ML20090F937

Rev 10 to Procedure E-1.4, Steam Generator Tube Rupture. W/Supporting Documentation Encl

ML20090F937
Person / Time
Site:	Ginna
Issue date:	03/13/1981
From:	ROCHESTER GAS & ELECTRIC CORP.
To:
Shared Package
ML20090B368	List: ML20090F937
References
FOIA-91-106 E-1.4, NUDOCS 9203110428
Download: ML20090F937 (40)

Text

{{#Wiki_filter:~ ~ Nlk l i ROCKESTER GAS AND ELECTRIC CORPORATION GINNA STATION CONTROLI.ED COPY NUMBER I PROCEDURE NO. E-1.4 REV. NO. 10 ~~~ S/C TUBE RUPTURE TECHNICAL REVIEW _ PORC 2/18/81 0c66 3-ll; ^ . [ QC REVIEW APPROVED FOR USE lHAf n. D TE FLANT SJN RINTENDENT QA / NON-QA CATAGORY 1.0 REVIIWED SY: THIS PROCEDURE C0tCAINS 18 PA0ES 106 PDR bdMSQhf b-3 metmA A

i, si E-1.6 1 E-1.4 S/G TUBE RUPTURE

1.0 SYMPTOMS

1.1 Refer to Section 1.0 of E-1.1. If not already performed. M 2.0 IMMEDIATE OPERATOR ACTIONS: 2.1 Refer to Section 2.0 of E-1.1. If not already performed. N$ 3.0 SUBSEQUENT ACTIONS: CAUTION: Do not rely upon S/G or Fressurizer level indication af ter any event where a high energy line break has occurred inside of containment. An erroneous level indication will be caused by reference leg heacup and possible boiling as a result of increased CV temperature and/or changes in S/G pressurizer pressures. Basis for this is shown in tables 1-4 and figures 1-4, attached. If S/G and pressurizer levels are maintained between 85% and 25% this will ensure an actual water level is present. Note: At a CV temperature of 300*F, CV pressure will be over $2 psig. The following tables show the ciaximum and minimum levels at h graduated levels of temperature during post accident conditions which will ensure an actual water level exists somewhere between the level caps. PRESSURIZER S/G (NARROW RANGE)- Min. Level Max. Level C.V. Min. Level Max. Level % of Span

of Span TEMPERATURE (*F)

% of Spar. % of Span 10% 85% 150 5% 95% 14% 85% 200 10% 95% 19% 85% 250 13% 95% 24% 85% 300 17% 95% 30% 85% 350 22% 95% 37% 85% 400 27% 95% CAUTION: The diesels should not be operated at idle or minimum load for extended periods of time. If the diesels are shut down, they should be prepared for restart.

.~.i s-4.*;4 NOTE: If at any time during the conduct of Steps 3.1 through 3.8 the faulted steam generator is positively identifiad, immediately g. proceed to Step 3.9. Following completion of this step, the b remainder of the recovery must be accomplished from the last g,g step of Steps 3.1 through 3.8 which had been completed prior to identifying the faulted steam generator. [ NOTE: Make arrangements to sample containment atmosphere and steam generators to identify presence of abnormal radioactivity. NOTE: The process variables referred to in this instruction are typically nonitored by more than one instrumentation channel, ,I The redundant channels should be checked for consistency while j I performing the steps of this Instruction. NOTE: The pressurizer water level indication should always be used in conjunction with other specified reactor coolant system indications to evalttate system conditions and to initiate manual operator actions. 3.1 Check both PORV's closed, and then verify open or open bothpt1t=0 isolation vslves MOV's_(515, 516) s# ~.. tJm w ** d 4pffc 3.2 4 Stop all reactor coolant pumps af ter the high head safety injection pump plc

• 8 operation has been verified and when the narrow range pressurizer pressure g[

is i 1715 psig. g g CAUT!DN M T reactor coolant pumps are stopped,'the-seal injection flow y# "~ should be maintained. NOTE: The conditions given above for stopping reactor coolant pu=ps should be continuously monitored through step 3.10 of this instruction. I 3.3 If of f site power and the condenser are available, open MSIV bypass valves gW and any closed main steam line isolation valves to provide a flovpath to pv the condenser dump valves to minimite steam release to the atmosphere. M 3.4 Establish power sources necessary to operate at least one 'ressurizer power operated relief valve, at least one steam generator power operated dg relief valve, and charging and letdown flowpaths by checking valve indicating lights, controllers etc. as these systems may be utilized during subsequent event recovery operations. NOTE: Ensure that containment isolation is maintained, i.e., not reset until such time as manual action is required on necessary process streams as symptoms of a LOCA may still exist at this time. S47 E 3.5 stabili:e the reactor coolant system at approximately no-loed temperature by steam dump to the main condenser if of fsite power and the condenser are j? available. If of f site power or the condenser is not available, utilize f[ the steam generator power operated relief valves to stabilize the reactor 3 4 gs coolant system at approximately no-load temperature. tr v 1

~. t-,1.*:a 3.6 Regulate the auxiliary feedwater flow to the steam generators to resto're and maintain steam generator water level to 25% in the narrow range span to assure that the U-tubes are covered. %-T gg e is above the low head safety injection 3.7 If reactor coolant system pre pump shut-off head and MOV825A or >cV825B are open, manually reset safety injection so that safeguards equipment can be controlled b/ manual action. Stop the RER pumps md place in the auto standby mode. CAUTION: If the recetor coolant system pressure decreases uncontrollably below the low head saf ety injection shut-of f head, the low head safety injaction pumps must be manually restarted to deliver fluid to the reactor coolant system. / CAUTION: Subsequent to this Step, should loss of offsite power occur, manual safety injectioa initiation will be required to load the safeguards equipment onto the diesel powered emergency busses. 3.8 Identify the faulted steam generator by one more of the following methods: 3.8.1 An unexpected rise in one steam generator water level with auxiliary feedwater flow reduced or stopped. 3.8.2 High radiation from the ef fected steam generator blowdown line as deter-mined by HP-9.2 (step 6.2.1.1 thru 6.2.1.7) , High radiation from any one steam generator, as determined by analysis of 3.8.3 a sample per HP-9.1. 3.8.4 High radiation from any one steam generator main steam line. (Contact readings with a portable radiation instrument) 3.9 When t.he f aulted steam generator has been positively identified, then Q isolate oy: 3.9.1 Stop all feedwater flow to the faulted steam generator. Se h 3.9.2 Close the main steam isolation valve and MSIV bypass valves associated y;g a with the faulted steam-generator. 3.9.3 Put the atmosphere steam dump valve in the manual closed position. 3.e 3.9.4 Close the turbine driven aux. feed pump admission valve from f aulted loop ): < and then place the control switch in pull stop. 3.9.5 Isolate the upstream traps from the faulted S/G

