IR 05000254/1999006
| ML20206S406 | |
| Person / Time | |
|---|---|
| Site: | Quad Cities  |
| Issue date: | 05/14/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20206S403 | List: |
| References | |
| 50-254-99-06, 50-254-99-6, 50-265-99-06, 50-265-99-6, NUDOCS 9905210125 | |
| Download: ML20206S406 (23) | |
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U. S. NUCLEAR REGULATORY COMMISSION l
REGION ll1 Docket Nos:
50-254;50-265 l
License Nos:
Report No:
50-254/99006(DRP); 50-265/99006(DRP)
Licensee:
Commonwealth Edison Company (Comed)
Facility:
Quad Cities Nuclear Power Station, Units 1 and 2
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Location:
22710 206th Avenue North Cordova, IL 61242 Dates:
March 7 through April 20,1999 Inspectors:
C. Miller, Senior Resident inspector K. Walton, Resident inspector
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L. Collins, Resident inspector P. Prescott, Senior Resident inspector, Duane Arnold T. Tongue, Project Engineer D. Roth, Resident inspector, Dresden R. Ganser, Illinois Department of Nuclear Safety i
Approved by:
Mark Ring, Chief Reactor Projects Branch 1 Division of Reactor Projects
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9905210125 990514 i
PDR ADOCK 05000254 f
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EXECUTIVE SUMMARY Quad Cities Nuclear Power Station, Units 1 & 2 NRC Inspection Report 50-254/99006(DRP); 50-265/99006(DRP)
This inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a 6-week period of resident inspection ending April 20,1999.
Operations Equipment problems caused delays in testing of the reactor core isolation cooling
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system. During these delays, the system configuration resulted in Unit 2 entering a shutdown limiting condition for operation due to high suppression pool oxygen content.
The licensee determined that improvements to the testing and operation of the reactor core isolation cooling system were needed to help improve the system availability and prevent unacceptable oxygen levels in the suppression pool (Section 1.2).
Inspectors found some plant material condition items that had not been identified during
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increased management tours or operator tours. The findings did not involve any loss of operation of risk-significant equipment (Section O2.1).
An operator secured cooling water for lubricating oil on a running reactor recirculation
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motor generator. The failure to operate the proper valve on the shut down unit almost resulted in a plant transient on the running unit. This failure to follow procedures was considered a non-cited violation of Technical Specifications (Section 04.1).
The inspectors found that the processes in place for corrective action review were
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acceptable and improving. However, several instances of less than effective oversight and follow-up of corrective action were identified (Section 07.1).
Insufficient follow-through for corrective actions from previous loss of condensate events
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led to an operational event, involving a near loss of feedwater, where approximately 25,000 gallons of condensate was diverted through the backwash receiving tank to the turbine building floor (Section E2.1.)
Maintenance An electrical jumper was incorrectly installed in Bus 23-1 instead of Bus 23 during a
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Unit 1 core spray logic surveillance. This failure to follow procedures was a non-cited violation. The significance of this pa ticular error was low because the test itself uncovered the problem. However, cWtwation control problems continued to occur and corrective actions to prevent such occurrences have not been fully effective (Section M1.2).
Maintenance workers identified a potential foreign material problem in the "1B"
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condensate demineralizer post strainer. However, engineering and supervision did not initiate action to find and remove the material. As a result, rework was required to remove the loose part after the system had been restarted and the material moved to the post strainer. Follow-up actions taken by licensee management were appropriate (Section M1.3).
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The "2A" control rod drive system pump failed three times from December 1998 to
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March 1999. Poor reassembly guidance, lack of verification of vendor supplied parts,
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and operation of the pump at a low efficiency point were identified as the root causes of failure in the licensee's preliminary report. The "2B" control rod drive pump showed degradation and was being repaired at the end of the period (Section M1.4).
A severe ground on the 125 Volt direct current system was caused by foreign material in
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the control room annunciators. The ground was corrected, but the system continued to experience grounds that had not been detected. Licensee corrective actions to date had not fully addressed permanent solutions (Section M2.1).
l The failure to receive authorization prior to disconnection of the reactor pressure vessel
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vent assembly resulted in control room operators losing reactor vessel water level j
indication. The unauthorized removal of the vent assembly was a procedure violation
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which was considered a non-cited violation (Section M4.1).
Maintenance rework on the "1 A" reactor water cleanup pump, the Unit i reactor head
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"O" ring, and Unit 1 snubbers contributed to a total of about 1000 millirem of additional station radiation dose (Section R1.1).
Enaineerina Insufficient engineering follow-through for corrective actions from previous loss of
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condensate events led to an operational event. Previously identified corrective actions from a similar 1992 event were not completed. Some preventive maintenance items for valve failures were not yet developed, and some corrective maintenance items planned to supplement missing preventive maintenance actions were not performed because of low priority (Section E2.1).
The inspectors found temporary tags used for testing on safety-related breakers which
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were not controlled by a program which ensured the accuracy of the information against plant prints (Section E3.1).
The plan developed by engineering and approved by the Plant Operations Review
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Committee to address a maintenance error in the Unit 2,250 Volt direct current battery was flawed. The plan and temporary modification did not contain the correct acceptance criterion nor sufficient resistance measurements to assure that the battery remained operable during maintenance. After the inspectors identified the errors, the licensee revised the plan (Section E4.1).
The inspectors concluded that the station was not tracking the use of structures erected
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with scaffolding materials which were in place for long periods of time. The licensee performed walkdowns on a portion of the scaffolding to ensure integrity, and planned to make procedure changes to address the integiity of long-term scaffold structures (Section F2.1).
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Plant Support Several floor contamination events occurred because of equipment problems with
reactor water cleanup relief valves and condensate system air-operated valves. No significant personnel contaminations resulted, but increased radiological dose resulted from the cleanup efforts (Section R1.1).
