ML16245A452
| ML16245A452 | |
| Person / Time | |
|---|---|
| Site: | Davis Besse, Oconee, Arkansas Nuclear, Crystal River, Rancho Seco, Crane  |
| Issue date: | 09/13/1979 |
| From: | Capra R NRC - TMI-2 BULLETINS & ORDERS TASK FORCE |
| To: | NRC - TMI-2 BULLETINS & ORDERS TASK FORCE |
| References | |
| NUDOCS 7910250436 | |
| Download: ML16245A452 (99) | |
Text
UNITED STATES NUCLEAR REGULATOXtY COMMISSION WASHINGTON, D. C. 3MME September 13, 1979 Docket Nos.
0-269, 50-270, 50-287 50 289, 50-302, 50-312 50-313, 50-346 FACILITIES:
Oconee Nuclear Station, Unit Nos. 1, 2, and 3 (Oconee)
Three Mile Island Nuclear Station, Unit No. 1 (TMI-1)
Crystal River Nuclear Generating Station, Unit No. 3 (CR-3)
Rancho Seco Nuclear Generating Station (RS)
Arkansas Nuclear One, Unit No. 1 (ANO-l)
Davis-Besse Nuclear Power Station, Unit No. 1 (DB-1) 9 LICENSEES:
Duke Power Company (Duke)
Metropolitan Edison Company (Met-Ed)
Florida Power Corporation (FPC)
Sacramento Municipal Utility District (SMUD)
Arkansas Power & Light Company (AP&L)
Toledo Edison Company (TECO) o
SUBJECT:
SUMMARY
OF MEETING HELD ON AUGUST 23, 1979, WITH THE BABCOCK &
WILCOX (B&W) OPERATING PLANT LICENSEES TO DISCUSS RECENT (POST TMI-2) FEEDWATER TRANSIENTS On August 23, 1979, members of the NRC staff met with representatives of the B&W operating plant licensees, and the B&W Company, to discuss feedwater transients at B&W operating plants which have occurred subsequent to the Three Mile Island Unit 2 (TMI-2) accident. Enclosure 1 is a copy of the meeting agenda. A list of attendees is provided as Enclosure 2.
BACKGROUND Following the TMI-2 accident, an NRC staff review of the B&W designed plants' response to feedwater transients concluded that they have an unusual sensitivity to these types of transients. The Commission issued Orders during May 1979, which confirmed that the plants would shut down and remain shutdown until several short-term action items were accomplished. These items were-required to mitigate the consequences of feedwater transients in these facilities. Subsequent to the accomplishment of these items and the lifting of the Commission Orders, several feedwater transients have taken place at the B&W operating plants. This meeting was called by the NRC staff to review those transients with respect to: (1) plant response, (2) operator action, (3) ICS response, and (4) licensees' actions to preclude similar events.
2-9&
DISCUSSION The meeting was divided Into two parts:
(1) The first part involved presentations by FPC, AP&L, Duke and SMUD. Each licensee discussed the feedwater transient events which have taken place at its facility.
(2) The second part of the meeting involved a discussion of the consequences of experiencing a loss of pressurizer level indication (LOPLI) during transient events on B&W plants.
RECENT FEEDWATER TRANSIENTS The following is a listing of the feedwater transients which-were discussed during the meeting:
FACILITY TIME & DATE DESCRIPTION OF TRANSIENT CR-3 0259 8/16/79 Reactor trip on high RCS* pressure, 72% power, reactor trip when "C" RCP* was secured.
1125 8/16/79 Reactor trip on high RCS pressure, 45% power, 3 RCPs operating, S/G* underfeed 0706 8/17/79 Reactor trip on high RCS pressure, 48% power, 3 RCPs operating, S/G underfeed 1825 8/17/79 Reactor trip on high RCS pressure, 26% power, 3 RCPs operating, S/G underfeed 0202 8/2/79 Reactor trip on low level in both S/Gs, 10% power (automatic anticipatory reactor trip)
ANO-1 1749 8/13/79 Reactor tripeon high RCS pressure, 75% power (Au tomatic. reactor-trip-on-turbine-trip did not work Oconee 1 0333 6/11/79 Reactor trip on loss of main feedwater, 99% power, (automatic anticipatory reactor trip) 0752 6/11/79 Reactor trip on loss of main feedwater (manual),
1% power Oconee 2 0344 5/7/79 Reactor trip on high RCS pressure, 28% power, feedwater oscillations 2046 6/3/79 Reactor trip on high RCS pressure, 30% power, feedwater oscillations Rancho Seco 1714 7/12/79 Reactor trip on turbine trip, 100% power, (automatic anticipatory reactor trip)
- RCS - reactor coolant system RCP - reactor coolant pump S/G -
-3 LICENSEE PRESENTATIONS The following is a brief summary of these events. Enclosures 3 through 7 contain the slides and any supplementary material used during the meetings by the licensees.
(1) CRYSTAL RIVER - 3 (Reference - Enclosure 3)
Within a time span of about 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> (0259 on 8/16/79 to 1825 on 8/17/79) CR-3 experienced four reactor trips, all of which involved abnormal feedwater response. These are discussed individually below:
8/16/79 - 0259 The reactor was operating at 72% power with all four RCPs running. Due to a seal malfunction in the third stage of "C" RCP, the operator tripped "C"
RCP. The decreased-reactor coolant flow in the "B" loop, caused by the tripping of "C" RCP, resulted in the RCS pressure in the "B" loop to increase to the reactor high pressure trip setpoint (2300 psig). Normal operating pressure for CR-3 is 2155 psig. Following the reactor trip, the "B" startup feedwater control valve failed in the open position. This failure was due to a malfunction in the air control relay for the startup control valve.
The open valve caused the "B" S/G to be overfed, which led the S/G to over fill and the RCS pressure to decrease to a minimum of 1845 psig.
The minimum pressurizer level was 36" indicated (111" above the bottom of the pressurizer). The operator recognized the open startup control valve and closed it.
In addition, the operator started two additional makeup pumps and opened the high pressure injection (HPI) valves. The failure of the startup control valve was not related to a failure of the integrated control system (IES).
FPC has contracted a firm to check out the operation of the MFW pump control circuits and pump characteristics.
FPC has also.
revised its operating procedures to reduce reactor power to below 60%
prior to tripping a RCP when starting from four pump operation. The reduced power should keep.the pressure surge below the high pressure reactor trip setpoint.
8/16/79 - 1125 Following recovery from the reactor trip which occurred at 0259 that morning, the plant was operating at 45% reactor power with three RCPs operating (only one pump in "B"' loop).
While in the process of making the transition from startup control to normal operating control of the MFW system, the operator manually opened "A" main feedwater block valve. The increased feed flow caused the "A" MFW pump to reduce speed. The pump overresponded in reducing flow and the reactor tripped on high RCS pressure in "B" loop. The A main block valve remained open and overfed the "A" S/G. The minimum RCS pressure reached 1550 psig. The pressurizer level instrument indicated 0" (75" above the bottom of the pressurizer) and 8" on the post-trip review.
The ICS responded correctly to the "A" main block valve-being opened manually by decreasing feed flow to "A" S/G; however, the. "A" main feedwater pump could not respond quickly enough to the rapidly changing demand. Operator actions included starting an additional makeup pump, opening the HPI valves,
isolating letdown and closing "A" main block valve.
FPC has revised its procedures to allow opening of the main block valves in the automatic mode only. Operator training is being conducted on valve mode transfer and the role of ICS during both 4 and 3 RCP operation.
8/17/79_- 0706 While recovering from the reactor trip at 1125-the previous day, the reactor again tripped on high RCS pressure at 0706. The reactor was critical at 48%
power with three RCPs operating (one pump in "B" loop). The "A" MFP was feeding both S/Gs with the main crosstie valve open. Feedwater was being supplied to the S/Gs in the "valve control" mode. As power increased, the operator manually opened the "A" main block valve. This action caused feed flow control for "A" S/G to shift to the "MFP speed control" mode and remain in the "valve control" mode for "B" S/G.
The operator then started "B" MFP.
As he brought "B" MFP up to speed, it began to supply some of the feed flow to both S/Gs.
This reduced the speed of "A" MFP. When the operator shut the crosstie valve, the "A" MFP could not respond fast enough to increase feed flow to "A" S/G and the reactor tripped on high RCS pressure. The maximum RCS pressure was 2297 psig, the minimum RCS pressure was 1952, and the minimum pressurizer level was 100 inches indicated. As corrective.action, FPC supplemented the operating procedures by providing a detailed sequence of steps on how the operator should make the transition from one to two MFPs when operating with only three RCPs.
