ML19210C968
| ML19210C968 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 11/15/1979 |
| From: | WESTINGHOUSE ELECTRIC COMPANY, DIV OF CBS CORP. |
| To: | |
| Shared Package | |
| ML19210C964 | List: |
| References | |
| NUDOCS 7911200379 | |
| Download: ML19210C968 (10) | |
Text
{{#Wiki_filter:*: *. WESTINGHOUSE EVALUATION OF LICENSEE INCIDENT Operating Plant - North Anna Unit 1 Operating Utility - VEPC0 Date of Incident - September 25, 1979 INTRODUCTION The North Anna Unit 1 plant is located in Virginia and began comercial operation June 6, 1978. It is a three-loop 2775 MWt PWR of Westinghouse Design. The event of interest is a turbine trip followed by a stuck-open steam dump valve which caused safety injection initiation. I. DESCRIPTION OF INCIDENT The description of the incident is taken from interviews with VEPC0 operating personnel and management, from review of plant records, and from the VEPC0 Licensee Event Report, No. LER 79-128/01T-0, a copy of which is Appendix A of this report. A. Plant Operating Conditions The plant was operating at 78% power in order to extend the life of the first core loading. Core average burnup was approaching 15,900 MWD /MTU. Boron concentration was 4 ppm, and one charging pump was operating under normal pressurizer' level control to balance the maximum letdown capacity of 125 GPM. Pressurizer heaters were manually set at full power to force pressurizer spray under automatic pressure control, in order to keep the pressurizer boron concentration in equilibrium with the reactor coolant system. The reactor coolant average temperature was about 30F below normal at 78% power. Pressurizer and steam generator water levels were normal. Two of the three main feedwater pumps were operating. The block valve on one of the two pressurizer power-operated relief valves was closed to prevent leakage. B. Sequence of Events The following description is sumarized, along with the timing and the source of the timing information, in Appendix B. Copies of control room recorder charts are shown in Appendix C, fol-lowed by some plots made from plant computer printouts.
- 1. Initiating Sequence At 0544 on 9/25/79 a low pressure feedwater heater drain cooler dump valve began to cycle. This cycling was believed to be due to tube leakage inside the drain cooler. Subse-quent examination has shown that a total of twelve tubes in
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the drain cooler were leaking. The leakage exceeded the capability of the drain valves, causing the extraction steam condensate level to rise into the heater to the turbine trip setpoint. At 46 seconds past 0609 turbine trip occurred. Turbine trip immediately caused a reactor trip, and also tripped open the eight condenser steam dump valves to the full-open posi-tion. As the valves modulated closed the first time, an operator noted from the valve position indicators that one valve had stuck in the full-open position. A man went immediately to see whether any manual action could be taken to close that valve. When it was found that the valve could not be closed, closing of the non-return valves in the main steam lines (a 3 minute process) was started. (The steam-line isolation valves were manually tripped at 0616.) Later disassembly and evaluation of the stuck steam dump valve showed that the valve had overtravelled when it opened. Instead of stroking the design stroke of 2-3/4 inches, the valve had stroked 3-1/8 inches. The overtravel caused the valve plug to wedge into a 15 degree taper at the top of the valve balancing cylinder. The wedging force was greater than the valve operator closing spring force so the valve remained open after it was signaled to close. In addition, when the valve overtravelled and wedged open, the maximum specified allowable flowrate through the valve could haye been exceeded. Instead of limiting flow to 1.02 x 10D lb/hr. steam at 1100 psia inlet the valve would have permitted a flowrate of pressure 1.29 x 10 $ lb/hr. at 1100 psia while it was open. Meanwhile, steam generator water levels fell as a normal result of the turbine trip, and the low-low level setpoint was reached and all three auxiliary feedwater pumps were automatically started between 8 and 12 seconds after turbine trip. About 1 minute later, one main feedwater pump was manually turned off, and the main feed control valves were closed automatically by the combination of low RCS tempera-ture and reactor trip. (The other main feed pump was tripped by SI initiation 5 minutes after turbine trip.)
- 2. Initiation of Safety Injection The steam dump control system closed the seven controllable dump valves for the last time less than a minute after turbine trip. Continued cooling of the primary system by steam flow through the stuck valve and by auxiliary feed-water caused a continued lowering of the pressurizer water level and pressure. Low pressurizer level caused automatic
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letdown isolation within two minutes. Low p-essurizer pres-sure initiated safety injection five minutes after turbine trip, at 0614:45. The resulting start of a second charging pump and redirection of flow through the safety injection path immediately started raising pressurizer water level and pressure. (Subsequent calculations indicated that although the water level dropped below the bottom tap of the level indicator, the pressurizer and surge line did not empty.) Between one and two minutes after safety injection initia-tion the main steamline isolation valves were manually tripped closed, terminating the steam flow through the stuck dump valve. All reactor coolant pumps were manually tripped, as is required by North Anna procedures following safety injection on low pressure.
