IR 05000254/1999001
| ML20205J295 | |
| Person / Time | |
|---|---|
| Site: | Quad Cities  |
| Issue date: | 04/01/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20205J291 | List: |
| References | |
| 50-254-99-01, 50-254-99-1, 50-265-99-01, 50-265-99-1, NUDOCS 9904090275 | |
| Download: ML20205J295 (25) | |
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U. S. NUCLEAR REGULATORY COMMISSION REGION lll Docket Nos:
50-254;50-265 License Nos-OPR-29; DPR-30 Report No:
50-264/99001(DRP); 50-265/99001(DRP)
Licensee:
. Commonwealth Edison Company (Comed)
Facility:
Quad Cities Nuclear Power Station, Units 1 and 2 Location:
22710 206th Avenue North Cordova, IL 61242 Dates:
January 21 through March 6,1999 inspectors:
C. Miller, Senior Resident inspector
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K. Walton, Resident inspector L. Collins, Resident inspector
' P. Prescott, Senior Resident inspector, Duane Arnold M. Kurth, Resident Inspector, Duane Arnold D. Wrona, Resident inspector, Monticello R. Ganser, Illinois Department of Nuclear Safety Approved by:
Mark Ring, Chief Reactor Projects Branch 1 Division of Reactor Projects
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9904090275 990401
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EXECUTIVE SUMMARY Quad Cities Nuclear Power Station, Units 1 & 2 NRC Inspection Report 50-254/99001(DRP); 50-265/99001(DRP)
l This inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a 6-week period of resident inspection.
Operations One event occurred which required prompt notification of the NRC pursuant to
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10 CFR 50.72. On February 17,1999, the "2A" reactor protective system bus de-energized due to a failure of the reserve power supply voltage regulator. The loss of power resulted in placing the reactor protective system and primary containment isolation system Group 1 alignment in a half tripped condition, and partial isolations of primary containment isolation system Groups 2 and 3 (Section 01.1).
On one occasion early in the Unit 2 planned outage, inspectors observed that high
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amounts of work activity in the control room, resulting in increased tension, existed foi a 1-hour period of observation during Unit 2 outage activities. One observed consequence of this period of high activity was a breakdown in some communications and in control of personnel in the control room (Section 01.2).
Failure to comp ly with an operating procedure for initiating shutdown cooling on Unit 2
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rerulted in a reactor vesselinventory loss of about 7000 gallons of water. The event involved several poor practicca in operations including poor communications, poor activity briefings for high risk activities, lack of shift briefings, inadequate supervision of important control room activities, failure to meet expectations for panel monitoring duties, and slow event response. This failure was treated as a Non-Cited Violation (Section 01.2).
During Unit 2 startup from the outage, inspectors found good control room
communication, peer checks, and supervisory oversight. Some lessons from the reactor vessel loss of inventory event appeared to have been implemented well (Section 01.2).
Operators failed to observe the requirements of an out-of-cervice tagout intended to
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prevent operation of the shutdown cooling suction header isolation valve. This violation of procedure requirements and Technical Specifications led to damaging the motor for the valve, which degraded the decay heat removal portion of the residual heat removal system untilit was repaired during Unit 2 reactor shutdown. The NRC refrained from issuing a violation '~ this issue because it repres6nted an additional example of a previous violation h,, which corrective actions were not complete (Section 01.3).
i During daily control rod exercising, operators chose to bypass the rod block monitor to
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prevent valid rod blocks rather than reducing the flow control line to perform the surveillance without experiencing rod blocks. The rod blocks were occurring more frequently than normal because of a high rod load iine which resulted from lower than j
normal recirculatiori flow required because of jet pump cracking Bypassing the rod
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block monitor under high power conditions during rod withdrawal was considered to be I
non-conservative, but was r.ot prohibited by the Technical Specifications (Section 014)
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Material condition of the control rod drive, core spray, and reactor core isolation cooling
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systems was adequate. Although no major deficiencies were found, the inspectors noted that operators, engineers, managers, and other station personnel who routinely entered these rooms were not reporting equipment problems or enforcing standards of cleanliness in all cases (Section O2.1).
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Maintenance The station did not accurately capture the reactor core isolation cooling system
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unavailability with the t ystem nnt automatically available and with one suction source unavailable. As a result, the plant was actually in an elevated risk condition (yellow) for longer than expected. Ultimately, the additional unavailability hours were tracked using the maintenance rule process (Section M1.3).
Numerous equipment failures occurred which caused operating transients or abnormal
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system configuration. Many of these problems were repaired during the Unit 2 planned.
outage, but some significant problems remained including the 2A control rod drive pump and some control rod drives which would not move with only normal operating pressure (Section M2.1).
I informal maintenance practices fer the verification of relay terminal points and a lack of
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procedural requirements resulted in the wrong lead being lifted on the radwaste floor drain sample pump control circuit (Section M2.2).
The inspectors found that the maintenance personnel working on the reactor core
isolation cooling system did not try to correct the poor condition of the belts for the room cooler. Later questioning by the inspectors led the system engineer and vendor to find discrepancies with the belts used and the periodicity of the preventive maintenance (Section M2.3).
Even though installation of an incore probe without a procedure was of minor safety
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consequence, the inspectors noted that this could be indicative of a more programmatic problem ir, which maintenance personnel w;re not adhering to administrative requirements for procedure adherence (Section M4.1).
Failure to follow procedures, communication breakdown, and inattention to detail were
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involved in the installation of a control rod drive with an expired shelf hfe tag. Later it was determined that the control rod drive bias qualified for installation (Section M4.2).
Enaineerina Until requested by the inspectors, the licensee did not adequately document an j
operability determination for operating Unit 1 with snubbers prone to vibration degradation. A second operability documentation did not address an additional drain
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path from the high pressure coolant injection system exhaust drain pot. However, both operability determinations provided reasonable assurance that the equipment would
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i perform its intended design function (Section E1.1).
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Plant Support Station outage performance in the radiation protection area was good. Inspectors noted
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good control of drywell work activities. The overall station dose for the Unit 2 planned outage was 29.5 person-rem which was under the outage stretch dose goal of 30 person-rem (Section R1.1).
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m. D I, Operations
. Conduct of Operations
.01.1 General Comments (71707)
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Both units operated at or near full power until Unit 2 was shut down for planned outage Q2PO1 on February 20,1999, to conduct 18-month surveillance testing and to complete several maintenance and repair work ite.ms. Unit 1 remained at or near full power.
throughout the period. The Unit 2 reactor was restarted on February 28,1999, and the turbine generator was synchronized to the electrical grid on March 1,1999.