p.,..-

4 3.9.6 Isolate the steam supply to the support heating steam from faulted S/G e CAUTION: Do not proceed to Step 3.10 until the faulted steam generator ogg has been identified and isolated. h (4 After the faulted steam generator has been identified and isolated, begin 3.10 a rapid cooldown of the reactor coolant system to approximately 490*F by use of the steam dump. If of fsite power and the conderser are available, dump steam to the main 3.10.1 condenser from the intact steam generator by manual control of the steam header pressure controller. If offsite power is not available or the main condenser is not availab le, 3.10.2 du=p sesam from the intact steam generator through the steam generator power operated relief valve. ~3.10.3 In the event the following conditions are presented, update report to Authorities as an Alert per SC-1.23 and, as an anticipitory measure activate the emergency organization per SC-1.3A. The primary to secondary leak race is: 3.10.3.1 1 gpm with loss of off-site power. 3.10.3.2 10 gym with a steam line break jy; associated MSIV failure to close. . m. 3.10.3.3 200 gym. 3.10.4 In the event the conditions given below are present, update report to authorities, and the emergency organization per SC-1,3A as Site Radiation Emergency. The primary to secondary leak rate is: 3.10.4.1 50 gpm with a steam line break and reactor coolant activity exceeding Technical Specifications limits cg R-9 monitor at 350 mr/hr. 3.10.4.2 200 gpm with loss of off-site power. n 3.11 After the reactor coolant system temperature has been reduced to i approximately 490*F temperature, manually initiate charging flow to the *], ' RCS from all available charging pumps, DO not reinitiate letdown. j ~__ L 3.12.1 Reset C.I. by use of key switch on control board. 3.12.2 Reset required pushbuttons at C.I. Panel to activate actual reset of C.I. valves 5 pu=ps as needed. (Refer to automatic actions in section 4 of this I procedure for containment isolation valve numbers ), i 3.12.3 If outside power is lost energi:e buses 13 & 15 and restart instrument air compressors as necessary. l 3.12.e Reset and open the containment instrument air isolation valve. C} ;3-7 l I l

E-1.4:5 e' l l l As soon as charging flow to the RCS has been verified, begin a 3.13 depressurization of the reactor coolant system to a value equal to the f aulted steam generator steam pressure. During subsequent controlled reactor coolant system NOTE: depressurization, the reactor coolant system pressure criteria for tripping the reactor coolant pumps established in step 3.2 DOES,NOT APPLY. If the RCP's are in service, use the pressurizar spray to reduce the. 3.13.1 pressure. 3.13.2 If of f site power is not available, or the RCP's are not in service open one pressurizar PORV to decrease pressure. ,, g If the pressurizer PORV is opened, an increase in pressurizer M^ NOTE: 1evel is expected as liquid replaces the escaping steam. CAUTION: Monitor containment ~ic4*icna to verify that a loss of reactor unerator tube rupture is not in v coolant other than

samp level or a containment sample progress.

If recit. 44 (if available at thi'

• .ak are not in the normal pre-event further accidr.. recovery enst be directed according to

range, Emergency Instructions E-1.2 Loss of reactor Coolanc, Step 3.6 (Small LOCA).

Unon loss of instrument air operation of the pressurizer PORV's NOTE: using the RCS overpressurtTation Nitrogen system can be achievedil 1). RCS pressure is > 435 psig and 2). There is > 200 psig of Nitrogen available from overpressurization storage tanks (normally at approximately 700 psig). 3). Mov 515 and/or Mov 516 open. 4). MCB switches f or PORV's, PCV 430 and PCV 431C are closed. One operator will have to be on the back of the board turning CAUTION: key switches as instructed below while another operator is watching pressure ' cation from the front of the control board. To open PCV 431C: 1). Turn " Surge TK V802B SVB616B" to open 2). Turn "PC 431 Sv8619B" to Arm ~--

.. E-1.4 6 4 To open PCV 430: 1). Turn " Surge TK V802A SV8616A" to open. 2). Turn "PC430 SV8619A" to Arm. These steps will open respective FORV until either "PC431 SV8619B" or "PC 430 SV8619A" is returned to the block position. If Nitrogen supply runs low, tanks can be refilled using procedure S-29.2. This will require reset of CV isolation. 3.14 As the reactor coolant system pressure d: 3reases, due to the quenching of the steam by the pressurizer spray or due to the steam release through the pressurizer PORV, monitor the pressurizer water level indications and stop the depressurization operation; 6:

1. g 3.14.1 If the indicated water level in the pressurizer rises above 50% of span gpf Eb.

ph, 3.14.2 As soon as the reactor coolant system pressure decreases to a value equal 34' y to the faulted steen generator steen pressure, p&* 3.15 Af ter the depressurization araration has been ver!.fied to have been terminated (using the pressurizer PORV steam-mounted position indicators or spray valve demand signal), continue to monitor the reactor system pressure and the pressurizer water level. 3.15.1 If the pressurizer water level continues to rise or remains nearly constant concurrent with a reactor coolant system pressure decrease, suspect leakage from the pressurizer steam space. Monitor the pressurizer relief tank (PRI) pressure, temperature and level to identify continuously increasing conditions. Close the PORV isolation valves if a reactor coolant leak to the PRT is identified and/or stop the operatint RCP if there is indication or a spray valve stuck open. Monitor PRT conditions to

• verify PRT integrity.

CAUTION: If pressurizer relief tank integrity is lost, abnormal containment conditions could exist and may not be true indications of a continued loss of reactor coolant. If conditions of Step 3.15.1 persist after closing the pressurizer PORV isolation valves, further recovery must be directed according to E-1,2 Loss of Reactor Coolant, Step 3.6. The conditions of Step 3.15.2 must be satisfied before proceeding to Step 3.16. 3.15.2 If the pressurizer water level subsequently continues to increase concurrent with a reactor coolant system pressure increase concurrent with verified PRT integrity, the safety injection)iov is gr e at er than the leak.

