ML20211E065
| ML20211E065 | |
| Person / Time | |
|---|---|
| Site: | Davis Besse, Crystal River, 05000000 |
| Issue date: | 09/26/1986 |
| From: | Bojduj W, Burris J, Horne M TOLEDO EDISON CO. |
| To: | |
| Shared Package | |
| ML19292G087 | List: |
| References | |
| NUDOCS 8610220342 | |
| Download: ML20211E065 (42) | |
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TRANSIENT ASSESSMENT REPORT DAVIS-BESSE UNIT 1 REACTOR TRIP ON HIGH FLUX MARCH 2, 1984 J. R. BURRIS M. M. HORNE W. B0JDUJ Transient Assessment Program 12-1151244-00 8610220342 060926 PDR ADOCK 05000302 S PDR
'e
- I. EXEC 1rTIVE
SUMMARY
A. Initial Plant Data Davis-Besse Unit 1 Reactor Trip and Stuck Open Main Steam Safety Valve Post Trip i
March 2, 1984 12:22:06 Hours B. Event Description On March 2, 1984, 103 EFPD into Cycle 4, Davis-Besse Unit I was operating at approximately 99% of full ~ power. The plant was in full automatic control. During periodic Steam and Feedwater
- Rupture Control System (SFRCS) surveillance testing,' an undetect-ed SFRCS channel failure resulted in the closure of the Main Steam Isolation Valve (MSIV) #2. The reactor tripped on high flux approximately 13 seconds after MSIV #2 closed.
I Following the reactor trip, steam pressure on SG #2 did not control as would be expected. It was determined through local observation that a main steam safety valve (MSSV) had stuck open on the #2 steam line. Initiation of SFRCS and manual operator action isolated feedwater to SG #2. Af ter auxiliary feedwater isolation, SG #2 depressurized to atmospheric pressure in approxi-mately five minutes.
Cooldown was accomplished with SG #1. At approximately 340*F RCS temperature, the replacement of the stuck open MSSV was completed, and SG #2 was restored to operable status. The plant was then further cooled down to cold shutdown.
C. Root Cause A wiring error on the Safety Features Actuation System (SFAS) switch for MS-100 in combination with a defective optical isolator in the relay driver card for SFRCS Channel 4 control relay *
(K104A) caused a pre-existent half trip on the Loop #2 MSIV (MS-100). This pre-existent half trip, combined with the other half trip of Channel 2, (created during surveillance testing),
caused the HSIV to close on SG #2. The closure of this MSIV in turn led to a feedwater transient and rea-tor trip on high flux, i
3 D. Performance Anomalies
- 1. Following the reactor trip, a MSSV on SG #2 (having a setpoint of 1070 psig) lifted and failed to fully close.
- 2. Following the reactor trip, another MSSV on SG #2 (havicg a
( setpoint of 1050 psig) failed to open.
I 3
. 3. When attempting to restore auxiliary feedwater to the dry i SG #2, SG #2 auxiliary feedwater isolation valve failed to open using its Limitorque operator.
- 4. For this event, the tube-to-shell temperature difference on the dry SG (SG #2) occurred both with the tube temperature higher (normal heatup state) and with the tube temperature lower (normal cooldown state) than the shell temperature.
During the najor time period of the event, the tube tempera-ture was higher than the shell temperature, thus placing the tubes in a compression condition. See Figure 22.
- 5. A defective relay driver card for SFRCS Chann'el 4 caused a pre-existent, undetected a false half trip on the Loop #2 MSIV (MS-100).
- 6. Af ter restoring level to SG #2 with the Auxiliary Feedwater System (AFW), the Main Feedwater'Stop Valve #2 failed to open during an attempt to restore the normal feedwater flowpath.
The valve torqued out in the open direction (requiring manual opening) due to a large differential pressure across the valve.
- 7. Following the reactor trip, Main Feed Pump (MFP) #1 began to control improperly. Local control had to be established.
II. TRANSIENT ASSESSMENT A. Sequence of Events The following sequence of events was derived from the Davis-Besse Unit 1 Alarm Log and Sequence of Events (SOE) Typer. Some problems with the SOE printout occurred due to testing which was in progress on the SOE and a software problem. The testing was completed, and a software change completed and tested satisfactorily.
