspectors evaluated engineering involvement with several equipment problems that occurred during the inspection period. The inspectors reviewed associated operability evaluations, root cause analyses, and self-assessments.
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Observations and Findinos Since January 1999 numerous main generator field ground annunciators have been received in the control room. On April 17,1999, a plant shutdown was commenced to determine and repair the cause of the main generator field ground alarms. The licensee worked with vendor representatives and other utility representatives to develop and perform troubleshooting efforts while the main generator was off-line. The licensee identified a tom copper " leaf" used to connect the positive main terminal studs to the main generator field. The main terminal studs were last removed during an outage in 1988 to support main generator preventive maintenance work. The licensee determined that the main terminal studs were over-torqued during reinstallation which led to the torn copper leaf. Through years of operation the tom copper pealed away from the main terminal stud due to centrifugal force and caused the intermittent grounds. The torn copper was repaired and the main generator was retumed to service.
On May 19,1999, at 5:47 a.m., the Cedar River water level reached the 742 foot elevation and operations personnei entered the required Abnormal Operating Procedure (AOP) 902, * Flood," Revision 12. Engineering personnel were effective in ensuring flood control materials and equipmeat were staged and available if needed prior to entering AOP 902. The inspectors i oted that several days prior to reaching this level, system engineering personnel were effectively trending river water levels with the assistance of the United States Geoegical Service. On May 20,1999, the river level crested at an elevation level of 743.7 feet. AOP 902 was exited on May 22 at 8:00 a.m.
when the river water level decreased to less than 742 feet. (Normal river water level ranged from 730 to 735 feet. At 744 feet water level, access to the river intake structure
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i is unavailable and at 757 feet, a reactor shutdown is required due to flooding concerns onsite.)
On May 13,1999, an annunciator in the control room alarmed indicating a power failure of the "A" residual heat removal (RHR) system logic. The necessary TS's were initiated
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and operations personnel discovered that a fuse had blown. Engineering and maintenance personnel performed troubleshooting efforts and determined that several l
wires had short circuited in the 1JX105A drywell penetration. Engineering personnel i
performed appropriate safety evaluations for the affected wires and systems. The short i
circuited wire leads were lifted using the Temporary Modification process. Meetings
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were conducted with operations, maintenance, and engineering to ensure that the
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troubleshooting efforts were thorough and the temporary modifications did not have a negative impact on safe plant operations. Warning tags were hung in the control room in accordance with the temporary mod'fications in place. The licensee was periodically
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i monitoring the remaining wires passing through the 1JX105A penetration to ensure that the short circuit did not have a negative impact on operations. The licensee initiated l
plans to correct the short circuit problem during the October 1999 refuel outage.
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Conclusions Engineering and maintenance departments were effective in identifying and correcting
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l the intermittent main generator grounding problem. Additionally, the system engineering staff was effective in ensuring adequate flood control materials and equipment were staged and available prior to river water level reaching the flood stage.
E8 Miscellaneous Engineering Issues (92902)
E8.1 (Closed) Inspection Followuo item 50-331/97007-04: Increased vibration on "A" residual I
heat removal service water (RHRSW) pump. Licensee's root cause determined that the l
increased vibration was due to broken locking collets on the line shaft sleeves. The collet failures were due to stress corrosion cracking. The collets are no longer being used on rebuilt / replacement pumps. For remaining pumps with the collet arrangement, vibration monitors will identify the need for pump replacement prior to the pump becoming inoperable. This item is closed.
E8.2 (Closed) LER 50-331/98004-00: Failure of four main steam relief valves and one main steam safety valve to meet TS setpoints. This event was addressed in inspection Report (IR) 50-331/98013(DRP), Section E8.2, and resulted in a Non-Cited Violation (50-331/98013-01) for failing to take corrective actions to address previous problems
with exceeding the setpoints. The licensee's corrective action was to expand the setpoint tolerances. This item is closed.
E8.3 (Closed) LER 50-331/98005-00: Inoperability of containment atmosphere hydrogen and oxygen monitors. This issue was addressed in IR 50-331/98004(DRP) and resulted in a l
Severity Level IV vialation (50-331/98004-08) for having inoperable hydrogen / oxygen in-line monitors at full power operations. The licensee has since implemented corrective l
actions. The Severity Level IV violation was closed in IR 50-331/99003(DRP). This item
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is closed.
E8.4 (Closed) LER 50-331/98007-00: Potential high pressure coolant injection (HPCI) room corridor wall steam leakage. This issue was addressed in IR 50-331/98008(DRP),
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Section E1,1. As documented, the inspectors briefly reviewed calculations and determined that the change in HPCI room peak pressure condition was due to advanced technological modeling and calculations and was not due to calculational errors in the original equations. Upon discovery, the licensee implemented corrective actions to provide additional wall support to maintain the wall's integrity during a high energy line break in the HPCI room. There was no potential safety consequence as a result of this condition. This item is closed.
The Severity Level IV violation listed below was issued in a Notice of Violation prior to the March 11,1999, implementation of the NRC's new policy for treatment of Severity Level IV violations (Appendix C of the Enforcement Policy). Because this violation
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E8.5 (Closed) VIO 50-331/98006-02: Inadequate post modification testing on RMC system.
This violation is in the licensee's corrective action program as AR 980733980733
IV. Plant Support R1 Radiological Protection and Chemistry Controls R1,1 Worker Receives Electronic Dosimeter (ED) Accumulated Dose Alarm a.