~ c.. 3.15.3 Then, when reactor coetant systen pressure has increased by at least 200 y pE~(after shutting the spray vain or verified closure of the pressuriser r" ?ORV) and an indicated water level of 20% has returned in the pressurizer, 7 7 stop all operating safety inject. ion pumpu. p# NOTEt Following termination of aafety injection, pressurizar pressure should decrease to a value equal to the faulted steam generator steam pressure. 3.16 Place all safety injes: tion pumps in a standby mode an6 maintain operable safety injeccion flow paths. 3.17 Reestablish charging and letdown flows to maintain the pressurizer water level in the operating range (approximately 20 percent indicated level): 3.17.1 Establish normal nake-up control if possiblc. NOTE: One, two or three charging pumps may be used at this ti:ne for pressurizer level. control. Ssetion from the VC1 or WST may be used. If the VCT is used caution must be axercised to prevent dilution of the RCS. y /pY CAUTION: If, during subsequent recovery actions, pressuriser water level Y g. j' cannot be naintained above 20 percent indicated levti, manually initiate safety injection flow to reestablish pressurizer water D p\\ S level in the operating range, If pressurizer water level cannot be established by this nutbod, return to Step 3.13 and proceed with tbe instrucci.on from that point. 3.18 Reestablish the use of the pressurizer heaters (refer to 0-8.1, " restoration of Pressurizer Betters to Maintain Natural Circulation at ESD". if no RCP's are running) to maintair. the reactor coolant system pressure. c RCP in the non-faulted loop, using normal RCP prestart limits, if 3.19-tart not already running. CAUTION: The following steps 3.20 and 3.21 must be parformed simultaneously. Failure to expeditiously reduce reactor coolant system pressure to a value equal t. the faulted steam generator steam pressure once system cooldown is initiated could cause loss of pressurizer level control. 3.20 If offsite power it available, begin a controlled cooldovu of the resetor ,n coolant at a rate of about 50'F/hr by use of the steam dump to the main condensers.from the non-f aulted steam generator. Control the water levels j. in the steam generators to maintain steam generator water level in the p(( narrov range span to assure U-tubes are covered. r f M 11 /,' If offaite power is not avai.lable, dump steam frem the non-f aulted steam k J generator through the stea:n pacerator power operated relief valves to f,g at a rate of about provide a controlled cooldow. of the reactor coolant Q 50*7/hr.

E-l.6i8 Q <N }l f l/ b i As precaura is reduced in the faulted steam generator, control the rasceor 3.21 coolant pressure at a value approxinstely equal to the steam pressure in Reactor the faulted steam generator to minimize the taakange flow. i cools.ut pressure control should be secomplished by use of the pressurizer heaters and action of,og of the folloving: 3.21.1 Wormal pressurizer opray (if an RCP is in service), OR Uwe of pressuriser auxiliary spray (if spray is heated by letdown through 3.21.2 the regenerative heat exchanger) You may close normal charging valve to increase flow through NOTE:_ auxiliary spray line if necessary. .. ~ OR 3.21.3 Brief intermittent opening of oEe PORV Maintain reactor coolant system terperature and pressure within NOTEi the limits of the normal cooldown curves in the Technical Specifications. If reactor coclant pressure control is accomplished by use of CAUTION: the pressurizu PORV, continuously monitor the PRT pressure, temperatute and water level and take appropriate actions to verify and maintain PRT integrity. Verify pressurizar PORV c'.osure using the PORV stem-mounted position indicatora and PRT conditions. If a reactor coolant leak to the PRT is identified, close the PORV isolation valves. leriodically sample and analyze the reactor coolant boren concentration dur4.ng the continuing cooldown. Borate as necessary to maintain the [ 3,22 all times during the required cold shutdova boron concentrasion at cooldown. 3.23 When the reactor coolant systen pressure approaches 1000 psig, close the h. safety injection accumulator isolation valves Mov841 and MOV865. Continue to cooldown and depressurize the reactor coolant system and 9g 3.24 faulted steam generator until the reactor coolant cold leg temperatures are below 350 and the reactor coolant pressure has reached about 360 psig (do not collapse tne pressurizer steam bubble). 3.25 Place the residual heat removal system in operation using Normal Cooldown Procedures when conditions permit. this cooldown pror.edure, maintain a steam bubble in NOTE: Throughout the pressurizer. Solid water pressure control may not be effective due to the existance of a bubble in the faulty S/C tubes. .d'"h.A

~ E-1.4:9 i 3.26 Continue the plant cooldown, except that after the RCP operation has been terminated, due to pressure consideration, Control RCS pressure to faulted S/0 pressure by using aux, spray to :ressurizer. NOTE: It may be necessary to close the charging valve to the RCS Loops to allow sufficient flow through the aux. spray line. 3.27 When the reactor coolant system cold leg temperatures are reduced below 200*F, the pressure in the pressurizer may be reduced by using auxiliary spray until reactor coolant system pressure and the f aulted steam generator pressure equilibrate. 3.28 Continue the operation of the residual heat ramoval system to remove the core residual heat and maintain the charging and letdown in service to control the pressurizer water level and provide a boration path. + 1 4

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'-~ E-1.4:11 Table 1 1 00 :ac.icn.o ir.:iica.ed Steam Genera.0: Water level for Reference Leg Heatup effects due to post-accident een Ainment tenpe: at'ce (before reacto: trip) Mard-u: C = *i-en: Correctic to Oc=pera =e' reached bafore S/G Level Lesc~c:

iz.

• ?