Date Time Event Description 3/2/84 12:21:53 MSIV #2 closed 12:21:59:060 RPS Channel 4 high flux trip 12:21:59:360 RPS Channel 4 flux / delta flux / flow bistable trip 12:22:06:090 RPS Channel 3 high flux trip 12:22:06:145 RPS Channel 2 high flux trip 12:22:06:160 Control Rod Drive Channel B/D trip 12:22:06:160 Control Rod Drive Channel A/C trip 12:22:06:170 Turbine-Generator Master Turbine trip l
l
, 1 Date Time Event Description 12:22:51:740 Reactor coolant pressurizer low level heater trip 12:26:48 Reactor coolant pressurizer low level heater -
normal 12:38:17 SFRCS full trip 12:38:29 AFW isolated to SG #2 by SFRCS on low SG pressure 12:38:49 Reactor coolant pressurizer low level heater trip 12:40:32 Reactor coolant pressurizer low level heater -
normal
~23:30 Work on stuck open MSSV commenced 3/3/84 07:30 Began feeding SG #2 with AFW Pump #2 after replacing the stuck open MSSV 07:45 Cleared low level trip on SG #2. SG #2 returned to operable status.
B. Plant Response
- 1. Pre-Trip Review Davis-Besse Unit I was operating at approximately 99% of full power. The plant was in full automatic control.
- 2. Initiating Event 2.1 Events Leading to Reactor Trip I&C personnel were performing a surveillahce test on the SFRCS Channel 2. When the I&C technician relieved the pressure on the Channel 2 switch being tested at 12:21 hours, the HSIV #2 closed due to an undetected failure that had occurred in SFRCS Channel 4. NSIV #2 was fully closed by 12:21:53 hours.
The closure of the MSIV #2 caused both the SG #2 pres-sure and the SG #2 cold leg water temperature to in-crease. The resulting increase in neutron leakage on the SG #2 side of the core (east) caused the nearby power range detector (NI-7) to trip RPS Channel 4 on 2
both high flux at 12:21:59:060 and on flux / delta flux / flow at 12:21:59:360. At the same time, high steam pressure in SG #2 diverted excessive feedwater into SG #1. The SG #1 pressure was dropping since it was the only SG
, supplying the turbine. The resulting overcooling of
4 reactor coolant in Loop #1, together with the negative moderator temperature coefficient, caused reactor power to increase on the SG #1 half of the core (west). This in turn caused the nearby power range detector (NI-8) to actuate a second RPS channel high flux trip (Channel 3) at 12:22:06:090. The Senior Reactor Operator realized the MSIV had closed and was about to manually trip the reactor when the automatic trip occurred. The reactor tripped approximately 13 seconds after MSIV #2 closed.
Figure 20 shows the positions of the power range detectors relative to the SGs.
2.2 Feedwater Flow Behavior Prior to Reactor Trip When MSIV #2 shut, the rapid increase in SG #2 pressure (see Figure 9) caused the MSSVs on Main Steam Line #2 to lift and also caused a rapid reduction in feedwater '
flowrate to SG #2 (see Figure 15). Consequently, the RCS cold leg temperature in Loop #2 increased to a maximum pre-trip recorded value of 573.4'F (versus 561*F prior to the transient). Since the power range indication has a sensitivity to downcomer temperature of approximately 0.5% FP/ F, we would expect the above 12.4'F increase in downcomer temperature adjacent to the NI-7 to yield an increase in indicated NI-7 power of about 6% FP. This would be sufficient for one RPS channel to reach the high flux (overpower) setpoint of approximately 105% FP and the flux / flow setpoint of approximately 106%FP.
This is exactly what was observed to happen.
The increase in SG #2 pressure and increased steam flow in the #1 steam line caused excessive feedwater to SG #1. The feedwater flow to SG #1 exceeded the full scale indication (7000 KPPH) for 10 to 12 seconds, and SG #1 level reached a maximum of 85% (see Figures 10 and 14). The steam pressure dropped in the SG #1 due to the excess feedwater and the main turbine dra. wing off steam from only the SG #1. This dropped the SG #1 cold leg temperature to a low of 548'F (versus 557"F prior to the transient).
The moderator and power doppler reactivity coefficients at this time in core life were approximately -2.01 x 10-4 AK/K/*F and -1.10 x 10-4aK/K/%FP, respectively.