Operations performance was good in many activities throughout the period, with a notable decline during some periods in the time frame of the Unit 2 outage. An event -
involving the inadvertent draining of about 7000 gallons from the reactor vessel to the suppression pool revealed significant weaknesses in procedure adherence, communications, control of work during outages, shift working schedules, briefing of risk significant activities, and supervisory oversight. The inspectors identified other activities performed during the outage with weak communications and oversight such as in paragraph 01.2.b. below. Plant management undertook what was described as a very aggressive outage schedule without ensuring operations had sufficien+ resources and oversight to perform well.
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During the inspection period, one event occurred which required prompt notification of l-the NRC pursuant to 10 CFR 50.72. On February 17,1999, the "2A" reactor protective
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system hus de-energized due to a failure of the reserve power supply voltage regulator.
l-The loss of power resulted in placing the reactor protective system and primary l
containment isolation system Group 1 alignment in a half tripped condition, and partial a
l isolations of primary containment isolation system Groups 2 and 3. The failure also led to a failure of the "2A" main steam line radiation monitor. Operators restored power to the bus and repaired the "2A" rnain steam line radiation monitor. The licensee promptly notified the NRC of this event, but had not determined the root cause for the failure of the reserve power supply voltage regulator at the end of the period.
01.2 Control Room Observations
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Inspection Sco_p_e (71707. 93702)
The inspectors observed control room activities, interviewed operators, and reviewed event response and corrective action.
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Observations and Findinas
~b.1 Control Room' Observations Durina Hiah Activity Periods On February 20,1999, the inspectors observed Unit 2 control room activities when there were four major test activities in progress, three of which were being conducted in close proximity to one.another. These tests were being conducted as part of 18-month interval surveillances and included logic testing for emergency core cooEng systems and automatic depressurization system blowdown, as well as dynamic testing for the core spray system. The inspectors observed a relatively high number of phone calls coming
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into the Unit 2 control room. Some of these caused unnecessary distractions and increased stress for the unit supervisor. The shift manager was not present in the control room during this high activity period. The inspectors observed examples where
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l three-way communications were not being practiced as expected by operations management. Some communications between control room operators and workers in the field were not adequately completed. Some information concerning testing, communicated by work control personnel to the administrative unit supervisor, did not get to the unit supervisor. An instrument technician was authorized by the unit supervisor to enter the "between the panel" area and this information was not passed on l
to the nuclear station operators. It did not appear that any of the four nuclear station l
operators were aware that the instrument technician had entered this area. This high l
activity period lasted for about 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> until one of the activities reached an end. Earlier during that day, a senior member of the operating staff had a!so identified an unacceptably high level of activity on Unit 2 and had spoken to the shift manager of the same shift about this. The inspectors discussed the unusually high level of activity in the control room with the unit supervisor.
On a later occasion, the inspectors observed startup activities on February 28 and March 1,1999, and found that the activities were very well controlled with good supervision, briefings, and communication. The site focus on improved standards from I
the lessons learned due to the loss of inventory event appeared to be well emphasized.
c.1 Conclusions On one occasion, inspectors observed that high amounts of work activity, resulting in increased tension, existed for a 1-hour period of observation during Unit 2 outage
activities. One observed consequence of this period of high activity was a breakdown in l
some communications and in control of personnelin the control room. A separate observation during Unit 2 startup from the outage found good control room l
communication, and supervisory oversight. Some lessons from the reactor vesselloss I
of inventory event appeared to have been implemented well, b.2 Inadvertent Drainina of About 7000 Gallons of Reactor Vessel Water On February 24,1999, Unit 2 was in cold shutdown with reactor water temperature at about 144 degrees Fahrenheit and reactor water levelin a band of 90 to 94 inches
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l indicated level (normal level during operations is 30 inches indicated or about 173 inches above the top of active fuel). Core cooling was being maintained in a band i
of 120 to 170 degrees Fahrenheit by the "A" loop of shutdown cooling, after being switched from the "B" loop at about 00:32 a.m. Sometime later operators noted a j
decreasing reactor water level and at about 01:02 a.m. secured the "2A" residual heat removal pump and isolated shutdown cooling.
i Operators then found that the minimum flow valve for the "2A" residual heat removal pump was not closed, as required by procedure, but was instead fully open with the breaker for the valve de-energized. This had allowed a drain path from the reactor, I
through shutdown cooling piping, into the suppression pool. The licensee estimated that about 7000 gallons of reactor vessel water were drained to the suppression pool.
At 01:55 a m. operators restored the "2A" loop of shutdown cooling to the proper lineup and started the "2A" residual heat removal pump, Water level had decreased to a
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minimum of about 45 inches indicated, and reactor water temperature had risen to a maximum of about 163 degrees Fahrenheit. Forced circulation of reactor vessel water using a reactor recirculation pump remained in effect throughout the event.
The licensee began a prompt investigation, and removed the involved operators from shift. Operators were sent to the simulator to review the event and discuss better means of control for evolutions in the control room. Comed management sent a corporate led team to the site to assist in the root cause investigation of the event. The team developed an interim report, which Quad Cities management used to address immediate corrective actions prior to the Unit 2 startup.
The inspectors interviewed members of the operating crew and the root cause team, and found several discrepancies which may have contributed directly or indirectly to the j
event.
The unit nuclear station operator was directing non-licensed operators to perform
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several different tasks in the plant including switching condensate transfer, i
aligning valves at the residual heat removal heat exchangers, and operating breakers for the "B" loop and "A" loop residual heat removal pump minimum flow valves (2-1001-18A&B). The operator did not control the assignment of the tasks in the order in which they needed to be accomplished in accordance with Quad Cities Operating Procedure 1000-05, Revision 21 dated December 6, 1998. The non-licensed operator was given permission to operate the breaker on the "A" residual heat removal minimum flow valve before the valve was taken to the closed position. Thus when the unit nuclear station operator went to verify that the valve was closed, there was no position indication in the control room to make that verification. The nuclear station operator made the incorrect assumption that the valve was already closed, and failed to verify the valve position. Instead, the operator indicated in the procedure that the valve was closed, and moved to the next step in the procedure. A peer check for the minimum flow valve was not requested, and there was no clear expectation from management that a peer check of the valve position should be made since the operator had not actually operated the valve. Failure to verify the position of the 2-1001-18A valve was a violation of Quad Cities Operating Procedure 1000-05,
" Shutdown Cooling Operation," Step F.1.e.(1) which stated " Verify closed MO 1(2)-1001-18A, RHR LOOP MIN FLOW VLV." Failure to follow this operating procedura which was a procedure mentioned in Regulatory Guide 1.33, was a violation of Technical Specificatior (TS) 6.8.A.1. This l
Severity Level IV violation is being treated as a Non-Cited Violation j
(50-265/99001-01) consistent with Appendix C of the NRC Enforcement Policy.