% o! Sven _90 ' 0% -j _,150' 2% 200* 5% ~250* 8% j 300* 12% 350' 16% 400* 1 i i 3 asis: ~ Level Calibration Pressure < 1000 Esia } Reference Leg calibration t'i.=perat'ce >_ 90'T Height of 7.eference Leg < 1.1 x Level Span i + 9 9 4 e

1WI E-1.4 :13 Table 2 C ::ec.icas to allowa.ble indicated Steam Generator water level for Reference Leg Esatup and 7:essnre chc=ges following a high-ene:{f line braa.k to yasure true leve. is between the level taps tht: Con *d-ment Correction to yd-d un Corre ic to Mar.imus temperat.re allowed Indica ed Level aH oved Indi=a.ed Leve 'T_ % ef Sean

• 4 e f st an 90*
• 1

-4 150* -3 -4 200' ~6 -4 250' -9 -4 300* +13 ~4 350*

• 17

-4 4g0* -22 -4 Basis: Level c*'dkratic: Presst:n ( 1000 Psia l Reference Leg Calibra-ion TEnperature > 90'? Height of Reference Leg < 1.1 x Level Span ?:csstre > 50 Psia Pressure [ 200 Psi + Calibration Pressu. e Boiliny in the Referance Leg is not assu=ed. \\

l l Table 3 i c:::ectics to indicated ?:sssu.rize: water level for Reference Leg Esatup effec.s due to post-acciden. contad mer. temperat"re i Maximu= C:st> M ent Oc :ection a .e=perarme reached Pressurizer Level 'T T of Stan 90' 0% 9 150' 3% 200* 7% 250' 12% 300* 17% 350' 23% 400* 30% 3 asis: Level Calibratien Pressure = 2250 Psia Reference Leg Calibrati:n Temperarre 1, 90'T Height of Referecem Leg i 1.1 x Level Span 4 9 0 9 deep "----^~^^- ~^^-~

. s. s. s s. \\ t l Table 4 Co=ee.icas to allowable indicated ?:sssurize water level for Reference Leg Heatup and i ?:sssure changes foller ng a high-ener[/ line break, o assure that : ue leve is be.: ween the level.aps C n > d mest correctics t.o Md dmum Co=ecei = .o Maximu= ta=pararre a.11ovad Indicated Level allowed Indicated Leva' l

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?' of son 1 90* +6 -9 150' +9 -9 l 200' +13 -9 250' +18 -9 300' +23 -9 350' +29 -9 400* +36 -9 Basis: Level Calibra:Len Pressure = 2250 Psia Reference Leg Calibration Temperature > 90*F Enight of Reference Leg f,,1.1 x Level Span Pressura > 100 Psia , Pressure 5 350 ?si e Calibration Pressure Sciling in reference Leg is

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Event Chronology: R. E. Ginna Steam Generator Tube Failure Time Event comment 9:2S a.m., 1/25/82 Charging Pump speed alarm; "B" Steam First indications Generator ($/G) steam flow - feed flow of tube rupture mismatch; air ejector radiation monitor in the "B" steam alarm;(Pressurizer (PZR) low pressure generator, alarm setpoint - 2170 psig). Shift Supervisor orders power reduction: Shift Supervisor one operator fast closes turbine control (SS) and operator valves; another operator commences actions based on normal boration. oral interview with the SS. 9:28 a.m. Reactortriponlowpressure(setpoint-Seal return 1873 psig with a rate factor); automatic isolation valve safety injection with a containment closed on contain-isolation (setpoint 1723 psig); Reactor ment isolation Coolant Pump (RCP) seal injection return causing line line pressurizes eventually lifting its to pressurize. relief valve; PZR level rapidly falling; The contribution S/G "A" and "B" low level alarms, of this relief to the PRT is believed insign-ficant (See Table VII ). The S/G low levels resulted from the combined effects of the power reduction and the reactor trip. 9:29 a.m. scth RCP's manually tripped in accordance Station procedures witn Station Emergency procedures E-1.1 require tripping and 5-1.4; RCS pressure about 1750 psig RCP's at 5 1715 and dropping. psig; Westinghouse guidance specifies trip pressure as 1200 - 1300 psig for Ginna. Licensee trips pumps at higher pressure due to pressure instrument qualification status. -,--.y- -, -.. ,,.y-,,-,v.,.--_--.-.-- ,,-,,,--..,~,,,,,,,,,,,-.-,.-y,,-w--, y ,--,----,--,-,--wwrw.- ,n

r 2 Time Event Comment 4 9:33 a.m. NRC Operations Center notified by the Further discussion licensee via the ENS phone; the Itcensee revealed that the reported a reactor trip from 100% power licensee strongly as a result of a steam generator tube suspected that the rupture. The faulted S/G and release "B" S/G contained information was not given by the lice'nsee the fault, but at this time, the licensee chose to confirm the situation prior to notifying the i NRC. Unusual Event declared by Itcensee. Subsequent to the event, comparison of an extrapolated curve for Reactor Vessel Head temper-ature with satur-ation temperature for RCS pressure indicates a steam void developed in the head at this time. (See Figure 4). 9:35 a.m. NRC Senior Resident Inspector arrived in The SRI had been the Ginna Station Control Room.- monitoring the ENS in his offico since 9:33 a.m. 9:40 a.m. Initial RCS pressure drop arrested at Termination of about 1138 psig, pressure drop due to actions of the SI pumps along with attaining saturation conditions in the Reactor Vessel Head. "B" Main Steam Isolation Valve manually closed and the "B" S/G was isolated. Plant cooling down by dumping steam from "A" S/G to the Main Condenser. 1 .. ~.. _ ~. _, - ~.. -. _ _.,.. - _. _ _.,. _. ~ -.. _ _ -. _ _ _ _ _. - _.. _ -_

1 ^ 3 Time Event Comment 9:40 a.m. Alert declared. 9:46 a.m. Ginna Plant Superintendent notified the State of New York. 9:55 a.m. NRC Region ! Incident Response Center activated. 9:57 a.m. Safety Injection initiation circuitry reset; containment isolation reset; instrument air restored to the contain-i ment. 9:58 a.m. Ginna Technical Support Center manned. 10:04 a.m. Charging pumps restarted. 10:07 a.m. (about) -Pressurizer PORV (430) manually opened Shcrtly after the to reduce the pressure differential PORV was opened, between the RCS and the "B" S/G; Pressurizer level Pressurizer Relief Tank (PRT) temperature was sufficiently and pressure rise (see Table VII ). high to cause the letdown orifice isolations and the inside containment letdown isolation (V-427) to open, resulting in lifting the let-down relief and adding water to the PRT. 10:08 a.m. (about) Pressurizer PORV (4301 manually cycled again. 10:09 a.m. (about) Pressurizer PORV (430) manually opened Rapid rise in PZR and failed to shut; RCS pressure dropped level without from about 1300 psig to about-900 psig; corresponding Pressurizer level rises; PORV Block injection flow was Valve begins to close. Pressurizer level-first clear indic-Increased rapidly, ation in the Control Room that a i steam void had formed in the Reactor Vessel Head. The void was growing as RCS pressure dropped. l , ~. - - -...,,. - - -,.. ,,,n,-------- -, -, + - -,, - -, - -, - -,. - -,,,., -, - - - - -, -, - -. - - - -, ~.. - -. - -, - - -