If the above 9'F decrease in cold leg temperature on the west half (SG #1) of the core was assumed for the entire core, the resulting increase in power due to moderator temperature feedback would be approximately 16% FP. The 9'F decrease in downcomer temperature would only reduce NI-8 sensitivity by about 4.5% FP. This would result in a net increase in expected NI-8 indication of about 12%FP. Therefore, the observed high flux trip
\ on the west half of the core is consistent with what would have been expected.
l l
5-Also, approximately ten seconds before the reactor 1
tripped, the Integrated Control System (ICS) began to
', restore normal feedwater flowrate (refeed) to SG #2 as can be seen in Figure 15.
2.3 Cause of MSIV Closure Prior to Reactor Trip The MSIVs at Davis-Besse receive a closure actuation signal both from the SFRCS and the Safety Features Actuation System (SFAS). The control and display circuitry for these valves utilize various relays and contacts controlled by either of these two systems.
The Loop 2 MSIV (MS-100) inadvertently closed during the performance of ST 5031.14, SFRCS Monthly Functional Test. Portions of this test require isolation of specific sensor strings which initiates a half channel trip. On March 2,1984, as part of the above surveil-lance test, the pressure sensing string associated with SFRCS Channel 2 was isolated causing a trip of SFRCS Logic Channel 2.
It is noted that on March 1, 1984, the data light for '
MS-100 in SFRCS Channel 4 was discovered to be off.
However, since the associated data light (DS43A) in the SFAS Channel 4 was still energized, it was concluded that the SFRCS Channel 4 Control Relay (K104A) was operable. The deenergized SFRCS Channel 4 light for MS-100 was attributed to a bad socket at that time.
Further troubleshooting (after the transient) revealed that an optical isolator in the relay driver card for relay K104A was defective. This resulted in a pre-existent SFRCS Channel 4 half trip on MS-100. This pre-existent half trip, when combined with the (other half) trip of Logic Channel 2 during the surveillance test, resulted in the automatic closure of MS-100.
During the above tv ubleshooting, some wiring anomalies were noted in the control switch circuitry for MS-100.
Contrary to the schematic drawings, there were some cross-connections between the Channel 2 and Channel 4 control circuitry for this valve. This enabled the DS43A SFAS light to incorrectly remain energized with an inoperable and faulty K104A SFRCS relay driver card.
This wiring anomaly was due to apparent ambiguity in the cable nomenclature utilized in the installation of the control switch for NS-100. Daring the troubleshooting, a broken cable in the MS-100 reset circuitry was also discovered. This broken wire did not relate to the inadvertent closure of MS-100 and was replaced prior to plant restart. It is emphasized that the above wiring anomaly did not, in any way, affect the closure capabil-t ity of MS-100 during full SFRCS or SFAS actuation of the associated actuation channel (s).
6-The wiring anomaly in the Loop 2 MSIV (MS-100) control circuitry was corrected and acceptably tested on March 4, 1984. In addition, such an anomaly was verified not to be present in the control circuitry for the Loop 1 MSIV (MS-101). ,
3 Post Trip Response (See Figures 1-24)
Summary 3.1 After the reactor trip, the rapid feedwater reduction circuit closed the main feedwater control valves, termi-nating the excessive feedwater flow to SG #1. The startup control valves went to the target position as designed. After the reactor trip, NFP #1 began to control erratically even when the control station was transferred to manual. Control was reestablished locally at NFP #1 after removing power from the motor gear unit.
Pressure was observed to be decreasing well below the expected post trip value on Main Steam Line #2 (see Figures 16 and 17). Atmospheric Vent #2 was closed to isolate one possible failure. A local observation of the MSSVs determined that a safety valve had stuck open on the Main Steam Line #2 [see Section B.3.3(a) for discussion of the MSSV failing open]. The SFRCS was manually initiated, per procedure, on low SG 1evel at 12:38:17 hours. This actuated both auxiliary feed pumps, isolated normal feedwater to each SG and closed the MSIV on SG #1. The operators manually shutdown the
- 2 AFP to stop the feeding of the #2 Steam Generator.
Since the safety valve was still open on Main Steam Line
- 2, SG #2 pressure reached the 612 psig low pressure trip setpoint at 12:38:29, actuating " low steam pressure" SFRCS. SFRCS realigned both auxiliary feed pumps to feed SG #1 as designed. SG #2 depressuriged (to atmos-pheric pressure) in approximately five minutes after feedwater was isolated.