l This violation is in the licensee's corrective action program as PIF-Q 1999-
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Monitoring of Unit 2 conditions following placing the "A" loop of shutdown cooling
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in service was insufficient to detect and correct an adverse trend in reactor vessellevelin a timely manner. Operators did not express a concern for decreasing level until about 13 inches of level decrease, which corresponded to j
a loss of about 2500 gallons of water. From that point. the operating crew was
slow to make the decision to isolate shutdown cooling, which resulted in the loss j
of about 20 more inches of reactor vessel water level. This action was slow even though recommended by a nuclear station operator early in the event and
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1 mentioned in the limitations and actions section of Quad Cities Operating
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Procedure 1000-05. (Section E.2 stated "lE an unexplained loss of inventory should occur, THEN close MO 1(2)-100147, SDC SUCT HDR DOWNSTREAM SV, MO 1(2)-1001-50 SDC HDR UPSTREAM SV, AND MO 1(2)-1001-29A/B, LPCI LOOP DOWNSTREAM SV.")
The operator who was directing shutdown cooling operations from the control
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room did not attend the Heightened Level of Awareness briefing which was held just prior to the evolution. In addition, the Unit 2 unit supervisor did not attend the brief. Identification of who attended the briefing was complicated by the fact
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that individuals were listed on the briefing sheets as attending who did not actually attend the brief (these briefing sheets were used as tracking documents internal to the Quad Cities Station and were not submitted for NRC information or review). The briefing did not address operating experience dealing with inadvertent vessel draining events. Specific abort criteria were only set for
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elevated reactor temperature concerns and did not address reactnr level concerns.
I The operator who was given charge of directing the changing of shutdown
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cooling from the "B" loop to the "A" loop was the Unit 2 nuclear station operator who had the primary responsibility for panel monitoring. Previous practice at Quad Cities had been to not give other assignments to the unit nuclear station operator. Unit supervisors and shiii managers interviewed did not believe the workload was excessive in the control room during the time when the event took place. However, nuclear station operators interviewed indicated that there was likely too much work for the unit nuclear station operator and administrative nuclear station operator to perform in conjunction with their other duties. The inspectors found that the duties, including switching reactor protective system busses (which generated many annunciator alarms), draining a reactor recirculation loop, aligning condensate transfer, securing one loop of shutdown cooling and aligning the opposite loop of shutdown cooling, required significant attention from the two nuclear station operators.
The attention of the shift manager and unit supervisor assigned to the unit was
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diverted by attending briefs for an upcoming logic test. An administrative unit supervisor was assigned to assist in the shutdown cooling evolution. While the administrative unit supervisor relieved some of the burden on the unit supervisor, multiple turnovers between the two contributed to problems with command and control. During the switching of shutdown cooling, the shift manager was only in the control room for about 6 minutes.
All control room nuclear station operators at Unit 2 during the event had already
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worked one full shift and were several hours into their second 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> on the midnight shift.
Unit supervisors and shift managers were on 12-hour shifts and nuclear station
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operators were on alternating shifts of 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> one day and 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> the next day in order to meet the increased demands of the outage schedule During this time of changed schedules for the mid-cycin Unit 2 outage, operating shift crew composition changed almost daily and did not have formal crew br efings for some of the afternoon and midnight crews.
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The inspectors determined that although the unintended loss of inventory to the suppression pool was significant and highlighted significant weaknesses in plant operations, the safety significance was minimized by two features. First, a reactor
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l recirculation pump remained in service throughout the event which served to distribute decay heat. Additionally, an automatic isolation of shutdown cooling would have occurred at 8 inches indicated level which would have stopped the draining event. Eight inches indicated water level corresponded to approximately 151 inches of water level
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above the top of the active fuel in the reactor core.
In response to the draindown event, the licensee took corrective action to prevent i
recurrence. All operating crews were briefed on the event. The training of the operators
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following the level transient included a refresher of the station expectations regarding self checking, peer checking, panel monitoring, briefings, and supervisory oversight. An interactive discussion concerning the expected response to placing shutdown cooling in service was observed. Computer traces of the level response to this event were discussed, and then the operators were shown the event on the simulator. Station management reviewed the interim corporate team report and implemented several additional corrective actions. These included requiring the shift manager to spend a majority of time in the control room, issuing memorandums regarding proper conduct of Heightened Level of Awareness briefings, proper communication between the control room and the outage work execution center, procedure adherence expectations, roles and responsibilities of operators and other issues, and aligning operator crew schedules so the entire crew rotates on and off shift together.
- c.2 Conclusions Failure to comply with an operating procedure for initiating shutdown cooling resulted in a reactor vesselinventory loss of about 7000 gallons of water, The event involved several poor practices in operations including poor communications, poor activity briefings for high risk activities, lack of shift briefings, inadequate supervision of important control room activities, failure to meet expectations for panel monitoring duties, and slow event response.
01.3 Operation of Out-of-Service Taaaed Eauioment Caused Shutc'?wn Coolina Valve Damaae I
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Inspection Scope (71707)
The inspectors interviewed personnel and reviewed documents related to the discovery
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of failed brushes on a Unit 2 shutdown cooling isolation valve motor.
b.
Observations and Findinas On February 18,1999, operators were performing a surveillance test procedure to check primary containment isolation logic. This test required installation of jumpers in the 2-1001-47 " shutdown cooling suction header downstream isolation valve breaker cub;cle." Installing the jumpers required opening the cubicle door for the breaker.
Following installation of the jumpers, the breaker for the valve was turned on locally at the breaker while the breaker cubicle remained open. Then, the valve was operated from the control room. Later, the test director (from operations) moved the door to the cubicle and found an out-of-service tag hanging on the outside of the cubicle door
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which required the breaker to be left open (Out-of-Service 980011229). Operators then opened the breaker for the valve. Operators Ister indicated that they had not seen the j
tag hanging on the breaker handle, which was located on the outside of the cubicle
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door, when operating the breaker from inside the cubicle. Problems with compliance J
with various portions of the out-of-service program at Quad Cities have been ongoing and documented in previous inspection reports.
The shutdown cooling isolation valve had been previously placed out-of-service in order to prevent inadvertent and spurious operations which could result in a loss of reactor vessel water inventory. In adoition to the breaker being opened, the brushes for the valve motor had been removed from their normal slots by electricians in order to prevent spurious operation in a fire, but were left connected to the wiring and not taped over.
When the valve motor was energized, the brushes began arcing against pieces of the valve motor, resulting in damage to the brushes. This made the valve inoperable until the brushes were replaced. Therefore, the abili.y to remove decay heat from the reactor following a shutdown was degraded because the valve would have had to be operated manually if operators could reach the valve location, in an emergency such as a fire.