I 4 Time Event Comment 10:10a.m.(about) PORY Block Valve closed; Pressurizer 1evel goes offscale high; Safety Injection increases RCS pressure, j 10:25a.m.(about) "B" S/G atmospheric relief placed in manual control and closed in accordance r with procedure E-1.4. 10:33 a.m. (about) "B" S/G safety lifts (setpoint - 1085 Based on conversa-psig) and rescats. Safety Injection tions with Pumps secured to prevent further release operators, through the "B" safety. All charging pumps are running. l 10:42 a.m. NRC Headquarters activated. 10:44 a.m. Site Emergency declared. 10:45 a.m.-(about) PRT rupture disc ruptures, releasing Disc ruptured water to the "A" Containment Sump. primarily due to PORV (430) and the letdown reitef with a mince contribution i from the RCP seal return relief. 11:00 a.m. Plant cooldown now via the "A" S/G Dumping steam to atmospheric relief-the condenser - secured to minimize spread of contamination in the secondary system. 11:15a.m.(about) One Safety Injection Pump restarted; Throttling of SI "B" $/G safety lifts and reseats. based on informa-tion gained through Safety Injection throttled to prevent discussion with further Itfting of the "B" S/G safety, the licensee's Operations staff. l l 11:19 a.m. The process computer f ails. Remains out Licensee reading j of service until 11:47 a.m. incere and head thermocouples manually to verify adequate core cooling. e e- +=-o->- +- -c,e.,,,.we s-,,a, y,y.a mg 4,p.-_. 9,+. gee >p=,,.gvg y.--gi ,,.,,,,,,,_.y% .-9,,,- .y-genw3,> ,6 ,,e

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s 9'"' 1 Pr blem Defint .#,M'Ycot'I pss o ion A. Summary of Tube Degradati t on the thr Degrada tion second majoree pressuriz d steam of e gen ea tor (PWR) verators (SG) m water hav cause r e r c of esulted for ufactured du ced materials e to plant outages s has beenby each of endor a design selection, andco bin tion m a Various fom ranked as the of Combustion Enand oper tio fabrication tm generator degradation stea s of a n. gin In the echniques m ha ical ec cor phosphatecra king andeering (CE) st ea ly and mi n rosion and r co trolling secsecondary w tertube thinninggenerators 70s, Westinghsecondary sys c of eam m n 59 contr lling theondary w ter chemistry, the p(wastage) duee ouse(W)and a in cau tic s to impr stress gggtn o a plants phosphate chemistry impuri redominant contr l p,g9de and oper 6 CE o Although verted seco dary wa te ties. techniqu con

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e an cr : king and wa conv r all v la t le (AVTchemistry tr difficulties of tim er io s o e for yga tD* n gr i eatly reduced of eatm the S.G. tubestage, other de ) secondary w ent, most W the bega ence a ter tr d"S#'ded g, A\\ n to s due to grada tion occur occur. corrosion modes including str ea tment, CD*t\\Bu* gge 4 of ess of the, carbo denting (defcorrosion ' 3 opef** son-n Babco k and Wi s teel,,suppo,r,t go the seco"*' om tion a tign tha c lc pla tes) ' Sb tdo*"' n W or CE and ox S.G., which relativ ly e have hav >@9g9059"ddd. i good operating opera ted e a A 4*9ons-rin ipal rode degr dation iexperience in thexcluflyely c ed of ffer to limited AVT water ent a eir set of tubes locatedn B&W units early ears chemis try. y was fatigu operation 7 of on th V ge

4-5 Time Event Comment 11:20 a.m. (about) "A" RCP restarted; Reactor Vessel Head Time based on temperatures approach incore temperatures; graph of Incore the steam void in the head collapses. and Head thermo-couples (Figure 4). Data for this graph was obtained manually in the control room. 12:00 noon (about) Steam bubble drawn in the Pressurizer. Normal letdown reestablished. 2:00 p.m. Licensee reported Containment Sump A Channel 1 on at 9.3 feet (approx. 8000 gal.); PRT Containment Sump at 92%. indicated 5.3 feet (1900 gals.); Channel 2 indicated 9.3 feet. Later, it was discovered that Channel 2 read incorrectly due to a static charge on the indicator. 4:15 p.m. NRC Region I-Incident Response Team onsite. 6:40 p.m. Level in "B" S/G back within indicating range. Plant cooling down by dumping steam from "A" S/G to atmosphere. "A" RCP providing flow through the "A" loop and backflow through the "B" loop. "B" S/G being cooled by feeding the S/G with AFW -hile bleeding it via the ruptured w tube to the RCS. 7:17 p.m. Site Emergency downgraded to Alert. 7:05 a.m., 1/26/82 RHR initiated to continue the cooldown. "A" RCP remained in operation. 10:45 .n. Alert downgraded to the Recovery Phase. 6:53 p.m. Plant in Cold Shutdown. 5:30 p.m., 1/27/82 Containtnent Sump A pumped dry; total pumped - 1320 gallons. .-_1.,_.. u....