8/17/79 - 1825 While recovering from-the reactor trip at 0706 that morning, the reactor again tripped on high RCS pressure at 1825. The reactor was at 26% power with 3 RCPs operating (1 in "B" loop).. The reactor demand and the startup feedwater control valves were in the manual mode. During the power ascension, the reactor operator shifted the reactor demand and startup feedwater control into the automatic mode without matching the automatic demand to the manual demand. The mismatch caused the startup control valves to close which underfed the S/Gs. The reactor tripped on high RCS pressure in "B" loop. Maximum RCS pressure was 2297 psig, the minimum pressure was 1924 psig, and the minimum pressurizer level was 70 inches indicated. Following this fourth reactor trip, the reactor was placed in cold shutdown and the "C" RCP seal was replaced.
FPC has scheduled additional operator training for all operators which will incorporate the lessons learned from all four reactor trips and the guidelines which B&W has developed for 3 RCP operation. This training will be completed by all licensed operators prior to future 3 RCP operation.
8/2/79 - 0202 Following the completion of zero power physics testing, the reactor was being brought up in power with all four RCPs operating and the "B" MFP feeding both S/Gs. At 10% reactor power, the "B" MFP experienced a governor malfunction. This malfunction caused the "B" MFP to drop in speed to the low speed stop. As the level in the S/G decreased to 18" on the S/U range indication, the reactor tripped on low level in both S/Gs. This trip was added to the Crystal River, Unit 3 facility as part ofitS compliance with The Commission Order of May 16, 1979.
The low level in the S/Gs caused automatic initiation of emergency feedwater to both S/Gs, recovering the level prior to S/G dryout.
The operator brought "A" MFP up to speed and secured the EFW pumps. Sub sequent investigation of the malfunction on "B" MFP showed dirt had clogged a control orifice in the MFP controller. The "B" MFP governor was flushed out, tested and returned to service. FPC is investigating the possibility of installing filters in all the MFP governors upstream of the control orifices.
(2) ARKANSAS NUCLEAR ONE, UNIT 1 (Reference - Enclosure 4) 8/13/79 - 1749 While operating at 75% reactor power, a switchyard relay failed causing a turbine trip. Upon turbine trip, the turbine lock-out relay should have picked up, causing a fast transfer of electrical loads from the auxiliary transformer to the startup transformer and should also have caused a reactor trip. Due to a loose lead on the turbine lock-out relay, neither of these actions occurred. The slow transfer of electrical loads resulted in deenergizing two non-vital busseT causing the "B" main feedwater block valve to fail in the open position and a trip of "A" main feedwater pump. The reactor tripped on high RCS pressure approximately 8.5 seconds following the turbine trip.
The operator carried out his immediate actions for a reactor trip followed by tripping of the "B" main feedwater pump, reenergizing the two non-vital busses, starting the auxiliary feedwater pump and securing the two emergency feedwater pumps. Following the reenergizing of the non-vital busses, the "B" main feedwater block valve received a "close" signal from the ICS. Due to a built-in time delay, the valve was slow in responding to the overfeed, condition in "B" S/G;.therefore, the operator shut the reactor buflding feedwater isolation valve to "B" S/G to correct the situation in a more timely fashion. The maximum RCS pressure was 2289 psig, the minimum RCS pressure was 1800 psig, and the minimum level in the pressurizer during the transient was 18" indicated. Corrective action included replacing the lug and terminal of the failed turbine lock-out relay. The turbine lock out and reactor-trip-on-turbine-trip interlocks were tested with satisfactory results.
OCONEE NUCLEAR STATION, UNIT 1 (Reference -
Enclosure:
- 5) 6/11/79 - 0333 While operating at 99% full power, the reactor tripped after both main feedwater pumps tripped as a result of all six low pressure turbine intercept valves going closed.
Specifically, at 0329 a leaking electrolytic capacitor caused the operational amplifier on the intercept valve amplifier board to fail.
When the intercept amplifier failed, all six low pressure turbine intercept valves failed, cutting off all steam to the low pressure turbines. This set up a sequence of events which led to all three condensate
booster pumps tripping on low suction pressure and subsequently tripping of both main feedwater pumps on low suction pressure. When both main feedwater (MFW) pumps tripped, the reactor tripped. Six seconds after the MFW pumps tripped, all three unit emergency feedwater (EFW) pumps started and both S/G were fed through the EFW header valves, which automatically opened to 60%. The operator took manual control of both valves and maintained S/G level at approximately 25" on the startup range indication until both MFW pumps could be brought back on the line.
Both MFW pumps were reset and brought back up approximately 20 minutes later.
The EFW pumps tripped when the MFW pump discharge pressure reached 750 psig.
The S/G levels dropped to approximately 15" before the MFW pump discharge pressure was high enough to move water into the S/Gs. The delay in reestablishing feedwater to the S/Gs was approximately two minutes.
Corrective action included repairing the malfunction in the intercept valve amplifier and returning the unit to service. In addition a change was made to the Loss of Steam Generator Feedwater Emergency Procedure, to require the operator to put the EFW pump/turbine control switch in the run position after automatic start to preclude a loss of EFW to the S/Gs when restarting the main feedwater pumps.
During this transient, the maximum RCS pressure was 2282 psig and the minimum RCS pressure was 1811 psig.
6/11/79 - 0752 At 0725 Unit 1 went critical after completing repairs to the intercept valve amplifier. The main steam header pressure was approximately 1000 psig.
Feedwater flow to both S/Gs was being maintained by manual control of "B" MFW pump through the ICS controlled startup feedwater control valves.
"A" MFW pump was reset but not operating. At approximately 0752, with the reactor at 1% power, "B" MFW pump tripped on high discharge pressure (1250 psig) caused by high steam header pressure. Since discharge pressure in the MFW header did not drop below 750 psig and "A" MFW pump was reset, the.reactor did not automatically trip.
The S/G levels decreased from 25" to 15",
at which point the operator manually tripped the reactor on low S/G levels, as required by unit operating directive. The operator started "A" MFW pump, but was unable to reestablish S/G level with this pump. "B" MFW pump was restarted and the level in the S/Gs was reestablished. EFW pumps were not automatically actuated since the necessary conditions for automatic starting were not reached. Corrective action included instructing the operators to maintain the steam header pressure as low as possible during unit startup.
(3) OCONEE NUCLEAR STATION, UNIT 2 (Reference - Enclosure 6) 5/7/79 - 0344 At 0344, with the reactor operating at 28% power, the reactor tripped on high RCS pressure. Prior to the transient, the turbine was off the line and power was being held about 15% for the performance of an emergency feedwater flow test. The reactor tripped prior to the conduct of the test. The cause of the trip was the operator's inability to control feedwater flow to the steam generators which was ultimately caused by the excessive leakage of feedwater past the main feedwater control valves (MFWCV). The main feedwater block valves (MFWBVs) are designed to open and close automatically. When in automatic, the MFWBVs open or close dependent upon a signal from ICS which is based on the positions of the startup feedwater control valves
(SUFWCVs). When the SUFWCVs reach 80% open (and opening), the MFWBVs open.
When the SUFWCVs get to 50% open (and closing), the MFWBVs close. If the MFWCVs (located downstream of the MFWBVs) leak past their seats, the opening and closing of the MFWBVs can cause large swings in total feedwater flow to the S/Gs. At approximately 0337, the operator manually blocked open the MFWBVs, to prevent any large oscillations in feedwater flow caused by the MFWBVs opening and closing. Reactor power was approximately 18% at this time. Because of excessive leakage past the seats on the MFWCVs, this opening of the MFWBV caused over feeding to occur in both S/Gs. The resultant decrease in RCS temperature was sensed by the ICS and compensated by increasing reactor power. The power increased from 18% to 28% in about 7 minutes. Upon seeing the overfeed condition, the operator shut the "B" S/0 MFWBV. This sudden drop in feedwater flow resulted in high RCS pressure and the reactor tripped at 2294 psig. During the transient, the level in the pressurizer remained on scale and the minimum RCS pressure experienced was 2000 psig. Corrective action included adjusting the stroke of the MFWCV to insure the valves would fully shut. The MFWCV for all three units leak past their seats, forcing the operators to take manual control of the MFWBV during startup and shutdown.
Work requests to make repairs to the MFWCVs were issued.
