IR 05000306/1993021
| ML20059F485 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  |
| Issue date: | 01/03/1994 |
| From: | Russ Bywater, Dapas M, Jorgensen B NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20059F451 | List: |
| References | |
| 50-306-93-21, NUDOCS 9401140043 | |
| Download: ML20059F485 (18) | |
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Report No. 50-306/93021(DRP)
Docket No. 50-306 License No. DPR-60 Licensce:
Northern States Power Company 414 Nicollet Mall Minneapolis, MN 55401 i
facility Name:
Prairie Island Nuclear Generating Plant, Unit 2 Inspection At:
Prairie Island Site, Red Wing, Minnesota Inspection Conducted:
December 6 through 22, 1993 Inspectors:
M. L. Dapas R. L. Bywater D~
E%% A
/~ 7,9,/
Approved By:
B'. L. Jo sen, Acting Chief s
f Reactor cts Branch 2 Date Inspection Summarv inspection on December 6 through 22, 1993 (Report No. 50-306/93021(DRP))
Areas Inspected:
Special safety inspection by the resident inspectors of work planning, configuration management, and control of outage activities related to four events that occurred over a two week period from November 16 to December 1,1993, during the Unit 2 refueling outage.
Specifically, events involving the overpressurization of safety injection system piping, core alterations while the required condition of refueling integrity did not exist, the lockout of a 4160 Volt, non-safeguards bus, and the inoperability of a Technical Specification-related, fire protection system pump, were reviewed.
Results:
four violations of NRC requirements were identified during the inspection. One violation involved the failure to maintain refueling integrity while core alterations were in progress (a violation of the Technical Specifications), two violations involved the failure to provide appropriate procedures for activities related to filling and venting of the reactor coolant system and establishing refueling integrity during core alterations (violations of 10 CFR 50 Appendix B, Criterion V), and one violation involved the failure to follow a procedure for equipment isolations (a violation of Appendix B, Criterion V). The identified violations are of particular concern because, collectively, they reflect inadequate planning and control of outage activities. Several concerns were identified during thi.s inspection. These included the failure of operations shift management to maintain an awareness of overall plant conditions before performing critical 9401140043 940105 PDR ADOCK 05000306 G
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'l evolutions, weaknesses in communications between work groups, the lack of a questioning attitude by operations personnel, poor attention-to detail, inadequate procedural review, and in one case, a non-conservative operating
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decision.
Staff training on the. work planning and control process, and
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operator training on the equipment isolation and verification process, appeared weak.
The licensee's initial corrective actions in response to each
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of the events were prompt and conservative.
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DETAILS 1.
Safety In.iection Suction Pipina Overoressurization Event A.
Event Description On December 1, 1993, the licensee was performing special operations procedure 208, " Filling and Venting the Reactor Coolant System," as part of the Unit 2 refueling outage restoration. At'
approximately 6:15 p.m., the Auxiliary Building assistant plant equipment operator (APE 0), while monitoring waste disposal control panel indications, noted that water level.in the aerated drain sump tank was rapidly increasing and reported this condition to the control room. A radiation protection specialist also contacted the control room and reported that water was draining into a floor drain funnel in the vicinity of No. 21 safety injection (SI) pump, overflowing the funnel and spilling onto the floor.
The APE 0 was dispatched to the area and reported that No. 21 SI pump suction relief valve, 2SI-4-1, had lifted.
The discharge from this relief valve is routed to a funnel, which in turn is routed to a floor drain.
Pressure in No. 21 SI pump suction piping had exceeded the 210 psig lift setpoint for 2SI-4-1.
The APE 0 discovered that MV-32208 (21 RHR HX to 21 SI pump-suction) was open.
It is assumed that this valve is closed to isolate residual heat removal (RHR) pump discharge flow from the
lower design pressure SI pump suction piping, before entering procedure 208. Operations department personnel determined that at the time of discovery, MV-32208 was open per a work request (WR)
i that had not yet been' completed (WR U4225-SI-Q, " Perform 18 month PM lubrication on MV-32208"). Operations personnel initiated action to clear the equipment isolations specified in the WR and closed MV-32208.
Concurrently, control room operators decreased
reactor coolant system (RCS) pressure below 200 psig, resulting in relief valve 2SI-4-1 reseating. The licensee. reviewed emergency response computer system data for the event, and based on a plot of No. 21 RHR pump discharge pressure, concluded that the maximum i
possible pressure in' No. 21 SI pump suction piping was 314 psig.
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Pressure in the suction piping was not limited to 210 psig by relief valve 2SI-4-1.
At the time of the event, RCS pressure was j
at approximately 275 psig.
j Floor drains in the Auxiliary Building are routed to the
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600-gallon, aerated drains sump tank (ADST) in the liquid waste system.
Depending on system alignment, the ADST contents'are pumped to the waste holdup tank or to other portions of the liquid waste system, by a primary and/or backup transfer pump, each'with 20 gallon capacity.
Floor drains in the SI pump area collected the discharge flow from 2SI-4-1, but this flow exceeded the
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capacity of the ADST transfer pumps, resulting in the tank
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overflowing into an associated sump pit.