Workers repaired the valve motor shortly after Unit 2 began shutting down for the outage on February 20,1999.
Failure to follow the requirements of Out-of-Service 980011229 was a Violation of TS 6.8.A.1 and of Quad Cities Interim Procedure 98-0165 " Equipment [Out-of-Service)"
dated November 6,1998, which was a procedure addressed in Regulatory Guide 1.33.
However, the NRC is refraining from issuing a violation in this case because this violation is considered a further example of Violation 50-254/98023-01 and corrective actions for that violation may not have had sufficient time to be fully effective. Corrective l
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l actions for Violation 50-254/98023-01 would be expected to be sufficient to address this l
additional example, as well.
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Conclusions i
Operators failed to observe the requirements of an out-of-service tagout intended to prevent operation of the shutdown cooling suction header isolation valve. This vie'ation of procedure requirements and TSs led to damaging the motor for the valve, which
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was repaired during the Unit 2 reactor shutdown.
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01.4 Rod Block Monitor Bvoassed Daily a.
Inspection Scope (71707)
The inspectors reviewed operator logbooks, reviewed applicable TSs, and discussed the operation of the rod block monitor system with nuclear engineers and licensee management.
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Observations and Findinas The inspectors noted that operators entered the limiting condition for operation action statement for TS 3.3.M every day when bypassing rod block Monitor 7 dunng control rod manipulations to support TS Surveillance Requirement 4.3.C.1.a. This TS surveillance requirement verified operability of the cuntrol rods by moving each rod at least one
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i notch once eve'ry 7 days. The station accomplished this task by testing some rods every day. Operators bypassed the rod block monitor to eliminate rod blocks that occurred in order to be able to move the rods for daily control rod testing and for power ascension.
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The rod block monitor rod blocks were occurring more frequently than usual because of an abnormal equipment problem. Unit 1 was operated at a higher than usual flow control line because of recirculation flow limitations based on identified cracking in jet pumps during the. refueling outage that was completed in December 1998. As a result, i
average power range monitor and rod block monitor rod blocks occurred more frequently. In order to prevent rod blocks during daily control rod surveillance testing,
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l operators inserted rods daily prior to the start of the testing to lower the flow control line.
After control rod surveillance testing, the flow control line was again raised by withdrawing control rods to return the unit to full power. Operators lowered power i
enough to prevent rod blocks from the average power range monitor but chose to bypass the rod block monitor rather than inserting the additional control rods to prevent rod block monitor rod blocks.
L Technical Specification 3.3.M required both rod block monitor channels to be operable
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when thermal power was greater than 30 percent. The limiting condition for operation action statement required that with one channel inoperable that the channel be restored within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or be placed in the tripped condition. The action statement also required
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l that operators verify the reactor was not operating in a limiting control rod pattern: Since the reactor was not in a limiting control rod pattern, both the T5s and the licensee's l
operating procedures allowed the rod block monitor to be bypassed.
i The rod block monitor system was designed to automatically prevent fuel damage in the event of erroneous rod withdrawal from locations of high power density during high power operations. As stated in the TS bases, the system backed up the operator, who withdrew control rods according to a written sequence. Although not prohibited by TSs, j
the inspectors considered the practice of intentional daily entries into limiting conditions t
i for operation by bypassing the rod block monitor daily during control rod withdrawal to be non-conservative plant operation. Operators apparently viewed the valid rod blocks produced by the rod block monitor as a nuisance and a distraction. The inspectors
. discussed the daily bypassing of the rod block monitor with the nuclear engineers and determined that the nuclear engineers were unaware that operators were bypassing the system.
' After discussions with the shift operations supervisor regarding this practice, operators discontinued bypassing the rod block monitor during this evolution. Problem Identification Form 1999-00450 was generated after operators experienced delays in returning the unit to full power after control rod surveillance testing with the rod block monitor un-bypassed. The delays were caused by numerous rod blocks during rod withdrawal. Resolution of the issue included adjustment of average power range l
Monitor 3, which was the reference for rod block Monitor 7, and which was reading slightly high.
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Conclusion Limitations on recirculation flo'w due to identified jet pump cracking resulted in reactor operation at a higher flow controlline than normal. As a result, frequent average power range monitor and rod block monitor rod blocks occurred. During daily control rod exercising, operators chose to bypass the rod block monitor and intentionally enter TS
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limiting conditions for operation to prevent valid rod blocks rather thLn reducing the flow
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controlline to perform the surveillance without experiencing rod blocks. Bypassing the rod block monitor under high power conditions during rod withdrawal was considered to i
be non-conservative but was not prohibited by the TSs.
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O2 Operational Status of Facilities and Equipment O2.1 Safety System'Walkdowns a.
Inspection Scope (71707)
The inspectors toured various areas of the plant including specific portions of the j
following systems:
i control rod drive
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reactor core isolation cooling
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Observations and Findinas The inspectors noted that ' drain manifold was connected to the Control Rod Drive 107 valves for each control rod drive unit. This drain manifold was not indicated on the piping and instrumentation diagrams. An oilleak on the "2B" core spray pump did not have a work request identifying the need for repair. A core spray keep fill valve l
handwheel was missing. A reactor coolant isolation cooling system root valve had a nut missing and another valve with the stem painted. The inspectors noted declining i
l housekeeping practices in some rooms such as the new computer room and the "A" l-control room heating, ventilation, and air conditioning room. Lighting in several rooms l
was poor, with up to 60 percent of the lights not working in some rooms with safety-related equipment, These and other discrepancies were turned over to the licensee for corrective action.
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Conclusions Material condition of the control rod drive, core spray, and reactor core isolation cooling systems was adequate. Although no major deficiencies were found, the inspectors noted that operators, engineers, managers, and other station personnel who routinely entereu these rooms were not reporting equipment problems or enforcing standards of cleanliness in all cases.
Miscellaneous Operations issues (92700)
08.1 [ Closed) Licensee Event Report 50-265/97007-00: Drywell to Torus Vacuum Breakers
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Inadvertently Actuated. On three separate occasions, with Unit 2 in Mode 4, the licensee inadvertently actuated engineered safeguards equipment. The operation of the
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' drywell to torus vacuum breakers occurred as.esult of the drywell purge fan operating, and a change of equipment status such as closing drywell hatches. The licensee attributed these events to changes in drywell to torus purge ventilation systern operating procedures without recognizing the breakers could actuate during changes in equipment status. The inspectors reviewed the licensee's corrective actions as stated in the licensee event report. The licensee did not change the differential pressure setpoint for the vacuum breakers. Warning signs were placed on affected hatches and.
appropriate caution statements were added to drywell ventilation procedures. This licensee event report is closed.