Inspection Scope (71750)
The inspectors reviewed the circumstances involving a worker who received an electronic dosimeter accumulated dose alarm. The inspectors conducted interviews and reviewed:
Radiation Work Permit (RWP) 224,' Step 1
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ACP 1411.21, ' Radiation Work Permits," Rev. 7
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ACP 1411.22, " Control of Access to Radiological Areas,* Rev. 8
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May 5,1999, Fact Finding Meeting Minutes.
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- Observations and Findinos On May 4,1999, a worker's ED alarmed as a result of reaching its accumulated dose alarm set point of 25 mrem. The individual was performing ultrasonic testing (UT)
examinations of welds on the RHR system piping which was located in a radiation area that varied from 0.2 to 50 millirem per hour. The worker immediately left the work area and reported the alarming ED to radiation protection personnel. The failure of the worker to follow the RWP requirements was considered to constitute a violation of minor significance and is not subject to formal enforcement action in accordance with the NRC enforcement policy.
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The licensee was effective in determining several contributing factors that led to the worker reaching his accumulated dose alarm set point:
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The worker did not remember the ED alarm set points; A health physics (HP) technician performed a radiological briefing prior to the
worker starting the job. The briefing did not include discussions regarding ED set points or alarms; The worker performed the UT examinations using a special RWP (RWP 224, -
Job Step 1). A briefing checklist developed for specific RWP's was not utilized; The RWP contained ambiguous language that suggested dose rate alarms were
acceptable; and There was confusion regarding the need to leave prior '.o receiving a cumulative
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dose alarm even though it was stated on the RWP.
Immediate corrective actions were taken to address the above mentioned contributing factors and the licensee planned longer term corrective actions in General Employee Training to emphasize the need for workers to leave the radiological area prior to I
receiving an accumulated dose alarm setpoint.
The inspectors reviewed the radiological work planning information used to develop the dose alarm setpoint and accumulated dose alarm setpoint for RWP 224, Job Step 1.
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The inspectors noted that the licensee work planner used a general room dose survey l
to determine the dose that the workers would be exposed to when performing the ultrasonic testing of the pipe welds. The actual dose levels the workers would be exposed to in working in close proximity to the piping were four to five times higher than the general dose information used to assign the dose alarming setpoints. If the planner had used specific piping survey results to develop the dose alarming setpoints, the setpoints would have been higher in relation to the work being performed. The inspectors reviewed five additional RWPs and did not identify any other work planning discrepancies. Therefore, this appeared to be an isolated occurrence.
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Conclusions The licensee was effective in determining several contributing factors that led to an individual reaching his accumulated dose alarm setpoint, which was not intended for this
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V. Manaaement Meetinas
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X1 Exit Meeting Summary
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The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on May 25,1999. The licensee acknowledged the findings l-presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.
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i PARTIAL LIST OF PERSONS CONTACTED Licensee R. Anderson, Manager, Outage and Support J. Bjorseth, Maintenance Superintendent D. Curtland, Operations Manager
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J. Franz, Vice President Nuclear R. Hite, Manager, Radiation Protection M. McDermott, Manager, Engineering K. Peveler, Manager, Regulatory Performance
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G. Van Middlesworth, Plant Manager i
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INSPECTION PROCEDURES USED
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IP 37551:
Onsite Engineering IP 61726:
Surveillance Observation IP 62707:
Maintenance Observation l
lP 71707:
Plant Operctions l
IP 71750:
Plant Support l
lP 92901:
. Followup - Operations l
IP 92902:
Followup - Engineering l
IP 92903:
Followup - Maintenance ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-331/99004-01 NCV Failure to meet TS in restoring the SBLC system i
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l 50-331/97007-04 IFl increased vibration on "A" RHRSW pump l
50-331/98001-00 LER Control room staff below TS minimum requirement
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50-331/98004-00 LER Failure of four MSRVs and one MSSV to meet TS setpoints
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50-331/98005-00 LER Inoperability of containment atmosphere hydrogen and oxygen monitors i
50-331/98006-00 LER Inadequate post replacement test on SBLC system explosive valves 50-331/98006-01 VIO Inadequate operating log entries for work on RMC system 50-331/98006-02 VIO Inadequate post modification testing on RMC system l
50-331/98007-00 LER Potential HPCI room corridor wall steam leakage 50-331/98008-01 VIO Failure to verify drywell clean of trash
50-331/99004-01 NCV Failure to meet TS in restoring the SBLC system J
Discussed None i
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LIST OF ACRONYMS USED
l ACP Administrative Control Procedure AOP Abnormal Operating Procedure
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AR Action Request l
ASME American Society of Mechanical Engineers CFR Code of Federal Regulations CMAR Corrective Maintenance Action Request CWO Corrective Work Order DAEC Duane Arnold Energy Center DRP Division of Reactor Projects ED Electronic Dosimeter HP Health Physics HPCI High pressure coolant injection IP inspection procedure IR inspection report LER Licensee Event Report NCV Non-cited violation NRC Nuclear Regulatory Commission ODI Operations Department Instruction RG Regulatory Guide RHR Residual heat removal RHRSW Residual heat removal service water RMC Reactor manual control RWP Radiation Work Permit SBLC Standby liquid control STA Shift technical advisor STP Surveillance Test Procedure TS Technical Specification UT Ultrasonic testing VIO Violation i
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