- 3. Control of Primary and Secondary Systems At 0619, four minutes af ter initiation of safety injection, the pressurizer level and pressure had returned approxi-mately to their normal values and one of the two high-head charging pumps was turned off. After another minute the pressurizer power-cperated relief valves started cycling to hold the pressure near 2335 psig.
A check was made of reactor coolant pump conditions with the thought of starting them to restore pressurizer spray, to achieve uniform mixing in the primary system, and to stabi-lize primary system conditions. Pumps A and C had lost their seal leakoff indications following the SI signal, preventing them from being started. RC pump B, which is not on a loop with the pressurizer surge line or a spray line, was started at 0629 to achieve coolant mixing. Letdown was initiated at 0627; however the flowrate cannot be determined since the orifice alignment and the effects of possible flashing (without charging through the regenerative heat exchanger) are unknown. By 0635 the charging system had been realigned to charge through the normal path instead of through the Boron Injection Tank. Charging flow was throttled to about 20 GPM, the auxiliary spray valve was opened, and letdown increased to the maximum. At 0637, the PORV stopped cycling, and pressurizer pressure and water let :1 started to decrease. The peak indicated water level rc 9ed was about 73% of span, and the total mass of steam reb >ased through the PORV was later calculated to be less than 3500 lb. Auxiliary feedwater pumps had brought the steam generator water levels well up into the narrow renge span by 0625. At that time one main feed pump was restarted and the auxiliary 063 3
pumps were secured. Feed flows were held to a low rate until 0631, when they were increased to bring indicated levels up to normal at about 0636. Then flows were throttled down, and again throttled to no flow at 0647 to 0650. Jold leg temperature reached a minimum of 4730F at 0627, following termination of auxiliary feed flow. After the RCP was started at 0629 and main feed was throttled at 0636, reactor coolant and secondary side temperatures were slowly increased by decay heat until they reached normal two hours after turbine trip. At 0646, about 36 minutes after turbine trip, volume' control tank high level and high pressure alarms were actuated, for reasons discussed in the next section. As a result, letdown flow was first reduced, and then temporarily stopped at 0659. Pressurizer water level and pressure increased and the PORV again was cycled from about 0701 until letdown was restored at 0705. Pressure continued to be sensitive to level changes until about 0820, when the pressurizer heaters finally brought the water in the pressurizer up to saturation temperature.
-Before Qout 0820, operators noted poor pressure control, similar to what would be expected with noncondensible gas in the pressurizer. After that time the pressure was held near normal while the pressurizer water level was gradually reduced to normal over the next hour. Subsequent analysis of a pressurizer steam space sample did not show unusual gas concentration, and the poor pressure control is attributed to lack of normal spray and pressurizer water subcooling.
During the cooldown transient the hot leg temperature went from an initial 5900F to a minimum indicated value of 4820F in 22 minutes. As a result of the primary system cooldown (greater than 1000F/hr normal cooldown rate) Westinghouse was requested to evaluate the effect of the cooldown on reactor vessel integrity. The cooldown was determined not to have any adverse impact on this reactor vessel.
- 4. Volume Control Tank Overflow When normal letdown was established, the operating charging pump was not aligned to take suction from the VCT and'was instead still aligned to the RWST. As a result, the VCT level increased so that the VCT level control valve began diverting water to tN Boron Recovery System (BRS) via the gas stripper. An upset in the gas stripper resulted in the closing of the inlet trip valve to the stripper due to high stripper level.
