05000301/LER-2002-001
| Docket Number | |
| Event date: | |
|---|---|
| Report date: | |
| Reporting criterion: | 10 CFR 50.73(a)(2)(i)(A), Completion of TS Shutdown |
| Initial Reporting | |
| 3012002001R00 - NRC Website | |
Event Description:
On February 20, 2002 at approximately 0100 (all times are CST), the Point Beach Nuclear Plant (PBNP) Unit 2 "B" train safety injection {BQ} pump {P} (2P-15B) was damaged during a routine monthly preventive maintenance procedure for a "lubrication bump" of the pump. This pump start and run was being performed in accordance with Attachment 'H' of Procedure 01-163, "SI, RHR, and CS PUMP RUNS." Upon starting the pump, normal starting motor {MO} current was initially observed; however, the pump did not develop normal discharge pressure. Running amps were then observed by two licensed operators in the Control Room to decrease to below normal at which time the pump was secured. The Auxiliary Operator (AO), assigned to the pump bump evolution, and in the area of the pump at the time of the event, heard the motor/pump spin up and shortly thereafter go into coast down. He also heard a loud bang at or near end of coast down. The AO then observed excessive leakage coming from the inboard pump seal {SEAL} and reported the presence of an acrid smell. The Shift Manager (SM) overheard the radio conversation between the AO in the field and the control operator (CO) in the control room. Shortly thereafter, the SM and a second AO arrived at the pump area and concurrently observed the excessive seal leakage and perceived the acrid smell. They concluded that the acrid smell was emanating from the inboard pump seal area. The SM then directed isolation of the pump to secure the excessive seal leakage.
The safety injection (SI) pump was declared inoperable as of 0100. Technical Specification (TS) LCO 3.5.2 "ECCS- Operating" was declared not met, and TS Action Condition (TSAC) 3.5.2.A was entered. LCO 3.5.2 requires two ECCS trains to be operable in Modes 1, 2, and 3. LCO 3.5.2, Condition 'A', requires an inoperable ECCS train to be restored to an operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
Corrective Maintenance began early on the February 20, 2002 dayshift concurrent with the start of the associated event investigation. Initial inspection of the pump/motor following the event revealed approximately 1" of the pump shaft to coupling keyway visibly distorted and angled approximately 45% down and to the right (towards the motor end) indicating that the rotating assembly shaft had been twisted. During subsequent inspection of the SI pump, the shaft coupling keys between the motor and the pump were found to be sheared. Upon disassembly of the pump several wear rings were found to be missing a piece. All pieces from the broken wear rings were recovered. A new pump rotating element with new wear rings was installed.
Replacement of the damaged parts and reassembly of the pump proceeded with the expectation that the pump repairs could be completed, and the pump tested for return to service, within the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allowed by the LCO action statement. Delays were experienced with the fit up of several replacement parts. At approximately 1400 on February 22, it was concluded that we were unlikely to complete the pump alignment and post maintenance testing necessary for returning the pump to service before the expiration of the 72-hour allowed outage time. Accordingly, preparations were initiated for an orderly unit shutdown. The shutdown commenced in accordance with OP-3A, "Power Operations to Hot Standby," at 1448. Unit 2 entered Mode 3, Hot Standby, at 1926 and reached Mode 4, Hot Shutdown, conditions at 0138 on February 23, 2002. The shutdown was uneventful and equipment required for the shutdown performed as expected.
As required by 10 CFR 50.72(b)(2), a four hour ENS (EN# 38718) telephone call was completed at 1618 for initiation of a Technical Specification required shutdown.
The SI pump repairs and reassembly were completed on February 23 and the pump turned over to Operations for the post maintenance testing in accordance with IT 02, "High Head Safety Injection Pumps and Valves (Quarterly) Unit 2.
Following that testing and evaluation, the 2P-15B SI pump was returned to service at 2004 on February 24, 2002. A PBNP Unit 2 critical approach was initiated at 0930 on February 25 and Unit 2 returned to Mode 1 at 1435 on that date.
Cause:
Based on the damage observed following disassembly and inspection of the pump, we concluded that the failure of the 2P-15B SI pump was due to gas binding. A representative of the pump vendor who inspected the damage agreed with this assessment. During the recent operating history of the unit, we experienced decreasing fluid level from the "A" SI accumulator {ACC}at the rate of between approximately 2% to 4% indicated level per day. We had assumed that this level loss was due to leaking drain and fill valves that were scheduled to be worked during the Unit 2 Spring 2002 refueling outage. We have now determined that at least a portion of this leakage of nitrogen-saturated fluid was migrating through two or more check or closed valves to the discharge of the SI pump. At this location, the fluid pressure is approximately 55 psig due to static head of the refueling water storage tank {TK}. This is much less than the nominal 700 to 800 psig gas pressure in the accumulators. At that reduced pressure, the nitrogen gas coming out of solution ultimately resulted in the pump becoming gas bound.