08.2 (Closed) Licensee Event Report 50-265/97011-00: Offgas Hydrogen Sampling Frequency Less than Required by TSs. With Unit 2 at full power and the offgas monitor inoperable, grab samples were collected every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> as rcquired by TSs. At steady state operations and constant offgas recombiner temperatures, the unit supervisor reduced sampling frequency to once every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> as allowed by TSs. On the following shift, hydrogen injection tripped, which reduced offgas recombiner temperatures slightly.
The unit supervisors did not increase the sampling frequency due to not effectively tracking the limiting condition for operation. This missed TS was a violation in Inspection Report 50-254/97014; 50-265/97014. The inspectors reviewed the corrective actions and found them acceptable. This licensee event report is closed.
11. Maintenance M1 Conduct of Maintenance M1.1 Gene,al Comments Mainttnance performed well in many of the activities observed during the period which included significant work during the 8-day Unit 2 surveibnce outage. Many equipment problems were corrected during the outage. However, some procedural errors i
occurred, and some longstanding equipment problems remained throughout the period or returned following startup from the outage. Inspectors found that maintenance workers failed to follow management expectations for procedure adherence on several occasions. Surveillance procedures observed were generally well contro!!ed using good communication techniques.
M1.2 Surveillance Procedures Watched The inspectors observed surveillance testing including the following procedures:
Quad Cities Operating Surveillance 5700-09, "[Emergercy Core Cooling
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System] Room and [ Diesel Generator Cooling Water r amp) Cubical Cooler
[ Differential Pressure] Test" J
6500-10, "Sesquiannual Functional Test of Unit 2 Second Level Undervoltage,"
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on February 11.1999 Quad Cities Operating Surveillance 1000-30, Revision 2, "A Loop [ Low Pressure
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Coolant injection Residual Heat Removal System] Outage Logic Test,"
performed on February 22,1999
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e Quad Cities Technical Surveillance 0240-04, Revision 5, " Unit One (Two)
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Service Test 250 Vdc Safety Related Battery," performed on February 23,1999 Quad Cities Operating Surveillance 6600-40, Revision 0, " Unit Two Emergency
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Core Cooling System Simulated Automatic Actuation and Diesel Generators Auto-Start Surveillance," performed on February 24,1999 Quad Cities Operating Surveillance 1400-09, Revision 8, " Flushing Core Spray
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Lines into the Reactor," performed on February 25,1999 Quad Cities Instrument Surveillance 0700-11, Revision 3 " Prior to Startup
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Average Power Range Monitor / Rod Block Monitor Downscale Control Rod Block Functional Test," performed on February 25,1999 l
With one exception, the inspectors noted good communications during the tests observed. In at least three of the surveillances observed, the procedures could not be performed as written, or the performance was not well planned for the plant conditions.
Many of the tests were planned for outages when decay heat was not as significant a l
factor such as it was in this outage. The test director generally gave a thorough and detailed pre-evolution briefing. The inspectors observed portions of the Bus 24-1 undervoltage test. During performance of the undervoltage testing, the Unit 2 diesel generator breaker closed as expected, then unexpectedly tripped. After a 5-minute time delay the breaker closed and then tripped again, unexpectedly. Some initial procedure problems and communications deficiencies between the operators in the control room and the field personnel hampered the efficient performance of this test. The licensee secured from the test and placed the Unit 2 diesel output breaker control switch in pull-to-lock. The licensee determined the breaker responded as designed and completed the test. Problem identification Form Q1999-00522 " Quad Cities Operating i
Surveillance 6500-10 Diesel Generator Breaker Closed and Auto Tripped" was initiated to track tnis issue.
M1.3 On-Line Maintenance Act;vities a.
Inspection Scope (62707)
r The inspectors reviewed the on-line risk assessment for the planned reactor core isolation cooling system maintenance on Unit 1 and the licensee's procedures for probabilistic risk assessment of on-line maintenance. The inspectors also reviewed the maintenance rule availability determinations for this system outage.
b.
Observations and Findinas For the first portion of work which involved room cooler maintenance, the reactor core isolation cooling system was considered to be available but inoperable. The second portion of the work involved the turbine governor and other components, during which the sistem was considered unavailable. The third portion of the work involved various breakers and valves in the system, incluCng the torus suction valve and the pump j
discharge valve. As a result, the configuration of the systern was such that only one j
suction source was available (the contaminated condensate storage tank), and the discharge valve was closed and coulo not be opened from the control room. During this
work, operators considered the system available The inspectors reviewed the
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maintenance rule and risk availability determinations and concluded that the system was actually unavailable 'during this third portion of the work. The failure to properly characterize the system as unavailable resulted in operators paying less attention to risk considerations (the risk status was considered " green") when risk considerations should have had increased attention (" yellow" risk).
The inspectors determined that the licensee's conclusion on the availability did not agree with the guidance in NUMARC 93-01, " Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," which requires that an automatic system be automatically available in order to be considered available under the maintenance rule. Nor did the conclusion agree with the licensee's probabilistic risk assessment procedure which considered systems available only with minimal operator action (within 5 minutes) to initiate the system. The inspectors asked the unit supervisor if a dedicated operator was stationed at the discharge valve to manually open the valve, and learned that no operator was dedicater for this activity. Since the valve was located in the reactor building and would have to be manually opened, the inspectors concluded that this activn could not be completed within 5 minutes.
Also, with only the contaminated condensate storage tank availsble, the system engineer concluded that the system was available because the Updated Final Safety j
Analysis Report stated that enough water was available for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> using the reactor
.1 core isolation cooling system. This was greater than the 4-hour coping time in the station blackout analysis. The inspectors questioned whether this determiration was appropriate since system trNsion time in the probabilistic risk assessment was 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Also, the inspectors found that the station probabilistic risk assessment expert was not consulted during the availability determinations regarding the single suction source, and the manual operation of the discharge valve.
After the work was completed and the system restored to an operable status, the inspectors learned that the out-of-service initially called for the discharge valve to be taken out-of-service in the closed position. The week befcre the maintenance work, planners intended to change the out-of-service and leave the discharge vabe in the open position but de-energized in order to consider the system available. However, due to mis-communication, the out-of-service was not changed, the valve was de-energized in the closed position, and the system was still considerC available, with reliance on operator action.
The initial determination of total unavailability time was approximately 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br />. The system engineer subsequently added approximately 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> of unavailability time after learning that the discharge valve had been out-of-service in thr. closed position. With the additional hours of unavailability time being tracked, the irapectors concluded that the maintenance rule monitoring was satisfactory.
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c.