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With the VCT level control valve fully diverted to the BRS, the closing of the stripper trip valve blocked letdown. This caused the lower pressure letdown relief valve to lift (setpoint 200 psig) discharging water directly to the VCT. At 0646, about 36 minutes after the turbine trip, the VCT high pressure and level alarms were actuated and shortly afterwards the relief valve lif ted (setpoint 75 psig). This relief valve discharged to the High Level Liquid Waste Tank (HLLWT); initially a mixture of H2 and radioactive gases were discharged, followed by water as the VCT became water solid. The HLLWT has a vent to the plant process vent which would have released the noble gases to the environment through a charcoal filter. However, the HLLWT vent line had a dis-connected flange which allowed the radioactive gases to leak into the auxiliary building. The noble gases were ulti-mately discharged to the environment via the plant charcoal and HEPA filters and the plant vent so that offsite doses were similar to those which would have resulted from a normal HLLWT vent line configuration. Even if the HLLWT vent had been connected, some gases might have escaped into the auxiliary building. The input from the VCT relief valve could cause the HLLWT pressure to rise slightly because of the limited vent capacity, causing radioactive gases to be vented to the Low Level Liquid Waste Tanks out into the auxiliary building through its overflow line. The airborne activity levels in the auxiliary building dur-ing the first three hours following the plant trip were up to 156 times MPC. As a result access to these areas was restric ted. Had a worker been exposed to these activity levels for the full 3 hours the dose would have been signif-icantly less than the quarterly limit. Af ter the first 3 hours restricted access was not necessary as the airborne activity was below MPC. See VEPC0 LER ( Appendix A of this report) for additional information on the auxiliary building radiation levels.
- 5. Reactor Coolant Pump Seal Leakage The indicated seal leakoff from Reactor Coolant Pumps A and C dropped to zero sometime following the plant trip. Based on subsequent inspection of the seals in pump C.the following sequence has been derived.
The seal leakoff was normal prior to the plant trip although that from pump C was low. The SI signal generated a con-tainment isolation signal which isolated the seal leakoff 4 ~i / i Q()5 5
line at the containment. This did not block the seal leak-off path because of a relief valve (setpoint 150 psig) located inside the containment. Inspection of the flo.1 seal indicated that it was leaking at its normal rate. However, the No. 2 seal was found to be worn, which together with the increased backpressure, indicates that the No.1 seal leakage was probably redirected through the flo. 2 seal. This increased flo. 2 seal leakage may have increased the leakage through the flo. 3 seal and contributed to a Hi-Hi air particulate alarm in the containment. C. Environmental Impact VEPC0 has determined that there was a noble gas release from the auxiliary building at less than 0.05 percent of the release rate limit allowed by the Technical Specifications. fio radiation exposures above background were observed in the 14 downwind TLD's on the perin1eter fence. 4 7/' Ol]I] 6
II. Evaluation of Sensitivities This section presents a general discussion of the transient in comparison with FSAR analysis of a similar event, and also dis-cusses briefly the effects of possible alternative operating procedures. Accidental depressurization of the mai: steam system is classified in the FSAR as a Condition II fault, tha is, a fault of moderate frequency. The specific challenge presented by such an event is whether the reactor would, because of the associated primary system cooldown, go critical and experience DN3 and possible fuel damage. The case which bounds the consequences of such an event is the spurious opening of a steam dump valve. The nature of the September 25 event was much less severe than the transient shown in the FSAR, since the FSAR analysis includes highly conservative assumptions which were not present in the September 25 event. Significant differences include the following:
- 1. Initial TAVG = 5700F, vs. hot no-load condition. This provided additional stored energy, most of which was dissi-pated by the controlled steam dump operation which brought TAVG to the no-load value.
- 2. Initial power = 78%, vs. no-load in the FSAR. Thus decay heat was available to reduce the cooldown rate and heat the plant after cooldown was terminated.
- 3. Automatic feedline isolation, not assumed in the FSAR. This tended to make the rate of cooldown less rapid than in the FSAR.
- 4. Manual main steamline isolation, not assumed in the FSAR.
This ended the plant cooldown.
- 5. Two high-head charging pumps on SI, vs. one (worst single failure assumption) in the FSAR. This, together with the termination of the cooldown and decay heat, induced a rapid repressurizatian, as opposed to the extended decrease in pressure shown in the FSAR.