Relief valve 2SI-4-1 reset when the SI pump suction piping was isolated.
During the
i approximate one hour that this relief valve was open, approximately 3500 gallons of water discharged to the floor i
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drains.
B.
Insnectors' Revi_ew and Findinas
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On the morning of December 1, 1993, the licensee was performing j
prestart checklists in accordance with procedure 208.
However,-
j checklist D8-2, " Reactor Coolant System Filling and Venting System j
Prestart Checklist," does not include position verification for j
RHR heat exchanger to SI suction, actor operated valves MV-32208 (train A) and MV-32209 (train B).
Also on the morning of December 1, a licensee engineer was reviewing Unit 2 outage work packages.that had not yet been completed, and informed operations personnel at the outage work control center that WR V4225-SI-Q was still outstanding and needed to be completed before the RCS was filled and vented.
This WR involved cleaning and lubricating the valve stem for MV-32208, and required that both MV-32208 and the associated valve actuator motor control center breaker be open.
The subject work activity had been scheduled for completion earlier in the outage, but it had been postponed on a number of occasions to support operations activities. The shift supervisor provided approval for equipment isolations and approval to start work with an understanding, based upon discussion with the engineer, that the work activity would only take a couple of hours, and the work would be completed before RCS fill and vent was scheduled to commence.
Operators
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L performed the isolations specified in the WR and completed them by 12 noon on December 1.
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The maintenance department is responsible for. conducting valve stem cleaning and lubrication. The maintenance supervisor-
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i responsible for WR U4225-SI-Q was informed by operations personnel that completion of the work request was important, but it was not
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l made clear to the maintenance supervisor that the work had to be j
completed before the start of RCS fill and vent. Since the l
maintenance personnel normally assigned to perform valve stem cleaning and lubrication, as well as the other maintenance
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personnel on duty, were involved in other important-outage work-
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activities, the maintenance: supervisor had no resources available to work on MV-32208. Therefore, the maintenance supervisor scheduled the MV-32208 work for the next day, when he.would have sufficient resources available. Meanwhile, operations personnel i
had opened MV-32208 and performed the required isolations specified in the WR. No hold had been placed on initiating fill and vent activities in procedure 2D8 pending completion of WR U4225-SI-Q.
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t On December 1, control room operators were not aware that MV-32208 was still open and proceeded with filling the RCS until it was water-solid, and began increasing pressure. At shift turnover i
(6 p.m.), RCS pressure and temperature were 240 psig and
93 degrees Fahrenheit (F), respectively.
Shortly.after shift
turnover, the status of MV-32208 was realized when the SI pump l
suction relief valve lifted.due to overpressurization of the
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associated piping. There was some delay in the immediate corrective action of closing MV-32208 while operators determined the current status of selected valves and breakers isolated per
WR U4225-SI-Q and verified with maintenance supervision that these equipment isolations could be cleared.
The Updated Safety Analysis Report (USAR) for the Prairie Island '
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Nuclear Generating Plant states that the design pressure of the SI suction piping is 210 psig at 30 degrees F.
The safety-related
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function of this piping is to provide a flow path for borated-water from the boric acid storage tanks and the refueling water I
storage tank to the suction of the SI pumps during the injection
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phase of a loss-of-coolant accident (LOCA) or high energy line break accident, and from the RHR pumps to the SI pump suction i
during the recirculation phase for a small break LOCA.
Per the i
USAR, pressure in-the SI pump suction piping is not expected to
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exceed 200 psig during the recirculation phase, the most limiting case. The licensee performed an evaluation to determine if the
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subject piping had been overstressed during the overpressurization event, and concluded that the code allowable stress for the piping was not exceeded since the system pressure corresponding to the
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maximum code allowable stress is 575 psi at 100 degrees F.
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licensee also identified that the original construction hydrostatic test of the SI pump suction piping was conducted at 315 psig, 150 percent of the system design pressure.
The licensee
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concluded that the suction piping was not overstressed during the l
overpressurization event because pressure did not exceed the hydrostatic test pressure. The licensee also removed relief valve 2SI-4-1 for inspection and testing, replaced the valve, and-performed surveillance procedure SP 2088, " Safety Injection Pumps
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Test," to demonstrate SI system operability.
Checklist D8-2 referenced in procedure 2D8-identifies specific
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valves that must be isolated before proceeding with RCS fill?and
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vent. Motor-operated valve MV-32208 is not contained in this
'l procedure. This omission contributed to the failure to recognize that an extension of the RCS pressure boundary would be breached upon pressurization. Criterion V of Appendix B to 10 CFR Part 50, i
requires that activities affecting. quality be prescribed by
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documented instructions, procedures, or drawings of a type
appropriate to the circumstances. The failure of checklist D8-2
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to include a required isolation valve to enfure RCS pressure
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boundary integrity, indicates that the procedure was not of a t/pe i
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appropriate to the circumstances for an activity affecting quality
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(RCS fill and vent). This is considered a violation of Criterion V of Appendix B to 10 CFR Part 50 (306/93021-01).