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Report Details I. Operations
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Conduct of Operations 01.1 General Comments (71707)
Both units were operating at full power at the beginning of the period. On March 6, 1999, Unit 2 was operating at full power when operators received a Unit 2 condensate booster pump suction low pressure alarm in the control room and noticed decreasing condenser hotwelllevel. Operators responded quickly and appropriately to the near loss of feedwater event. The event lasted about 7 minutes and resulted in about 25,000 gallons of condensate being diverted to the backwash receiving tank at a rate of about 3,500 gallons per minute. Unit 2 operated at or near full power for the remainder of the period, with periodic power reductions for testing. On April 10,1999, operators shut down Unit 1 for a planned outage to repairjet pump riser cracking and perform sesquiannual surveillance tests. Unit 1 remained shut down for the remainder of the period.
01.2 Reactor Core isolation Coolina Unavailability Extended Due to Hioh Torus Oxvaen Concentrations a.
inspection Scope (71707)
Inspectors observed reactor core isolation cooling testing plans and the effects of that i
testing on plant operations, b.
Observations and Findinas On March 10,1999, an overspeed trip test on the Unit 2 reactor core isolation cooling system had to be halted because the oxygen levels in the suppression pool had
exceeded the limits in the Technical Specifications. This placed Unit 2 in a 24-hour shutdown limiting condition for operation. The operators were unable to restore the suppression pool oxygen levels while reactor core isolation cooling was in a test alignment. Instead, the operators had to stop the reactor core isolation cooling test for about 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> to inert the torus. This resulted in additional reactor core isolation cooling unavailability time, and kept the plant at a " yellow" fire risk longer than planned.
it also challenged operators by requiring additional actions and system realignments.
Inspectors questioned the licensee on March 30,1999, about the cause of the high oxygen levels in the suppression pool. Later investigation found that the reactor core isolation cooling overspeed testing was delayed by a tachometer problem and by several attempts to reset the overspeed trip device. Operators kept the barometric condenser vacuum pump running during this time period, which allowed air to be drawn through the turbine seats and put into the torus. Operators planned to change the procedure for testing to ensure the vacuum pump running was minimized, and to monitor suppression pool oxygen if the pump were left running.
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Conclusions Equipment problems caused delays in testing of the reactor core isolation cooling system. During these delays, the system configuration resulted in Unit 2 entering a shutdown limiting condition for operation due to high suppression pool oxygen content.
The licensee determined that improvements to the testing and operation of the reactor core isolation cooling system were needed to help improve the system availability and prevent unacceptable oxygen levels in the suppression pool.
O2 Operational Status of Facilities and Equipment O2.1 Plant Tours a.
Inspection Scope (71707)
Inspectors observed plant conditions by observing field conditions of systems structures and components.
b.
Observations and Findinas inspectors noted more licensee management tours during the period. This effort, along I
with operator tours, was helpful in identifying some problems, but did not identify some other degraded plant conditions.
The inspectors identified that the "2B" residual heat removal pump motor lower oil level was below the " standstill" level on its sight glass and local controllers for the 2-1601-57
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drywell inerting upstream isolation valve and the 2-1301-25 reactor core isolation cooling pump suction valve had no indicating lights lit. The licensee corrected these problems.
On March 9,1999, the inspectors noted a ladder chained to an instrument rack (2201-30A) in the Unit 1 core spray & reactor core isolation cooling room. The inspectors were concerned that a potential existed to damage sensing lines on the instrument rack during ladder removal and installation. On March 11,1999, the fire protection engineer informed the inspectors that he had identified conflicting procedural guidance regarding the acceptability of ladders being chained to the rack. As a result, the fire protection engineer wrote Problem identification Form Q1999-00924 to continue the investigation. The problem identification form (as written by the engineer) said that no immediate action was required. The ladder remained chained to the instrument rack until the inspectors again discussed the fire protection engineer's findings with the Unit 1 unit supervisor. Eventually two ladders were removed from the rack area.
Inspectors found areas of the plant that were not adequately lit on different occasions.
On two separate tours on March 22,1999, inspectors found lighting in the residual heat removal service water vaults to be low. Eight of twelve bulbs had burned out in one vault, and about half had burned out in another. Several weeks later, inspectors found a similar condition existed in residual heat removal service water vaults. Inspectors noted another lighting problem on April 15,1999, in the % emergency diesel generator room where seven of twelve lights were not lit. Some of these conditions were not fixed by the end of the inspection period.
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In another case, on April 1,1999, inspectors found flow indicating Switch 1-1001-76A stuck at an indication of 40 percent flow in the residual heat removal system when actual flow was O percent. The switch only provided alarm and local indication functions. Operators wrote Problem Identification Form Q1999-01229 and Action Request 990020144 to track and correct the problem.
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Conclusions inspectors found plant material condition items which needed correction and had not been identified during increased management tours or operator tours. The findings did not involve any loss of operation of risk-significant equipment.
Operator Knowledge and Performance 04.1 Wrona Unit Error a.
Insoection Scope (71707)
The inspectors reviewed the licensee's prompt investigation and proposed corrective actions, and spoke to licensee staff regarding a wrong unit error. Inspectors monitored an operator discussion session, attended various licensee meetings, and reviewed other documents associated with this event.
b.
Observations and Findinas On April 14,1999, an operator was briefed and dispatched by control room operators with a copy of the procedure step to remove the Unit 1 "A" recirculation motor generator set lubricating oil coolers from service. The operator maintained communications with control room personnel during the operation. However, subsequent to operating the valve to remove the oil coolers from service, the operator realized he had incorrectly removed the Unit 2 "A" recirculation motor generator set lubricating oil coolers from service instead of the U1 coolers. The operator immediately returned the Unit 2 "A" lubricating oil cooler to service. Unit 2 operators received a high temperature lubricating oil alarm which cleared shortly afterwards. Unit 2 operations were otherwise unaffected.