In both cases safety injection was initiated when the cooldown had adequately reduced pressurizer pressure, and was sufficient to prevent the reactor from returning to a critical condition. Therefore, in both the FSAR case and the actual incident, DNB was precluded. Emergency operating instructions in effect at the time of the event required the operators to trip off all reactor coolant pumps immediately following safety injection initiation due to low pres-surizer pressure. If, instead, the procedure called for tripping the pumps only af ter a lower reactor coolant pressure had been 4 ?/1 Q {' 7
reached, the RCP's would have been left running. The principle effect of this difference would have been that pressurizer spray would have been available under automatic control throughout the transient. The spray capacity would be more than adequate to pre-vent the pressure from rising to the pressurizer power-operated relief valve control setpoint, and thus, PORV's would not have opened at all. Following termination of safety injection, pressure control below the PORV setpoint pressure would be by charging and spray, rather than by charging, auxiliary spray, and letdown. Thus, the necessity for the operator to letdown either to reduce pressure or to provide tempering of auxiliary spray would not be present; letdown could be controlled as required for pressurizer level control and as dictated by conditions in the volume control system. Another area under current discussion is the appropriate criteria for termination of safety injection flow. The procedures in effect required SI to be terminated no sooner than 20 minutes af ter initi-ation unless overpressurization (pressure approaching the safety valve setpoint of 2485 psig) was imminent. An alternate procedure which has been proposed would, in this case, permit SI termination when the indicated RCS pressure goes above 2000 psi, the steam generator water levels show that the U-tubes in at least one steam generator are clearly covered, and the indicated pressurizer water level is above 50%. In this event the RCS pressure reached 2000 psi about three minutes after SI actuation; the narrow-range steam generator level signals gave unambiguous non-zero indications eight minutes after the PORV's started cycling; and the pressurizer level reached 50% fourteen minutes af ter SI actuation and eight minutes after PORV cycling started. Again, with reactor coolant pumps operating, pressurizer spray would prevent PORV opening. 4 7 /; ()lg P; 8
III. RECOMMENDATIONS A. Steam Dump Valve Failure The incident of a valve overtravelling and wedging open has the potential to occur in all plants which ave the Copes Vulcan Valve, Model D-100, with second generation tandem trim. All plants for which this valve has been supplied by Westinghouse will be notified and instructed how to adjust the valves to prevent such an occurrence. B. RCP and SI Termination Procedures Westinghouse recommendations concerning instructions for termi-nating reactor coolant pump and safety injection operation following events which actuate safety injection have previously been discussed with the Westinghouse Owrers Group. These recom-mendations are being reviewed to determine whether any changes should be made. These procedures are also presently being discussed with the NRC. C. Spray With One RCP Current Westinghouse reference operating instructions state that with only one RCP operating spray is available only when that RCP is on the loop having the pressurizer surge line. This is because the static pressure in the active-loop hot leg is lower than in the inactive hot legs, mainly due to the high velocity head in that loop. It is recommended that plant operating instructions consider this situation. D. Auxiliary Spray /Subcooled Pressure Control Operating procedures should recognize the differences in pres-surizer operating characteristics when pressurizer water is subcooled. For rapid pressure reductions during normal opera-tion, flashing of saturated pressurizer liquid is the dominant mechanism slowing the rate of pressure decrease. For longer-term recovery (over tens of minutes), pressure is restored by boiling saturated liquid with pressurizer heaters. If the pres-surizer liquid is subcooled, neither of these mechanisms exists, pressure drops rapidly as pressurizer water level decreases, expanding the steam bubble. Therefore, under these conditions, maximum pressurizer heaters should be energized, and pressurizer liquid temperature monitored, until saturated conditions are restored. Similarly, pressurizer spray normally controls pressure increases. Without spray, an increase in pressurizer level compresses the steam bubble into the superheat range with a 3 ;/' 069 9
relatively large pressure increase. The pressure characteristic is similar to compressing a non-condensible gas. Auxiliary spray may be used to mitigate pressure increases, but will not be as effective as the much higher flow rate obtainable with normal pressurizer spray. The preferred ncde of auxiliary spray operation is to use letdown flow in order to minimize thermal shocks. To achieve sufficient spray flow the charging line isolation valve to the cold leg should be closed, the auxiliary spray valve opened, and the charging line flow control valve used as necessary to control spray. E. Letdown Initiation After SI Actuation Each utility should review its policy and procedures for reset-ting containment isolation, and restoring normal letdown, following an automatic containment isolation signal. In partic-ular, are exis' ng radiation monitoring or sampling practices believed adequate to preclude significant contamiratio n of auxiliary systems or atmospheric release in the ( nt that reactor coolant activity increased significantly during whatever transient actuated containment isolation? (Note: According to NUREG-0600, the principal pathway for radioactive release to the environment from the TMI-2 accident was "through the makeup and purification system".) 1 7/1 n -- U/- 10
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APPEllDIX A October 9, 1979 "r. Jm s .". C'?cilly. nirector f.ertal W. 32") Office of Inspection i.nd Enforce-+nt F0/?:C:bxu . t' . S. .';uclear Re tulatory Cer=ission Docke t No. 30--33' Pegion II 101 Parietta Street, Suite 3100 Licenst !!o. !!PF-4 Atlanta. Ceor;;ia 30303 C#ar ."r. O'Feilly: OJ. .- Pursuar t to '* orth Anna Powvr Station echnical Specifications, the Virr, inia Electric and ?cver Cc=;:4ny hereby suk_its the fot.lovin:: I.ieen_ce Event Feport O f or Torth Anna Unit *!o.1. report.ra. Applicable Technica1 Specificatiens O L3.R 77-123/01*-O T. O. 6.9. I .S .I .