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C.
Analysis of Root Causes There were several contributirg causes to this event.
There was an inadequate checklist for system lineup before filling and venting the RCS.
Procedure 208, in step 5.1.2, requires shift supervisor acknowledgement that SP 2088, " Safety Injection Pumps Test," has been completed for any 51 pump that has had its breaker racked out since the last completion of SP 2088.
Performance of SP 2088 includes a verification of proper SI system lineup before the test is started.
However, step 5.1.2 does not require performance of SP 2088 if an SI pump breaker has not been racked out, nor does it ensure that SI system configuration has not changed since SP 2088 was last performed. Therefore, procedure 2D8 should not rely on SP2088 to ensure that the SI system is in
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the correct configuration because SP2088 may not be performed.
There was inadequate work planning concerning the recurrent deferral of WR V4225-SI-Q.
This resulted in a routine outage
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maintenance activity being hurriedly inserted into the work schedule as a critical item.
If the work activity had been discussed at the previous day's outage. work planning meeting, all
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work groups would have been fully aware of the need for WR U4225-SI-Q to be completed before RCS fill and vent.
There were inadequate communications among work groups once it was.
i decided that WR U4225-SI-Q needed to be performed before RCS fill
and vent on December 1. Inadequate plant configuration control on j
the part of operations shift management resulted in the RCS f1il and vent evolution proceeding without confirmation of the status of the completion of WR V4225-SI-Q and the position of MV-32208.
D.
Safety Sianificance The technical safety significance of the event was relatively minor. The piping had a design pressure rating much' higher than the relief valve lift setpoint.
The reactor had been; shut down since October 28, several sources of makeup water to the RCS were available, and RCS temperature was less than 100 degrees _ F.
On the other hand, the conditions that led to this event were i
significant in that they demonstrated a less than adequate attention to detail on the part of plant personnel, an insufficient questioning attitude towards the scheduling of a work activity that resulted in an abnormal equipment lineup, and a loss of command and control of a plant evolution. The overpressurization of the SI suction piping and the resultant safety relief valve operation constituted an unnecessary challenge -
to plant equipment.
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E.
Licensee Initial Corrective Actions
'r Upon identification that relief valve 2SI-4-1 had lifted and RCS water was being discharged to the Auxiliary Building floor drains,
the licensee. immediately initiated actions to reduce RCS pressure, investigate the status of WR V4225-SI-Q, and close.MV-32208. The licensee initiated a nonconforming item report.to evaluate the potential overstressing of the SI system piping, and also initiated a nonconforming activity report to review pre-evolution
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checklists and other critical task procedures to ensure.that-they include required system lineups to prevent overpressurizing system components.
In addition, the licensee drained the RCS to
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50 percent pressurizer level, completed a review of all outstanding-quality WRs to ensure that they were appropriately scheduled, ano ie-performed the 2D8 checklists (with RHR HX to S1
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Pump Suction values included) before again attempting to fill and _
i vent the RCS. T0e licensee also initiated an Error. Reduction Task Force (ERTF) review of the event.
F.
Conclusions One violation was identified for this event involving an j
inadequate fill and vent pre-evolution checklist.
There were also
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weaknesses identified involving poor communications between work groups, the recurring postponement of a WR requiring completion
before the end of the outage, the failure to include a hold in the 2D8 procedure until completion of WR U4225-SI-Q, _and the lack of a
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questioning attitude on the part of operations personnel when the WR was not ccmpleted and the work package was not returned to the work control center within the time originally expected.
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Operations shift management did not maintain an awareness of plant conditions before performing a critical plant evolution.
2.
Core Alterations in Proaress without Containment Refuelina Intearity A.
Event Description On November 23, 1993, the licensee initiated fuel handling activities to transfer 121 fuel assemblies from the spent fuel pool to the Unit 2 reactor vessel for use in the next. operating _
cycle. During performance of these activities on November 24,-
1993, at approximately 9:40 a.m., a licensee quality assurance-(QA) specialist observed that air was coming-from motor-operated valve MV-32151. This valve is a cooling water (CL) return isolation valve for No. 22 containment fan coil unit (FCU), and is the outside-of-containment isolation valve in the line through Containment Building Penetration No. 38B. The subject valve was disassembled per WR U2156-ZC-Q for inspection and repair due to leakage.
The QA specialist reported to the control room that the ~
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cooling water return piping from No. 22 FCU was possibly providing an air transmission path from the Unit 2 Containment Building to the Auxiliary Building.
The QA specialist informed the control
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room that he was going to enter the Containment Building and investigate the condition. The QA' specialist observed that MV-32150, the inside-of-containment, CL-return isolation valve
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from No. 22 FCU, was open but had an equipment control card
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hanging from the valve actuator handwheel stating that the valve j
was closed.
The QA specialist reported the status of MV-32150 to
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the control room, and the shift supervisor ordered an operator who i
was on-duty in the Containment Building to manually close the valve.
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The shift supervisor reviewed Checklist C.19.9-2, " Inventory and.