The licensee counseled the individual involved with this event and discussed this event with other operating crews. The licensee reset the event-free clock after this event and was continuing to evaluate long-term corrective actions. The inspectors noted this human error almost resulted in a transient on Unit 2. Although the need for self-check was important, the safety significance of this event was minimal and no equipment damage was sustained. Under different circumstances, another human error resulted in draining 7000 gallons of reactor coolant into the torus in February 1999 (see Inspection Report 50-254/99001; 50-265/99001).
Quad Cities Operating Procedure 0202-04, " Reactor Recirculation System Shutdown,"
Step F.9.a. required that Valve 1(2)-3999-50 be closed. The operator closed the Unit 2 3999-50 valve in lieu of the Unit 13999-50 valve. Technical Specification 6.8.A.1, required that applicable procedures in Regulatory Guide 1.33, Appendix A, be implemented. Recirculation system procedures were referenced in Section 4.a of the Regulatory Guide. Failure to implement the operating procedure was considered a violation of Technical Specifications. This Severity Level IV violation is being treated as
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a Non-Cited Violation (50-254/99006-01), consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as Problem identification Form Q1999-01368.
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Conclusions An operator erroneously secured cooling water for lubricating oil on a running reactor i
recirculation motor generator. The failure to operate the proper valve on the shut down unit almost resulted in a plant transient on the running unit. This failure to follow procedures was considered a non-cited violation of Technical Specifications.
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Quality Assurance in Operations 07.1 Manaaement Oversiaht Meetinas a.
Inspection Scope (71707)
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The inspectors reviewed corrective action documents and attended various management meetings to evaluate the functioning of the licensee's corrective action process. Meetings attended included the Events Screening Committee, the Plant Operations Review Committee, and the Corrective Actions Review Board.
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Observations and Findinas The Event Screening Committee meetings attended early in the period were lengthy and appeared somewhat disorganized. Members spent significant time on classification of items. During the Event Screening Committee meeting of March 11, one required committee member left without comment during the middle of the meeting. Another member realized that the Event Screening Committee no longer had a quorum and halted the meeting while a replacement member was found. The Event Screening Committee appeared to classify problem identification forms correctly and to recommend follow-up actions appropriately. Later, the inspectors found that the Event Screening Committee meeting process had been improved. Members were given material to review further in advance, and spent less time in the meeting discussing classification and resolution approaches.
The inspectors attended a Plant Operations Review Committee meeting regarding the installation of a temporary alteration on the 250 Volt direct current battery in Unit 2. The Plant Operations Review Committee accepted a plan presented by engineering that was non-conservative. The Committee members failed to ask the appropriate questions to learn that the plan presented by engineering had an acceptance criterion that could have resulted in an inadvertent entry into a limiting conditir.,n for operations. The inspectors subsequently discussed with licensee management why the plan was non-conservative. The licensee reassembled the Plant Operations Review Committee and re-revie'ved a modified version of the plan. The licensee also wrote Problem Identification Form Q1999-00901. Additional details are in Section E4.1 of this report.
The inspectors observed the March 26,1999, Corrective Actions Review Board, which met to decide the effectiveness of corrective actions for past problems. The Corrective Actions Review Board from the previous week had not met due to schedule conflicts.
Some effectiveness reviews were rejected and sent back to the originating department
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for further review. Some requirements for effectiveness reviews were unclear to board members, who decided to review procedures in order to determine what actions were required for discipline related actions. Efforts were in place at the end of the period to improve the quality of packages presented to the corrective actions review board.
One problem identification form (01999-1286) reviewed by the inspectors involved problems with qualifications of the fire brigade members due to unavailability of silicone masks in which they were qualified. The inspectors found that corrective actions for this problem were not well documented or understood by shift personnel. Some radiation protection personnel had discussed the issue with corporate counterparts, and had ensured silicone masks were available in the radiation protection spaces. However, on Apol 9,1999,2 days after discovery of the problem, the shift operations supervisor and shift manager were not aware of the qualifications of their fire brigade personnel. The next week the licensee determined that all fire brigade members would have been qualified to an acceptable level for fire brigade members, but not to the requirements of the Quad Cities Appendix R Procedure 5210.03. In addition, at least one emergency response member would not have met the requirements for mask fit. The inspectors found that licensee response to the issue, and communication of the actions to operators was initially insufficient. Sections M1.4, M2.1, and E3.1 of this report document other conditions of less than effective corrective action follow-up.
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Conclusions The inspectors found that the processes in place for corrective action reviews were acceptable and improving. However, several instances of less than effective oversight and followup of corrective actions were identified.
Miscellaneous Operations issues 08.1 (Closed) Licensee Event Report 50-254/97017-00: Unit 1 Entered a 12-Hour Hot Shutdown Limiting Condition for Operation. The inapprooriate entry into the shutdown limiting condition for operation was caused by a scheduling error. This licensee event report was submitted voluntarily. The station complied with the limiting condition for operation action statement. This licensee event report is closed.
08.2 (Closed) Licensee Event Report 50-254/97018-00: Valve Lineup. This item was associated with Violation 50-254/97011-03; 50-265/97011-03 which was closed in inspection Report 50-254/98012; 50-265/98012. This licensee event report is closed.
08.3 (Closed) Licensee Event Report 50-254/97019-00: Technical Specification 3.0.C Was l
Entered When Both Doors for an Interlock Were Opened Simultaneously. During the performance of a required surveillance which rendered secondary containment isolation instrumentation inoperable, both doors in one reactor building interlock were simultaneously opened momentarily. At that moment, operators entered Technical i
I Specification 3.0.C because secondary containment integrity was no longer maintained as required by Technical Specification 3.2.A, and the action statement could no longer be met. The doors were immediately closed and secondary containment integrity restored. Operators then exited Technical Specification 3.0.C. Additional administrative controls over the interlock doors were added to several procedures to prevent recurrence. This licensee event report is closed.