By 12:43 hours, the pressurizer level was restored to approximately 100 inches, and the Reactor Coolant System (RCS) pressure and temperature were at approximately 2200 psig and 515'F, respectively. SG #1 was being used to remove the reactor coolant pump heat and decay heat, and SG #2 was depressurized and dry.
Since SG #2 was dry, cooldown was accomplished quite slowly minimizing shell to tube differential temperature.
The RCS cooldown was conducted at a rate to match the temperature of SG #2 shell. By 07:20 hours on March 3, 1984, the RCS had been cooled to 340'F. The stuck open safety valve was replaced with a spare, and at 07:30 hours, the refill of SG #2 began. By 07:45 hours, SG #2
~7-was restored to operable status. The plant continued its cooldown, entering Mode 4 at 12:40 hours oc March 3, 1984.
One plant operating condition worth noting is that with the present design, an operator has to be dispatched outside the protected area to add hydrogen to the makeup tank. This action is necessary after a trip and detracts from the available personnel.
3.2 Review of Primary and Secondary Parameters The primary and secondary parameters were examined during the post-trip response. The following maximum and minimum values were found between the time of the reactor trip and the time that SG #2 boiled dry (about 21 minutes after the reactor trip).
MAXIMUM MINIMUM PARAMETER VALUE VALUE FIGURE NO.*
Primary Loop 1 Th (F) 607 516 2 Loop 2 Th (F) (computer point not reading)
Loop 1 Tc2 (F) 569 501 3 Loop 2 Tct (F) 573 506 4 Loop 1 RC pressure (psig) 2200 1780 5 RC PZR level (inches) 206 25 6 MU tank level (inches) 82.5 13 7 Seconda ry Loop 1 SG pressure 1070 634 8 Loop 2 SG pressure 1060 ~0** 9 Loop 1 Operate level (%) 83 ~0 10 Loop 2 Operate level (%) 49 ~0 11 Loop 1 S/U level (inches) 211 26 19 Loop 2 S/U level (inches) 147 0 16 Loop 1 MFW flow mlbe >7 0 14 hr Loop 2 MFW flow mlbe 6.9 0 15 hr -
- Figures only have about 5 minutes of data immediately after reactor trip. Minimum and maximum values were obtained from computer data trend (Validyne at one second intervals).
- See following page.
. 8-
- Computer trend data indicates approximately 100 psig at this point. However, Figure 17 shows that the SG #2 steam pres-sure indication varied around 100 psig for >30 minutes.
SG #2 steam pressure indication later slowly decreased to "0" over the next hour. It was verified that the stuck open MSSV had stopped steaming around this time. Also, Loop 2 startup level had been indicating "0" for approximately one minute at the time that SG #2 steam pressure indication reached "100 psig".
Consequently, it is assumed that the SG #2 was approximately at atmospheric pressure when the indication reached "100 psig".
By 12:34:10 hours, pressurizer level had recovered to 65 inches in spite of SG #2 feedwater flow of about 400 KPPH. RCS temperature had decreased to about 520*F.
However, the leaking MSSV continued to overcool the RCS, i allowing about 350 KPPH of feedaater flow through the SG #2 at 12:38:00, just before operators manually actuated " low SG level" SFRCS isolating normal feedwater to both SGs. This excessive steaming had decreased pressurizer level to 45 inches and decreased RCS temper-ature to about 511*F. After " low SG level" SFRCS actuated, AFW flow to SG #1 increased the SG #1 level to 44 inches as designed (AFW to SG #2 was terminated within 12 seconds of manual actuation). This AFW flow decreased pressurizer level to a minimum of 25 inches at 12:39:30 hours with reactor coolant temperature reaching about 504*F. The overcooling was terminated at this point. By the time SG #2 had depressurized, reactor coolant temperature had been increased back to about 516'F. It can be seen by comparing SG outlet pressures (Figures 8 and 9) that, when SG #2 pressure reached the
" low SG pressure" 5FRCS setpoint (612 psig), SG #1 pressure was only about 100 psig greater. This is due to the fact that, since SG #1 is not steaming, its pressure is saturation pressure for the primary T-cold.
At the time SG #2 reached 612 psig, RCS T-cold was about 511*F for which the corresponding saturation pressure is 751 psig. This corresponds closely with SG #1 pressure a which was reading 711 psig.
