IR 05000271/1998009
| ML20236P984 | |
| Person / Time | |
|---|---|
| Site: | Vermont Yankee File:NorthStar Vermont Yankee icon.png |
| Issue date: | 07/10/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20236P964 | List: |
| References | |
| 50-271-98-09, 50-271-98-9, NUDOCS 9807170240 | |
| Download: ML20236P984 (26) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket N Licensee N DPR-28 Report N Licensee: Vermont Yankee Nuclear Power Corporation Facility: Vermont Yankee Nuclear Power Station Location: Vernon, Vermont Dates: - June 9 through 12,1998 - On Site June 15 through 19,1998 - In Office Review I
inspectors: John T. Shediosky (Team Leader), Senior Reactor Analyst Russell J. Arrighi, Resident inspector Pilgrim Station
. Larry E. Briggs, Senior Operations Engineer
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George W. Morris, Senior Reactor Engineer Approved by: Richard J. Conte, Chief Operator Licensing and Human Performance Branch Division of Reactor safety
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EXECUTIVE SUMMARY j This special safety inspection was to evaluate the personnel actions and equipment
! response associated with an event of June 9,1998,in which there was a reactor vessel high water level turbine trip and reactor scram followed by an electrical transient about an hour late On the basis of an independent review, the team agreed with the licensee's cause and the, probable contributing factor The major findings and conclusions of this inspection were:
Operations:
- The Vermont Yankee (VY) review of this event wat timely and effective with some exceptions noted. During their review, VY did not question the calibration of the electrical bus overcurrent relays. (Section 01.1)
- The NRC team determined that this transient had relatively low risk significance. All l safety equipment operated as expected. (Section 01.1)
l * Overall the on-shift operations crew performance was acceptable with some exceptions. A problem relating to the on shift operating crew concerned the failure
- .to conduct a full shift briefing to discuss re-energizing bus 6 prior to conducting the
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evolution and the failure to place the standby reactor feedwater pumps (RFP::) in pull-to-lock (PTL) (Section 01.2)
- Procedure inadequacies were identified that complicated the scram recovery actions: 1) abnormal or emergency procedures not ensuring the RFPs in PTL; 2)
procedure for reenergizing bus 6 did not identify automatic restart of turbine l auxiliary oil pump. These two examples are considered a violation of Technical Specifications, Section 6.5. (Section 01.2)
- The failure to continuously monitor and record torus temperature readings every five l minutes as required by Technical Specifications 4.7.A.1. was identified and corrected immediately by the licensee and is being treated as a non-cited violatio (Section 01.2)
Maintenance:
i ( * During their investigation of the 'A' feedwater regulating valve (FRV) failure, the 'B'
Recirculation Pump M/G (RP-M/G) bearing failure, and the 'C' reactor feedwater pump (RFP) minimum flow valve, VY identified human performance problems in the maintenance process concerning foreign material c.ontrol, analysis of failed parts, and'of preventive maintenance inspections of the feedwater pump minimum flow valve pneumatic positioner. (Section M2)
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- The cause of the 'B' RP-M/G set trip was unknown but licensee troubleshooting and testing efforts were sufficient to assure the equipment was operating properly just before plant startup. (Section M2)
Enaineerina:
- The licensee's failure to consider the calibration of the bus 1 overcurrent (0/C) relay a potential contributing cause is a shortcoming in their root cause analyse (Section E2.1)
- The discrepancy between the bus 1 O/C relay setting, which was based on starting a single RFP and the control circuit diagram which permitted a two pump automatic start, reflected an oversight in the licensee's Design Control process. (Section E2.1)
- The licensee's failure to enter their event reporting (ER) process and initiate appropriate corrective action as a result of their repeated out-of-tolerance findings j (including the November 1997 'D' RHR O/C trip delay calibration finding) was a violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action. (Section E2.1)
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- The licensee's procedure control process exhibited a problem in that the operations and surveillance procedures for a loss of normal power (LNP) were not well
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coordinated. Specifically, prior to the June 9,1998 event, there was no documented evidence that either Reactor Protection System (RPS) motor generator (M/G) set or vitalinstrument M/G set would perform satisfactorily in service during l the starting of a residual heat removal (RHR) pump on an emergency diesel generator (EDG) supplied bus. (Section E2.2)
- The licensee's failure to verify the EDG required frequency setting by a documented independent review was a shortcoming in their EDG surveillance procedur (Section E2.3)
- The licensee's failure to identify the deficiency in the VY design basis document ,
EDG-1 regarding frequency control, was a deficiency of the licensee's Design l Control and would be addressed in inspection report 50-271/98-80. (Section E2.3) I i
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- The Final Safety Analysis Report (FSAR) does not establish criteria for frequency stability of the EDGs. (Section E2.3)
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TABLE OF CONTENTS EX EC UTIVE S U M M ARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii Sumrnary of Plant Status ............................................1 1. Operations ....................................................1 .
1 01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1 01.1 G e ne ral Com m e nts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 01.2 Reactor Scram with Subsequent Complications . . . . . . . . . . . . . . . . . . 2 11. M ai nt e n a n c e . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 M2 Maintenance and Material Condition of Facilities and Equipment . . . . . . . . . . . . 6 lil Engine e ring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 E2 Engineering Support of Facilities and Equipment .......................8 E Partial Loss of Off-site Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 E2.2 RPS M/G Set Underfrequency Trip . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 E2.3 Lack of Defined EDG Frequency Regulation . . . . . . . . . . . . . . . . . . . . . 11 V. Management Meetings ..........................................13 1 X1 Exit Meeting Sum mary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 ITEMS OPENED, CLOSED, AND DISCUSSED . ............................13 i l
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LIST OF ACRO NYM S U S ED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Attachtnent A:
Special Team inspection Charter Attachment B:
Sequence of Events l
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I Report Details Summarv of Plant Status At the start of this inspection, the plant was preparing to enter a maintenance outage as a result of an unanticipated trip from reactor vessel water high level on June 9,1998, due to a malfunction in the feedwater control system. Complications following the scram included: an unexplained trip of the 'B' recirculation pump resulting in natural circulation, a trip of the 'C' reactor feedwater pump (RFP), a partial loss of normal power (LNP) and multiple additional scrams and isolations associated with loss of the 'A' reactor protection i system (RPS) motor-generator se i
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J. Operations 01 Conduct of Operations 01.1 General Comments on Safety Significance and Licensee Event Review (93702)
Using inspection Procedure 93702 and the Special inspection Team (SIT) Charter (Attachment A), the team reviewed the circumstances of the transient that occurred during the morning of June 9,1998. A sequence of events is included with this report as Attachment 8. In general the team concluded the reactor trip was due to foreign materialin one of the main feedwater regulating valves and the operator's response to the reactor scram was acceptable. All safety equipment operated as expected. However the electrical transient was due to inadequate procedures and subsequent operator response was complicated by an inadequate procedure coupled with poor judgment. The decision to re-energize non-vital bus 6 was made without ,
i full consideration and discussion by the shift (no full shift briefing) in anticipation of !