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ll. Maintenance M1 Conduct of Maintenance M1.1 General Comments in general, maintenance activities were accomplished in a safe manner and in accordance with procedures. However, a deficient condition (foreign materialin a condensate demineralizer) was not appropriately addressed by station staff. This resulted in rework to retrieve the lost piece. A human error resulted in an electrical jumper being installed in the incorrect safety-related emergency bus. Another error caused by maintenance electricians resulted in the destruction of a phase-checking device and a tripped breaker on the safety-related 18-3 motor control center. None of these incidents was of high risk significance, but they were indicative that aspects of quality were missing from some maintenance activities.
M1.2 Confiauration Control Error a_.
Inspection Scope (61726)
The inspectors observed portions of the core spray logic testing for Unit 1, including a heightened level of awareness briefing, reviewed the applicable procedure (Quad Cities Operating Surveillance 1400-11. "Sesquiannual Core Spray Logic Functional Test"),
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and reviewed the prompiinvestigation for Problem Identification Form Q1999-01202.
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Observations and Findinos On March 31, the % emergency diesel generator output breaker to safety-related 4 kV Bus 23-1 failed to close as expected during the core spray logic surveillance test. The breaker had been racked into the test position and the % emergency diesel generator was inoperable. Troubleshooting determined that a jumper had been incorrectly placed in Bus 23-1, Cubicle 1, which should have been placed in Bus 23, Cubicle 1.
The jumper had been placed in Bus 23-1 by an electrician and verified by the test director. Concurrent dual verification was the verification method used as required by CWPI-NSP-OP-1-11 " Verification Practices." The prompt investigation identified that
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both the breaker cubicle at Bus 23 and Bus 23-1 had the same layout inside, each with a terminal board labeled "ZD," which contributed to the test director's confidence that the jumper was being placed in the correct location. Additionally, both the procedure steps preceding and following the installation of this jumper were located at Bus 23-1, similarly enforcing the mindset that all work to be performed was at Bus 23-1.
The prompt investigation concluded that the suspected cause of the event was the lack of integrity of the independence of the concurrent dual verification. Initial corrective actions were to remove the jumper and restore the system. A problem identification l
form was generated and screened by the Event Screening Committee. The committee l
reviewed the prompt investigation and determined that an apparent cause evaluation with corrective actions was required and that the issue would be reviewed in the future by the Corrective Action Review Board. These plans were entered into the corrective action program under Action Request 9534.
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The jumper was intended to simulate the condition of the Bus 23 to Bus 23-1 feed breaker in the open position which would allow the % emergency diesel generator breaker to close onto Bus 23-1. Instead, the jumper was incorrectly placed around contacts associated with the Bus 23-1 to Bus 13-1 crosstie. With normal offsite power available, the crosstie breakers are open and this particular set of contacts normally closed. Therefore, placement of the jumper around the contacts did not affect the condition of the bus. However, in the event of a loss-of-offsite power, the incorrectly placed jumper could have allowed the two buses to be crosstied, which potentially could have allowed the % diesel generator to be overloaded. This scenario was unlikely because the procedure to crosstie the buses did not cover situations where the emergency diesel generator was supplying power.
The failure to adequately implement a surveillance test procedure required by Technical Specification 6.8.A.1 and Regulatory Guide 1.33 was considered to be a violation. This Severity Level IV violation is being treated as a Non-Cited Violation (50-254/99006-02),
consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as Problem Identification Form -Q1999-01202.
The significance of this event was low because the emergency diesel generator was already inoperable for the planned test and because the test itself revealed the configuration control problem. However, this event highlights a continuing trend of configuration control problems, especially those involving poor independent verification.
Previous examples of violations and non-cited violations involving poor independent verification were described in Inspection Reports 50-254/98012; 50-265/98012, 50-254/98013; 50-265/98013, and 50-254/98020; 50-265/98020, and involved such events as fuel assembly mispositioning in the spent fuel pool, high pressure coolant injection and reactor core isolation cooling system vent valve mispositioning, and emergency diesel generator crankcase drain valve mispositioning. Based on the continued high numbers of configuration control events, it appeared that corrective actions have not been fully effective to prevent recurrence.
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Conclusion An electrical jumper was incorrectly installed in Bus 23-1 instead of Bus 23 during a Unit 1 core spray logic surveillance. This failure to follow procedures was a non-cited violation. The significance of this particular error was low because the test itself uncovered the problem. However, configuration control problems continued to occur and corrective actions to prevent such occurrences have not been fully effective.
M1.3 Foreian Material in the "1B" Condensate Demineralizer Post Strainer a.
Inspection Scope (62707)
The inspectors reviewed licensee response to an identified foreign material exclusion problem (Problem identification Form Q1999-01082).
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Observations and Findinas During replacement of the "1B" demineralizer elements, workers identified that a metal piece was missing from the bottom of one of the removed elements, and informed the system engineer. The workers believed that the system engineer indicated that it was
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permissible to reassemble the vessel without retrieving the missing part. Later, when the workers informed their supervisor of the missing part, the supervisor did not write a problem identification form or question if it was acceptable to return the demineralizer to service without retrieving the missing part. Following the filter element change-out and return-to-service of the "1B" condensate demineralizer vessel, a noise at the post strainer indicated a loose metallic part. The demineralizer was again removed from service and the missing part was retrieved from the post strainer.
Although the workers recognized a potential problem, the problem was not adequately addressed by licensee staff. The maintenance manager met with all mechanical maintenance supervisors and reinforced his expectations for control of foreign material.
Emphasis was put on timely generation of a problem identification form, prompt notification when work does not go as expected, and the need for workers to have a more questioning attitude when de:isions do not make sense. The maintenance department held a worker stand down several days later to discuss this issue and other related issues with all maintenance department personnel.
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Conclusions Maintenance workers identified a potential foreign material problem in the "1B" condensate demineralizer post strainer. However, engineering and supervision did not initiate action to find and remove the material. As a result, rework was required to remove the loose part after the system had been restarted and the material moved to the post strainer. Follow-up actions taken by licensee management were appropriate.
M1.4 Repetitive Failures of the "2A" Control Rod Drive System Pumo a.