i I. Problem Defintion I A. Summary of Tube Degradation i Degradation of steam generators (SG) manufactured by each of the three pressurized water reactor (PVR) vendors has been ranked as the second major cause of forced plant outages. Various fonns of degradation have resulted due to a combination of steam generator mechanical design, materials selection, and fabrhelion techniques and secondary system design and operation. In the early and mid-1970s, Westinghouse (W) and Combustion Engineering (CE) steam generators experienced caustic stress corrosion cracking and tube thinning (wastage) due to improper control of phosphate secondary water chemistry, the predominant technique at' that time for controlling secondary water chemistry impurities. Because of difficulties in controlling the phosphate secondary water chemistry treatment, most W and CE plants converted to an all volatile (AVT) secondary water treatment. Although this conversion greatly reduced the occurence of stress corrosion cracking and wastage, other degradation modes including denting (defonnation of the S.G. tubes due to corrosion of the, carbon steef"suppo7t plates)- began to occur. / Babcock and Wilcox S.G., which have a significantly different design than W or CE and have operated excludvely with AYT water chemistry, had relatively good operating experience in their early years of operation. The principal mode of degradation in B&W units was fatigue crack growth e,onfined to limited set of tubes located on the open inspection lane. ENO LCSdE9

However, more recently B&W steam generators have suffered a growing l spectrum of degradation modes, including erosion-corrosion and primary [ side integranular attack. To date, many different forms of steam generator i degradation have been identified including stress corrosion cracking, wastage, interpranular attack, denting, i erosion-corrosion, fatigue cracking, pitting, fretting, and support plate degr idation. One or more of these forms of degradation have affected . at least ',0 operating PWRs and have resulted in extensive S.G. tube pluccing, repair, or replacment with '. heir accompanying personnel exposure and financial costs. Referencas 1, 2, and 3 present detailed discussions of domestic S.G. operating experience. B. Safety Significance The safety significance of S.G. tube integrity can be divided into three categories: tube failures under normal operating conditions; tube failures concurrent with postulated accident condition; and' personnel exposure associated.with S.G. inservice inspection, repair, and replacement. l The majority of the S.G. tube failures under nomal erating conditions are small stable leaks that require plant shutdown, inspection, l and corrective actions. However, four significant S.G. tube ruptures l-have occurred.in domestic PWRs since 1975. These events occurred on February 26, 1975, at Point Beach Unit 1. Septaber 15, 1976, at Surry 2

) l Unit 2, October 2,1979, at Prairie Island Unit 1 and on January 25, 1982, at R. G. Ginna. The first three of these events were evaluated in IWREG-0651, " Evaluation of Steam Generator Tube Rupture Events." The report includes evaluation of systems response, operator action, and radiological consequences during the three events. The leak rate associated with these events ranged from about 80gpm to 390 gpm and exceeded the nomal charging flow capability in every case. The conclusion of the report is that no significant offsite doses or systems inadequacies occurred during the tube rupture events analyzed. The plant operators and systms successfully. avoided direct releases to the environment and brought the reactors to safe shutdown condition. However, the potential for more significant consequences was recognized and a number of procedural recommendations were made to correct the deficiences that were noted. The recommendations were intended to ensure that subsequent S.G. tube rupture events would not have unacceptable consequences. These recanmendations have been included as licensing requirements in the implementation of Unresolved Safety Issues A-3. A-4, and A-5 regarding S.G. tube integrity. To date, the evaluation of S.G. tube rupture events under nomal operating conditions have concentrated on single tube ruptures. The potential for and consequences of ru1tiple tube failures during nomal operation have not been rigorously studied. Furthemore, the potential for complicating i l l circumstances such as the stuck open'PORY during the Ginna incident have i not been evaluated. Although the consequences of S.G. tube rupture I l under nomal operating conditions have been small, such events present a l-significant challenge to plant operators and safety systems. During postulated accident conditions, HSLB or LOCA, the S.G. tubes are subject to sudden increased pressure differentials and possible 3

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l pressure wave and vibrational loadings. These loads create the potential for S.G. tube failures which could exacerbate the accident sequence. In the event of a itSLB, failed S.G. tubes would provide a leakage path from the primary to secondary system and several potential leak paths for the radioactive primary coolant to the environment wott1d then exist. One path is through the atmospheric dump valve or the S.G. safety / relief l valves which would be used to remo,e heat from the secondary system. A 1 second potential leak path exists if the break is postulated outside the containment,- upstream of the outboard isolation valve, and failure of the inboard isolation valve is postulated as the single failrue. In the event of a LOCA, the core reflood rate could be retarded by steam binding. This phenomonon is associated with a cold leg break, in which reflood of the core requires displacing steam through the hot leg, the affected steam generator, and out of the cold leg break. S.G. tube failures would create a secondary to primary leak path which aggravates the steam binding effect and could lead to ineffective reflood of the core. Analytical and experimental evaluations _ of this phenonmonon are contained in references 4 and 5. Large itSLBs and LOCAs are considered extrenely low probability events, but are postulated as bounding conditions. More realistic events might include small and intemediate size itSLBs or LOCAs. Although these postulated accidents pose a less severe challenge to S.G. tube integrity, tube rupture (s) leading to or following such eTents could be extremely damaging. This is particularly true if fuel damage has occurred as in the case of Three liile Island-2, l The final area of concern', which becomes more significant every day, is the radiation exposure of personnel involved in S.G. l t L,.__-__._._.______._..__._____._._._.__.____._

l inspection, repair, and replacement. Reference 3 per4ents a summary of data on S.G. related personnel exposure for selected plants from 1974 to 1980. In recent years, as much as 25% of some plants' annual occupational exposure has resulted fran routine S.G. inspection and maintenance and I as high as 60% for S.G. repla'ccuent. Recent tube sleeving operations at San Onofre incurred 3500 men rom exposure and similar operations are planned for other plants. The issue of personnel exposure related to S.G. degradationis real, it occurs every day, and ef forts to control such exposure are important. Regulatory Approach The NRC approach to ensuring S.G. tube integrity is based on inservice inspection (ISI) requirements, primary to secondary leakage rate limits, and preventative tube plugging. Guidance for perfoming 151 is provided in R.G.1.83, " Inservice Inspection of S.G. Tube," and plant technical specifications include requirements for 151. Typical plant specifications require periodic inspections of 3% of the S.G. tubes in the plant and augmented 151 in the event tube degradation is detected. Required frequency of inspection is generally flexible enough to allow inspections to be perfomed concurrent with refueling outages. However, certain incidents such as tube leakage require unscheduled ISIS. Furthemore, many plants with extensive degradation problems heve licensing amendments imposing higher frequency and larger size inspections. The purpose of the required ISIS is to detemine if tube degradation is occurring in the S.G., detemine the rate of tube degradation based on results of successive inpections, and identify those tubes requiring 5