Refueling Integrity Containment Boundary Checklist - Unit 2,"
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penetration No. 38B..The checklist indicated that the subject penetration was controlled as an " alternate isolation" per a
refueling integrity control sheet associated with WR U2156-ZC-Q.
Alternate isolations are controlled per procedure C19.9,-
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" Inventory and Refueling Integrity Containment Boundary Control."
i The normal isolation for the FCUs is to have both CL supply and I
return valves open with the associated CL line filled with water.
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However, because WR U2156-ZC-Q required draining of the CL lines I
for No. 22 and No. 24 FCUs, an alternate isolation was needed.
The shift supervisor noted that the alternate isolation refueling integrity control sheet also required that valves MV-32387 (outside-of-containment, CL-supply to No. 22 FCU through penetration No. 378) and MV-32156 (inside-of-containment, CL-return from No. 24 FCU through penetration No. 38D) be closed.
The shift supervisor ordered the operator in the Containment Building to check the status of MV-32156 and another operator in the Auxiliary Building to check the status of MV-32387.
Both of these valves were reported open with equipment control cards hanging on the respective valve actuator handwheels stating that the valves were closed.
The shift supervisor directed the operators to close each of these valves manually.
No air communication path existed through penetrations No. 378 or No. 380 from the Containment Building to the Auxiliary Building'because the CL piping outside of the Containment Building was intact for these penetrations.
However, relief valve 2CL-57-4, located in the CL return line from'No. 22 FCU between the FCU and MV-32150, had been removed for testing, and various CL piping vent and drain valves were open while MV-32151 was disassembled. As a result,'a direct air path existed from inside of the Containment Building to the Auxiliary-Building through penetration No. 38B.
B.
Inspectors' Review and Findinas The Prairie Island Technical Specifications define core alterations as, "the movement or manipulation of any component within the reactor pressure vessel with the vessel head removed and fuel in the vessel, which may affect core reactivity." The definition also contains a clarification statement, " Suspension of '
core alteration shall not preclude completion of movement of a
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component to a safe conservative position."
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Section 3.8. A.1 of the Technical Specifications-(TS) requires, in part, that during core alterations, "The equipment hatch and at least one door in each personnel air lock shall be closed.
In addition, at least one isolation valve shall be operable or locked closed in each.line which penetrates the containment and provides a direct path from containment atmosphere to the outside."
If these conditions are satisfied, refueling integrity has been
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established and core alterations may proceed. On November 23,
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1993, core alterations commenced when a direct path from the containment atmosphere to the outside (in this case the Auxiliary Building) existed through penetration No. 38B because MV-32150 was open. The failure to maintain at least one isolation valve either
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operable or locked closed in the CL-return line from No. 22 FCU while core alterations were in progress on November 23 and 24, 1993, is considered a violation of Technical Specification 3.8. A.1 (306/93021-02).
Section 3.8.A.2 of the TS requires, "If any of the above conditions are not met [in Technical Specification 3.8.A.1], core alterations shall cease. Work'shall be initiated to correct the violated conditions so that the specifications are met, and no operations which may increase the reactivity of the core shall be performed." As defined in the TS, ceasing core alterations shall not preclude placing a component in a safe, conservative position.
When the breach in refueling integrity was identified on November 24, 1993, the control room shift. supervisor did not inform the refueling shift supervisor in the Containment Building of the
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condition or order that core alterations be ceased.
Core alterations continued. The licensee subsequently identified two
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other penetrations with valves that were mispositioned per the refueling integrity checklist (MV-32387 for penetration No. 378 and MV-32156 for penetration No. 38D). The inspectors questioned the licensee as to why core alterations were not stopped upon identifying that MV-32150 was open.
The licensee stated that the time required to place a fuel assembly in a safe, conservative position following an order to cease core alterations would have-taken longer than the actions required to close MV-32150 and restore refueling integrity. While the inspectors agreed that'it would probably take less time to close MV-32150 then it would.take to cease core alterations, depending on the position of the fuel assembly during the transfer evolution from-the spent fuel pool to
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the reactor vessel, the inspectors concluded that the. licensee'
l should have ceased core alterations when the' breach in penetration No. 38B was identified, until a review of refueling integrity boundaries had been completed. The inspectors concluded that continuing with core alterations once the : licensee identified that the conditions of Technical Specification 3.8.A.1 were no longer met, was not conservative.
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Work Request U2156-ZC-Q was written to disassemble and repair MV-32151. This activity required two conditions of equipment
J-isolation.
First, an isolation was required to drain the CL
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d-i piping associated with No. 22 and No. 24 FCUs (performed at a time
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when refueling integrity was not required).
Second, after the FCU l
I CL piping was drained, another isolation was required to establish an alternate refueling integrity boundary in anticipation of work
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being performed on MV-32151 when refueling integrity was required.
The isolations were included in the WR V2156-ZC-Q package. -The inspectors noted an error in the isolation and restoration sheet associated with this WR in that MV-32387 was described as, "23
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containment-fan coil unit cooling water inlet isolation," when
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MV-32387 is actually the CL-inlet isolation valve for No. 22 FCV.