1 l
3.3 Discussion of Anomalies The following anomalies occurred during the post trip response.
a) One Main Steam Safety Valve Failed Partially Open MSSV SP17A4 is a Dresser type 3707 RA-RT 21 valve.
SP17A4, having a set pressure of 1070 psig, lif ted and failed to fully close. See Figure 25.
( Inspection of SP17A4 revealed the release nut cotter
! pin (Item 16A), which secures the release nut (Item 16) to the valve spindle (Item 8), was missing.
, The release nut had moved down on the spindle approximately one inch and was jammed on the top
- lever (Ites 17). .The spindle was also bent.
Apparently, the release nut cotter pin had broken during plant operation and vibrated out, allowing !
the release nut to travel down the threaded end of the spindle while the valve was open. The bottom of the release nut made contact with the top lever preventing complete spindle travel for valve closure.
All other MSSVs were visually inspected for similar problems with specific attention for missing or
, damaged release out cotter pins. Visual inspection revealed no abnormalit'es on the remaining MSSVs.
Since the design of the MSSVs are similar to most
. other safety valves used in nuclear safety related applications, other safety valves (e.g., primary code safety valves, decay heat removal, core flood, etc.), were inspected for similar problems. Approxi-mately half of the nuclear safety related valves were in,spected and no problems were noted.
b) One Main Steam Safety Valve Failed To Open MSSV SP17A1, having a set pressure of 1050 psig, failed to open following the reactor trip. A visual inspection of the valve indicated it appears to be in satisfactory condition. SP17Al was tested and found to have an inconsistent lift pressure, and was declared inoperable and gagged.
c) Steam Generator No. 2 Auxiliary Feedwater Isolation Valve Did Not Open Automatically ,
Just prior to restoring AFW to SG #2, AF599 failed to open using the Limitorque Operator, The valve j was manually opened, after which it cycled normally
! using the motor operator. Troubleshooting of AFS99 did not reveal any mechanical or electrical problems with the valve or motor operator, however, the torque switch settings were changed to prevent wedging the valve disc too tightly in the seat.
d) One Main Feedwater Stop Valve Would Not Automatically open After restoring level to SG #2 with the Auxiliary Feedwater System, the normal feedwater flowpath was aligned to the SG. To accomplish this, FW601, (Main Feedwater Stop Valve #2) had to be manually opened.
i This was a result of the unusually large differential pressure (approximately 800 paid) across the 18 inch valve disc as the Startup Feed Pump (SUFP) was in operation and pressurizing the upstream side of the
valve. During all normal operations, this valve is open and its function is only required to shut on a SFRCS or a Safety Features Actuation System (SFAS) actuation. The valve performed its tasked function satisfactorily in the safety direction. The only procedural opening would occur under abnormal conditions of a complete loss of main and auxiliary feedwater event. During this procedure, FW601 is opened before the SUFP is started. However, during the event, the SUFP was already in operation and feeding SG #1 so the large differential pressure could not be avoided.
e) Plant Cooldown Two hours following the reactor trip, the RCS parameters stabilized at 515'F and 2200 psig (see Figure 20). In approximately an hour and 40 minutes, the cooldown of the RCS began. Heat reroval was accomplished by dumping steam to the atmosphere through the atmospheric vent valve from the SG #1.
SG #2 remained depressurized since the one MSSV remained open. Its shell temperature indicated by the shell thermocouples continued to drop due to the natural cooldown toward the ambient temperature conditions. As this cooling process progressed, the RCS pressure was reduced by normal spray flow into the pressurizer. This cooling /depressurization occurred over the next 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> where the RCS conditions were approximately 340*F and 400 psig.
At this time, the SG #2 shell thermocouples were averaging 330*F.
At around 07:25 hours on March 3, 1984, an auxiliary feedwater pump was aligned to refill the SG #2 and restore the level and steam pressure.
From the time that AFW was injected into the SG, the steam pressure was restored to 100 psig in 5 minutes, and the level restored to 50 inches on startup range in 13 minutes.
At this point, both SGs were fully restored to operation, and the plant was taken to the Mode 5 status.
- 4. Operator Actions / Procedural Adequacy Operator Actions 4.1 Acting appropriately per procedure, operators manually actuated the SFRCS to isolate the indicated steam leak occurring in SG #2 steam line.