i plugging or repair. Primary to secondary leak rate limits are an extremely important requirement for ensuring safe S.G. operation. Some foms of tube degradation have been observed to degrade tubes to an unacceptable level during the interval between inspections. primary to secondary leak rate limits requiring shutdown, !$1, and corrective acitons provide protection against this type of degradation Many serious conditions of tube s degradation have been detected by monitoring of primary to secondary leakage and subsequent inspection. Primary to secondary leak rate limits exist in each plant's technical specifications. The basis for these linits are twofold. First, the leak rate limit ensures that the dosage contribution from tube leakage will be limited to a small fraction of 10CFR Part 100 ifmits in the event of a S.G. tube rupture or MSLB. Second, the leak rate limit is intended to correspond to a defect size that would not result in tube rupture under.nomal or postulated accident conditions. Finally, degradation limits for tube plugging exist in the plant technical specifications. Criteria for' establishing the tube plugging limits, are presented in R.G.1.121, " Basis for Plugging Degraded Pressurized Water Reactor Steam Generator Tubes." These criteria require ~ that the plugging limit include margins for eddy current testing error und continued degradation between inspections. Thus, it is important to have a good estimate of the rate of degradation based on successive ISI results and an understanding of the degradation phenomena. The prirsary focus of the current NRC philosophy is directed at maintaining primary systen integrity. In a sense, it is directed at ,,----v-, ~, ~, -,e r- -i s. -,,, m. .-r...% ,w, r

S treating thesymptons and not the cause of S.G. degradation, which lies primarily in secondary system design and operations. This philosophy i has been debated extensively, but the current position makes eliminating the problem at its source an industry responsibility. !!!. Current Corrective Actions t r r There are no simple corrective actions to elimiate S.G. deg radation. This is particularly true for those plants which have significant operating time and have experienced 5.G. degradation. Design changes in operat'.ng S.G.s that would be-necessary to eliminate or reduce degradation problems are impossible. Furthermore, once the secondary system is contaminated by an aggressive environment it is of ten difficult to reverse the adverse affects. For example, caustic stress corrosion cracking and wastage, due to residual phosphate water chemistry conditions, still continue in some plants long after conversion to AVT water chemistry. Several corrective actions, however, have beer: proposed and are in use. These fixes include such actions as tube sleeving, reduced operating temperatures to slow corrosion, boric acid injectio6'to arrest denting, support plate modifications to retard denting, S.G. replacement, and improvements in secondary system design and operation. Seconda ry system improvements include prompt correction of condenser leakage, condenser retubing, removal of copper based alloys from the secondary system, and addition of demineralizing systems. Chemical cleaning has 7

m also been proposed but has not been implemented due to uncertainties regarding its effect on. tube integrity. These fixes have met with varying degrees of success, but none of them are a panacea. Furthermore, short tem solutions to one problem may create other problems. Conversion from phosphate to AVT water chemistry is a case in point. tiany of the design deficiences which are in part responsible for the tube degradation are impossible to correct in operating steam generators. For example, tube to tubesheet crevices already contaminated with corrosive enviroments are very difficult to clean, carbon steel support plates cannot be replaced with rore corrosion resistant materials, and residual fabrication stresses cannot be removed. Thus, corrective actions may prolong S.G. life, but tube degradation is expected to continue in operating plants. Furthemore, the majority of the plants under review for operating licenses have S.G.s of similar design to those currently in operation. Potential for S.G. tube degradation exist in these plants. In fact, steam generators just put on line have experienced S.G. tube degradation problems with a new integral preheater design during praoperational tests. Howewr, NRC does not review secondary cystem design changes. The real solution to S.G. tube degradation problems.inay require radical design changes, significantly upgraded operation of the secondary water system, ' and should include the entire secondary system not just the 5.G.s. Current technology is available to design and operate S.G.s 8

l + capable of perfoming without degradation for more extended periods than those now operating. Future designs might well incorporate features facilitating maintenance and replacment of important components, and j inspection of the secondary side. i IV. Research and Development Activities HRC's steam generator research program addresses improved eddy current inspection techniques for steam generator tubing, stress corrosion cracking of steam generator tubing and evaluation of tube integrity using an out-of-serv',ce degraded steam generator. The objective of the eddy-current program is to upgrade and improve eddy-current inspection probes, techniques and associated instrumentation for inservice inspection of steam generator tubing to improve the ability - of identifying and characterizing defective tubes at early stages. Furthermore, it is 4 desired to improve defect detection and characterization as affected by tube diameter and thickness variations, tube denting, probe wobble, tubesheet and tube support interference, ard defect location and type. The strest corrosion cracking. program ' will develop data and models which will be used to predict the streTs corrosion cracking initiation and service life of Inconel 600 steam generator tubing. The testing program will include variables which influence stress corrosion cracking such as tenperature stress, strain and strain L rate, metallurgical structures and processing and ingredients in the primary and secondary coolant. l 9

e 4 4 id W U A s% W vEnss e .42M % 4,(w.c4.,( degradatiori 4 Q g/s. wg/ f pnA4 cl sh% w 4 and confidence limits of nondestructive inspection instrumentation and techniques, burst and collapse tests on field degraded tubes to validate tube integrity models, and developing data for' validation of previously developed stress corrosion cracking predictive 9ndels, chemical cleaning and decontartrination, dose-rate reduction and secondary side characterion. In addition, statistically based sampling models for inservice insepetion programs will be confti and/or improved utilizing the.first-ever confirmed data ' base. b?$ M nmy (;ny p, mm cc./ dz a c., ,o N %,C.* m. 's.2 W n& QD S k<w WA& 7 f y J e e<-- W . are subdivided into the following areas: (1) Chemistry and Corrosion, (2) Materials Selection and Testing, (3) Thermal, Hydraulic and Structural Testing and Analysis, and (4) Thermal and Hydraulic Code Development. Specific tasks in chemistry and corrosion involves the determination of the causes of denting, general intergranular corrosiofi*of tubing, and cracking la cold-worked tubing (e.g., u bends, square bends, rolled areas), in-plant monito ring of wate. chemistry parameters evaluation of the effectiveness of water soaks in preventing corrosion, development of one or more neutralizers for crevice acids or for caustic deposits, and the developrent of-alternative water chemistry control systems (e.g., on-line chelant orinhibitoradditions). This effort includes collection, evaluation and