Inspection Scope (62707)
The inspectors reviewed the licensee's investigation, preliminary findings, and proposed corrective actions concerning the repetitive failures of the "2A" control rod drive pump.
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Observations and Findinas in December 1998 a bearing failed on the "2A" control rod drive pump, causing a fire in the bearing housing. The licensee's investigation determined that the pump failed due i
to random bearing failure, but the root cause was inconclusive. In February 1999 the j
"2A" control rod drive pump failed again after approximately 15 days in service. The licensee's preliminary root cause investigation indicated that the pump experienced rapid deterioration of pump internals. The "2A" control rod drive pump was rebuilt and placed back in service. In March 1999 the "2A" control rod drive pump failed again. At this point the root cause investigative effort for the previous failure was expanded to include the third pump failure.
Representatives from General Electric and Ingersoll-Dresser Pump Company, as well as engineering and maintenance assistance from Dresden Station provided technical assistance. According to preliminary information from the licensee investigation team, the primary root causes for the repetitive failures of the control rod drive pumps overall were:
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poor pump reassembly guidance
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lack of verification of vendor supplied parts (New vendor supplied parts were
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found not to have adequate tolerance control.)
operation of the pump at a low efficiency point (Iow flow)
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Other possible contributing factors to low pump reliability included:
inadequate venting following maintenance
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lack of bearing oillevelindication
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use of non-original equipment manufacturer parts
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lack of appropriate training
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lack of a complete problem matrix reflecting the industry knowledge of the
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system The licensee's investigation identified that much of the information needed to improve the performance of the control rod drive pumps had been known at the station since 1996. Action was initiated to evaluate these contributing factors and implement necessary improvements.
The "2A" control rod drive pump was rebuilt using all new internal components under Work Request 990029125. Current industry information was added to the pump rebuild j
procedures. Vendor supplied parts were inspected and those that were not satisfactory were corrected prior to installation. The licensee initiated an evaluation of the vendor parts specifications to determine whether they could improve the quality of vendor supplied spare parts. A modification to reduce the size of the impeller stages was implemented to allow improvement in the operating band of the pump such that less internal stress would occur during normal operation.
During this investigation, the "2B" control rod drive pump began to show signs of aging wear. The licensee ordered parts and initiated planning for a repair effort. Both control rod drive pumps on Unit 1 were reaching their projected life expectancy based on historical data. The inspectors noted that the control rod drive system had an interim system engineer for several years and that many of the aspects of this problem lacked ownership and adequate follow-up.
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Conclusions The "2A" control rod drive system pump failed three times from December 1998 to March 1999. Poor reassembly guidance, lack of verification of vendor supplied parts, and operation of the pump at a low efficiency point were identified as the root causes of failure in the licensee's preliminary report. The "2B" control rod drive pump showed degradation and was being repaired at the end of the period.
M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Ground on 125 Volt Direct Current System a.
Inspection Scope (71707)
The inspectors reviewed the licensee's act!ons to identify and correct an electrical ground on the 125 Volt direct current system. The review included interviews with
o licensee personnel and review of Problem Information Form Q1999-1227 and supporting documentation.
b.
Observations and Findinas On April 3,1999, the licensee identified a significant ground on the Unit 1,125 Volt direct current bus. The operators documented this on Problem Identification Form Q1999-1227 and initiated ground location procedures. Maintenance personnel identified the source to be stray pieces of metalin an annunciator circuit card, and removed the metal. A preliminary investigation could not identify the source of the foreign material.
The 125 Volt direct current system had experienced grounds in the recent past due to people stepping on limit switches, weather-related grounding of switches due to rain, and equipment aging. The use of ground detection equipment resulted in identifying
. and correcting the source of most of the grounds in a reasonable time period. However, intermittent grounds were continuing to occur without operators being able to identify the source of the ground. The licensee previously documented numerous system grounds on an adverse trend problem identification form, but this issue was not pursued aggressively. To date, the licensee had not adequately addressed permanent solutions for this problem.
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Conclusions A severe ground on the 125 Volt direct current system was caused by foreign material in the control room annunciators, The ground was corrected, but an adverse trend of direct current grounds continued. Licensee corrective actions to date had not fully addressed permanent solutions.
M4 Maintenance Staff Knowledge and Performance M4.1 Unauthorized Disconnection of the Unit 1 Reactor Pressure Vessel Head Vent Pipina a.
Inspection Scope (71707)
The inspectors reviewed the circumstances surrounding the unauthorized disconnection of the Unit i reactor pressure vessel head vent piping (Problem Identification Form Q1999-01346) and prompt investigation associated with this event. The inspectors reviewed activities on the refuel floor and spoke to personnel involved with refuel floor activities.
b.
Observations and Findinas On April 12,1999, with Unit i shut down and reactor vessel water level at the reactor vessel flange area, maintenance personnel on the refuel floor were making preparations to remove the reactor pressure vessel head vent piping. Control room operators communicated to refuel floor maintenance personnel that the head vent assembly was not to be disconnected prior to installation of an additional reactor vessel water level indication system Due to communication errors by refuel floor personnel, maintenance personnel commenced disconnection of the vent piping prior to authorization. This resulted in draining of the reference leg to a level indicator which produced an
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erroneously high water levelindication in the control room. Operators ensured reactor vessel water level remained nearly constant until another remote level indication system was established.
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commenced a prompt investigation. This investigation identified that Step l.5.d of l
Quad Cities Mechanical Maintenance Procedure 0201-04, " Reactor Disassembly," to remove the vent piping was not authorized to be performed. In addition, workers in the contaminated area relied on verbal instructions for work authorization since the procedure was kept in a " clean" area.
The licensee's prompt investigation identified poor communications as the reason for the loss of a reactor vessel water levelindicator. The inspectors determined the prompt investigation adequately identified the initial cause and initial immediate actions for this event. The licensee continued to evaluate long-term corrective actions to this event at the end of the inspection period.