However, the equipment contr01 card for closure of MV-32387 was attached to the correct valve in the plant.
On November 17, 1993, an operator vas instructed to perform isolations and hang equipment contrel cards for alternate
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isolation refueling integrity control as specified in WR V2156-
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ZC-Q.
The operator attached equipment control cards on the actuator handwheels for MV-32387, MV-32150, and MV-32156. Upon
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observation of these valves in the plant, the operator believed
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that the valves were closed and attached equipment control cards to the respective valve handwheels. The subject valves have no
valve stem local position indication, and no position indication status for these valves was available in the control room at the -
time the cards were attached to the handwheels. This contributed to the difficulty in visually checking valve position status.
Also, these valves did not require an independent verification of
position status by another operator before the work package could
be released to the maintenance department for disassembly of
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MV-32151.
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On November 18, 1993, separate WRs were initiated for performing preventive maintenance on the power supply breaker for each of-
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four FCV, inside-of-containment, CL-return isolation valves.
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WR contained a procedural step to verify that the subject valve _
was closed, in performing this step, operators in the Containment-a
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Building observed that MV-32150 and MV-32156 each had an equipment-control card attached to the actuator handwheel indicating that
the valve was closed. No other work activities were identified
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that could have resulted in repositioning MV-32387, MV-32150, or
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MV-32156.
The inspectors did not-identify any information to
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dispute the licensee's conclusion that MV-32387, MV-32150, or MV-32156 must have been in the open position when an operator i
attached equipment control cards to the respective valve actuator
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handwheels on November 17, 1993.
Criterion V of 10 CFR 50 Appendix B, requires _that activities
affecting quality be prescribed by documented instructions, j
procedures, or drawings, of a type appropriate to the-I circumstances and shall be accomplished in accordance with these
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procedures.
Establishing _ containment building penetration-boundary isolations in support of fuel handling is an activity affecting quality.
Section 6.6.3 of Administrative Work
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Instruction (5AWI) 3.10.3, "Use of NSP Safety Tags," states that E
when performing an equipment isolatiun, " Operators or other j
authorized plant personnel shall place switches, valves, etc. in-the required position, complete and install the safety tags." The i
failure to follow procedure SAWI 3.10.3 by placing MV-32387, i
MV-32150, and MV-32156 in the required position is considered a violation of Criterion V of 10 CFR 50 Appendix B (306/93021-03).
Procedure Checklist C19.9-2, which implements the requirements of procedure C19.9, required independent verification of the isolation status for each Containment Building penetration.
However, for those penetrations controlled with an alternate isolation, procedure C19.9 did not require independent
verification of the alternate isolation status.
The isolation of MV-32387, MV-32150, and MV-32156 per WR U2156-ZC-Q, did not require independent verification of valve position status.
Criterion V of 10 CFR Part 50, Appendix B, requires that activities affecting quality be prescribed by documented instructions, procedures, or drawings, of a type appropriate to
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the circumstances. The failure of procedure C.19.9 to ensure the independent verification of all Containment Building penetration
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isolations is considered a violation of Criterion V of Appendix B j
to 10 CFR Part 50 (306/93021-04).
The inspectors discussed a previous event involving Containment Building penetration boundary control in NRC Inspection Report 50-282/93019; 50-306/93019(DRP).
The inspectors concluded.that that event resulted from a weakness in the work planning,.
scheduling, and approval process, and noted that-the November 24, 1993 breach of refueling integrity is the second Containment Building penetration control problem that has occurred in a three week period.
C.
Analysis of Root Causes The apparent root cause for this event is that the operator who applied the equipment control cards to CL isolation valves MV-32387, MV-32150, and MV-32156 on. November 17, 1993, had not been provided with adequate training in performing system.
isolations.
System isolation was difficult because valve position status was not available via indicating lights in the control room, valves had no local stem position indication, and in the case of MV-32387, the valve was difficult to reach. Also, other opportunities were available to identify that the valves were
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open, specifically the motor-operated valve supply breaker j
preventive maintenance activity and completion of the refueling
integrity checklist. The lack of a questioning attitude on the i
part of operations personnel also contributed to this event.
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D.
Safety Sionificance Refueling integrity requirements are established to prevent the
release of radioactive material to the environment in the event of
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a fuel handling accident.
Failure to-have MV-32150 closed during
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core alterations on November 23-24, resulted in a potential-transmission path for radioactive material from the Containment
Building to the Auxiliary Building should there have been a fuel i
handling accident. The licensee had previously submitted a l
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license amendment request to the NRC for a change to Technical Specification 3.8.A.l.
This change would not impose any containment closure requirements during refueling for penetrations
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with lines that exited the Containment Building into areas within
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the Auxiliary Building special ventilation system (ABSVS) zone boundaries. The licensee's basis for this proposed change is that the Updated Safety Analysis Report does not take credit for-containment isolation or_ABSVS filtration in demonstrating that a a
fuel handling accident will not result in an offsite dose that exceeds 10 CFR Part 100 limits. The NRC is still reviewing this proposed Technical Specification change. The opening associated with penetration 38B did not provide a path to the outside environment, but rather provided a communication path from the
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Containment Building to an area within the ABSVS zone boundary.