~hin report has been reviewed by thr= :;t-1 tion ruclear ';afety and Operatinr.
% comit tee and will be placed on th.= a.o.anda for tho next nesting of the Svatem ::uclear % fety and rporatine cce.nittn .
Yr ry truly yours,
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\\ Vice "renident-70 er Supply
\*/ -nd Production Crerations ll ,
j Inclosures (3 copies) cc: *t. Victor Stello, Director (40 copies) Office of Inspection an.1 Enforcerent "r. Villian fi. "cDonald, Director f copies) Of fice of ?fana;;c: ent Infornation ::nd TYogran Contrnf bc: Mr. W. L. Proffitt ifr. C. !!. Stallings fir. W. C. Daley Mr. B. R. Sylvia Mr. J. A. Ahladas Mr. U. L. Stewart Mr. E. A. Baun Mr. J. L. Perkins ?fr. P. R. Beanent(8)
!!r. C. A. Olson-EEI Ifr. R. M. Taylor lir. A. L. Hogy,-N. Anna Ifr. M. U. Stubbs Ifr. D. U. Speidell, Jr. Mr. ". R. Cart.rcight(2)
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] At 0614 a Safety In_4ection Occurred dua to n T w v'vacevir* n- Toua enh -W t I O 2 O ;3 l vith low pressuricar prassure. 'Ihis event in a 2I. hour repore nblo or-ner - o v p_v I I
lo141) req. guide 1.16 and as per T.S. 6.9.1.8.i. Follettf ar tb mee- n r,A4,* ire -M o e n . I O s Icecurred which was less than 0.03% of the iT'stantsceous relenna rato -r F 'F 9 - Boundarv radiarien detectors *we enT y h,rhe~na -,ai me-is y u I o e i2.2.3.a. O 7 l therefore at no tir:e 19ts the health and qfety of the canaval rnh11e nFrarted_ I O n l 50 7 8 9 SY3TEu CAUSY CAL.53 COMP. VALVE CDDi. CCDE SUSCCDE COV'ONENT COCE SUSCODE SUDCCOE 7 o 9 8 I s t r I@ LE_l@ O @ I v l ^ I r. i r i v i x l8 [3_J@ [3_1 9 10 11 12 13 13 19 20 SEQUENTIAL OCCURRENCE RE PO81T REVISION EVENT YEAR REPCMT NO: CODE TYPE . N O. L a
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27 10 11 l 23 29 b' 3a L--J 31 Lo_] 32 EFFECT EHUTDCwN AT*ACNVENT NP R O-4 PRIME CCMP. CouPCNENT ACTION FUTURE MANUFACTUR ER TAKEN ACTION ON PLANT METHOD HOURS SUSvnTED FORM 5Ua. SUPPLIE A l33I]gl34 Xl@ l Alg 05 C l35l@ [0 p l0 31 40 l lYl@ 41 lNl@ 42 [A_j@ 43 ICl6l3l5_h 44 47 CAUSE OESCRIPTION AND CORRECTIVE ACTIONS h _ i 0 {'Ibe cause of the SI was steam dt==o valve TC7-140SG <: tuck onen follmr w n ~a-n- 1 I g } trip, which depressuri::ed the reactor coolant nvs t m . Cor ectiva --ti m & -a en g } return the plant to stable conditions by the control roo-1 oneratorn nnd la ~ l
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Virginia Electric and Power Company ; North Anna Power Station, Unit #1
Attachment:
Page 1 oE 5 Docket No. 50-333 Report No. LER 79-123/01T-0 . Description of Event: At 0544 on 9/25/79 with reactor power at 78%, the fif th point heater drain cooler du=p valve LCV-SD-182B began to cycle. This cycling was believed to be due to a tube rupture inside the 5B drain cooler. The leakage was note than the capability of the drain valves causing extraction steam condensate to back up into the 5th point heater to the turbine trip setpoint. . At 0609, a turbine trip occurred and resulted in a reactor trip. At this time the main steam dump valves opened to reduce RCS temperature to 547'F. When the RCS temperature decreased below the steam dump setpoint, steam du:np valve TCV-140BG failed to close. The steam dump valve was_ then isolated by closing the main steam trip valves. Excessive cooldown caused by the