A root cause evaluation team was initiated on February 23, 2002, to identify why this event occurred and to determine corrective actions to prevent recurrence. This evaluation identified that the organization had not properly responded to adverse SI accumulator leakage trends that increased the potential for gas binding of the SI pumps. We also determined that the stations industry operating experience program was not effective to ensure timely implementation of corrective actions from previous lessons learned.
Corrective Actions:
♦Prior to returning the 2P-15B SI pump to service an Operability Determination (OD) that addressed requirements to ensure the future operability of both trains of SI for both units was approved. In addition to the direct issue of gas binding of the SI pumps, this evaluation also addressed the following considerations:
1) Potential for unacceptable water hammers due to rapid refilling of the voided pipe upon pump start 2) Possible instrumentation effects due to gas voids in sensing lines, 3) Potential effects of various leaking (or failed open) valves in the system, 4) Potential for gas migrating to portions of the ECCS piping that may render other adjacent pumps sharing common piping inoperable, and 5) Potential impact on Accident Analysis of having voided volumes in the SI pump discharge line(s).
♦The OD evaluation determined that the SI pumps would remain operable provided periodic venting of the SI discharge lines is conducted ♦Procedure 01-100, "Adjusting SI Accumulator Level and Pressure," has been revised to accomplish the periodic SI line and pump venting required by the OD.
♦A review and backlog "scrub" of open industry operating experience issues was conducted to provide assurance that other similar issues or events have been properly addressed.
- The Roof Cause Evaluation identified a series of additional corrective actions to avoid recurrence and improve organizational performance. These action items will be entered and tracked within the PBNP corrective action program.
♦During the PBNP Unit 2 refueling outage that commenced this April, inspections and maintenance are being performed as appropriate on several valves, which contributed to the accumulator fluid back-leakage.
Component and System Description:
The SI system is described in Section 6.2 of the PBNP FSAR. The primary purpose of the safety injection (SI) system is to automatically deliver cooling water to the reactor core in the event of a loss-of-coolant accident. This limits the fuel clad temperature and thereby ensures that the core will remain intact and in place with its heat transfer geometry preserved. The principal components of the high head safety injection system consist of two accumulators (one for each loop) and two high head pumps.
The accumulators are pressure vessels maintained filled at their designated levels with borated water and pressurized with nitrogen gas. During normal plant operation, each accumulator is isolated from the reactor coolant system by two check valves in series. Should the reactor coolant system pressure fall below the accumulator pressure, the check valves open and borated water is forced into the reactor coolant system. Mechanical operation of the swing-disc check valves is the only action required to open the injection path from the accumulators to the core via the cold leg. The normal accumulator pressure is 750 psig with a minimum water volume at operating conditions of 1100 cubic feet.
Additional design parameters are presented in Table 6.2-4 of the FSAR.
The two high head safety injection pumps for supplying borated water to the reactor coolant system are horizontal centrifugal pumps driven by electric motors. Parts of the pump in contact with borated water are stainless steel or equivalent corrosion resistant material. A minimum flow bypass line is provided on each pump discharge to recirculate flow to the refueling water storage tank in the event the pumps are started under low flow or shutoff head conditions.
The pumps have a design pressure of 1,750 psig and a design flow rate of 700 gpm. The pumps are driven by 700 HP, 4160-volt motors. Additional design parameters are presented in Table 6.2-6 and Figure 6.2-4 of the FSAR.
Safety Assessment:
As discussed in the Event Description, the Technical Specification required unit shutdown that prompted this LER was achieved in accordance with the Technical Specification and approved plant procedures. Equipment required to function during the shutdown to Mode 4 conditions performed as expected and in accordance with design. The subsequent reactor heat-up and return to power was accomplished without any unusual equipment malfunctions. The TS LCO Action statement for the "B" ECCS train out of service permitted 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> for restoring the train to operable status. When it became apparent that pump repairs and testing would exceed that completion time, the plant staff conservatively took immediate actions to shutdown the plant although approximately eleven hours remained on the allowed outage time for the "B" SI train. During the time that the "B" ECCS train was inoperable, the "A" ECCS train remained in standby service and capable of providing adequate core cooling and the negative reactivity addition required for accident mitigation. Accordingly, the safety and welfare of the public and the plant staff were not impacted by this event. At no time during this event, was there a complete loss of system, structure, or component related safety functions. Accordingly, we have also concluded that this event did not involve a safety system functional failure.
Similar Occurrences:
A review of LERs for the past three years identified no other unit shutdown that were the result of a Technical Specifications required action or condition.