Since the ABSVS was operable on November 23-24, 1993, had a fuel i
handling accident occurred.during this time, the ABSVS would have been available to filter and dilute any potential radioactive release to the environment.
E.
Licensee Initial Corrective Actions The licensee restored refueling integrity by closing MV-32387, MV-32150, and MV-32156.
The licensee also reviewed-the alternate isolation log and verified the status of those penetrations with
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alternate isolations.
In addition, the licensee initiated an ERTF review of the subject event.
The General Superintendent of Plant Operations issued a memorandum to the operations department staff stating that if electrical power has been' removed from a particular motor-operated valve such that the valve's position cannot be verified by referring to control-board indications, then actions must be taken to verify the position of the valve locally, including possibly requesting that an electrician relieve actuator spring pack tension and then manually position the valve. Only after the position of the valve has been verified should the associated equipment control card be applied.
F.
Conclusions Although the potential consequences of this event were of minor -
safety significance, there were three violations associated with this event.
ihe problems identified with the equipment isolation
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and verification process are of particular concern because this
process is routinely relied upon to ensure both nuclear and personnel safety.
The lack of a questioning attitude by operations personnel was also apparent in this event.
The licensee should have ceased core alterations, when the breach in penetration No. 38B was identified, until a review of refueling
. integrity boundaries had been completed.
The decision to continue j
with core alterations was not conservative.
3.
4160 V bus No. 23 Lockout Event A.
Event Description j
On November 16, 1993, the licensee started to perform periodic, electrical maintenance procedure PE-0023-02T, "4.16kV Bus 23 Cubicle 2, 2M Aux. Transformer Electrical Maintenance - Test Tripping." Bus No. 23 is a non-safeguards, 4.16 kV electrical bus, however, it provides power to No. 121 screenwash pump and No. 21 cooling water (CL) pump.
While No. 121 screenwash pump and No. 21 CL pump are non safety-related components, they are each addressed in the Technical Specifications. At the time of the event, bus No. 23 was energized through source. breaker No. 23-9, from reserve station auxiliary transformer 2RY, and No. 21 CL. pump was in operation. During power operations, bus No. 23 is normally energized from station auxiliary transformer 2M, through source-breaker No. 23-2.
Step 2.0 of Procedure PE-0023-02T required manually operating the 51-1 overcurrent relay. When this step was performed, the bus lockout relay picked up, breaker No. 23-9 tripped, and bus No.-23 de-energized. At the time of the event, loop A and loop B CL supply headers were isolated with No. 21 CL pump in operation supplying train B CL loads. When No. 21 CL pump was de-energized, pressure in loop B of the CL system dropped below the 80 psig, automatic starting setpoint for No. 121 standby CL pump.
Pressure j
in loop B of the CL system was restored to normal'after No.121 CL
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pump started. Th0 licensee immediately recognized that bus No. 23 was de-energized and took actions to reset the bus lockout relay and close breaker 23-9 to restore power to the bus.
B.
Inspectors' Review and Findinos A note in Procedure PE-0023-02T states that, "This procedure is to-be used in conjunction with PE-0023 only." Procedure PE-0023 pertains to test tripping of the breakers on bus No. 23.
Historically, test tripping of non-safeguards, 4 kV breakers had
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been performed with the associated buses de-energized.
However,
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the recent completion of breaker treadle modifications, enables the licensee to perform test tripping of breakers with the associated buses energized. Work request U5213-EA-Q, " Isolate and
Restore Bus 23 for PM," was initiated on October 31, 1993, to perform PE-0023 with bus No. 23 de-energized.
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Number 121 screenwash pump serves as a backup pump for the fire water suppression system, and will. automatically start _if pressure in the fire water suppression system drops below 105 psig for greater than 15 minutes. With the de-energization of bus No. 23 on October 31, 1993, the licensee entered a 7-day limiting condition for operation (LCO) action statement, per Technical Specification 3.14.B.2, for No.121 screenwash pump.
Test tripping of bus No. 23 breakers continued during the week of October 31. As of Friday, November 5,1993, the licensee had not
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l yet performed test tripping of breaker 23-2 per PE-0023-02T.
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However, the licensee elected to re-energize bus No. 23 and postpone performance of PE-0023-02T because the allowed outage time per the LC0 action statement for No. 121 screenwash pump was running out.
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The licensee decided to perform PE-0023-02T on November.16, 1993, with bus No. 23 energized.
The responsible system engineer was offsite on November 16, and other licensee personnel were not aware that procedures PE-0023 and PE-0023-02T needed revision to allow test tripping of source breaker 23-2 with bus No. 23 energized. Therefore, the licensee used the existing procedures to perform test tripping of breaker'23-2, resulting in a lockout of bus No. 23.