Conclusion
)
The station did not accurately capture the reactor core isolation cooling system unavailability with the system not automatically available and with one suction source unavailable. As a result, the plant was actually in an elevated risk condition (yellow) for longer than expected. Ultimately, the add;tional unavailability hours were accounted for using maintenance rule tracking mechanisms.
'4 M1.4 Hiah Risk Activity Scheduled Concurrent with Unit 2 Emeraency Diesel Generator Out-of-Service -
a.
Inspection Scope (62707)
.The inspectora reviewed the daily work schedule and discussed on-line maintenance risk assessment with plant personnel.
b.
Observations and Findinas
- During a review of the daily work schedule, the inspectors noted that a Bus 24-1 second level undervoltage logic test was scheduled during a period of Unit 2 emergency diesel generator maintenance, when the emergency diesel generator would be unavailable.
The Unit 2 emergency diesel generator was the emergency power supply to the safety- -
related 4 kV, Bus 24-1. Although the test was not planned to de-energize Bus 24-1, it was considered to be a high risk activity due to the potential to lose power if something went wrong. Additionally, this was the first time the test was performed with the unit operating.
The inspectors were. concerned that the risk of these two concurrent activities, Unit 2 emergency diesel generator maintenance and a' logic' test with the potential to cause a loss of power to a safety-related bus, was not adequately evaluated prior to scheduling the two activities at the same time.
Plant personnel involved with planning and schedu ig the test indicated that it was appropriate to perform the test during the Unit 2 emergency diesel generator maintenance. The logic was that the test rendered the diesel inoperable since the output breaker was required to be in the test position. Additionally, the station considered the shared emergency diesel generator, the station blackout diesel generator, and the 4 kV crosstie in the event that power was lost to Bus 24-1 to be sufficient mitigating systems. The inspectors agreed that several other power sources were available, but concluded that the best situation in terms of on-line maintenance risk planning would also include recovery of the Unit 2 emergency diesel generator.
. However, the test was initially scheduled during the portion of the diesel maintenance in which the maintenance activities would have rendered recovery very difficult (oil drained, parts removed, etc.) rather than when the diesel would be fully functional with the exception of the breaker in the test position.
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Station management reconsidered the sequence of activities and decided to perform the Pus 24 J undervoltage test after the completion of the diesel maintenance. Although the diesel was considered inoperable and unavailable, recovery was simpler. Therefore, the potential risk of the Bus 24-1 test was lessened.
c.
. Conclusion
~ Concurrent scheduling of emergency desel generator maintenance and a surveillance test with the potential to lose power to a safety-related bus indicated a lack of thorough risk evaluation. The surveillance test was rescheduled to be performed during a period of the emergency diesel generator outage in which the diesel would be recoverable.
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M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Eauipment Problems a.
Inspection Scope (61726)
The inspectors reviewed several notable equipment problems which occurred this period. Some were repeat problems from last period, others were new, b.'
Observations and Findinas On January 31,1999, Unit 2 Control Rod K-6 failed to withdraw from Position 00.
During the Unit 2 planned outage, operators used a special procedure to increase differential pressure across the drive and were able to withdraw the rod. Subsequently, the control rod drive was replaced.
Operators kept feedwater control for Unit 2 in single element control instead of 3 element control during most of the petiod due to problems with the control circuitry.
On February 11 and February 19,1999, following repairs to the circuitry, IMnc.
i feedwater transients occurred. Additional repairs were made to the circuitry during the Unit 2 planned outage, and a root cause report was being written by the investigating team at the end of the period.
On February 6,1999, the "1D* residual heat removal service water pump breaker tripped shortly after pump start and also failed to close when in the test position. The licensee had not determined the cause of failure at the end of the period.
On February 15,1999, the % emergency diesel generator cool:ng water pump breaker tripped unexpectedly whi'e being supplied from Bus 28, with an " overload" condition being indicated on the tria device for the breaker. Licensee testing indicated the motor and wiring for the pump v'ere acceptable, but had not found the cause for the breaker trip at the end of the perici On February 17,1999, the "2A" reactor protective system bus de-energized due to a failure of the reserve power supply voltage regulator. The loss of power resulted in placing the reactor protective system and primary containment isolation system Group 1 i
alignment in a half tripped condition and partialisolations of primary containment isolation system Groups 2 and 3. The failure also led to a failure of the "2A" main steam i
line radiation monitor. The root cause of the problein was not known at the end of the i
period.
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On February 26,1999, the "2A" control rod drive pump failed at the inboard bearing and mechanical seat area. The pump had recently failed and caused a minor fire in
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December 1998 (see Inspection Report 50-254/98023; 50-265/98023). The licensee j
restarted Unit 2 with only one control rod drive pump available and then repaired the
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"2A" pump with the unit restarted. A root cause evaluation for the failure was not I
available at the end of the inspection period,
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On February 28,1999, during startup from the Unit 2 planned outage, operators experienced numerous problems with control rod drives which could not be moved at
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. normal operating pressure. This was a long-standing problem and remained a source of significant additional operator antion during the reactor startup. The licensee plans to correct the problem at some future date.
c.
Conclusions Numerous equipment failures occurred which caused operating transients or abnormal l
system configuration. Many problems were repaired during the Unit 2 planned outage, but some significant problems remained.
M2.2 Out-of-Service Error q
a.
. Inspection Scope (62707)
The inspectors reviewed the licensee's prompt investigation of an out-of-service error.
b.
- Observations and Findinos On January 22 the operational analysis department discovered an out-of-service error i
during testing of a recently installed control switch for the radwaste floor drain sample pump. An expected light indication did not illuminate. The subsequent prompt
- investigation (Problem Identification Form Q1999-00220) found that an incorrect lead had been lifted during the out-of-service. The out-of-service required that the wire at
Terminal 6 on Relay CX-4T be lifted, and the wire at Terminal 7 had actually been lifted.
Terminal 7 would have deactivated the annunciator circuit. The error did not result in a safety hazard for the electricians who replaced the switch.
The investigation attributed the error to inadequate electrical maintenance work practices for identifying leads. In this case, electricians used a smalllabel present on the lifted lead which was numbered "6." Electricians indicated that these labels were not present on all conductors (approximately 50 percent) but could be considered accurate if present. The electricians did not use Quad Cities Electrical Maintenance Procedure 0700-07, " Maintenance Temporary Alterations for Troubleshooting / Lifting and Landing Leads," which showed the terminal points for various types of relays. This procedure was required only during troubleshooting and not during all activities requiring the lifting of leads. Failure to verify the proper lifted leads was a violation of the out-of-service procedures, but was considered minor in nature because of the equipment being repaired. Corrective actions included a procedure change to require verification using drawings in all cases.
c.
Conclusion informal maintenance practices for the verification of relay terminal points and a lack of procedural requirements resulted in the wrong lead being lifted on the radwaste floor drain sample pump control circuit.