l automatic start of equipment. Natural circulation was properly monitore l
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l Licensee review of this event was effective and timely with some exceptions note !
It included performance of a formal root cause analysis. Their review began on the morning of June 9 and continued in process at the conclusion of this inspectio The team found that the Vermont Yankee (VY) review was sufficiently thorough to ;
identify causes of the reactor trip and the electrical transient and provide adequate 1 corrective actions to support a safe restart of the unit. However, NRC team noted that the Vermont Yankee review did not thoroughly investigate the overcurrent relay calibration setpoint history for electrical bus The NRC team evaluated the risk significance of this transient through the use of the NRC accident sequence precursor (ASP) model for Vermont Yankee. In that analysis, the team assumed a loss of the power conversion system which provides reactor feedwater, and decay heat removal and a loss of the offsite power supply to one of the two safety divisions. The resultant conditional core damage probability calculated for this transient was relatively small (2.0E-06). ,
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01.2 Reactor Scram with Subseauent Complications i
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a. Insoection Scope (93702)
The inspectors conducted interviews with all licensed operators on shift at the time
' of the transient. The duty shift engineer and the operations manager were also interviewed. In conjunction with the interviews, the referenced procedures were also reviewed to verify correct usage by the operators and technical adequacy of the procedures.
! b. Observations and Findinas l
l Reactor Scram due to Hiah Reactor Water Level The control room operator (CRO) was reducing power by inserting control rods to !
l remove the 'B' recirculation pump motor generator (RP-M/G) from service when the 1 l plant operators noticed that reactor water level was increasing. This was noted at l about + 163 or + 164 inches (normal level is + 160 inches) just prior to the high reactor water level alarm at + 165 inches. The CRO took master manual control of the feedwater regulating valves (FRV) and went to the closed position. The CRO l
observed that the 'B' FRV indicated closed but the 'A' indicated an intermediate l position. He took individual manual control and drove both FRVs in the closed
[ direction. The 'A' FRV still indicated an intermediate position. Shortly thereafter j the main turbine tripped on high reactor water level (about + 173 inches), it was i later determined that a hex head cap screw had lodged in the 'A' FRV preventing it i j from fully closin During interviews, the control room operators indicated that the power reduction I was being expedited to allow removal of the 'B' RP-M/G. This M/G set had a high l bearing temperature. The inspectors reviewed the computer printout of power l changes and calculated the power decrease averaged over the 30 minutes prior to l
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the scram to be about 15 percent per hour. OP 0105," Reactor Operations" allows l power reductions for normal shutdown of 1 percent per minute (or 60% per hour)
using recirculation flow. The rate of power decrease was well within specified limits. The inspectors determined that operator response to the transient was acceptable and in accordance with plant procedure Prior to plant restart Vermont Yankee disassembled both FRVs and inspected upstream piping by borescope. No other foreign material was found (Reference j report section M2.b).
Reactor Feedwater Pumos Not in Pull To Lock (PTL) after the Reactor Scram Following the high water level reactor scram at 1:32 a.m. on June 9,1998, the CRO did not place the reactor feedwater pumps (RFP)in PTL, The team determined that operator actions were in accordance with procedures; however, an opportunity was missed in the 50 minutes following the reactor scram to identify and place all RFPs not needed to provide makeup to the reactor in PTL. Plant procedures did not
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require that the RFPs be placed in the PTL position. Only one procedure, Operating Procedure 0105, Revision 3, " Reactor Operations," which is a normal operating procedure that covers plant operation from subcritical to full power and back to cold shutdown, states that only one RFP should be in standby (auto) at one time. OP 0105 does not address transient or abnormal conditions. Neither OP 2172,
"Feedwater System," nor OT 3114, " Reactor High Level," contain any precautions
or special conditions addressing placing RFPs in PTL. Training material (lesson plans) reviewed by the team did not specifically address placing the RFPs in PTL following a reactor scram although, having only one RFP in standby, was discussed in severallesson plans dealing primarily with plant startup and discussions of the j feedwater system. Failure to place the RFPs in PTL resulted in the automatic j starting of both the 'A' and 'B' RFP on bus 1 at the same time. This caused a bus {
overcurrent trip resulting in a loss of power to non-vital 4 kV bus 1 ('A' RP-M/G) !
and vital bus 3. The overcurrent trip also resulted in the loss of 480 Vac vital bus 8 and non-vital busses 6 and 11 (discussed below).