At the time of the event, emergency diesel generator (EDG) D6 was
"available" for use as an emergency power source to Unit 2, 4 kV safeguards bus No. 26; however, to support other outage activities, the licensee had placed the bus No. -26 voltage restoration selector switch in manual, preventing.the EDG from automatically starting on an undervoltage condition. When the licensee placed the D6 EDG in this condition, it entered abnormal operating procedure (A0P) 1C20.6 A0P2, " Loss of Diesel Generator-Backup Power to MCC 1AB2." One of the compensatory actions contained in this A0P, to address the contingency of a loss-of-offsite power with D6 EDG incapable of automatically loading onto bus No. 26, is to " pre-align" the CL system for
" safeguards" use.
The subject A0P required the alignment of No.121 CL pump to loop B of the CL system, with its power supply from 4 kV safeguards bus No. 25.
The emergency power source for bus No. 25 is D5 EDG. The Technical. Specifications define the required CL system configuration for No. 121 CL pump to be considered an engineered safety feature (ESF) or " safeguards" pump.
Because No. 121-CL pump was aligned to loop B but was powered from bus No. 25, a train A power supply, the CL system was not configured to satisfy train separation requirements for
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No. 121 CL pump to be considered an ESF per the Technical
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i Specifications. However, No.121 CL pump provided additional i
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defense-in-depth because it augmented the availability of No. 22
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i-diesel-driven CL' pump, which is always aligned to loop' B.
If i
No. 121 CL pump had not been aligned to loop B, No. 22
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diesel-driven CL pump would have automatically started when loop B
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CL system pressure decreased below 75 psig.
If this had occurred,
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then the event'would have been reportable to the NRC per 10 CFR i
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50.72 as an automatic actuation of an ESF.
C.
Analysis of Root Causes
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The inspectors concluded that when initial conditions for a j
planned activity had changed, an inadequate procedural review was performed to ensure that the' procedure was still appropriate for the new circumstances.
When the responsible engineer was not j
available-at the time the test was performed, other licensee personnel proceeded to perform the test without thoroughly j
reviewing the procedure.
j D.
Safety Sionificance The consequences of this event were minor, consisting of a loop B
'l CL system pressure transient which was mitigated by the automatic start of No. 121 CL pump. Although the mechanical configuration of the CL system was the same as that specified in the Technical i
Specifications for " safeguards" operation of.No. 121 CL pump, the I
licensee concluded that the automatic start of this pump was not reportable as an ESF actuation per 10 CFR 50.72, since the pump
was not in its electrical " safeguards" alignment.
E.
Licensee Initial Corrective Actions The licensee ' modified procedure PE-0023-02T to perform test -
tripping of breaker No. 23-2 with bus No. 23 energized.
The licensee also initiated actions to review and modify other breaker test tripping procedures, which had been historically performed with the associated buses de-energized,. to allow test tripping of breakers independent of bus condition.
F.
Conclusions The licensee had a plan in place for accomplishing an activity assuming a given set of initial conditions. However, when the licensee changed those initial conditions, the original plan for-accomplishing that activity was inadequately reviewed for acceptability.
This event reflected a weakness in work planning and control of an outage activity.
4.
Inoperability of No. 121 Screenwash Pumo for Fire Protection Use A.
Event Description On November 16, 1993, the-licensee initiated painting activities in the vicinity of No. 121 screenwash pump per WR U6412-CW, " Paint equipment on 665' elevation in screenhouse." On. November 16, control room operators requested the painters to inform the control room each time that they started or stopped painting in-
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the vicinity of No. 121 screenwash pump, so that an' operator could
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be dispatched to the screenhouse to place the pump's local / remote
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control switch in the " local" position.
The painters informed the
control room operators that painting in the vicinity of No.121 screenwash pump could be performed safely while the pump was.
running. While WR U6412-CW did not require securing of No.-121
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screenwash pump, operations personnel decided, as.a courtesy to the painting crew, to transfer control of the.screenwash pump to.
j local by placing the local / remote control switch-in the local l
position to preclude cyclic operation of the pump when the
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painters were nearby. The licensee therefore placed the pump's
control switch in the local position with the pump not running on November 16,17, and 19 for varying lengths of time on each of the
dates.
Placing the pump's control switch in local when the pump
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is not running renders the pump inoperable because it will not
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automatically start. The licensee did not make an entry into its Technical Specification " Limiting Condition for Operation Log (LCO Log)" for any of these occurrences.
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On November 20, 1993, the licensee initiated WR U5920-CW,
" Isolate, drain, and restore circulating water intake bays."
In his review of this WR, the outage work control center shift supervisor noted that the associated procedure required recording the date and time that No. 121 screenwash pump was rendered-inoperable. This observation prompted the licensee to review its j
practice of placing the screenwash pump in local control, which
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had occurred throughout the week without making any LC0-log entry.
The licensee determined that if the screenwash pump was-placed in local control, then it should be declared inoperable per Technical.
Specification 3.14.B.
The licensee performed a~ review of No. 121 screenwash pump's operational history for the week of November 15, 1993, and made " late entries" in its LCO Log for each instance where control of the pump had been transferred to local.