Although this event was of minimal safety significance, the failure to receive authorization prior to removing the reactor pressure vessel vent assembly was considered a violation of Technical Specification 6.8.A.1 and Regulatory Guide 1.33, Appendix A, Section 2.k, which required that refueling procedures be implemented.
This Severity Level IV violation is being treated as a Non-Cited Violation (50-254/99006-03), consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as Problem Identification Form Q1999-01346.
c.
Conclusions The failure by workers to receive authorization prior to disconnecting the reactor pressure vessel vent assembly resulted in control room operators losing reactor vessel water levelindication. The unauthorized removal of the vent assembly was a procedure violation which was considered a non-cited violation.
M8 Miscellaneous Maintenance issues M8.1 (Closed) Licensee Event Report 50-254/97002-00: Generic Letter 96-06 Concerns.
Engineering calculations performed in response to NRC Generic Letter 96-06 indicated that several isolable piping sections on each unit may experience stresses above Updated Final Safety Analysis Report allotvable limits following a loss of coolant accident. On May 2 and May 16,1997, the licensee provided initial responses to Generic Letter 96-06," Assurance of Equipment Operability and Containment Integrity During Design-Basis Accident Conditions." Review for this item will be addressed by the l
Office Of Nuclear Reactor Regulation under Tracking Numbers M96856 and M96857.
l This licensee event report is closed.
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Ill, Enaineerina E1 Conduct of Engineering E1.1 General Comments inspectors noted some problems with engineering support to Operations and Maintenance. Insufficient corrective action follow-up to a condensate demineralizer draindown_ problem in 1992 led to a repeat event in March of 1999. Inspectors found an engineering plan designed to correct 250 volt battery problems and subsequent engineering and Plant Operations Review Committee reviews of the plan were deficient.
E2 Engineering Support of Facilities and Equipment E2.1 Condensate Demineralizer Drainina Event a.
Insoection Scope (71707)
The inspectors reviewed the circumstances surrounding a loss of condensate event which diverted approximately 25,000 gallons of contaminated condensate water into the backwash receiving tank and then onto the condensate pump room floor.
b.
Observations and Findinas On March 6,1999, Unit 2 was operating at full power when operators received a Unit 2 condensate booster pump suction low pressure alarm in the control room and noticed decreasing condenser hotwell level. Operators were sent to the demineralizer panel to investigate. Upon seeing high flow in the system, the operators placed the " cycle control advance" switch to manual, That action terminated the water loss by placing all the demineralizer vent and drain valves in the closed position. Operators also started another condensate and condensate booster pump, which increased feed booster pump suction pressure and helped to prevent a low suction pressure trip of the reactor feed pumps. The event lasted about 7 minutes and resulted in about 25,000 gallons of condensate being diverted to the backwash receiving tank at a rate of about 3,500 gallons per minute. Problem Identification Form Q1999-00852 was written to document the event.
A team of engineers and operators reviewed the problem, and found the likely cause to be an open drain valve from the "2C" condensate demineralizer. After two similar condensate draining events in 1992, engineers had developed a plan to change out dual action solenoid drain valves for the condensate demineralizers. The diaphragm material of these valves was found to be subject to degradation because of the heat generated from being continuously energized. Another draining event which flooded the condensate pump area in 1994 was caused by a different air-operated valve failure. An engineering exempt change modification package was completed in 1994 which would have replaced dual-action solenoid valves with single-action solenoid valves. In 1995 engineers canceled the exempt change and planned to accomplish the task with a parts replacemer;t package.
Most, but not all, of the dual acting valves were changed out by September 1998. Two dual action drain valves which remained in the system were the "2B" and "2C"
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demineralizer drain valves. Engineers concluded, based on valve history and
demineralizer flows during the event, that the "2C" drain valve diaphragm had failed, which allowed the valve to open. This allowed a drain path from the pressurized
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condensate system to the depressurized backwash receiving tank until the " cycle control advance" switch was taken to manual.
The inspectors found during interviews that maintenance items to ensure other valves in the concensate system were in good working order were entered into the electronic work control system about 2 years ago by the system engineer. However, many items were not accomplished, partially because of being assigned a low priority. At the end of the period, the licensee had replaced the "2B" and "2C" dual-action solenoid valves with single-action valves. Radiological consequences of the condensate flooding the turbine building condensate pump area floors and walls are discussed in Section R1.2.
c.
Conclusions insufficient engineering follow-through for corrective actions from previous loss of condensate events led to an operational event, involving a near loss of feedwater, where approximately 25,000 gallons of condensate were diverted through the backwash receiving tank to the turbine building floor. Previously identified corrective actions from 1992 were not completed. Some preventive maintenance items for valves were not yet
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developed, and some corrective maintenance items planned to supplement missing preventive maintenance actions were not performed because of low priority.
E3 Engineering Procedures and Documentation E3.1 Poor Control of Eauipment Labelina Used for Testina Breakers a.
Inspection Scope The inspectors reviewed administrative controls for some tags observed during a switchgear inspection.
b.
Observations and Findinas On March 11,1999, the inspectors found several 4160 Volt busses with temporary handwritten cards hanging on the outside of the breaker to indicate circuit identification for test switches on the breakers. The breakers included safety-related breakers at Bus 13-1 as well as nonsafety-related breakers on Busses 11 and 12. The information was located on non-laminated paper cards which had been signed by one individual and referenced electrical prints.
The inspectors asked station management whether temporary tags of this type were a' lowed by station procedures. Concerns about use of temporary cards identifying plant configuration and used for testing of safety-related breakers were discussed with operations and maintenance management. Operations management indicated that the temporary cards were considered temporary labels and controlled under the Quad Administrative Procedure 0300-06 " Temporary Labeling." Inspectors venfied that a unit supervisor had approved the hanging of the temporary labels, but found the following configuration control weaknesses.
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The labels were not laminated to resist wear and unauthorized alteration as
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required by Step C3 of the procedure.