Discussions with the on-shift crew concerning this area revealed that there was no clear understanding concerning placing the RFPs in PTL by the licensed operators j and there was also no specific procedural direction. The team determined that this '
was an inadequacy in the licensee's procedures. Technical Specifications, Section ;
6.5, Plant Operating Procedures, item A.3, requires procedures to be prepared and '
approved to address actions to be taken to correct specific and foreseen potential malfunctions of systems or components. Failure to address placing the RFPs in PTL resulted in the loss of bus 1 and a challenge to the safety related electrical busses and a loss of control of feedwater and condensate components needed for reactor water level control. This is one of two examples of procedure inadequacy in which i the licensee failed to address a known (or foreseen) malfunction of systems or components. (VIO 50-271/98-09-01). ;
l Affected procedures were revised by the licensee prior to the team leaving the sit g Failure of 'C' RFP to Start and Subseauent Loss of Electrical Busses l
At 2:23 a.m. the control room operators attempted to start the 'C' RFP to provide a l source of makeup to the reactor. When the 'C' RFP was started, it tripped within l several seconds on low flow. The low flow trip was due to the failure of its i minimum flow valve. The minimum flow valve is required to open far enough to !
allow 3 million pounds mass per hour flow within 8 seconds. Flow is then !
monitored by the system for an additional 2 seconds to verify flow is maintained l
above the minimum. If minimum flow is not established, the pump will trip on low '
flow. Since the 'A' and 'B' RFPs were not in PTL they both started when the 'C'
pump tripped. Simultaneous starting of both RFPs on station service elactrical J
bus 1 caused an overcurrent trip of the bus and resulted in a loss of bus 1 and !
several other buses. The team determined that the electrical distribution system !
responded as designed. Operator initial actions were appropriate in terms of j verifying proper system respons I l
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Restoration of Non Vital Bus 6 by Cross Connectina with Non Vital Bus 7 Following the loss of bus 1, the on-shift management decided to restore power to bus 6 by cross connecting it with bus 7. The cross connection was being performed to regain control of miscellaneous components in the feedwater and condensate system which would facilitate control of reactor level / inventory. The operators followed OP 2143, Section M, " Energizing 480 Volt Bus 6 from Bus 7."
Step 2 of the procedure directs the operators to notify computer engineering that the VAX computer will be lost and to refer to Appendix A of OP 2143 to secure non essentialloads. Since bus 6 was already deenergized, the shift supervisor determined that step 2 did not apply. When bus 6 was reenergized the main turbine auxiliary oil pump started and supplied control oil to the turbine bypass valve Because the bypass valve pressure controller setpoint was set at a lower pressure than existed in the reactor at the time, the bypass valves opened to reduce reactor pressure. The resultant high steam flow (>40 percent with the mode switch not in run) caused the main steam isolation valves (MSIV) to close. Closure of the MSIVs resulted in a loss of the main condenser as a heat sink and required the operators to use Safety Relief Valves (SRVs) for temperature and pressure control and RCIC for inventory control. Use of the SRVs and RCIC resulted in additional operator activities to control torus temperature and level as well as the reactor temperature, pressure, and level. These activities were performed in accordance with existing procedure The team determined that failure of OP 2143 to identify the automatic restart of the turbine auxiliary oil pump was an inadequacy in the licensee's procedure. Technical Specifications, Section 6.5, Plant Operating Procedures, item A.3, requires procedures to be prepared and approved to address actions to be taken to correct specific and foreseen potential malfunctions of systems or components. Failure to address the automatic restart of the turbine auxiliary oil pump resulted in a challenge to the reactor protection system and a group 1 isolation (MSIV closure)
and an additional challenge to the on shift operators in dealing with the reactor scram recovery. This is the second of two examples of procedural inadequacy in the licensee failed to address a known (or foreseen) malfunction of systems or components. (VIO 50-271/98-09-01)
Affected procedures were revised by the licensee prior to the team leaving the sit While using the SRVs for temperature and pressure control and heat is being added to the torus, the licensee is required, by Technical Specifications (TS) 4.7.A.1. , to continually monitor torus temperature and to log it every 5 minutes until heat is no longer being added. During the transient, a duty shift engineer trainee that was assigned to monitor and log torus temperature failed to do so for a 45 minute period between 4:15 a.m. and 5 a.m. This failure was identified and corrected by the duty i
shift engineer. He directed the trainee to resume readings and subsequently initiated an event report to officially identify the problem. Torus
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temperature readings, which were also available from a chart recorder and the plant ,
computer, revealed that temperature limits were not exceeded. The violation of TS l 4.7.A.1 meets the criterion of NUREG-1600, Revision 1, Section Vll.B.1. and is !
being treated as a non-cited violation (50-271/98-09-02) j The team noted that OP 2143 was followed by the operators. However, by not having a shift briefing prior to reenergizing bus 6, the operators missed an opportunity to identify the automatic restart of the turbine auxiliary oil pum ,
Appendix A of the procedure listed the loads on bus 6 but did not specifically i identify the main turbine auxiliary oil pump as a load that would automatically I restart when bus 6 was reenergized. OP 2143 has been revised by the licensee to add a caution stating that the auxiliary oil pump will restart when bus 6 is reenergized. The licensee stated that other procedures dealing with re-energizing of electrical busses will also be reviewed and procedures revised appropriately, Overall Conclusions for Conduct of Ooerations The Vermont Yankee review of this event was timely and effective with some exceptions noted. During their review, VY did not question the calibration of the electrical bus overcurrent relay I The NRC team determined that this transient had relatively low risk significanc All safety equipment operated as expecte Overall the on-shift operations crew performance was acceptable with some exceptions. The team noted a problem relating to the on shift operating crew concerning the failure to conduct a full shift briefing to discuss re energizing bus 6
- prior to conducting the evolution and the failure to place the standby RFPs in PT Some procedure inadequacies were identified that complicated the scram recovery actions: 1) abnormal or emergency procedures not ensuring the RFPs in PTL; 2)
procedure for reenergizing bus 6 did not identify automatic restart of turbine l auxiliary oil pump. These two examples are considered a violation of Technical Specifications, Section 6.5 (VIO 50-271/98-09-01). These inadequacies have been addressed through proceduio changes and will be further addressed through training and pre-shift briefing The failure to continuously monitor and record torus temperature readings every five s minutes as required by Technical Specifications 4.7.A.1. was identified and corrected immediately by the licensee and is being treated as a non-cited violation (NCV 50-271/98-09-02).