open stean dump valve resulted in an RCS depressurization and a resultant Pressurizer Lo Pressure signal. This signal, combined with the administrative 1y tripped Pressurizer Lo Level signal, ini-tinted a safety injection of the E=ergency Core Cooling System. This event occurred at 0614. The RCP's were ic=ediately manually tripped as required. As a result of the safety injection and the ternination of the cooldown, the RCS pressure began to increase. One of two SI charging pumps was secured at 0619. At 0620, the pressurizer pow r operated relief valve began to cycle and main-tained pressure at 2335 psig until normal letdown and charging were estab-lished. When nor=al letdown was established, the recaining charging pump was still drawing suction from the RWST. This resulted in an increasing level within. the Volume Control Tank (VCT) such that the VCT Icvel control valve (LCV-1115A) began to modulate to divert reactor coolant letdown to the Boron Recovery System via the gas stripper. The high flow to the stripper resulted in the inlet trip valve to the stripper closing due to high stripper level. At this time, LCV-1115A was fully diverted to the gas stripper; however, the inlet control valve to the stripper (TV-BRillA) was closed. The pressure in the letdevn line increased to the low pressure letdown line relief valve (RV-1209) (setpoint of 200 psig. This valve discharged directly to the VCT. The VCT pressure increased to the VCT relief valve (RV-1257) setpoint of 75 psig. This valve discharged letdown water and gases directly to the High Level Liquid Waste Tank (ELLWT). The nortal action at this point would be the release of noble gases from the HLLWT through a vent line and through the plant process vents. In a point in the vent line a flange had been disconnected and the noble gases were released into the auxiliary building. The gases were then vented through the plant charcoal and HEPA filters and out of the plant ventilation vents. Had the flange not been disconnected, a release of noble gases to the auxiliary building may have occurred. The discharge rate of VCT reactor coolant to the HLLWT may have been too much to pass through the norcal vent line, therefore the reactor coolant gases would have vented to the Low Level Liquid Waste Tanks and out into the auxiliary building via the Low Level Liquid Waste Tank overflow line. A-3 4 73' 073
Attachment Page 2 of 5 The following ic cubmitted as additional infensation. h release mn well within the Environmental Technical Specifications limit. AUXILIARY BUILDIliG AIRBORIiE ACTIVITIES 09 /25/79 TIME ELEVATION EXPLANATION 0700 274' 100.9 6* Times MPC. Principle Nuclei involved were Ie 133 & 135 with some Kr 85 and Rb 88. 259' . 155.68* Times MPC. Principle Nuclei involved were Ze 133 & 135 with some Kr 85 and Rb 88. 0800 274' 1.12* Times MPC. Principle Nuclei involved vere Ie 133 & 135 with traces of Rb 88. 0900 259 6.01* Times MPC. Principle Nuclei involved were Ie 133 & 135 with traces of Rb 88. 1000 259' O.68* Times MPC. Principle Nuclei involved were Ze 133.6 135 vith traces of Rb 88. 1030 259 ' Less than 0.1 times MFC. Principle Nuclei involved was Rb 88._All readings af ter 1030 vere less than 0.1 times MPC.
*This value represents the total subeersion hazar' involved with the total of all Nuclei.