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- M2.3 Poor Maintenance of Room Cooler Parts a.
Inspection Scope (61726L The inspectors observed portions of maintenance performed on the reactor core J
isolation cooling system while Unit 1 was operating.
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b.
Observations and Findinas On February 3,1999, the inspectors noted the very poor condition of the replaced fan belts for the reactor core isolation cooling room cooler. The two belts were cracked in approximately 1/2 inch increments all the way through to the outer cords. The inspectors discussed the condition of the belts with the mechanical maintenance foreman and technician. The inspectors noted that on the following day, no problem identification form had been written, and the system engineer was not made aware of the problem.
i Initially, the mechanical maintenance supervisor discussed with the inspectors that the condition of the belt was due to normal service wear. The inspectors requested the system engineer review the condition of the belts. The system engineer contacted the belt vendor. The system engineer subsequently informed the inspectors that the
removed belts were too wide for the pulleys and not of the right design (for example, a solid belt instead of a serrated belt). A problem identification form was then written by mechanical maintenance personnel to document the belt condition (Problem
- Identification Form Q1999-0-402).
The periodicity of the room cooler preventive maintenance cycle was 36 months. The system engineer decided to move the preventive maintenance frequency to 18 months due to input from the belt vendor. The inspectors found one of the two be;ts on Unit 2 to be cracked, though not as severely. The Unit 2 preventive maintenance cycle was still on an 18-month periodicity because the cooler had been found to accumulate deposits
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of silt. The inspectors were informed that a work request would be generated for the
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Unit 2 fan belts.
c.
Conclusion j
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l The inspectors found that the maintenance personnel working on the reactor core isolation cooling system did not try to correct the poor condition of the belts for the room cooler. Later questioning by the inspectors led the system engineer and vendor to find discrepancies with the belts used and the periodicity of the preventive maintenance described.
M4 Maintenance Staff Knowledge and Performance M4.1 Work Reauests and Surveillance Observations
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a.-
Inspection Oooe (61726. 62707)
The inspectors reviewed maintenance activities associated with replacement of the
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Unit 2 traversing in-core probe Number 4 (Work Request Number 990003624) and assessed maintenance worker performance and compliance with plant requirements.
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- Observations and Findinas On January 21,1999, the inspectors observed installation of a traversing in-core probe Detector Number 4 on Unit 2. Step 5 of Quad Cities Instrument Procedure 700-5, j
referenced installation of the new detector per a vendor procedure (GEK 62922A).
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However, the inspectors observed the instrument maintenance technicians install the detector without use of this vendor procedure.
The Quad Cities Administrative Procedure 1100-12," Procedure Use and Adherence,"
required procedures be implemented to direct all tasks and the procedure step be
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I initialed upon completion. Even though the instrument technicians implemented the steps required by GEK 62922A, the procedure was not on-hand and was not initialed as required by the administrative requirements. This violation of station procedure adherence requirements was considered minor in natute. Even though this event was of minor safety consequence, the inspectors noted this could be indicative of a more programmatic problem in which maintenance personnel were not adhering to administrative requirements for procedure adherence, i c.
Conclusions l
Even though installation of an in-core probe without a procedure was of minor safety consequence, the inspecters noted this could be indicative of a more programmatic problem in which mainten'
+.e personnel were not adhering to administrative requirements for proced adherence.
M4.2 Poor Control of Inventoi, /ith Shelf Life Exoirations a.
Inspection Scope (61726. 62707)
The inspectors reviewed maintenance reports, and spoke with stores personnel regarding problems with shelf life noted on Control Rod Drive K-6 for Unit 2.
- bl Observations and Findinas Inspectors questioned maintenance personnel about Problem identification
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Form Q1999-00662 which was written to document that the shelf life had expired for Control Rod Drive K-6, which was installed during the Unit 2 planned outage. Stores management personnel later produced an apparent cause evaluation report which documented some areas of procedural non-compliance. The drive originally had a shelf life of 1 year, which expired September 25,1998. Quad Cities Administrative Procedure 1400~05, " Control of item With Limited Shelf Life," required inventory with expired shelf life to be tagged with a hold tag. An inventory control shelf life criteria data sheet and electronic entry should have been made which would have notified stores personnel of the shelf life expiration. Maintenance and stores personnel decided not to tag the control rod drive because it was in an area with higher than normal radiation dosec The inspectors contacted radiation protection personnel and found that general dose rates in the area of the stored control rod drives was actually low and in the range of 2 milkrern per hour.. In November 1998, the shelf life for control rod drives was extended to 5 years - This was not reflected in some locations of the stores database.
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A When the drive was installed in February 1999, the mechanical maintenance personnel
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failed to notice the expired shelf life tag and Quality Assurance red tag. Some communication problems between reactor services and mechanical maintenance supervisors also occurred. The expired shelf life was finally noticed during package closure after the drive had already been installed. Station personnel performed a thorough review of the problems associated with this failure to follow procedures. Some other areas were reviewed by the station for shelf life problems, and none were found.
The inspectors found that since the control rod drive was qualified for 5 years, the safety significance of this actual event was low. The violation of station procedures was considered minor. However, the inspectors found that the issues involved in this maintenance activity including failure to follow procedures, communication breakdowns, and inattention to detail were indicative of similar problems across the station.
c.
Conclusions Failure to follow procedures, communication breakdown, and inattention to detail were involved in the installation of a control rod drive with an expired shelf life tag. Later it was determined that the control rod drive was qualified for installation.
111. Enaineerina E1 Conduct of Engineering E1.1 Review of Engineering Evaluations a.
Inspection Scope (37551. 92903)
The inspectors reviewed two operability evaluations generated by the Enoineering Department. These evaluations were a result of deficiencies identified by e::%r the incpectors or the licensee. The issues were dispositioned to engineering for operability determinations to ensure the equipment would be able to perform the intended safety function during accident conditions.
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i Problem identification Form Q1999-00213 Unit 1 Shutdown Cooling Pioing Supports Degrading at increased Frequency Problem identification Form Q1999-00201 Unit 2 High Pressure Coolant injection Exhaust Drain Pot in Alarm Condition b.
Observations and Findinas b.1 Unit i Shutdown Coolina Header Supports Dearaded Mechanical snubbers used to support the shutdown cooling header inside the Unit 1 drywell were subjected to a vibrating environment. The environment caused an increased rate of degradation of the snubbers. The licensee was aware of the snubber degradation and increased the frequency of testing and inspection of the affected snubbers. During the last refuel outage, the licensee attempted to replace the mechanical snubbers with a hydraulic snubber but could not complete the replacement
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The inspectors requested the licensee to provide supporting documentation to provide reasonable assurance that Unit 1 could operate safely during an accident condition with these snubbers installed in a vibrating environment. The licensee did not adequately document any operability determination for this issue until requested by the inspectors.