The unit supervisor did not make a thorough review of the electrical prints to
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verify accuracy of the labels. compared to the drawings, nor was there a requirement in the procedure to have that verification made. Since dual verification against the prints was not required for hanging the tags, technicians could get inaccurate information from the tags for use during testing.
The procedure did not call for a second verification of the labels against plant
drawings.
The procedure referenced above and used by the operators to approve the
temporary labels was intended to be used on " control room and in-plant control panels" only. These breakers did not meet that intent as described in the purpose section of the procedure.
The inspectors noted that the temporary labels that had been installed in
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November of 1998 were still hanging in March of 1999 when the inspectors pointed out the discrepancies, and later found hanging on April 8,1999, during a subsequent inspection. This appeared to counter the intent of the procedure Step C1 which indicated use of the tags should be kept to a minimum such as when a permanent label is not available. The inspectors verified that a permanent label material was available.
The maintenance manager indicated that the temporary labeling procedure was
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not rigorous, and that the procedure would be revised to correct the problem. A procedure change request was submitted. However, during a breaker inspection about a month later, inspectors found the same tags still in dace.
c.
Conclusions The inspectors found temporary tags used for testing on safety-related breakers which were not adequately controlled by a program which ensured the accuracy of the information against plant prints. The licensee initiated procedural changes to address this issue; however, existing tags were not promptly addressed.
E4 Engineering Staff Knowledge and Performance E4.1 250 Volt Battery a.
Inspection Scope The inspectors reviewed the plan developed by engineers to address poor intercell resistance on the 250 Volt battery on Unit 2.
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b.
Observations and Findinas The licensee learned that the 250 Volt direct current battery in Unit 2 had a cell-to-cell resistance that was greater than the 150 micro ohms allowed by Technical Specification 4.9.C.2.b. The cause appeared to be poor maintenance work that allowed a washer to be installed between the connector and the cell post.
To remove the washer, the licensee developed a plan to add a second set of connectors, then remove the original set. Engineers developed a temporary modification, and presented the plan to the Plant Operations Review Committee. The Plant Operations Review Committee approved the plan.
The inspectors noted that the plan was flawed. The acceptance criterion for resistance following the installation of the temporary modification was 80 micro ohms. Given that each set of connectors was limited to 150 micro ohms, and the connectors were in parallel, the maximum acceptable resistance should have been 75 micro ohms.
Otherwise, there would not be empirical evidence that the temporary modification met the Technical Specifications. The inspectors also noted that the plan for the installation of the temporary modification did not include steps to verify resistance still met Technical Specifications after removal of the original connectors.
The inspectors discussed the concerns with the system engineer and with a representative from the Plant Operations Review Committee. Licensee personnel agreed with the concerns. The licensee revised the temporary modification plan and again presented the plan to the Plant Operations Review Committee. During the presentation, a nuclear oversight member identified that engineers had not revised the resistance acceptance criterion within the body of the temporary modification. The Plant Operations Review Committee subsequently approved the plan with the condition that the final fully-revised plan be presented to the Plant Operations Review Committee chairperson for approval.
The inspectors discussed the flaws in the plan with the system engineer. The system engineer stated that judgement, rather than math, had been used to determine the acceptance criterion. The engineer also stated he had planned to require additional resistance verifications that he did not list in the plan.
c.
Conclusions The plan developed by engineers and approved by the Plant Operations Review Committee to address a maintenance error on the 250 Volt direct current battery in Unit 2 was flawed. The plan and temporary modification did not contain the correct acceptance criterion nor sufficient resistance measurements to assure that the 250 Volt direct current battery remained operable during maintenance. After the inspectors identified the errors, the licensee revised the plan.
E8 Miscellaneous Engineering issues (92902)
E8.1 (Closed) Inspection Follow-up Item 50-254/96020-04: Component Trending. Inspectors found that Quad Cities had conflicting justification for not characterizing emergency diesel generator start failures as valid failures, and that the guidance may not meet the intent of Regulatory Guide 1.9. Quad Cities initially sent a letter to the NRC on
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March 20,1997, which explained the methodology used for emergency diesel generator classification of the January 17,1997, failure. Comed corporate engineers reviewed the failure data and stated that the failure should be reclassified as a valid start failure.
Quad Cities reclassified this failure as a valid start failure. Written direction from Comed with an interpretation of Regulatory Guide 1.9 and details of how to uniformly apply the guidance was sent to all Comed sites on March 31 and June 30,1998. This item is closed.
E8.2 LQlosed) Licensee Event Report 50-254/96025-00: Emergency Core Cooling System Suction Strainer Head Loss Value is incorrect. Problem Identification Form 96-3571 identified that the original head loss calculation for emergency core cooling system j
suction strainers was incorrect. This issue was discussed further in Inspection
Report 50-254/98201; 50-265/98201 and tracked as Unresolved Item 50-254/98201-01; 50-265/98201-01. This licensee event report is closed.
E8.3 (Closed) Inspection Follow-up IterL50-254/97002-06: 50-265/97002-06: Instrument Calibration Program Weaknesses. The licensee addressed the weaknesses with l
actions documented in Corrective Acuon Request 04-97-004, which is closed. This item
is closed.
I E8.4 (Closed) Violation 50-254/97014-07: 50-265/97014-07: Safe Shutdown Makeup Pump Surveillance Acceptance Criteria Did Not Adequately Incorporate Design Requirements.
The licensee originally agreed with the Notice of Violation and submitted a response to the Nuclear Regulatory Commission. On March 13,1997, the licensee disagreed that the test acceptance criteria did not incorporate instrument tolerances to ensure that the flow and system head design requirements would be met. The licensee's revised response stated that an ongoing Architect Engineering inspection had raised an instrument uncertainty issue and that Quad Cities would address this issue in cooperation with the Architect Engineering inspection team. The larger issue of instrument uncertainties identified by the Architect Engineering inspection was not yet closed by the NRC (Unresolved item 50-254/98201-03; 50-265/98201-03). However, the licensee response to this Notice of Violation addressed the instrument uncertainty issue as it pertained to the safe shutdown makeup pump system. An instrument error analysis (ER 9604270, October 16,1997) and detailed calculation (NDIT 97-096, October 2,1997) were performed to determine the minimum pressure criteria, including instrument uncertainties, for operation of the safe shutdown makeup pump. The surveillance procedure was also revised to direct the use of a high accuracy pressure instrument to assure that the acceptance criteria was met, and thus verified that the system met the Technical Specification requirements. The licensee's corrective actions for this Notice of Violation were satisfactory. This item is closed.