Perimeter TLD's were pulled and evaluated. No radiation exposures above background were observed in the 14 TLD's in the downwind direction on the perimeter fence. Total Noble gas releases from ventilation vents A and B and the process vent amounted to 4.7E-02% of the release rate limit of noble gases. During this event, several other events occurred which are contrary to Technien1 Specifications. Af ter the turbine trip, a turbine reheat valve failed to close which is contrary to T.S. 3.7.1.8. The action statecent was entered and the turbine was isolated from the main steam supply. When the main steam du=p valve failed to close, an RCS cooldown of 110*F in 30 minutes occurred. 'Ihis event is contrary to T.S. 3.4.9.1.b. The RCS temperature was restored to within the T.S. limits by closing the main steam trip valves. n I '- s * ! (. O i 'i A-4
Attachment Page 3 of 5 Upon receiving the SI signal, the control room bot tled air system failed to initiate as required by T.S. 3.7.7.1. The Action Statement requirements were cet by cooling down to the cold shutdown mode. As a result of the safety injection, the Eoron Injection Tank was lef t containing 2000 pp= borated water instead of 20,000 ppa borated water as required by T. S. 3.5.4.1 and the Ecergency condensate Tank was de-pleted less than 110,000 gallons by the Auxiliary Feedwater Pumps which is contrary to T.S. 3.7.1.3. The appropriate Action Statements of these events were entered. Although not reportable, a Hi Hi air particulate alarn in the Contain-
/
cent occurred. This is believed to be due to leakage by the #3 seals from the secured RCP's. The ECCS actuation is reportable as per T.S. 3.5.2 which requires a 90 day report, Reg. Guide 1.16 requires a 24 hour notice and written follow . up as per T.S. 6.9 .1.8.f. This is the third ECCS actuation reportable as per T.S. 6.9.1.b. This event is generic to Unit #2 since it uses the same type of steam dump valves. Probable Consequences of Occurrences: The purpose of the Emergency Core Cooling System is to ensure adequate cooling of the reactor in.the event of a loss of coolant accident. Since the ECCS actuated as required and at no ti=e was the reactor in danger of being undercooled, the safe operation of the plant was not affected. Also, since the radiation release was well within the limits of the Tech-nical Specifications at no time was the health and safety of the general public affected. Cause of 0::currence: The cause of the intial reactor trip was a turbine trip'due to a El Level in the 53 feedwater heater. The resulting RCS cooldown of 110*F and depressurization was due to a steam de=p valve failing to close. The reason for the valve failure is currently being investigated by Vepco, Westinghouse and Copes-Vulcan. The cause of the Reheat Stop valve failing to close is unknown at this time and will be investigated by Vepco a,d Westinghouse during a turbine inspection. The low level of the ECST and the underboration of the BIT are results of the safety injection. The safety injection pumps draw suction from the RWST and pump through the BIT leaving 2000 ppa borated water in the BIT. The ECST level was lowered by the Auxiliary feedwater pucps feeding water to the steaa generators. A-5 4 7g3 qe'/q-
Attachment page 4 of S The failure of the control room bottled air syster; was the result of an apparent pressure shock to the Bourdon tubes in the discharge of pressure controller of the system. This pressure chock deformed the tubes leaving them inoperable. The release of radioactive nobic gases was due to the automatic shutdown of the gas stripper and the continued letdown of the reactor coolant uhile the VCT was not supplying cakeup to the reactor coolant system. The overfilling of the VCT occurred during the time operations personnel were regaining RCS pressure control while still caintaining the required high head safety injection flow to the RCS. The transition from the safety injection riode to the normal charging mode of operation was made 14 a slow and cautious manner so as not to overpressurize the RCS. This evo14 tion resulted in overfilling the VCT and the resultant release of radioactive gases. Immediate Corrective Actions: Upon actuation of the automatic reactor trip, the operators perforced the required i= mediate corrective actions of the emergency procedures. After the cain steam dump valve failed in the open position, the operators attempted to isolate the valve by manually closing a steam dump isolation valve. It was determined that closing the large valve would consume too much time, therefore, the dump valve was isolated by closing the main steam trip valves. Af ter the autecatic initiation of safe ty injection from low RCS pressure, the operators canually tripped the RCP's as required by procedures and began monitoring RCS parameters to ensure adequate core cooling. At approximately 0619 the operators secured one of two High Head Safety injection pumps and at approximately 0627 began to establish normal letdown. Af ter 20 minutes of cold leg injection, at approximately 0633, safety injection was secured. At this tita a RCP and a feedwater pump were in operation and the plant was determined to be stable. When a high level and pressure were noted in the VCT, operations personnel re-established the RCS letdown to the Boron Recovery System via the gas stripper. This alleviated the high pressure and level condition in the VCT and the relief valve closed ending the release of reactor coolant to the liquid vaste tank. The disconnected flange in the HLLUT vent line was reconnected.
~
The operators refilled the ECST as required by the appropriate action statements and began to cooldown the plant to the cold shutdown mode by following normal procedures. Following the 110*F cooldown of the RCS, Restinghouse was notified and they determined that there was no effect on the RCS fracture toughness properties. Scheduled Corrective Actions: During the current refueling outage, investigations into the failure of A-6 '2(' Ob
Attachment page 5 of 5 the main steam dump valve and the turbine reheat stop valve will be conducted by Vepco, Westinghouse and Copes Vulcan. An engineering review of the letdown divert to the boron recovery system vill be performed to determine if any improvenents raay be implemented to the present system. A design change vill be incorporated into the control room bottled air' system which will provide protection to the Ecurdon tubes from over-pressuris:stion. , A continued investigation into the effect of the transient on the plant is being performed by Vepco and Westinghouse. Also, Vepco and Westinghouse are reviewing the problem of #3 seal leakoff from secured RCP's. Actions Taken to Prevent Recurrence: Corrective actions to the main steam dturp valves and reheat stop valves will be performed when the results of the investigations are available. An engineering review into the problem of high flow in the High Level Liquid Waste Tank vent line will be undertaken- - Any lessons learned from Vepco and Westinghouse reviews of the transient will be inc.orporated into Vepco procedures and vill be forwarded to the Westinghouse Owners Group.