In the operability evaluation, the licensee evaluated snubber historical performance data. This data revealed that the snubbers had average service lives greater than 3 years < In mid-November 1998, two of the four snubbers were replaced; two remaining snubbers were tested satisfactorily. The operability evaluation concluded that there was reasonable assurance that the snubbers would perform their required design function until the end of the operating cycle, January 2001. At that time the licensee planned to replace the mechanical snubbers with hydraulic snubbers which would be less prone to degradation in a vibrating environment. The operability determination provided reasonable assurance that the equipment would perform its intended design function.
b.2 Unit 2 Hiah Pressure Coolant Iniection System Exhaust Drain Pot Hiah Level Alarm On January 20,1999, operators attempted to time the opening of the Unit 2 high pressure coolant injection steam admission valve followed by the operation of the system. However, a failed stop watch required the operators to stop the test. During the time the valve was open, steam entered into a portion of the high pressure coolant injection system and condensed. The condensate was collected in the exhaust pot drain tank, and the tank high level switch alarmed. The routine surveillance was aborted, and the system was declared inoperable until the exhaust pot drained. After about 104 minutes, the drain pot high level alarm cleared, and the system was operated i
satisfactorily.
Engineering personnel determined by both calculation and observation that a total of 50 gallons of water condensed from steam over the 104 minute period. This condensate drained from the system at a slow rate but did not result in the turbine blades being impacted by water. The licensee determined that for the time the Unit 2 high pressure coolant injection exhaust drain pot was in a high level alarm condition, the system was still operable. Similarly, temperature readings observed during the time indicated that the condensate did not back up into the turbine.
The inspectors reviewed the licensee's calculations and determined the calculations did not adequately describe the level of condensate in the system as a function of time. In addition, a second drain path was not evaluated as a source of condensate removal from the system. However, the calculations were adequate to provide reasonable assurance that the system was operable during the time the drain pot high level alarm was annunciating.
c.
Conclusions Until requested by the inspectors, the licensee did not adequately document an operability determination for operating Unit 1 with snubbers prone to vibration degradation. A second operability documentation did not address an additional drain path from the high pressure coolant injection exhaust drain pot. However, both operability determinations eventually provided reasonable assurance that the equipment would perform the intended safety function.
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p; e A E8 Miscellaneous Engineering issues (92902)
E8.1 (Closed) Licensee Event Report 50-265/97003-00. -01. and -02: Unit 2 "B" Core Spray Room Cooler Fouled Due to Hydrolazing Debris. On March 21,1997, the licensee identified 10 of 18 tubes in the Unit 2 "B" room cooler completely plugged and identified 6 other tubes significantly plugged. The room cooler was declared inoperable. System engineers did not adequately trend room cooler differential pressure. This deficiency was not documented nor analyzed for operability. This issue was considered a violation in Inspection Report 50-254/97006; 50-265/97006. The licensee cleaned the room cooler and initiated a monthly room cooler performance trending procedure. The
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licensee also added flow indicators to room coolers serving both the residual heat removal and core spray rooms. The inspectors reviewed the cooler performance trending procedure and verified the installation of the room cooler flow indicator modifications. These licensee event reports are closed.
E8.2 (Closed) Licensee Event Report 50-254/97005-00: High Pressure Coolant injection Declared inoperable. Engineering personnelidentified a degraded cable during a walkdown. The cable was later identified to be the p7wer supply cable to the gland seal condenser exhauster for the Unit 1 high pressure coolant injection system. To prevent spurious operations, operators placed the control switch to "off" which made the high pressure coolant injection system inoperable.. The licensee later identified that the cable was previously abandoned in place and another cable supplied power to the high pressure coolant injection system exhauster. The licensee declared the high pressure coolant injection system operable. Engineering-controlled drawings were not properly updated to reflect that the degraded cable had previously been abandoned in place.
The inspectors reviewed the licensee's corrective actions as stated in the licensee event report and verified placement of abandoned equipment tags & the affected cable. This licensee event report is closed.
E8.3 { Closed) Inspection Follow-up item 50-254/98023-03: Increased Degradation of Unit 1 Shutdown Cooling Header Snubbers. This item was discussed in Section E1.1. This item is closed.
IV. Plant Support R1 Radiological Protection and Chemistry Controis R1.1 Outaae Performance
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The inspectors observed good Radiation Protection Department performance in the conduct of pre-job briefings and control of radiation work in support of the Unit 2 surveillance outage,02PO2. Radiation exposure for the Unit 2 drywell work was well controlled. The estimate for the replacement of the reactor safety valves was l
10 person-rem. This job was completed at slightly over half of the estimated exposure due to dose saving efforts of the mechanical maintenance workers. The total persor..
rem exposure for both units during the outage was 29.5. This was just under the stretch goal of 30 person-rem which had been reduced from the original estimate of 39 person-rem. The number of personnel contamination events was also lower than was estimated.
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V. Manaaement Mee_ tings X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management near the conclusion of the inspection on March 4,1999. The licensee acknowledged the findings presented.
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,..* O INSPECTION PROCEDURES USED IP 37551:
Onsite Engineering IP 61726:
Surveillance Observations IP 62707:
Maintenance Observations IP 71707:
Plant Operations lP 92700:
Onsite Follow-up of Written Reports of Nonroutine Events at Power Reactor i
Facilities IP 92902:
Follow-up - Maintenance IP 92903:
Follow-up - Engineering IP 93702:
Prompt Onsite Response to Events at Operating Powec Reactors ITEMS OPENED, CLOSED, AND CISCUSSED Opened 50-265/99001-01 NCV inadvertent draining of about 7000 gallons of reactor
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vessel water Closed 50-265/99001-01 NCV inadvertent draining of about 7000 gallons of reactor vessel water I
50-265/97007-00 LER drywell/ torus vacuum breakers inadvertently actuated 50-265/97011-00 LER offgas hydrogen sampling frequency less than required by j
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Technical Specifications 50-265/97003-00,-01,-02 LER Unit 2 "B" core spray room cooler fouled due to hydrolazing debris J
50-254/97005-00 LER high pressure coolant injection declared inoperable 50-254/98023-03 IFl increased degradatior. of Unit 1 shutdown cooling header snubbers LIST OF ACRONYMS USED i
CFR Code of Federal Regulations
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IDNS Illinois Department of Nuclear Safety IFl Inspection Follow-up Item i
LER Licensee Event Report PDR Public Document Room OCOS Quad Cities Operating Surveillance Procedure URI Unresolved item VIO Violation WR Work Request
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