B.
Inspectors' Review and Findinoi The principal function of No.121 screenwash pump is to provide i
spray pressure cleaning of the intake traveling screens.
The pump
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is also used as a backup fire protection system pump, and will j
automatically start when there is a low pressure condition in the R
fire protection system.
Placing No.121 screenwash pump in local control precludes it from automatically starting and performing.
its fire _ protection function.
Technical. Specification 3.14.B.1.a requires that No. 121 screenwash pump be operable.. Technical Specification'3.14.B.2
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requires that, "With one or.two of the pumps required by
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Specification 3.14.B.l.a inoperable, restore the inoperable
equipment to operable status within 7 days or provide a special report to the Commission within 30 days outlining the plans and procedures to be used to provide for the loss of-redundancy in the fire suppression water system."
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Procedure 5AWI 3.2.4, " Conduct of Work," identifies the
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responsibilities of the shift supervisor for review and approval
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of work packages prior to work commencement.
Section 6.2.1.b.3 of
this procedure states, "The status of plant systems and redundant
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trains of equipment shall be reviewed as well as Technical Specifications to determine if a Limiting Condition for Operation will exist." Also, Section.6.2.2.b of this procedure states, "The Fire Protection System Engineer or backup shall be notified whenever fire protection and/or detection equipment is removed from service." The shift supervisor did not identify that placing i
No.121 screenwash pump in local control on November 16, 17, 18,
and 19, 1993, rendered the pump inoperable, and therefore,
required entry into a Technical Specification, limiting condition for operation-(LCO) action statement; nor did the shift supervisor l
notify either the Fire Protection System Engineer or that person's
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designated backup.when No. 121 screenwash pump was removed from
service on those dates.
C.
Analysis of Root Causes
Control room operators and shift supervisors did not recognize that placing the local / remote control switch for No.121 screenwash pump in the local position rendered the pump-l inoperable. As a result, control room personnel did not recognize the failure to satisfy the operability requirements of_ Technical
Specification 3.14.B.1.a, and therefore did not record entry into the 7-day LCO per Technical Specification 3.14.B.2 each time that j
the screenwash pump was transferred to local control.
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D.
Safety Sionificance
.I The No. 121 screenwash pump is a backup fire protection pump to No.121 motor-driven fire pump and No.122 diesel-driven fire pump. Technical Specification 3.14.B.2 allows one or two of the three fire protection pumps to be inoperable for up to 7 days.
Collectively, the actual out-of-service time for No.'121 ll
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screenwash pump was less than 7 days. Also, both of the normal fire _ protection pumps were operable during each time that No.121 screenwash pump was inoperable.
In addition, the cooling water system can be aligned, via manually operated cross-connect valves, to provide a supply of water to the fire protection system.
E.
Licensee Initial Corrective Actions The General Superintendent of Plant-Operations issued a memorandum to all operations department shift managers and shift. supervisors informing them of the issue with No. 121 screenwash pump, and
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reminding them.of the requirement to make entries into'the LCO log.
when equipment addressed by the Technical Specifications, including fire protection equipment, is rendered inoperable.
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Conclusions Control room operators, including shift management, failed to identify and record the entry into a Technical Specification LCO action statement for No. 121 screenwash pump on four separate.
occasions. Although the transfer of control for No.121 screenwash pump was initiated by operations personnel to enhance personnel safety, the resulting condition of the screenwash pump-was not properly recognized as a reduction in fire protection capability by operations shift management.
5.
Manaaement Interview The inspectors met with the licensee representatives denoted in paragraph 6 after the conclusion of the inspection period on December 22, 1993. The inspectors also discussed the likely -informational content of the inspection report with regard to documents or processes.
reviewed by the inspectors during the inspection.
The licensee did not identify any documents or processes reviewed as proprietary.
6.
Persons Contacted i
- E. Watzl, General Manager, Prairie Island L
- M. Wadley, Plant Manager
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- K. Albrecht, General Superintendent, Engineering G. Lenertz, General Superintendent, Maintenance
- D. Schuelke, General Superintendent, Radiation Protection i
l and Chemistry J. Sorensen, General Superintendent, Plant Operations
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- M. Reddemann, General Superintendent, Electrical and Instrumentation Systems
- G. Rolfson, General Superintendent, Engineering-Nuclear Generation Services
- G. Miller, Superintendent, Technical Support
- A. Hunstad, Staff Engineer
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- P. Kamman, Manager, Nuclear Operations QA
- D. Krech, Quality Supervisor, Nuclear Quality Dept.
C. Hoglin, Nuclear Quality Department-i l
- R. Lindsey, General Superintendent Safety Assessment l
J. Maki, Superintendent, Electrical Systems.
P. Ryan, Shift Manager M. Schmidt, Outage Manager E. Eckholt, Nuclear Support Services J. Leveille, Nuclear Support Services G. Aandahl, Superintendent. Design Standards
- M. Dapas, NRC Senior Resident Inspector
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- R. Bywater, NRC Resident Inspector
- Denotes those present at the management interview of' December 22, 1993.
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