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11. Maintenance
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M2- Maintenance and Material Condition of Facilitles and Equipment Inspection Scope The inspectors reviewed the licensee's actions to investigate equipment problems occurring during this transien Observations and Findinag Feedwater Reaulatina Valve Failure
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- VY disassembled the 'A' FRV to investigate the valve's failure to close. A hex head cap screw was found lodged in the valve preventing its closure. The cap screw was a 7/8 inch,9 threads per inch, with 13/8 inch fastener length. The overall length of the screw, including the 1 1/4 inch diameter cap, was 21/8 inch. The cap screw appeared to be cut off to the 13/8 inch length. The minimum standard length of that fastener is 2 inches. The head accepted a 3/4 inch hex key.
!- Information obtained from the licensee was that the cap screw was covered with rust, similar to the valve internals. This indicated that it had been in the system for -
I a longer period of time than the recently completed refueling outage. Since the cap screw had been cut to a 13/8 inch length, it had probably been used during a previous outage and threaded into a blind hol VY. disassembled the.'B' FRV and inspected piping up stream of both FRVs by borescope. There was no other foreign material foun .The piping from the feedwater pump discharge to the FRVs consists of a common header in which all three feedwater pumps discharge. This is also the common supply to the two main FRVs and to the startup feedwater regulating valve. Each pump has a discharge isolation valve 'and discharge check valve. VY calculated that flow velocities are sufficient to have moved the foreign material from the feedwater pumps to the FR 'B' Recirculation Pumo Motor-Generator Bearina Failure
- VY disassembled the 'B' Recirculation Pump motor-generator (RP-M/G) generator collector end bearing and found that it had failed due to excessive wear on the inner portion of the bearing lower half. The bearing was replaced.
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During their review of work performed during the recently completed refueling outage, VY determined that this bearing was inspected and the electrical maintenance technicians had recommended its replacement. However, their recommendation was changed by an engineer assigned to the maintenance department. Personnel had failed to properly communicate their understanding of the bearing condition and the worn bearing was reused, it failed the first time the
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recirculation pump was brought to full speed after the recent refueling outag 'B' Recirculation Pumo M/G Lockout Trio The 'B' RP-M/G sustained a lockout trip while running at minimum speed at 0226.
l This trip does not appear to be associated with the generator bearing failure. There l were no protective relay targets found that would identify the cause for the lockout l tri VY investigated several circuits that may cause non-target lockout trips. Their focus was on the loss of a frequency reference signal to the M/G control circuit j from bus 1 when it tripped on overcurrent. This occurred 2 minutes 43 seconds before the M/G lockout tri VY conducted troubleshooting of the M/G during the post maintenance test following its bearing replacement. The M/G operated normally during that test. At the end of the inspection, VY was obtaining additionalinformation on the speed I stabilization circuit from the vendor, General Electric Compan 'C' Reactor Feedwater Pumo Minimum Flow Valve Failure The 'C' Reactor Feedwater Pump (RFP) tripped shortly after start at 0223 because it failed to obtain minimum flow measured at the pump suction. The minimum flow
! was not attained, which resulted in a low flow trip of the 'C' RFP, a protective trip of the RFP when it failed to have minimum flow after ten seconds. This led to the subsequent automatic start of both the 'A' and 'B' RFP The VY investigation found that the linkage between the minimum flow valve and
, its pneumatic positioner had jammed when a bushing associated with the linkage l slipped out of place. That device converts the vertical motion of the valve stem to j a rotary input to the pneumatic positioner. The valve failed to operate correctly during the transient. When this broken feedback linkage was discovered, the licensee immediately inspected the other minimum flow valve to ensure that a
! similar problems did not exist.
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Also the reactor feedwater system is in the maintenance rule (a)(1) status since April 1997 and the minimum flow valves have had extensive maintenance performed on them to ensure that they stroke open fast enough to prevent minimum flow trips of the RFPs. The team questioned when or if the linkage had been inspected. The licensee responded that the linkage inspection had not been performed as part of the preventive maintenance (PM) program and was an oversight. The licensee added the minimum flow valve linkage inspection to their i
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PM program. However, there is no assurance that an inspection would have detected this specific problem with the bushing prior to the valve malfunction. This issue will be reviewed during a future maintenance rule follow up inspection. (IFl
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l Conclusion During their investigation of the 'A' FRV failure, the 'B' Recirculation Pump M/G bearing failure, and the 'C' RFP minimum flow valve, VY identified human performance problems in the maintenance process concerning foreign material control, analysis of failed parts, and of preventive maintenance inspections of the feedwater pump minimum flow valve pneumatic positione Also the cause of the 'B' RP-M/G set trip was unknown but licensee troubleshooting and testing efforts were sufficient to assure the equipment was operating properly ,
just before plant startu Enaineerina E2 Engineering Support of Facilities and Equipment E Partial Loss of Off-site Power Scope of Insoection During the licensee's recovery from the June 9,1998 feedwater transient event, VY experienced a partialloss of normal power (LNP) when power was lost to safety-related 4 kV bus 3 following the overcurrent (O/C) trip of the bus 1 feeder breake The team reviewed the licensee's evaluation of the partial LNP in order to assess the licensee's root cause analysis of this part of the even Observation The team observed that the licensee had identified that the loss of power to safety-related 4 kV bus 3 was caused by an overcurrent (O/C) trip of the bus 1 feeder breaker from the start-up transformer (SUT). Bus 1 feeds 4 kV bus 3 and 480 V buses 6, and 11, which also lost power. Emergency diesel generator (EDG) 'B'
started and restored power to bus 3 as designe The licensee had documented the selection of the O/C relay setpoints in safety-related calculation VYC-1087, Rev. O, Relay and Circuit Breaker Coordinatio Attachment 8 to that calculation addressed Bus 1, Largest Load - Reactor Feedwater Pumps (RFP). The licensee determined that the O/C relay setpoints were based on starting only one RFP on bus 1 at a time, consistent with normal startup procedures. Therefore the licensee concluded that the reason for the trip was the combined starting current magnitude and length of time seen by the O/C relay and also concluded the relay operated as designed to protect the switchgear, start-up and unit auxiliary transformers. The team confirmed that starting the two RFPs ('A'
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& 'B') upon trip of the 'C' RFP on bus 2 was consistent with the RFP control wiring (elementary) diagram B-191301, Sheet 550A in that there was no interlock to prevent automatically starting all the RFPs simultaneously. This demonstrated that the discrepancy between the relay setting and the control circuit diagram reflected a weakness in the licensee's Design Control proces The team inquired what was the actual as-installed setting of the O/C relay. (The licensee had not considered that the actual setting could be a contributing cause to this chain of events.) The team's review of the relay calibration the licensee had performed in December 1997 identified that all 3 phases' time delays were out-of-tolerance low. The team also observed that the permissible tolerance for the as-found and as-left settings were identical. The team confirmed that the relays' time i
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delays had been reset to within the as-left tolerance. (Phase 'A' was left barely within the lower limit by only .02 seconds.) The team also noted that no additional corrective action was recommended by the licensee as a result of their calibration finding, such as changing the three year calibration frequency. The team confirmed that the O/C relay scheduled calibration frequency had not changed. In as much as buses 1 and 2 are the offsite power supplies for safety-related busses 3 and 4, the licensee's failure to initiate appropriate corrective action as a result of their 12/97 calibration finding potentially challenged this preferred power supply. Following questioning by the team, the licensee checked the calibration of the O/C relays and found the 'A' phase time delay had again drifted to the lower tolerance limit in only 6 months. The licensee responded by entering the O/C relay calibration discrepancies into their corrective action program (ER 98-1451.)