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IV. Plant Support
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R1 Radiological Protection and Chemistry (RP&C) Controls
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R1.1 General Comments in general, radiation protection and chemistry activrUes were acceptable. Dunng the Unit 1 shutdown for jet pump riser repairs, the licensee injected noble metals into the reactor coolant in order to reduce stress corrosion cracking and to limit the amount of
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hydrogen injection needed to protect reactor recirculation piping and vessel internals.
Some floor contamination events occurred because of equipment problems with reactor water cleanup relief valves and condensate system air operated valves. No significant personnel contaminations resulted, but increased radiological dose resulted from the cleanup efforts. Maintenance rework on the "1 A" reactor water cleanup pump, the Jnit i reactor head "O" ring and Unit 1 snubbers contributed to a total of about 1000 millirem of additional station radiation dose.
R1.2 Contamination Events Two contamination control events resulted in contamination of large areas of the reactor building and turbine building this inspection period. Details of the cause of the first event were discussed in Section E2.1. Thousands of gallons of contaminated condensate water flooded the floors of the Unit 2 turbine building. As a result, contamination ievels up to 2.5 million disintegrations per minute were identified across the entire condensate pump floor area of the Unit 2 turbine building. Crews worked to
clean up the area, and no major personnel contaminations resulted. Radiation dose associated with the cleanup effort for this area was not available as separate data from other radiation work.
The second event resulted in contaminating the third floor of the reactor building on the Unit 1 side. Relief Valves 1-1299-79 or 80 from the Unit 1 reactor water cleanup system lifted unexpectedly on March 14,1999, and the water backed up from drains which eventually contaminated the third floor sample sink and floor areas in proximity to the sink. Dose rates as high as 180 millirem per hour and contamination as high as
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1120 millirad per hour were recorded after the event. Cleanup crews decontaminated most of the areas, and posted boundaries on the remaining areas. Workers received an additional accumulated dose of about 260 millirem due to cleanup activities for this event. Approximately 1 month later, the same relief valves lifted again, but contamination did not spread to the same extent due to the drains being isolated (in response to the first lifting of the relief valves). These relief valves were replaced during the Unit 1 outage. The licensee also issued trend Problem Identification Form Q1999-00986 to document 13 events involving unplanned spread of contamination. The inspectors concluded that equipment problems led to unplanned contamination events. No significant personnel contaminations resulted, but excess effort and accumulated dose were required to clean up the contaminated areas.
F2 Status of Fire Protection Facilities and Equipment F2.1 Scaffoldina Concerns The inspectors observed the condition of some equipment staged for Appendix R safe shutdown purposes. Severalinstances of scaffolding erected for periods of time over 1 year were identified by the inspectors. Inspectors asked whether en evaluation had been performed for the long-term installation of the scaffolding, some of which was erected over safety-related equipment. The licensee had indicated these scaffolds were originally quahfied for seismic conditions, but were not in any program which evaluated the long-term condition of the scaffolding. The licensee walked down much of the accessible scaffolding following the inspectors' questions, and found approximately 11 scaffolds which had been erected for over one year. The scaffolds were checked for
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structural soundness, and were found to be intact. Some scaffolding had been erected in 1993. Four scaffolds were in place for safe shutdown concerns.
The inspectors found that the licensee had not initiated a problem identification form to track this discrepancy. However, after discussing the inspectors' observations, the licensee issued a procedure change submittal to modify the corporate procedures (Nuclear Station Work Procedure A-24 " Station Scaffold Erection and Inspection" and 25 " Station Scaffold Installation / Modification and Removal Request"). In addition. the licensee planned to address the issue with the corporate structural peer group. The inspectors concluded that the station was not tracking the use of structures erected with
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scaffolding materials which were in place for long periods of time. The licensee performed walkdowns on a portion of the scaffolding to ensure integrity, and planned to make procedure changes to address the integrity of long-term scaffold structures.
V. Mananement Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on April 20,1999. The licensee acknowledged the findings presented.
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'o INSPECTION PROCEDURES USED IP 61726:
Surveillance Observations IP 62707:
Maintenance Observations IP 71707.
Plant Operations IP 92902:
Follow-up - Engineering ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-254/99006-01 NCV wrong unit error 50-254/99006-02 NCV configuration control error 50-254/99006-03 NCV unauthorized disconnection of the Unit 1 reactor pressure vessel head vent piping Closed 50-254/99006-01 NCV wrong unit error 50-254/99006-02 NCV configuration control error 50-254/99006-03 NCV unauthorized disconnection of the Unit 1 reactor pressure vessel head vent piping 50-254/97017-00 LER Unit 1 entered a 12-hour hot shutdown limiting condition for operation 50-254/97018-00 LER valve lineup 50-254/97019-00 LER Technical Specification 3.0.C was entered when both doors for an interlock were open simultaneously 50-254/97002-00 LER General Letter 96-06 concerns 50-254/96020-04 IFl component trending 50-254/96025-00 LER emergency core cooling system suction strainer head loss value is incorrect
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50-254/97002-06; IFl instrument calibration program weaknesses 50-265/97002-06 50-254/97014-07; VIO safe shutdown makeup pump surveillance acceptable 50-265/97014-07 criteria did not adequately incorporate design requirements LIST OF ACRONYMS USED IFl Inspection Follow-up item LER Licensee Event Report NCV Non-Cited Violation URI Unresolved item
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VIO Violation I
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