6/3/79 -
2046 At 2046 with the reactor at 30% power, the reactor tripped on high RCS pressure caused by a feedwater transient which led to an underfeed condition on "A" S/G. At the time of the incident the main feedwater block valves (MFWBVs) were in automatic. When the "A" main feedwater startup valve (MFWSUV) reached the 80% open position, ICS sent a signal to the "A" MFWBV to open. Due to a malfunction of the mA" MFWBV, the valve did not open. Since the feedwater flow demand was not being met, the ICS continued to open the "A" MFWCV until it reached the 100% open position. The unit supervisor "cracked" the "A" MFWCV off its seat loe41ly (turbine building).
Since the "A" MFWCV was in the 100% open position, this caused the level in "A" S/G to rise rapidly and RCS pressure began to decrease. The operator in the control room took manual control of the "A" MFWCV and began to close the valve. RCS pressure dropped to 1950 psig and began to increase. The operator then manually opened the "A" MFWCV in an attempt to stabilize feedwater flow; however, the system was not able to react in time to prevent the RCS pressure from reaching 2294 psig, causing a reactor trip. During this transient, the minimum RCS pressure reached 1850 psig and pressurizer level remained on scale.
Operating procedures have been modified to allow operators the option of controlling the MFWBVs in manual as required to maintain flow stability. In addition, a work request was issued to investigate the malfunction of "A" MFWBV.
(4) RANCHO SECO (Reference - Enclosure 7) 7/12/79 - 1714 With the reactor operating at 100% power, a pressure transmitter, sensing pressure in the moisture separator reheaters, malfunctioned causing the reheater stop valves to cycle approximately 6 times. The operator responded by placing the main generator in manual and decreasing the load. The cycling of the reheater stop valves caused the reheater relief valves to open. This action caused the main steam pressure to decrease, resulting in a main turbine trip. This trip caused a reactor trip. During this translant, the feedwater discharge pressure decreased below the pressure which
would also cause a reactor trip; however, since the turbine trip occurred first, the low feedwater discharge pressure signal served only as a backup.
Both auxiliary feedwater pumps started; however, since the MFW pumps continued to operate, the AFW pumps were not needed to control S/G level.
The ICS automatically controlled S/G levels at the low level limits (24" on startup range indication) and steam was relieved to the condenser via the IC$
controlled turbine by pass valves. The RCS temperature stabilized at 555uF and pressurizer level remained on scale. Two days following this trip, a similar transient Cfailure 6f a pressure transmitter) occurred.
However, in that case the operator was successful in running the turbine governor valves back fast enough to prevent a turbine trip.
OPEN DISCUSSION Following the presentations by the licensees, a caucus was held between members of the staff to discuss staff concerns related to feedwater transients in the B&W operating plants. The following is a summary of those concerns. These items were discussed with the licensees following the caucus.
- 1. Based on the presentations which were made by the licensees, no unresolved safety issues were identified by members of the staff.
- 2. As expected, the lowering of the high pressure reactor trip.setpoint from 2355 psig to 2300 psig and the raising of the PORV lift setpoint from 2255 psig to 2450 psig (except for Davis-Besse 1, whose PORV setpoint was changed to 2400 psig) has decreased the number of challenges to the PORV but increased the number of reactor trips associated with feedwater transients.
Out of the 11 transients presented by the licensees, most would have lifted the PORV had the old setpoints remained, fixed.
- 3. Operator training and guidelines are needed on operation with only three RCPs operating.
- 4. The control of main feedwater during low power operation (startup and shutdown) is especially sensitive to both operator error and/or equipment malfunctions.
Several instances were discussed where either operator error, equipment malfunction, or pump/valve overreaction or underreaction lead to a sequence of S/G overfeed conditions followed by underfeed conditions and vice versa.
- 5. Overfilling the S/Gs leads to rapid primary coolant system temperature and pressure decreases. This condition can be caused by a single failure of many components in the MFW system. This overfilling can lead to a rapid cooldown of the primary system, reactor trip, actuation of the high pressure injection system, and loss of pressurizer level indication due to shrinkage.
- 6. Underfilling the S/Gs leads to rapid primary coolant system temperature and pressure increases resulting in reactor trips on high-RCS pressure.
- 7.
None of the B&W operating plants has an automatic trip of the MFW or AFW pumps on a high S/G level.
If a malfunction occurs to a MFW valve which would cause it to stick in the fully open position, the S/G could be filled completely in a matter of a few minutes. The resultant carryover of liquid into the main steam lines could lead to equipment damage to both the main turbine and any auxiliary turbines (i.e., AFW pump turbines) being supplied steam from the main steam system. In addition the carryover could lead to excessive waterhaniner. It is also possible that the weight of the water in the
steam lines could cause excessiye stresses on the piping system and pipe supports.
- 8. Several concerns associated with the ICS were expressed,
- a. Most of the problems associated with feedwater control occur during the transition from manual to automatic control or vice versa. There should be a clearly defined way of making this transition and all operators should be trained on this technique.
- b. The staff needs to complete its reytew of the failure modes and effects analysis (FMEA) submitted by B&W on 8/17/79 on a timely basis. The scope of this review will most likely result in additional analysis being required on the ICS and modifications to the present system.
- c. Concerns about the stability of the ICS were expressed. It was pointed out.
that stability criteria needs to be developed for control systems such as this, even though they may not be classified as "safety related".
- d. It was clear in several of the transients discussed, that the feedwater valves and main feedwater pumps cannot react fast enough in many situations to keep from tripping the reactor on either high or low reactor coolant system pressure.
- e. The need for increased operator training n the methods of controlling of the main feedwater system was emphasized.
- 9. The adequacy of the presently installed hard-wired, control-grade anticipatory reactor trip was questioned. As discussed earlier, this trip did not function during the 8/13/79 transient at ANO-1.
Licensees were asked to review the present installation schedule for the safety-grade reactor trip to see if the schedule could be expedited. In addition, licensees were asked to look at options available to them, by which they could increase the reliability of the presently installed trip. These modifications would be used as an interim measure until the safety-grade trip could be installed.
- 10.
The signals used and/or the parameters measured to obtain the anticipatory reactor trip should be looked at again. For example, the 0752 transient at Oconee 1 on 6/11/79 resulted in a manual trip of the reactor, even though the unit had experienced a total loss of main feedwater. This was not due to a failure of-the circuitry but rather a mode of operation which occurs during every startup or shutdown for which this trip was not designed to operate. Another example, was the Crystal River 3 transient which occurred on 8/20/79. Most of the B&W plants do not have an automatic reactor trip on low S/G level.
When operating at low power levels (less than 15% power) an underfeed condition can occur where the reactor can trip on high RCS pressure prior to the operator manually tripping the plant on low S/G levels.
An automatic reactor trip on low S/G level should be reconsidered for.all B&W plants.
- 010, LOSS OF PRESSURIZER LEVEL INDICATION (LOPLI)
The role of pressurizer level indfcation during feedwater transients was discussed with the licensees. It was pointed out that the subject of IE Bulletins issued subsequent to the TMI-2 accident dealt with possible erroneous level indication which could occur during a small break loss-of-coolant accident. These Bulletins did not address the problem of overcooling events which can lead to a LOPLI. Some of the concerns of Mr. James Creswell (NRC Inspector attached to I&E Region III) were discussed with the licensees. Most of Mr. Creswell 's concerns were associated with the 11/77 feedwater transient at Davis-Besse 1 which led to a LOPLI for several minutes. This subject was reviewed in the past by both NRR and I&E. The conclusion of that study was that LOPLI was not desirable; however, it was not a safety concern.
It was pointed out to the licensees that the NRC staff was undertaking another look at this subject to make an assessment of its safety significance. This report will discuss the'events that can result in a reduction or loss of pressurizer level indication, and a review of the operating history of the B&W plants. It will also discuss the role of operator training and procedures for a LOPLI and will present analyses of limiting faults. An outline of this staff study is included as Enclosure
- 8. Several considerations will be looked at if the staff concludes that the LOPLI is unacceptable. Included will be a review of the design to see if the pressurizer is too small, possibly retapping the pressurizer to extend the range of indication, higher initial operating level, increased makeup pump capacity, modifications that would automatically isolate letdown flow and start an additional makeup pump(s) upon reactor trip. In addition, it was pointed out that the staff would be reviewing the adequacy of the pressurizer level indication instrumentation, i.e.,
environmental qualiftcations, control functions, etc. The interaction of LOPLI with pressurizer heater control needs further study.