The team found that the same type O/C relays were used in the protective circuits for the 4 kV safety-related motors on buses 3 and 4 and had exhibited similar calibration findings. As an example, the team found that safety-related RHR pump
'D' was found with all three phase time delay overcurrent relay setpoints out-of-tolerance low during calibration performed in November,1997. Additionally, phase
'A' was marginally returned to the low tolerar'ce as-left/as-found ban The licensee's corrective action program is based on their Event Reports (ER)
procedure, AP 0009. The ER process is used to assess events resulting in adverse conditions, problems or deficiencies affecting VY to initiate appropriate corrective
. action. The . licensee's failure to issue an event report and enter their corrective action program following their repeated out-of tolerance finding of calibration problems is a violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Actio (VlO 50-271/98-09-04)
c. Conclusions The licensee's failure to consider the calibration of O/C relay a potential contributing cause to the partial loss of normal power is a shortcoming in their root cause analyses. The discrepancy between the bus 1 O/C relay setting, which was based on starting a single RFP and the control circuit diagram which permitted a two pump automatic start, reflected an oversight in the licensee's Design Control proces _ _ _ _ _ _ _ - _ _ -
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The licensee's failure to enter their ER process and initiate appropriate corrective action as a result of their repeated out-of-tolerance findings (including the November 1997 'D' RHR O/C trip delay calibration finding) was a violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action. (VIO 50-271/98-09-04)
E2.2 RPS M/G Set Underfrecuency Trio Scope The team reviewed appropriate sections of the Final Safety Analysis Report (FSAR)
Chapters 7 and 8, Technical Specification (TS) 3/4-10 and design basis documents (DBD) AC-1, Safety Related 4 KV and 480 Vac Systems, and EDG-1, Emergency Diesel Generator, to assess the licensee's evaluation of the trip of the 'A' RPS M/G Set following loading of RHR pump 'D' on the 'B' emergency diesel generato Observations and Findinas The licensee identified that the setpoints for the RPS protective devices, as required by TS Table 4.10.1, required a frequency of > 56.5 Hz for the power protection l panels' Underfrequency trip circuits. The licensee's evaluation identified that the
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'A' RPS M/G set had already been manually loaded on 'B' EDG supplied bus 8 when ,
~ the RHR 'D' pump was started to support torus cooling. The RHR pump j successfully started and loaded the EDG supplied safeguards bus. The licensee also l identified that the frequency transient which resulted when the diesel reacted to the increased demand in load, resulted in a trip of the 'A' RPS M/G set. The licensee concluded that the RPS protective circuitry had operated as designe The team confirmed that under normal response from an LNP, the recently revised operating procedure, OT 3122, Rev.18, Loss of Normal Power, dated April 18,1998, has the operators loading the RPS M/G set (and vital instrument M/G set) early in the recovery and cautions the operator to assure sufficient l capacity remains on the EDG to permit loading the RHR and core spray (CS) pumps i later, if required. The RHR and CS pumps are not automatically loaded in response to a LNP event. Under this sequence, the RPS M/G set, being loaded onto the EDG
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prior to any attempt to load an RHR pump, will always experience a frequency dip associated with starting the RHR pump motor, as was demonstrated in the June 9,1998 unplanned even VY does not have separate LNP and ECCS/LNP surveillance procedures. The team's review of the ECCS/LNP surveillance procedure OP 4100, Rev. 24, ECCS Integrated Automatic initiation Test, revealed that the RPS M/G set is manually loaded after i the RHR pumps are automatically started and the test is completed without manually loading the vital instrument M/G set back onto the diesel generator supplied bus. Therefore, neither the licensee nor the team could confirm that either instrument M/G set could withstand the starting frequency transient on the EDG nor I
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could it be demonstrated that the vital instrument M/G set could normally run on the EDG supplied bus. This lack of documented evidence that the vital M/G sets could successfully operate on a diesel supplied bus followed by a start of an RHR pump was identified as a problem in the licensee's EDG surveillance procedure. The team noted that the vital instrument M/G would remain on its de drive motor if unable to transfer to ac drive because of poor bus voltage and frequency stability, Conclusion The licensee's procedure control process exhibited a problem in that the operations and surveillance procedures for a LNP were not well coordinated. Specifically, prior to the June 9,1998 event, there was no documented evidence that either RPS M/G set or vital instrument M/G set would perform satisfactorily in service during the starting of an RHR pump on an EDG supplied bu E2.3 Lack of Defined EDG Freauency Renulation Scope The team reviewed the licen.=ee's design basis documents (DBD), licensing basis documents and calibration test data to assess the degree of frequency regulation provided by the EDG control system. The team also reviewed the appropriate sections of the FSAR Chapters 7 and Observations and Findinas Emergency diesel generators (EDG) in nuclear service must be designed to provide sufficient power at rated voltage and frequency required by the connected loads following a loss of the preferred (offsite) power supply. The EDG must also be able to be periodically test loaded by being paralleled to the utility grid. This dual design requirement results in a governor design that can run in an isochronous mode when isolated from the grid and in the droop mode when tied to the grid. The governor ;
controls the EDG's speed and therefore its frequency response. The team reviewed
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the recently issued emergency diesel generator DBD, EDG-1, and determined there was no description, design requirement or criteria established for either the transient or steady state frequency response of the VY ED The licensee indicated that their emergency diesels had mechanical governors and therefore did not have a separate isochronous control, but instead, relied on operator action to adjust the droop control to zero and the frequency to 60 Hz following each EDG readiness demonstration test per procedure OP 4126, Diesel Generators Surveillance. The licensee indicated that because of this, some limited decrease in steady state frequency would be experienced when the load was increased from zero to rated load even in the "isochronous" mode.