correlation of c>erating plant data,and pot and model boiler laboratory tests. Tasks reltted to materials testing include the characterization of heat-treated Incenel 600, the investigation of the corrosion resistance 1 of Inconel 690 and other candidate tubing materials, and corrosion testing in model boilers of various candidate structural material-tube -{ material cmbinations. Environmental fretting and corrosion fatigue testing of Ir. conal 600 and other steam generator tubing will be prefomed ) as needed to extend the data base. EPRI has steam generator NDE programs with the principal focus I to develop inspection techniques which overrome the shortcomings of conventional eddy-current systems used in the field. With that objective in mind, major emphasis has been placed on the use of nultifrequency/multiparameter eddy-current technology for the inspection of steam generator tubing. j in addition, tasks have been undertaken to develop a variety -) ) of inspection devices and techniques for: a. inspection of tube condition to supplement eddy current. I s b. . measurment of dent size, c. detemination of the amount of corrosion product that has accumulated in the tube to support plate gap, and 10 . ~

l I d. inspection of the support plates for damage. Other tasks involve (1) developing automatic eddy-current signal analysis to speed up signal interpretation and reduce operator dependence, and (2) providing a better theoretical understanding of the interactions between eJdy-current and steam generator conditions. Another inportant element of the EPRI liDE program involves the establishment cod operation of the EPRI liDE Center. The purpose of the center is to provide the utility industry with a dedicated flDE capability that concentrates on accelerating the transfer of P,50 results into a fonn directly beneficial to the industry. V. Recumenda tions / A. Implementation of Task Action Plan, Addressing Steam Generator Integrity: A-3, A-4, and A-5 11

) a ~ i In 1978, the HRC established Unresolved Safety issues A-3, A-4, and A-5 regarding degradation in W. CE, and B&W steam generators, respectively. Task Action Plans (TAPS) which were developed to resolve these issues have been empleted and a report, HUREG-0844, presenting the NRC staff resolution of these generic safety issues has been prepared. This report is currently being prepared for transmittal to the Generic Requirements Revievt Group and the Commission. The approach taken in the TAPS to resolve the generic safety issues, integrates technical studies in the areas of systes analyses, inservice inspection (ISI), and tube integrity to establish improved criteria for ensuring adequate tube integrity and safe steam generator operation under all conditions. In the systems analyses, the consequencas of steam generator tube failures during nomal operation and postulated loss-of-coolant and main steam line break accidents were evaluated. The evaluation considered predicted fuel behavior. ECCS (mergency core cooling system) perfomance, radiological consequences, and containment response. The results of the systems analyses defined criteria for establishing a tolerable level of steam generator leakage during postulated accidents. The in.sewice inspection portion of the Task Action Plans, ~ ISI techniques have been evaluated and statistically based ISI programs have been developed which, when implemented,-will provide adequate assurance that no more than the tolerable level of tube leakage, defined by the systes analyses, would occur during nomal or postulated accident 12

] conditions. i in the tube integrity portion of the Task Action Plans, the behavior of degraded tubes during nomal and postulated accident conditions and tube plugging criteria have been evaluated. Changes in operating f procedures and design charges to minimize tube degradation have also been identified. Implementation of the proposed requirements and criteria developed in the TAPS are not expected to totally eliminate S.G. degradation. As discussed earlier, such degradation wil' be difficult to arrest and eliminate in operating S.G.s and some degradation is likely to occur in S.G.s of similar design that are presently cwiing into operation. I The intent of the preposed requirments is to establish a logical approach to evaluating steam generator tube integrity and ensuring safe steam generator operation. HUREG-0844 establishes criteria and requirements that can be used to evaluate current and future degradation problems in steam generators. The establishment of maximum allowable steam generator tube leak rates and associated tolerab1'e number of defective tubes is a major contribution to the evaluation of steam generator tube degradation problems. It provides objective criteria against which steam generator tube integrity can be evaluated. Similarly, the development of statistical ISI programs' provides a rational, scientific basis that can be used to establish and evaluate ISI requirements that will ensure the above criteria are satisfied. 13

~ in keeping with the NRC's current and past philosophy on this issue, the regulatory requirements developed in the TAPS focus on 151 programs and techniques and tube plugging criteria. The primary res,ponsibility for attacking the problem at its source and eliminating S.G. degradation falls clearly on the industry. However, several of the requirements proposed in flVREG-0844 are intended to prunote industry efforts in this a rea. Specifically, establishment of a t4RC-approved secondary water chemistry monitoring and control program is a requirement. Under this requiranent, it is the industry's responsibility to establish specific water chenistry limits.and' effective and monitoring techniques. This will ensure that each utility at least considers the importance of secondary system water chemistry and puts in the effort to develop a canprehensive water chemistry program. Similarly, requirements ISI of condensers ~ are proposed. These requiranents will hopefully reduce the frequency of condenser leaks and encourage utilities to improve condenser perfonnance. Use of noncopper based alloys when retubing condensers and feedwater h'esterscii also a. requirement. Additional requirements are proposed for plants in the peroperating license stage and many recommendations for operating and future plants are made. The intent in the proposed requirements is to leave primary responsibility for correcting the S.G. problem in the hands of the industry, to allow the industry flexibility in addressing the issue, but at the same time, to encourage proper industry'a'ctions. B. Comprehensive fiRC/ Industry Program NRC/ industry cooperative efforts addressing steam generator 14

-~ I .) issues have not been extensive. This is due largely to the different focuse on the issue. NRC has been primarily concerned with requiring adequate 151 and corrective actions to ensure primary system integrity, while the industry has been concerned with developing fixes to prolong S.G. service life and reliability. To date, NRC and industry efforts have been r.marily complementary in nature. However, to the extent that reliability implies safety and vice-versa the NRC and industry efforts hould be synonomous.' It is, therefore, logic ~ l that 'the NRC and a industry initiate a joint, comprehensive program addressing both near-tem and long tem actions required for continued safe operation of steam generators. Possible cooperative efforts of this nature are %?'ng investigated by the staff, and will be addressed in a succeeding document. In this connection, the retired steam generator program underway at PNL is open for industry cooperation, l 4 15 - -}}