CONCLUSIONS As a result of the meeting, the following actions will take place:
- 1. Anticipatory Reactor Trip
- a. Licensees will be directed to review their schedule for installing the safety-grade reactor trip for turbine trip and loss of main feedwater to see if these schedules can be expedited.
- b. Licensees will be directed to review their present control-grade trip design and submit proposed modifications to improve its reliability and testability.
- c. Licensees will be directed to rereview the desirability of installing a reactor trip on low-steam generator level (similar to the trip presently installed on Crystal River 3).
Note: Subsequent to this meeting, a letter was sent to each B&W licensee, directing that this action be undertaken.
(
Reference:
letter from R. Reid (NRC) to all B&W operating plants, dated September 7, 1979)
v11
- 2. ICS
- a. The staff will expedite its review of the ICS FMEA submitted by B&W on August 17, 1979. This review will be done in coordination with Oak Ridge National Laboratory.
- b. The scope of the staff review of the ICS FMEA may be expanded to include a stability study of the ICS.
- 3. Loss of Pressurizer Level Indication (LOPLI)
The staff will consider whether licensees should submit a report covering the safety significance of a LOPLI. This report would include as a minimum:
- a. events which lead to a LOPLI;
- b. FSAR analysis;
- c. interpretation of GDC-13;
- d. the desirability of upgrading the pressurizer level instrumentation to safety-grade;
- e. method(s) to idsure that pressurizer heaters are secured on low.1evel in the pressurizer;
- f. operator training and procedures;
- g. recommendations on improvements'to prevent LOPLI; and,
- h. the desirability of installing a MFW/AFW pump trip on high steam generator level.
The list should include a priority listing and schedule for submission. The staff will review this list and provide feedback to B&W and the operating plant licensees as to its acceptability.
Note:
Subsequent to this meeting, B&W has submitted this listing and schedule.
Feedback on its acceptability will be provided in a meeting with B&W and the Owners' Group on September 13, 1979.
R..A. Capra, B&W Project Manager Bulletins & Orders Task Force Office of Nuclear Reactor Regulation
Enclosures:
See next page
-12
Enclosures:
- 1. Agenda
- 2. List of Attendees
- 3. CR-3 Transients
- 4. ANO-1 Transient
- 5. Oconee 1 Transients
- 6. Oconee 2 Transients
- 7. Rancho Seco Transient
- 8. Outline NRC Report on LOPLI
BABCOCK & WILCOX OPERATING PLANTS Mr. William 0. Parker Jr.
Vice President -
Steam Production Duke Power Compa.ny
'P.O. Box 2178 422 South.Church Street Charlotte, North Carolina 28242 Mr. William Cavanaugh, III Vice President, Generation and Construction Arkansas Power & Light Company Little Rock, Arkansas 72203 Mr.- J.
J. Mattimoe Assistant General Manager and Chief Engineer
__"C Sacramento Municipal Utility District 6201 S Street P.O. Box15830 Sacramento, California 95813 Mr. Lowell E. Roe Vice President, Facilities Development Toledo Edison Company Edison Plaza 300 Madison Avenue Toledo, Ohio 43652 Mr. W. P. Stewart Manager, Nuclear Operations Florida Power Corporation P.O. Box 14042, Mail Stop C-4 St. Petersburg, Florida 33733 Mr. R. C. Arnold Senior Vice President Metropolitan Edison Company 260 Cherry Hill Road Parsippany, New Jersey 07054 Mr. James H. Taylor Manager, Licensing Babcock & Wilcox Company Power Generation Group P.O. Box 1260 Lynchburg, Virginia 24505
Duke Power Company Mr. William L. Porter Mr. Robert B. Borsum Duke Power Gompany Babcock & Wilcox Post Office Box 2178 Nuclear-Power Generation Division 422 South Church Street Suite 420, 7735 Old Georgetown Road Charlotte, North Carolina 28242 Bethesda, Maryland 20014 J. Michael McGarry, III, Esquire Manager, LIS DeBevoise & Libernan NUS Corporation 700 Shoreham Building 2536 Countryside Boulevard 806 15th Street, N.W.
Clearwater, Florida 33515 Washington, D. C. 20005 Office of Intergovernmental-.Relations 116 West Jones Street Honorable Janes M. Phinney Raleigh, North Carolina 27603 County Supervisor of Oconee County Walhalla, South Carolina 29621 Director, Technical Assessment Division Office of Radiation Programs (AW-459)
U. S. Environmental Protection Agency Crystal Mall #2 Arlington, Virginia 20460 U. S. Environmental Protection Agency Region IV Office ATTN:
EIS COORDINATQR 345 Courtland Street, N.E.
Atlanta, Georgia 30308 U. S. Nuclear Regulatory Commission Region II Office of Inspection and Enforcement ATTN: Mr. Francis Jape P. 0. Box 85 SenEca, South Carolina 29678
Arkansas Power & Light Company Phillip K. Lyon, Esq.
Director, Technical Assessment House, Holms & Jewell Division 1550 Tower Building Office of Radiation Programs Little Rock, Arkansas 72201 (AW-459)
U. S. Environmental Protection Agency Mr. David C. Trimble Crystal Mall #2 Manager, Licensing Arlington, Virginia 20460 Arkansas Power & Light Company P. 0. Box 551 U. S. Environmental Protection Agency Little Rock, Arkansas 72203 Region VI Office ATTN:
EIS COORDINATOR Mr. James P. O'Hanlon 1201 Elm Street General Manager First International Building Arkansas Nuclear One Dallas, Texas 75270 P. 0. Box 608 Russellville, Arkansas 72801 Mr. William Johnson Director, Bureau of Environmental U. S. Nuclear Regulatory Commission Health Services P. 0. Box 2090 4815 West Markham Street Russellville, Arkansas 72801 Little Rock, Arkansas 72201 Mr. Robert B. Borsum Babcock & Wilcox Nuclear Power Generation Division Suite 420, 7735 Old Georgetown Road Bethesda, Maryland 20014 Troy B. Conner, Jr., Esq.
Conner, Moore & Corber 1747 Pennsylvania Avenue, N.W.
Washington, D.C.
20006 Honorable Ermil Grant Acting County Judge of Pope County Pope County Courthouse Russellville, Arkansas 72801
Florida Power Corporation Mr. S. A. Brandimore Mr. Robert B. Borsum Vice President and General Counsel Babcock & Wilcox P. 0. Box 14042 Nuclear Power Generation Division St. Petersburg, Florida 33733 Suite 420, 7735 Old Georgetown Road Bethesda, Maryland 20014
- Mr. Wilbur Langely, Chairman Board of County Commissioners Citrus County Iverness, Florida 36250 Bureau of Intergovernmental Rel at ions U. S. Environmental Protection Agency 660 Apalachee Parkway Region IV Office Tallahassee, Florida 32304 ATTN:
EIS COORDINATOR 345 Courtland Street, N.E.
Atlanta, Georgia 30308 Director. Technical Assessment Division Office of Radiation Programs (AW-459)
U. S. Environmental Protection Agency Crystal Mall #2 Arlington, Virginia 20460 Mr.
R Shreve The Public Counsel Room 4 Holland Bldg.
Tallahassee, Florida 32304 Administrator Department of Environmental Regulation Power Plant Siting Section State of Florida Montgomery Building 2562 Executive Center Circle, E.
Tallahassee, Florida 32301 Attorney General Department of Legal Affairs The Capitol Tallahassee, Florida 32304
Metropolitan Edison Company G. F. Trowbridge, Esquire Dauphin County Office Emergency Shaw, Pittman, Potts & Trowbridge Preparedness 1800 M.Street, N.W.