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The team confirmed that the EDG procedure OP 4126, which has an acceptance criteria of 59 to 61 Hz during the loading tests, instructed the operator to ensure the EDG frequency was left at 60 Hz following completion of EDG testing. The j setting cannot be confirmed by observing the machine between EDG tests. The team found that this step in the procedure did not require sign off or an independent review. The licensee had recently issued an event report (ER-98-1281)on j May 27,1998 documenting that an operator, using this same procedure, had failed j to adjust the droop setting to 50 during the monthly readiness demonstration tes The licensee indicated they would address the team's concern as part of the corrective action for the existing E During development of the EDG DBD, the licensee questioned the lack of required l freauency transient response. The licensee issued ER 97-1600 and BMO 97-54 to I cddiess that concern. The licensee's review concluded there was no licensing basis for fiequency response for VY and the only requirement for frequency would be for the EDG to maintain the frequency within limits that will not degrade the 1 performance of any design loads below their minimum requirement. In additien, the licensee maintained that the 1998 Integrated Test data demonstrated that tha connected loads accelerated to rated speed with rated voltage and frequency within limits. For this reason, the licensee closed the BMO and reworked the DBD to delete arty reference to a required frequency response for VY. The licensee initiated a commit nent tracking item using their 0028 process to assess the 5% transient response requirement furthe .
The team d:d confirm that the licensee was aware that frequancy shifts affect pump speed and tnat could affect the ECCS analyses. Pump speed could also : affect the drive motor brake HP as seen by the EDG. The licensee indicated they had not included a frequency adjustment factor in the EDG loading calculation. Although the licensee was aware that frequency regulation should be a design requirement, and will be a factor required by their developing improved technical specification (ITS) program, the licensee failed to initiate an open item or interim change against DBD, EDG-1. This failure to initiate an open item against the issued DBD was contrary to their configuration control procedure AP 6007, Control, Update and Maintenance of DBDs. This deficiency is identical to the item identified in inspection report 50-271/98-80and enforcement action will be addressed in that repor l While performing the inspections discussed in this report, the team reviewed )
appropriate sections of the FSAR Chapters 7 and 8. The team noted that the FSAR l
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does not establish criteria for frequency stability of the EDGs under loa c. Conclusions
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The licensee's failure to verify the EDG required frequency setting by a documented j independent review was a shortcoming in their EDG surveillance procedure. The j licensee's failure to identify the deficiency in the VY design basis document EDG-1 l regarding frequency control, was a deficiency of the licensee's Design Control that )
would be addressed in inspection report 50-271/98-80. The FSAR does not !
establish criteria for frequency stability of the EDG l l
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V. Mansaement Meetinas X1 Exit Meeting Summary The team met with licensee representatives periodically throughout the inspection and ,
- following the conclusion of the inspection on June 30,1998 by telephone call. At that i time, the purpose and scope of the inspection were reviewed, and the preliminary findings l were pre:ented. The licensee acknowledged the preliminary inspection finding ,
PARTIAL LIST OF PERSONS CONTACTED D. Amidon Electrical Systems Engineer !
K. Bronson Operations Manager D. Calsyn Technical Support Manager ]
J. DeVincentis Assistant to Engineering Director l E. Harms Assistant Operations Mgr., Event Response Team Leader !
F. Helin . Operations and Tech Support Supt., Acting Plant Manager R. January Electrical and I&C Design Engineering Manager P. Johnson Principal Electrical Design Engineer E. Lindamood Director of Des lgn Engineering W. Mathis Electrical Maintenance Engineer !
D. Maidrand Electrical Systems Engineer G. Maret Director of Operations C. Nichols Electrical and Controls Maintenance Manager R. Ramsdell Tech. Support Engineer, Response Team Root Cause Analyst M. Romeo Sr. Training Instructor, Response Team Communicator M. Watson Maintenance Manager INSPECTION PROCEDURES USED j i
93702 Prompt Onsite Response To Events At Operating Plants i ITEMS OPENED, CLOSED, AND DISCUSSED l
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Opened I 50-271/98-09 01 VIO Procedures Failed to Address Challenges to Safety Systems j Feedwater Pump Control 50-271/98-09-01 VIO Procedures Failed to Address Challenges to Safety Systems Restoration of Power to Electrical Bus 6
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50-271/98-09-03 IFl Maintenance rule action plan for (a)(1) system feedwater
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50-271/98-09-04 VIO Lack of Overcurrent Relay Corrective Action t
Opened / Closed ,
j 50-271/98-09-02; NCV Failure to Record TS Required Torus Temperatures Y
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LIST OF ACRONYMS USED j BMO Basis for Maintain Operation CFR Code of Federal Regulations CR control room CRO Control Room Operator CS Core Spray DBD Design Basis Document ECCS Emergency Core Cooling System EDG Emergency Diesel Generator E Event Report F Fahrenheit FRV Feedwater Regulating Valve ;
FSAR Final Safety Analysis Report l
~ IFl inspector follow-up item I
. ITS Improved Technical Specifications kV- kilovolt l 'LCO Limiting Condition for Operation
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LNP Loss of Normal Power M/G Motor-Generator l MSIV Main Steam Isolation Valve .l
'NRC Nuclear Regulatory Commission i NNS- Non-nuclear safety ;
O/C Overcurrent i PORC Plant Operations Review Committee j PTL Pull-to-Lock i RCIC Reactor Core Isolation Cooling !