- _~ - - - _ _ _ _ _ _ - - . . _ _ _ . - - -
4.2 Operators locally operated MFP #1 to prevent erratic operation when restoring main feedwater to SG #1.
4.3 Operators manually opened the A W Isolation Valve #2 when the Limitorque operator would not open this valve.
y 4.4 Operators correctly cooled down the plant with a failed open NSSV to minimize the tube to shell temperature difference.
4.5 After the leaking MSSV had been replaced, operators restored SG #2 level and pressure by injecting AW to the SG.
Procedural Adequacy As soon as the operators reslized that a MSSV had failed open, they activated SFRCS on low SG 1evel, per procedure.
However, since it was known that an unisolable steam leak had occurred on SG #2, it would have been better if the procedure had allowed the operator to actuate " low SG pressure" SFRCS on that SG. The emergency procedure for steam supply system rupture was revised to allow this.
During the cooldown, it was necessary to cool the RCS to the SG shell temperature (maximum tube to shell AT allowable is 75'F), and then adjust the cooldown to a rate equal to the cooldown of the SG shell. These instructions were added to the Plant Shutdown and Cooldown Procedure. Instructions were included to add AW to a dry SG (actual data from this transient was added to show how the RCS and SG will react).
Additional guidance was provided for manual calculations of SG shell temperatures in the event the station computer is inoperable. Instructions were added to allow borating the RCS to the cold shutdown baron concentration to eliminate the need for trippable reactivity during cooldown. This would enhance efforts to reduce RCS pressure by not requiring the RPS be placed in shutodwn bypass. Rapidly reducing RCS pressure to the fuel pin in compression limit is necessary to reduce tube hoop stress.
C. Safety Considerations Although one SG was inoperable, one operable SG is sufficient to remove core decay heat and pump heat. Adequate subcooling margin existed at all times both during the overcooling phase and following isolation of the inoperable SG.
The impact of this transient on the reactor coolant pressure boundary components has been evaluated. The Babcock & Wilcox evaluation concluded that each of the primary pressure boundary components (i.e., reactor vessel, pressurizer, reactor coolant
( piping, and steam generators) still meets all of the requirements of the ASME Boiler and Pressure Vessel Code,Section III and that
the transient experienced by the RCS can be documented on the basis of existing design transient cycles originally designed for and defined in the RCS Functional Specification of Record (with the possible exception of a fraction of the tubes in SG #1 which experienced flow-induced vibration due to high NFW flowrate, see Assessment Conclusions).
Also, the failure of the SG #2 auxiliary feedwater isolation valve to open using its Limitorque operator was not serious because only one AFW train is required for adequate heat removal.
Moreover, these AFW isolation valves are designed to be opened manually as a backup.
D. Assessment Conclusions The primary and secondary plant responded as expected for the transient. Engineered Safety Features Systems actuated within the Technical Specifications limits, and performed these de-scribed functions. An evaluation of the transient event by Babcock & Wilcox concludes that this transient for SG #2 can be depicted and enveloped by the combination of a normal cooldown cycle in combination with a " stuck open turbine bypass valve" design transient cycle. Therefore, the SG #2 and its components during this event were subjected to no effects beyond the design transient, and no degradation was sustained. The reactor trip is classified as a transient 8P. For unusual plant events like this one in which one or more equipment failures occur, the best logging method is to cover the event by more than one design basis transient. The March 2, 1984 Davis-Besse Unit I reactor trip will be logged as one occurrence for each of the following design basis transients listed in the reference document.
- a. Transient 8B - Reactor Trip
- b. Transient 9 - Rapid Depressurization
- c. Transient IB - Cooldown
- d. Transient 17B - Stuck Open Turbine Bypass Valve Overall Plant and SG No. 1 SG No. 2 Pb 8B 9 9
! IB 1B partial (340*F to 140'F) 17B A B&W evaluation of high steam flow in SG #1 showed that about 100 tubes were subjected to vibration. This vibration could have resulted in some denting and gouging of SG #1 tubes. SG #1 was also monitored during startup for leakage.
During the startup, prior to Mode 2, SG water samples will be analyzed for Tritium every fout hours when samples are available.
From Mode 2 until 50% reactor power, SG water samples will be analyzed for Tritium once per shift. Above 50% reactor power, monitoring of the condensate pump discharge will be conducted on a normal weekly basis for gross beta activity.