Court.House, Room 7 Washington, D. C. 20036 Front & Maret Streets Harrisbuirg, Pennsylvania 17101 GPU Service Corporation Richard U. Heward, Project Manager Mr. T. Gary Broughton, Safety and Department of Environmental Resources Licensing Manager ATTN:
Director, Office of Radiological 260 Cherry Hill Road Health Parsippany, New Jersey 07054 Post Office Box 2063 Harrisburg, Pennsylvania 17105 Pennsylvania Electric Cor.pany Mr. R. W. Conrad Vice President, Generation Division 1001 Broad Street Office of Radiation Programs Johnstown, Pennsylvania 15907 U. S. Environmental Protection Agency Miss Mary V. Southard, Chairman Crystal Mall #2 Citizens.for a Safe Environment Arlington, Virginia 20460 Post Office Box 405 Harrisburg, Pennsylvania 17108 Mr. Robert B. Borsu1 Babcock & Wilcox Nuclear Power Generation Division Suite 420, 7735 Old Georgetown Road Bethesda, Maryland 20014 Dr. Edward 0. Swartz Board of Supervisors Londonderry Township Governor's Office of State Planning RFD--l -
Geyers Church Road and Development tHiddletown, Pennsylvania 17057 ATTN:
Coordinator, Pennsylvania State Clearinghouse U. S. Environmental Protection Agency P. 0. Box 1323 Region III Office Harrisburg, Pennsylvania 17120 ATTN:
EIS COORDIN4ATOR Curtis Building (Sixth Floor)
Mr. J. G. Herbein 6th and Wal nut Streets
.Vice President Philadelphia, Pennsylvania 19106 Metropolitan Edison Company P.O. Box 480 Middletown, Pennsylvania 17057
acrarento Municipal Utility Page 1 of 2 District Christopher Ellison, Esq.
David S. Kaplan, Secretary and Dian Grueuich, Esq.
General Counsel California Energy Commission 6201 S Street 1111 Howe Avenue P6 0. ox 15830 Sacramento, California 95825 Sacramento, California 95813 Ms. Eleanor Schwartz Sacramento County California State Office Sar ounty 600 Pennsylvania Avenue, S.E., Rm. 201 Board of Supervisors WsigoDC 00 027 7th Street, Room 424 Washington, D.C.
20003 Sacramento, California 95814 Docketing and Service Section Office of the Secretary U. S. Nuclear Regulatory Commission Washington, D.C.
20555 Michael L. Glaser, Esq.
Director, Technical Assessment 15 h Set
.20 Division Office of Radiation Programs Dr. Richard F. Cole (AW-459)
Atomic Safety and Licensing Board U. S. Environmental Protection Agency Panel Crystal Mall #2 U. S. Nuclear Regulatory Commission Arlington, Virginia 20460 Washington, C. 20555 U. S. Environmental Protection Agency Mr. Frederick J. Shon Region IX Office Atomic Safety and Licensing Board ATTN:
EIS COORDINATOR Panel 215 Fremont Street U. S. Nuclear Regulatory Commission San Francisco, California 94111 Washington, D.C.
20555 Mr. Robert B. Borsum Timothy V. A. Dillon, Esq.
Babcock & Wilcox Suite 380 Nuclear Power Generation Division Suite 420, 7735 Old Georgetown Road 1850iKgtre, D..
Eethesda, Mary land 20014
~s~g~,DC 00 James S. Reed, Esq.
Michael H. Remy, Esq.
Reed, Samuel & Remy 717 K Street, Suite 405 Sacramento, California 95814
Page 2 of 2 Sacramento Municipal Utility District Atomic Safety and Licensing Board Panel U. S. Nuclear Regulatory Commission Washington, D.C.
20555 Atomic Safety and Licensing Appeal Board Panel U. S. Nuclear Regulatory Commission Washington, D.C.
20555 Mr. Richard D. Castro 2231 K Street Sacramento, California 95814 Mr. Gary Hursh, Esq.
520 Capital Mall Suite 700 Sacramento, California 95814 California Department of Health ATTN:
Chief, Environmental Radiation Control Unit Radiological Health Section 714 P Street, Room 498 Sacramento, California
£5314
Toledo Edison Company Mr. Donald H. Hauser, Esq.
Director, Technical Assessment The Clevel'and Electric Division Illuminating Company Office of Radiation Programs P. 0. Box 5000 (AW-459)
Cleveland, Ohio 44101 U. S. Envir Crystal-Mall #2 Gerald Charnoff, Esq.
Arlington, Virginia 20460 Shaw, Pittman, Potts and Trowbridge U. S. Environmental Protection Agency 1800 M Street, N.W.
Federal Activities Branch Washington, D.C. 20036 Region V Office ATTN:
EIS COORDINATOR Leslie Henry, Esq.
230 South Dearborn Street Fuller, Seney, Henry and Hodge Chicago, Illinois 60604 300 Madison Avenue Toledo, Ohio.
43604 Mr. Samuel J. Chilk, Secrefary U. S. Nuclear Regulatory Commission Mr. Robert B. Borsum Washington, D.C.
20555 Pabcock & Wilcox Nuclear Power Generation Division The Honorable Tim McCormack Suite 420, 7735 Old Georgetown Road Ohio Senate.
Bethesda, Maryland 20014 Statehouse Columbus, Ohio 43216 The Honorable Tim McCormnack 170 E. 209th Street Euclid, Ohio 44123 President, Board of County' Comissioners of Ottawa County Port Clinton, Ohio 43452 Attorney General department of Attorney General 30 East Broad Street Columbus, Ohio 43215 Harold Kahn, Staff Scientist Bruce Churchill, Esq.
Power Siting Commission Shaw, Pittman, Potts & Trowbridge 361 East Broad Street 1800 M Street, N.W.
Columbus, Ohio 43216 Washington, D.C.
20036 Docketing and Service Section Atomic Safety & Licensing Board Panel Office of the Secretary U. S. Nuclear Regulatory Commission U. S. Nuclear Regulatory Commission Washington, D.C.
20555 Washington, D.C.
20555 Atomic Safety and Licensing Appeal Pane U. S. Nuclear egulatory Commission Washington, D.C.
20555
Toledo Edison Company Ivan W. Smith, Esq.
Atomic Safety'and Licensing Board Panel U. S. Nuclear Regulatory Commission Washington, D.C. ' 20555 Dr. Cadet H. Hand, Jr.
Director, Bodega Marine Laboratory University of California P. 0. Box 247
.Bodega Bay, California 94923 Dr. Walter H. Jordan 881 W. Outer Drive Oak Ridge, Tennessee 37830 Ms.
Jean DeJuljak 381 East 272 Euclid, Ohio 44117 Mr.. Rick Jagger Industrial Commission State of Ohio 2323 West 5th Avenue Columbus, Ohio 43216 Ohio Department of Health ATTN: Director of Health 450 East Town Street Columbus, Ohio 43216
ENCLOSURE 1 AGENDA FOR AUGUST 23, 1979 B&W FEEDWATER TRANSIENTS TIME:
SUBJECT:
9:00 AM Introduction (D. Ross)
Concerns:
(1)
Does the ICS perform satisfactorily?
(2) Is the system response to loss-of-feedwater well known?
(3) Do B&W plants have an anticipatory reactor trip, based on feedwater transients, that increases the time to reach steam generator dryout?
(4) Is it acceptable to have the pressurizer empty on antic 1pated transients?
- 9:15 AM Feedwater transients at Oconee Units (Duke Power Company)
- 9:45 AM Feedwater transients at ANO-1 (Arkansas Power & Light Company)
- 10:15 AM Feedwater transients at Crystal River 3 (Florida Power Corporation)
- 10:45 AM Feedwater transients at Rancho Seco (Sacramento Municipal Utility District)
- 11:15 AM Feedwater transients at Davis-Besse 1 (Toledo Edison Company) 12:00 PM Lunch 1:00 PM Joint discussions (NRC-Licensees-B&W) 4:00 PM Approximate end of meeting
- Note - All licensees should be prepared to present a summary of recent (post TMI-2) feedwater transients.
For each transient provide a sequence of events and brush recorder traces for key primary and secondary system parameters.
ENCLOSURE 2 ORGANIZATION NAME POSITION Duke Power Company J. N. Pope Superintendent of Operations (Oconee)
N.
Rutherford Licensing D.
Holt Licensing Metropolitan Edison Company M. J. Ross Operations Superintendent K. P. Bryan Shift Supervisor General Public Utilities D. G. Slear Engineering Sacramento Municipal Utility J. J. Mattimoe Chief Eng.-Asst. General Manager District D. C. Blachly Mech. Eng.
N. C. Brock E/I Eng.
Arkansas Power & Light Co.
B. A. Terwilliger Operations & Maint. Manager D. G. Mardis Licensing Engineer Toledo Edison Company T. D. Murray Davis-Besse 1, Superintendent T. J. Myers Nuclear Licensing Engineer B. F. Hill Engineer F. R. Miller Nuclear Systems Engineer Florida Power Corporation B. L. Griffin Senior Vice President G. C. Moore Asst. VP for Power Production R. M. Bright Nuclear Support Specialist P. F. Mckee Tech. Services Superintendent G. P. Beatty Plant Manager (CR-3)
W. P. Stewart Manager, Nuclear Operations E. M. Good.
Engineer (I/C)
R. E. Clauson Engineer (I/C)
W. E. Kemper Tech. Spec. Coordinator Consumers Power Co.
B.