RHR Residual Heat Removal RFP Reactor Feedwater Pump RP-M/G Recirculation Pump Motor-Generator RPS Reactor Protection System RWC Reactor water cleanup system SRV Safety Relief Valve j SUT- Start-up Transformer :
TS Technical Specification URI unresolved item VIO Violation VY Vermont Yankee
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Attachment A - June 10,1998 MEMORANDUM FOR: Richard Conte, Chief, Operator Licensing - Human Performance Branch, Division of Reactor Safety FROM: Larry Nicholson, Deputy Director, Original Signed By:
Division of Reactor Projects Richard Crienjak, Deputy Director, Original Signed Sy:
Division of Reactor Projects SUBJECT: SPECIAL TEAM INSPECTION ISTI) CHARTER - VERMONT YANKEE REACTOR SCRAM WITH COMPLICATIONS You are directed to perform a special team inspection to review the causes, safety implications, and associated licensee actions which led to the reactor scram with complications at Vermont Yankee Station on June 9,1998. The basis cf the NRC concern is the apparent independent failures of various balance of plant equipment that complicated the operator recovery actions, as well as possible operator performance concerns during the recovery activities that caused the complex transient and resulted in a loss of forced reactor circulation, MSIV closure and loss of the normal heat sink, and a loss of preferred, off-site power to various vital and non-vital buses. The inspection shall be conducted in accordance with NRC Manual Chapter 2515 Inspection Procedure 93702 and edditional instructions in this memorandu DRS is assigned responsibility for the oveall usnduct of this inspection. DRP is assigned responsibility for resident inspector and clerical support and coordination with other NRC offices. Richard Conte is the Team Manager for this inspection. Thomas Shedlosky is designated as the onsite Team Leader. Team composition is described at the end of this memorandum.- Team members will work for Tom Shediosky and are assigned to this task until the report is completed. DRS, in coordination with DRP, is responsible for the timely issuance of the inspection report and identification of any potential generic issues or enforcement actions, as warrante Attached to this memorandum is a draft STI inspection plan, which details the scope of the inspection. The inspection will begin on June 10,1998. On-site inspection activities are expected to take about three days and the inspection report should be available within about three weeks following completion of the inspectim activitie Attachment: Special Team inspection (STI) Plan and Membership l
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cc'w/ attachments:
C. Thomas, NRR B. McCabe,- OEDO R. Croteau, PM, NRR
. W. Axelson, DRA,- RI L', Nisolson, DRP
. J. Crienjak, DRP R. Summers, DRP
- C. Cowgill, DRP -
D. Screnci, PAO
B. McDermott, Vermont Yankee SRI -
STI Members
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l ATTACHMENT- SPECIAL TEAM INSPECTION (STI) PLAN AND MEMBERSHIP OBJECTIVES The general objectives of this SIT are to: Conduct a timely, thorough and systematic review of the circumstances surrounding the event, including the sequence of events that led to and followed the June 9, ,
1998 reactor scram; l
! Collect, analyze, and document relevant data and factual information to determine i the causes, conditions, and circumstances pertaining to the event, including the j response to the event by the licensee's operating staff; i l Assess the risk and safety significance of the event related to any problems identified; and, l Evaluate the licensee's review of and response to the event and any planned or implemented corrective action I SCOPE OF THE INSPECTION The SIT should identify and document the relevant facts and determine the probable .
causes of the event. It should also critically examine the licensee's response to the even The SlT should: Develop a detailed chronology of the event; Determine the root causes of the event as a result of the SIT's evaluation and
, document equipment problems, failures, and/or personnel errors which directly or
! indirectly contributed to the event.
l l Potential items to be considered:
- Licensee staff actions before, during and following the event, including l' operator use of procedures, especially any emergency operating procedures that were required, and the adequacy thereof.
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- Configuration controls; including any modifications and event related system alignment * Management oversight and administrative controls in place before, during and following the event.
l l * Coordination of maintenance and operations activities before and during the event.
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- Licensee staff sensitivity to plant conditions, especially since power operations had only recently recommenced following completion of the 4 refueling outag * Scheduler impacts (and effect on human performance) due to the ongoing
. restart activities of the uni Determine the expected response of the plant and compare it to the actual response, due to the loss of the electrical buses and the resultant isolation of the normal heat sink (main condenser); as well as the decision to secure RCIC and use the CRD system and SRVs to control reactor vessel water level and pressure, Determine the adequacy of the responses of the operations and technical support staffs to the event and the initial licensee analysis, and decisions on NRC notification including event classification and deportability, Determine the management response including the scope and quality of short-term actions and gather information related to the long-term actions intended to prevent recurrence of this even Determine the relationship of previous events or precursors, if any, to this event as appropriat SCHEDULE
'The SIT shall be dispatched to Vermont Yankee so as to arrive and commence the inspection on June 10,1998. A written report on this inspection shall be available within three weeks of completion of the onsite inspectio TEAM COMPOSITION I The assigned team members are as follows:
i Team Manager: R. Conte, DRS I Onsite Team Leader: J. Shediosky, DRS Onsite Team Members: R. Arrighi, DRP j
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G. Morris, DRS ;
! L. Briggs, DRS l l
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ATTACHMENT B .