During this startup, the sain steam line radiation monitors (RE 600 and RE 609) were in the gross count mode and monitored once per hour until Mode 2 is reached. Above Mode 2, the moni-tors were shifted from the gross count mode to the analyze mode for monitoring N-16 gamma radiation. Readings are being taken once per shif t until reaching 50% reactor power. Above 50%
reactor power, the normal alarm functions are being used to provide indication of any leakage.
During the startup, after the MSIVs are opened, hourly readings were taken on the Steam Jet Air Ejector Radiation Monitors (RE 1003A&B) until Mode 2 was reached. Above Mode 2, readings will be taken once per shift until reaching 50% reactor power.
Above 50% reactor power, the normal alarm functions are being used to provide indication of any leakage The SG shell thermocouples (T/Cs) are necessary to ensure cooldown within SG shell to tube AT limits. During the cooldown for this transient, only two SG shell T/Cs on the dry SG appeared to be reading correctly. Prior to startup, had T/Cs were replaced to ensure four good T/Cs on each SG (eight total).
5
a.
~ .
, LIST OF FIGURES Figure 1A-Post-TripP-TDiagramLoop1 Figure IB - Post Trip P-T Dirgram Loop 2 Figure 2 - RC T-hot WR versus Time (Loop 1)
. Figure 3 - RC T-cold WR versus Tuse (Loop 1/ Leg 2)
Fi,3ure 4 - RC T-cold WR versus Time (Loop 2/ Leg 1)
Figure 5 - RC Pressure WR versus Time (Loop 1)
Figure 6 - PRZR Ccap. Level vhrs'us Time Figure 7 - RC MU Tank Level versus Time Figure 8 - SG #1 Pressure versus Time Figure 9 - SG #2 Pressure versas Time Figure 10 - SG #1 Operate Level versus Time Figure 11 - SG #2 Operate Level versus Time
' Figure 12 - MFV SU Flow #1 versus Time Figure 13 - MFW SU Flow #2 versus Time Figure 14 - MEV Comp. Flow #1 versus Time Figure 15 - MFW Comp. Flow #2 versus Time Figure 16 - SG #2 Blowdown Parameters versus Time (Sheet 1)
Figure 17 - SG #2 Blowdown Parameters versus Time (Sheet 2).
Figure 18 - SG #1 Parameters During Blowdown versus Time (Sheet 1)
Figure.19 - SG #1 Parameters,During Blowdown versus Time (Sheet 2)
Figure 20 - Orientation ~of Power Range NIs Figure 21 - SG #2 Refill Parameters versus Time Figure 22-SG#2T-cckdandShellTemperatureversusTime Figure 2:1 - Schematic of MSSV F(gure 24'- Plot of Cooldown
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. RCS W10E R ANGE TEMPER ATU A E (TI-R C 4 A 2,52
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o
- 3. OTSG Water Level Response F.A
(. OTSG level initially decreased to about 5% (equivalent n to minimum indication) on the operate range. Startup.
(
range level indication was available to the operators, j' but_not recorded for later analysis. This drop is normally
\ expected during any event which stops or rapidly re-
.- duces MFW flow. Loss of flow causes the dynamic por-f tion of the operate level signal to go to zero. The OTSG's did not dry out.' Emergency feedwater then j rapidly restored the levels to 50% on the operate range.
r-
\
- 4. Steam Pressure Response
- k. Steam pressure prior to the trip was approximately 900 psig. When the trip occurred, the pressure in-
- f. creased rapidly to approximately 1050 psig and was decreased by the MSSV's. OTSG pressure dropped to f( about 680 psig after approximately 7 minutes: .this was the result of excessive feeding of cold EFW to
{ the OTSG's. This cooler feedwater, when sprayed I into the top of the OTSG, reduced the steam generator pressure. During the next approximately 30 minutes,
( pressure increased to approximately 800 psig be-cause of RCS heatup. The turbine bypass valves
(, were manually operated and some steam was dumped' to the condenser during this time, in an attempt
{ to prevent RCS heatup and consequently, RC volume
(' swell. Prevention of RCS heatup after an over-cooling is per recommendations previously issued
)
\, by B&W. This action slowed the rate of steam pressure rise, but did not maintain a steady
( steam pressure. Normally, the ADV's would be used to control OTSG pressure when circulating water is not available to the condenser, but the
( .-
! ADV block valves were shut and electric power to
\.
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