Hamm Midland Project Babcock & Wilcox Co.
J. H. Taylor Manager, Licensing E. A. Womack Manager, Plant Design V. R. Roppel Simulator Instructor D. F. Hallman Manager, Plant Performance Svc.
R. W. Winks Plant Design Section D. H. Roy Engineering V. H. Day Translation B. A. Karrasch Engineering R. E. Ham Customer Service Babcock-Brown Boveri Reaktor B. L. Day B&W/BBR Liaison K. 0. Layer BBR Resident Engineer ACRS C.
Michelson Consultant P.
Tam Staff Engineer Oak Ridge National Laboratory J. L. Anderson I&C Herb Hill I&C page 2 0
ORGANIZATION NAME POSITION NRC (B&O Task Force) D. F. Ross Director T.
Novak Deputy Director C. J. Heltemes Leader, Project Management Group Z.
Rosztoczy Leader, Analysis Group P. R. Matthews Section Leader, Systems Group J.
Mazetis Section Leader, Systems Group F.
Ashe Systems Group L. B. Engle Project Manager - TMI-1 Restart R.
Audette Analysis Group B.
Siegel Systems Group
- 0. F. Thatcher Systems Group M. K. Rubin Systems Group W. T. LeFave Systems Group C. Y. Liang Systems Group P.
Norian Section Leader, Analysis Group B.
Sheron Analysis Group R. A. Capra B&W Project Manager NRC Staff N. K. Trehan Power Systems Branch' E. C. Marinos Rx. Sys. Standards Branch D. L. Basdekas Rx. Safety Research S.
Diab Rx. Safety Branch, DOR T. P. Speis Chief, Adv. Reactors Branch F.
Odar Analysis Branch J. P. Norberg Eng. Methodblogy Branch
- 0. P. Chopra Power Systems Branch R. M. Satterfield Chief, ICSB A.
Oxfurth ICSB D. R. Lasher L..
Beltrochi Lessons Learnea alr.. Force M.
Fairtile Oconee Project Manager/DOR S.
Lewis Staff Counsel/OELD C.
Nelson CR-3 Project Manager/DOR D. C. Dilanni TMI-1 Project Manager/DOR R.
Reid Chief, Operating Rx. Branch #4 G. P. Florentine Office of the Commission P. F. McKee IE Headquarters H. A. Wilber IE Headquarters
- 0.,R.
Quick IE Region II
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ENCLOSURE 5 page 3 bUCKE POWER COMPANY OCONEE NUCLEAR STATION INCIDENT TNVESTIGATION REPORT 08-860 & B-861 UNIT 1, TRIP #73 & #74 1.0 Introduction During the e4rly morning hours of June 11, 1979, Unit I was operating normally at 99* FP. At approximately 0333, the reactor tripped after both feedwater pumps tripped as a result of all six low pressure turbine intercept valves going closed.
The Station Manager and General Office representative were contacted at 0900 and 0850, June i2, 1979, respectively.
Incident Investigation Report Classification #7, Component Failure/
Malfunction.
During the subsequent trip recovery, Unit I went critical at 0730. At 0753 while at 1' FP, the reactor was manually tripped by Control Operator "A" due to OTSG levels below 15" according to ONS Directive 3.1.30 (OP).
(Enclosure 6.5).
The Station Manager and General Office representative were contacted at 0900 and 0850, June 12, 1979, respectively.
Incident Investigation Report Classification #4, Personnel Error.
2.0 Sequence of Events 0329:30 Low Pressure Turbine Intercept valves closed due to failed operational amplifier.
0333:03 Condensate Booster Pumps A, R. & C tripped on low suction pressure.
G333:04 Main feedwater pnmps, A & D, tripped on low suction pressure.
0333:04 Reactor and Lurbine-generatur trip.
0333:10 Emergency ieedk.,ater pumps
..11 three units starte;d.
0355:58 Emergency feedwter pumps stopped due to FDW pumps "TA" and "lB" at 750 lbs. discharge presrure.
(For a more detailed se n
of events in regard to this trip, see En, 1-jsnre 6.1.)
ENCLOSURE 5 page 4 hJR IJB86(j.&1-86]
0725 Reactor critiCal.
0752:04 "1B" FWPT tripped on high discharge pressure.
0753:00 Manual reactor trip by Control Operator "A".
% 1110 Reactor criticil.
% 1549 Generator on line.
3.0 Evaluation At approximately 0329 on June 11, 1979, a leaking electrolytic capacitor caused the operational amplifier (preamp) on the Intercept Valve (IV) amplifier board to fail.
When this operational amplifier failed, (see.2) it caused the output of the intercept valve amplifier to be ^ 0.4 V instead of the 5.0 -
5.1 V necessary to keep the intercept valves open. When the intercept amplifier failed to % 0.4 V, all six intercept valves (MS-115, 116, 119, 120, 123, 124) closed. The closing of the.intercept valves essentially cut off all steam to the low pressure tWVVhines.
The bypass valves, providing a high pressure relief when the turbine header pressure exceeds its setpoint by 50 psig, lifted to ap proximately 50% open for 15 seconds.
When the intercept valves closed, they also cut off extraction steam to the low pressure feedwater heaters.
E2 Heater Drain Pump tripped off due to loss of extraction steam.
This purmp proiides between 500 to 600 gpm additional feedwater flow.
When it tripped,.CEP (Conden:.at.
LIBooster Pump) "18" started to pick up the flow lont when E2 'DP tri p' After the intercept valves closed, steam to the Jo% pressure Lurt j;,-.
directed into the condenser. With all three condensate bcoster pa::
verating, the powdex was automatically bypassed due Lo high differt-i i
i erssure.
All three condensate booster pumps trippled approximatel n r mtes later on low suction pressure (% 16 psi ) as a result to pump more water from the hotwell than was available. Both fec..
pump turbines tripped on low suction pressure
(-
2 3 psig) a fe.
- -r.
ater.
When both feedwater pumps tripped,' the nw.: reactor trip cI: ii loss of both feedwater pumps or trubine trip,
'-k.70, tripped t1 ort.
Six seconds after the feedpumps tripped, al
- hree unit emet. I twater pumps started.
Both steam generators rv fed through ib -
ad IFDW-316, the Emergency Feedvater Hv.RaJer valf-.es, which autum.a opened to 60%.
Assistant Control Op.2ratror "1
' l k manual unt i both valves and maintained minimum level (
2L-) until both man.
.t pumps could be brought back up to '5c psig d::cha.ge pressurc.
L li* main feedwater pumps were reset. atn brought Lack up approximatel
- !nutes later, level decreased in both steam generators when the enhrency pumps stopped at 750 psig discharge pressure on main pumps.
OTSG !
1.. decreased to approximately 15" until discharge pie.sure was high enuu h to move water into the steam generators.
The
<'.y in re-estibl hi:.
.L u tefedwater flow was % 2 minutes after the emrgency pumps automatically stopped.
For actual data such as steam gen!irjtor startup levels see attached transient monitor plots (Trip #1, E~il:;re6.3).
ENCLOSURE 5 page 5 IP
'Ii-ftO & B-861 Page 3 At 0725 Unit I went critical after completion of the operational am plifier changeout on the IV amplifier.board by I&E. Main steam header pressure was approximately 1000 lbs.
EMPT "IB" was in manual. Control Operator "A" was throttling "1B",
complementing IFDW-35 and 1FDV-44, the ICS startup feedwater valves, which were maintaining minimum level in both steam generators.
As the (alves opened up, Control Operator "A" increased flow until valves started to close and then, he would cut back 6n flow. Bifferential pressure across the valves was approximately 35 lbs.
At 0751 levels started decreasing in bootsteam generators. Levels decreased below 25" in both steam generators. At 0752 FWPT "11" tripped on high discharge P sure (% 1250 psig). Since FWPT "IA" was reset and discharge oressurdecrpsed below 750 nai the reactor was not auto ma ically tripped by loss of pumps or low discharge pressure.
Control Operator "A" manually tripped the reactor when level drdpped below 15" according to ONS Directive 3.1.30. Control Operator "A" started FWPT "IA", but was unable to reestablish level with this pump.
FWPT "IB" was restarted and level was reestablished in both steam generators at 0754.
The emergency fteedwater system was never initiated due to the fact conditions.necessary for actuation were never reached. See transient rmojnitor data (Enclosure 6.b) for additional data.