'M
- 077 A-7
APPEtlDIX B SEQUEf1CE OF EVEf1TS
SUMMARY
Table B lists significant events in sequence, and the sources for the timing listed. The time base is that indicated by the plant computer (Westinghouse P-250) printout. Clock times listed by the alarm type-writer (time source 4) are rounded down to the next lowest even minute. The timing sources are as follows:
- 1. P-250 Sequence of Events Record
- 2. P-250 Post-Trip Review
- 3. P-250 Post-Accident Analysis Log
- 4. Alarm Typewriter
- 5. Control room recorder charts (time scale 1 in./hr)
- 6. Operator interviews, 9/27/79
- 7. Discussions with operating staff, 9/28/79 4 7/' O'[ f)
B-1
TABLE B SEQUEllCE OF EVErlTS
SUMMARY
Clock Minutes Event Timing Time After Source Turbine Trip 0545 -25 LP FW heater drain dump va lve alarm 4 0609:46 0 :0 Turbine trip on high FW haater drain level 1 Reactor trip on turbine trip 1 Steam dump valves trip open 6 One dump valve stuck open 6 0609:54 0:08 All three auxiliary FW pumps start on 1, 4 S/G lo-lo level within 3 seconds 0611 1 One main feedwater pump tripped manually 4 0611:10 1:24 Main feedwater ficw goes to zero 2 0611:30 1:44 Letdown isolation on low pressurizer 1,4 pressure 0612 2 Volume Control Tank low level alarm 4 0614:45 4:59 Safety injection on low pressurizer 1,4 pressure 0615 5 Second main feedwater pump tripped 4 from SI 0616 6 Main steam stop-check valves tripped 5,4 closed manually 0616 6 All reactor coolant pumps turned off 4 manually 0617 7 Pressurizer level returned to 9% 4 0618 8 Pressurizer pressure 2160 psig 4 0619 9 One charging pump stopped manually 4 0620:30 10 :45 Pressurizer PORV starts cycling open 3 0625 15 One main feed pump started, auxiliary 3,7 feed stopped 0627 17 Letdown initiated 4 0629 19 Reactor coolant pump B started 4,3 B-2 1 7/1 Q79
. s TABLE B (Continued) 0634 24 First S/G level returns above normal 3 0635 25 Charging flow realigned to normal 4 0637 27 Pressurizer PORV stops cycling 3 0646 36 VCT high level alarm 4 0646 36 VCT high pressure alarm 4 0701 51 Pressurizer PORV opens, cycles about 5 4 minutes 0704 55 Bank of dump valves isolated, start 5,6 opening main steam valves bypass (next 40 minutes) 0716 42 Containment particulate lii-Hi 4 radiation alarm 1005 190 Pressurizer level at normal, Tavg and 5 pressure normal, S/G levels in manual control 0 >J O B-3
- + APPEtiDIX C GRAPHS OF TRANSIEtiT RESP 0fiSE A. CONTROL ROOM CHARTS, SCALE = 1 Ifi./HR
- a. flote that time scales are not exactly the same
- b. Where 2 or more signals are on the same chart, the time scales are offset. An attempt has been made to align the turbine trip time for the first or basic variable on each chart.
FIGURE C-1 Wide range S/G water level flarrow range S/G water levels also showing steam and feed flows FIGURE C-2 Steam header pressure Wide range hot leg temperatures Wide range cold leg temperatures Pree,surizer pressure (The compensated control oressure signal has been partially blanked out for clarity) Pressurizer water lever B. PLOTS FROM PLANT COMPUTER TYPED OUTPUT 0-3 Minutes: from post-trip review 9-47 Minutes: from post-accident analysis log Alarm events are also shown to the nearest minute FIGURE C-3 flarrow range steam generator water levels Wide range cold leg temperatures FIGURE C-4 RCS pressure Pressurizer water level C-1 1 7/1 Op1 vJi
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