Vermont Yankee Sequence of Events on 6/9/98 Times with seconds are from the computer sequence of events printout, times without seconds are from the control room operators log or from recorder charts 0005 'B' RP-M/G Bearing End Collector Temperature Alarm - Peak Temperature, 220 degree F. Control Room directed plant operators to investigate M/G se Reduced power /recirco:ation flow in preparation for single loop operation based on information concerning M/G set conditio Continued power reduction using control rod I 0126 'A' FRV fails at approximately 45% open (Later inspection found a 7/8 inch, 9 threads per inch,1 and 3/8 cap screw lodged in the valve. Overall length of the screw, including the cap, was 2 and 1/8 inches). :
i 0129:22 High reactor vessel level alarm (165")
CRO took master manual control of feedwater regulating valves (FRV) to decrease feedwater flow and observed that the 'B' valve closed but the 'A'
valve did no CRO took individual manual control of feedwater regulating valve in an attempt to further reduce feedwater flo :13 Reactor vessel water level increases rapidly, causing a main turbine trip at 173" !
Reactor scram from 68 percent power due to turbine trip S/U transformer breaker 23 (bus 2) & breaker 13 (bus 1) close 0132:18 'A' & 'C' RFPs trip due to high vessel level 0132:20 'A','B', and 'C' RFP breakers close, vessel level 155" Reactor water level shrinks due to reactor and turbine trip 0132:23 Reactor water level scram low level (due to shrink)
l 0132:23 Primary Containment Isolation System Groups 2 (Misc. water valves, DW
' sumps, etc.), 3 (Containment Ventilation), and 5 (RWCU) isolate due to low reactor level Control rod 42-19 does not indicate fully inserted (indicated notch 05 on panel 9-5), believed to be a position indication problem since notch 05 is between normallatching positions. Position went to 00 when the scram '
l was reset at time 0142:20, below.
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0132:27 Reactor manual scram l
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0132:43 Reactor low water level scram cleared - level increasing through low level scram reset point (normal plant response)
l 0133:05 Reactor feedwater pumps A, B, and C trip on 2nd high reactor water level l (normal response for a plant scram on high water level)
0142:20 Operators reset SCRAM and verify all control rods are fully inserted 0212:39 Reactor water high level turbine trip clear, level 171 inches
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0222:59 Plant operators start 'C' RFP to increase reactor water inventory 0223:10 'C' RFP trips on low flow (due to min flow valve problem) causing 'A' and
'B' RFP to auto star l Auto start of both 'A' and 'B' RFPs on Bus 1 at the same time causes an overcurrent trip resulting in a loss of power to non-vital 4 kV bus 1 ('A' RP- l M/G) & vital bus 3. The overcurrent trip also resulted in the loss of 480 Vac '
vital bus 8 and non-vital busses 6&1 I O223:16 'C' RFP attempts to auto start due to trip of 'A' and 'B' RFPs when Bus 1 trips on overcurren :20 'C' RFP trips, due to min flow valve proble ,
0223:22 'A' Recirculation Pump (RP) breaker trip, due to loss of bus 1 0223:22 Loss of 4 kV vital bus 3 causes the 'B' EDG to start on undervoltage 0226:05 'B' RP-M/G set trips (reason unknown)
Beginning of natural circulation 0231:59 Power restored to bus 6 by cross connecting it with bus 7. Restoration of bus 6 resteres Aux oil pump which causes the Main Steam bypass valves to cpen resulting in the MSIVs tripping on high steam flow (40%) with the Rx mode switch not in run 0236 First SRV cycled by operators to control pressure (all SRV actuations were controlled by plant operators)
0246:30 Started RCIC for Rx vessel level control 0255 SRV cycled 0257:49 Placed 'A' RHR on torus cooling 0302 SRV cycled
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0303:43 Rx SCRAM signal on low Rx water level 0310 Notified Chemistry of loss of stack gas monitors 0310 SRV cycled 0314 SRV cycled 0320 Entered TS LCO due to DW/ torus D/P < 1.7 psid due to Group 3 isolation, 0328 Seismic monitor trouble alarm will not reset due to loss of power 0349 RCIC tripped because of reactor vessel high water level l
0352 SRV cycled 0400 Started 'A' RPS M/G set and reset SCRAM J
0403 ReEnergized Bus 1 0409 Restored power to bus 11-0410 Restored RWCU system 0427 RWCU isoisted due to Temp switch adjustments 0428 SRV cycled 0430 Entered Containment TS LCO due to torus V> 69,3OO cubic feet-0442 SRV cycled 0452 SRV cycled 0500 Restored RWCU 0504 SRV cycled 0510 'B' RHR put on torus cooling caused a minor underfrequency transient on bus 3 which resulted in 'A' RPS M/G output breakers tripping and initiation of a Group 3 (containment ventilation) isolation 0519- SRV cycled
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l 0522 Restored normal power to vital bus 3 from non-vital bus 1 0525 Started RCIC to maintain Rx vessel level l l
.0528 Secuted 'B' EDG !
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0600 Reset Group 3 isolation, reset % scram, reset RPS 'A'
0601 SRV cycled (Last cycle pre reactor level strip chart)
J 0630 Closed breakers to restore ring bus 0705 Commenced transfer of excess torus water to radioactive waste
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0720 Made 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> notification per 10 CFR 50.72 l
l 0725 Secured transfer of torus water, volume 69,230 cubic feet l
l 0755 Restored bus 6 to normal lineup (power from bus 1)
l l 0935 Exited torus Technical Specifications LCO, volume and delta pressure normal l
1007 Started 'C' RFP for level control 1015 Secured RCIC l 1030 Secured RHR 'B' loop torus cooling l 1255 Secured 'C' RFP, using condensate pump to provide reactor makeup j
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i 1405 Plant management decided to go to cold shutdown conditions 1505 Secured RHR 'A' loop torus cooling June 10,1998 0710 Started the 'A' reactor recirculation pump. The reactor had been in a natural circulation cooldown from 0226, June 9 until this time. As a prerequisite prior to restoring forced circulation, the reactor vessel bottom head drain temperature was required to be 145 degrees F of the vessel steam dome saturation temperature. This was accomplished by realignment of reactor water cleanup system manual valve CU-46, which is located in the primary containment drywell.
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