4.0 Correct ive Action In regard to the first trip, there is no preventive maintenance that can be performed on line that would identify an electrical failure on the EHC system such as the operational amplifier failure.- There is a procedure issued 6/3/77, I?/0/B/280/15, Turbine Electro Hydraulic Control Spped, Load, and Flow Control Unit Calibration, which has never been run which would identify and correct control problems during an-outage.
- However, this prnteure would only identify components that have failed at the :-%.inning of the outage.
In reference to the Emergency Feedwater System
'operation after the first trip, Operations has submitted a chanie Lo F.P/O/A/1800/14, Loss of Steam Generator Feedwater Emergency Prozedure, to require putting the EFDW pump/turbine control switcn (!t--93) in run position after the auto start. This will prevent the 1 r of emergency feed water flow to the steim generators when rest.Vrtng the main feedwater pump. set E ccz&ote
- 4.
In regard to tht second trip control t -
h"& be advised to keep header pressure is low as possible durinz unit tartuo.
Four hours after the ILrst rip, needer p-essure sho:uld have been lower than 1000 lbs.
5.0 VerificaLion I&E tinician "A" 1isLt-Led the operationzl amplifier card on Unit 3 and checked the output -)f the circuit (% 0.4 V).
lie then replaced the leaking capacitor ind reinserted the card.
Output was 5.1 V which is vuoLage required Li Lvi' alves open.
ENCLOSURE 5 page 6 11R B-860 & B-861 6.0 Enclosures 6.1 Detailed Sequence of Events -
1st Trip 6.2 Schematic Diagram -
Intercept Valve Control System 6.3 Transient Data on Ist Trip 6.4 Letter from G. Ridgeway to Shift and Assistant Shift Supervisors, Operation of Emergency Feedwater System 6.5 Station Directive 3.1.30, Required Manual Trips of the Reactor 6.6 Transient Data on 2nd Trip 7.0 Safety Analysis The unit was safely shutdown and restarted.twice. The emergency feed water system performed its intended function during both trips.
No danger to the health or safety of the public was incurred. The loss of feedwater trip circuit performed its intended function.
George B. Beam GBB/bhd/2/1
9 L.P. Turbi.
Intercept Valves Closed
.1
.^..L....
Cn.trol Valves Closed.
Turbine bypass Valves Open C,0P cI 3:29:34 RC-1 (Pzr. Spray) Open 3:29:34 E2 H. D. Pump Off 3:29:42 Main Turbine Control Valves Open 3:29:44 C. B. Pump 3 On 3:29:47 RC-1 (Pzr. Spray) Closed 3:29:47 Powdex Bypass Open (D/P High) 3:39:04 FDWP "A" Suction Press Low 3400 3:30:04 H. D. Pump Disch Hdr Press Low 3520 3:30:15 Main Steam Press Low 805#
3:30:24 FDWP "B" Suction Pressure Low 343#
3:30:34 C. B. Pump Suction Press 760 3:30:34 H. S. Pressure 870#
3:30:31 H. D. Pump Disch Press Low 3580 3:31:06 C. B. Pump Suction Press.Low 47#.
3:31:16 FDWP Suct. Press Low 3420 3:31:29 D2 Htr. Drain Pump Off 3:32:04 FDWP A Suct. Press Low 325#
3:32:04 FDWP B Suct. Press Low 3321#
3:32:27 D1 Htr. Drain Pump Off 3:33:03 C. B. Pump A Off 3:33:03 C. B. Pump B Off 3:33:03 C. B. Pump C Off 3:33:04 FDWP A Tripped 3:33:04 FDTWP B Tripped 3:33:04 Reactor Trip 3:33:04 Turbine/Generator Trip
ENCLOSURE 5 page 8 3:33:06 C. E.
- B On 3:33:10 MS-93 Cn EFDW Pump Start 3:34:27 RP Ch A Trip -
Low Pressure 3:36:21 SG "B" S/U Level 23 Inches 3:36:40 MS Pressure A 10010 3:36:40 MS Pressure B 10050 3:37:05 RCS Pressure 19200 3:37:25 Pzr. Level 94 Inches 3:43:21 SG "3" S/U Level 29.5 Inches 3: 3:57 FDWP "B" Started 3: P:25 RC Pressure 21550 3:5:48 EFDWP Stopped C. B. Pup Low Suction Press Trip Is:
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ENCLOSURE 5 page 19 June 13, 1979 INTRASTATION LETTER 0CONEE NUCLAkR SIATION TO:
Shift Supervisors Assistant Shift Supervisors
SUBJECT:
Operation of Emergency Feedwater System File No.
OS-114.01 On June 11, 1979 Unit 01 tripped from 100% full power due to a loss of both main feedwater pumps.
All three units emergency feedwater pumps started (EFDW headers were interconnected) and valves IFDW-315 and 1FW-316 opened to 60%.
The reactor operator took manual control of 1FDW-315 and 1FDW-316 and throttled the valves closed to maintain minimum OTSG level. Valve positions of ^. 20% open were required to maintain the 25 inch minimum level. The emergency feedwater flow rate to each OTSG was 1 240 gpm at the 20% open valve position.
When the main feedwater pump was being restarted ("3" pump), the emergency feedwater pumps stopped when the main feedwater pump discharge pressure exceeded 750 psig. OTSG levels decreased to ".. 15 inches each before main feedwater pump discharge pressure was high enough to refill the OTSG's. The delayin-re-establishing main feedwater flow was v 2 minutes after the emergency pumps automatically stopped.
Changes have been made to the Loss of Steam Generator Feedwater Emergency Procedure (E?//A/1800/14) to require putting the EFDW pump/turbine control switch (MS-93) in run position after the auto start. This will prevent the loss of emergency feedwater flow to the steam generators when restarting the main feed'.ater pump.
MS-93 is returned to auto after main feedwater flow is re-e-:tablished.
Also, be aware that the emergency feedwater valves FDW-315 and FDW-316 must be manually throttled very soon after an EFDW initiation to prevent excessive cocldowrn of the RC System.
Please inform all licensed operators of these changes to E?/O/A/1800/14.
Document this by each licensed man, including supervision, initialing a copy of this letter and return it to me.
Georgy)A. Ridge 4
a Operating Engineer GAR/db CC:
J. N. Pope Backup Licensees
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ENCLOSURE 5 page 20 Oconee Nuclear Staticn Directive.
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Approval
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OriginaIl Date 2
Revised Date DUKE POWER COMPANY OCONEE.NUCLEAR STATION REQUIRED MALNJUAL.TRIPS OF THE REACTOR To prevent or to minimize pressure transients in the Reactor Coolant System, the Control Room Operator (RO) is to manually trip the reactor immediately when the following conditions occur:
- 1.
Turbine trip (when reactor power > 20% FP),
- 2.
Main Steam Stop Valve Closure (two on same OTSG or all four valves),
- 3.
- 4.
Low OTSG level (< 15 inches).
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DUKE PCER COMPANY OCONEE NUCLEAR STATION INCIDENT REPORT B-849 REACTOR TRIP ON HIGH PRESSURE DUE TO LOSS OF FEEDWATER CONTROL UNIT 2 TRIP #45 1.0 Introduction At 0344 on May 7, 1979, Unit 2 was at about 28% F.P. when the reactor tripped on high RC pressure.
Before.the transient began, the turbine was off line and power was being held at around 15%
F.P. for TT/O/A/325/01 (Emergency Feedwater Flow Test).
When the reactor tripped the test had not yet begun.
The Station Manager was notified at 1430 on May 7, 1979.
The General Office representative, S. R. Lewis was contacted at 0930 on May 7, 1979.
This incident is not reportable to the NRC.
The classification for this Tncident Investigation Report is 7.0, Component Failure/Malfunction.
2.0 Sequence of Events 5/7/79 0317 Generator off line.
0333 Operator A manually beginb to o.pen FDW-31 SG A Main Block Valve.
0335 Operator A minually begins t.* -'n FDW-40 SC B Main Block Valve.
0337 FDW-31 and FDW'-40 are fully open.
0341 Operator A niiiuilly begins rc lose FDW-40.
0343 FDW-40 is fully closed.
0344 Reactor = tripped on high pressure.
0431 Reactor is critical and increasing power for TT/O/A/325/01.
3.0 Evaluation The cause of this incident was the inabilicy to control feedwater flow to the steam generators.
This loss of control was ultimately
ENCLOSURE-.6-page 3 causcJ by excessive lenkaigv of feedwater past the seats on the main feed Cer control 'vvs, rL -32 and FL-41.
The main FDW block valves (FUW-31 and !U1--40) were designed to open and close automatically.
While in autCm.3tic, FDW-31 and FDW-40 open or close on a signal which is based on the positions of the startup FDW control valves (FDW-35 and FDW-44).
When the startup control valves get to 80% open, and opening, the main.FDW block valves open. Then the startup control valves get to 50% open, and closing, the main FDW block valves close.
If the main FDW control valves (downstream from the main block valves) leak past their seats, the opening and closing of the main block valves can cause large swings in total FDW flow.
The amount of swing depends on the amount of leakage.
In order to prevent these characteristic sWings in FDW flow which take place when the main blocks are left.in auto, Operator A manually blocked open FDW-31 and FDW-40.
Reactor power was at 18%
F.P.
Because of the excessive leakage past the seats on FDW-32 and FDW 41, the opening of the main blocks resulted in the overfeeding of both steam generators. The "B" steam generator was overfeeding more than the "A" steam generator (see transient monitor plots).
The ICS sensed decreasing RCS average temperature and ccmpensated by increasing core power.
The reactor power was increased from 18%
F.P. to 28% F.P. in about.seven minutes.
Even though FDW-41 was closed the leakage past its seat was great enough to make FDW-44 go closed.
Operator A then manually closed.
FDW-40. This sudden drop in FDW flow (decrease in heat removal rate from the core) resulted in a high RC pressure trip.
4.0 Corrective Action/Verification A priority 5B work request has been issued to make repairs on 2EDW 32 and 2FDW-41.
At the date of this report, 6/5/79, the work order was outstanding.
2FDW-32 and 2FDW-41 have had their stroke (length of travel) adjusted. This was done to insure these valves could complete l.
close.
The main FDW control valves leak past their seats on all three units. Because of the inability of the main FDW control valves to function. as designed, reactor operators are forced to take manual control of the main FDW blocks during startups and shutdowns.
ENCLOSURE 6 pag Also, the possibility of modifying the main FDW control valves thenselves should be considered.
5.0 Safety Analysis The RPS tripped the reactor at 2294 psig.
During the transient both steam generators maintained an adequate water inventory.
The health and safety of the public was not compromised.
6.0 Enclosures Transient Monitor Plots Rarold Woodall Junior Engineer 7 A W9/#
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ENCLOSURE 6 page 15 DUKE POWER COMPANY ZLEt NUCLEAR ST.'TION REACTOR TRIP ON HIGH PRESSURE DUE TO MALFUNCTION OF MAIN FDW BLOCK VALVE UNIT 2, TRIP #47.
1.0 Introduction, At 2046 hours0.0237 days <br />0.568 hours <br />0.00338 weeks <br />7.78503e-4 months <br /> on June 3, 1979, Unit 2 was at about 30% FP when the reactor tripped on a high RCS pressure signal.
The high RCS pressure was the re sult of a feedwater transient which was initiated by a malfunction of the "A" main block (FDtW-31).
The Station Manager was notified at 1330 hours0.0154 days <br />0.369 hours <br />0.0022 weeks <br />5.06065e-4 months <br /> on June 4, 1979.
The GCneral Office representative, R. L. Gill,.was con tacted at 1315 on June 4, 1979.
The incident is not reportahle to the NRC.
The classification for this incident investigation report is 7.0, Component Fail ure/Malfunction.
2.0 Sequence of Events June 3, 1979 17:44 Reactor critical. Main FDW blocks in auto.
19:46 Turbine.generator on line.
20:40 Shift Supervisor A, U.0. A and U.0. B go to location of FDW-31 and manually open the valve approximately one-half inch.
FDW transient begins.
20:42:06 RCS pressure is about 1975 psig and dropping.
Operator A takes FDW-32 from auto to manual and begins to manually close FDW-32.
20:42:40 RCS pressure has bottomed out and turns around at 1950 psig.
20:43:27 Operator B begins to onen FDW-31 (this was done using valve switch in control room).
20:43:55 Pressurizer begins to spray down (RCS pressure at 2205 psig).
20:44;56 FDW-31 is fully open.
20:45:4S Reactor trips on high RCS pressure signal at 2294 psig.
ENCLOSURE,6 page 1 21:10 Operators are unable to i control rod groups 1-4.
Shift Supervisor "A" issues a priority 1 work request (WR #41171).
June 4, 1979 03:39 Reactor critical.
04:15 R & R issued to "block" main FDW blocks shut.
05:5.5 Turbine generator on line.
06:25 R & R is cleared to "block" main FDW blocks shut. R & R issued to "block" main FDW blocks open.
3.0 Evaluation The failure of FDW-31 to open when FDW-35 (startup FDW control valve) reached the 80% open position was the cause of this incident.
Because FDW-31 was stuck shut, the ICS feedwater demand could not be satisfied.
The ICS opened FDW-35 and FDW-32 in an effort to get more feedwater flow in the "A" loop.
The transient monitor indicates that FDW-32 reached 100%
open at about 2027 and remained in that position until the transient began (see Figure 5).
When it was determined that FDW-31 had malfunctioned, Unit Supervisor "A" and Utility Operators "A" and "B" went to the turbine building to manually "crack" open FDW-31. FDW-32 was left in auto in order to let the ICS con trol feedwater flow.
After FDW-31 was cracked opun, the "A" steam generator began to fill and the RCS pressure began to decrease (see Figure 1).
Operator "A" then took FDW-32 into manual and began to close this valve. RCS pressure bottomed out at about 1950 psig.nd began to r.i= upward.
Operator "B" then manual ly opened FDW-31 using the control rocm switch. At 2205 psig, the pres surizer spray control vAlve began spra-.ing down the pressurizer in order to reduce RCS pressure. About two minutes after the pressurizer began to spray down the reactor tripped on a hiRh RCS pressure signal.
As mentioned in a previu'is trip report \\11-849), FDW-32 and FDW-41 leak past thoir seats.
Woi m:,t LhiS aJ !
fact that FDW-31 and FDW-40 follow the startup control valves (UD.-35 and FDW-44),
large feedwater swings can take pldce at abouc 15% FT if the main blocks (FDW-31 and FDW-40) are lI Q.
in auto.
TL, opratvors were r.(Uired by OP/l/A/1106/06 to place FDW-31 and FDU'-40 in auto during the startup on June 3, 1979.
Although the cause of this trip wais ar equipment malfunction, this investigator feels that OP/1IA/1106 should b2 modified to let operators place FDW-31 and FDW-40 in manual as required to maintain feedwater flow stability.
ENCLOSUIE 6-page 17 When the unit was brogiht back on line after the trip, the transition from startup feedwater valve control to main feedwater valve control was achieved by firs-t manually blocking FDW-31 and FDW-40 shut, and then blocking these valves in the open position (since both FDW-32 and FDW-41 leak past their seats, this is the preferred method for making the transi tion in feedwater control).
4.0 Corrective Action/Verification The KllB auto/manual relay on the control rod drive was replaced. This corrected the control rod malfunction.
A work requestrwas not issued to investigate the malfunction of FDW-31 since this valve can't be tested at power operation.
The next time Unit 2 comes down for an outaee, the malfunctiorAhould be investigated and corrected. It is recommended that Operations generate a work request to do this.
OP//A/1106/06 should he modified to give ooerators the option of placing F D.- I1 mr4 11"-4L) in manual during starrtuns. In order to prevenL Ih ieed water swings which are characteristic of auto operation.
5.0 Safety Analysis The-RPS tripped the reactor at 2294 psig. During this transient, there was not.a loss of'feedwater and the steam generators maintained sufficient water inventory. The health and safety of the public was not comptromised.
6.0 Enclosures Transient Monitor Plots.
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ENCLOSURE 8 LOSS OF PRESSURIZER LEVEL MDiCATION IN B&W PLANft L C ~~TENTS A
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DTSCUSSION OF E'.ENTS THAT RES ULT" 3 0 ERATVNG RITOY 3.2 Events that Produced Loss of Level radicatton 3,2 Operator Response to Loss of Level Indication 22 Followup Actions Taken by Licensees 4.0 A,"ALYSES OF LIMITING EVENT 4,1 FSAR - Type Analyses 4,2 Effect of Operator Actions to Terminate Loss of Level Indication 4,2,1 Options 4,2.2, Discussion 5,0 OPERATOR TRAINING 6,0 PROS AND CONS OF AVOIDING LOS OF INDIMAti 7,c 0MOCLUSION