ML20236P025

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Proposed Tech Specs,Allowing Response Time of 8 for Overtemp delta-T & Overpower delta-T Instrumentation Based on Supporting Analysis Discussed in Encl Safety Evaluation for Significant Hazards Considerations
ML20236P025
Person / Time
Site: South Texas STP Nuclear Operating Company icon.png
Issue date: 11/12/1987
From:
HOUSTON LIGHTING & POWER CO.
To:
Shared Package
ML20236P004 List:
References
NUDOCS 8711170111
Download: ML20236P025 (67)
v • d • e


Text

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m s l -. . Attachment 3 i November 10, 1987 ST-HL-AE-2409-i l l i 1 I 1 1.I I l ATIAOMENT I-A l FSAR ONTER 15 ION-IOCA REVISIONS i i 1 l 4 l

ATTACHMENT 3 , ST.HL.AE. 2409 1 ggi. OF 6 5 - I STP FSAR TABLE 15.0-3 s-NOMINAL VALUES OF PERTINENT PIANT PARAMETER'S UTILIZED IN THE ACCIDENT ANALYSES"- I Thermal output of NSSS (MWt) See Table 15.0 2 b Core inlet temperature ('F) 560.0 Vessel average temperature (*F) 593.0 18 Reactor Coolant System pressure (psia)^ 22'a0 ~ .h4 b 18 Reactor coolant flow per loop (gpm) 94,100 Steam flow from NSSS (1b/hr) 16,960,000 l18 a: Steam pressure at steam generator 1100 outlet (psia) Maximum steam moisture content (t) 0.25 Assumed feedwater temperature at steam 440 generator inlet (*F) ( Average core heat flux (Btu /hr-ft ) 181200 [ rsl1.4 a b of [60. % d 7h a a% q. Ta<b u Trq, hM % f_ed$ In-bMb va+cha euna uchJ<W P* yavuM % e4 + 1%eur p kfdy of KCL / bN

  • Steady state errors discussed in Section 15.0.3 are added to these values to cbtain initial Locp i m 95,^^^ r
red '

-5 17:b d rerer -->r fr '= n:1 :i:. 7 [ 15.0 19 Amendment 54 m.___

~ .o. .i ATTACHMENT 3 ST HL;AE. 2409 1 J..S.._.L. 2_OF 65 b TABLE 15~.0-4 ,[ TRIP POINTS AND TIME DEIAYS TO TRIP ASSUMED IN ACCIDENT ANALYSES Limiting Trip Trip Point Assweed Time Delays Function In Analysis (Seconds) Power range high neutron n ux, hi h setting 1186 0.5 5 Power range high neutron flux, low sorting 354 0.5 Neutron Flux Reactor Trip Interlock, P 8 reset for 3 loop operation (coincident 43 with low reactor coolant flow) 854 0.5 Overtemperature AT Variable see b.1(" 8. 0 Figure 15.0-1 ? Overpower AT variable see M I.0 l Fi e 15.0 1 \\ 1.0 Eish pressurizer pressure .260$ psig 2.0 low pressurizer pressure W psig 2.0 W lbW low recctor coolant flow ~ (from loop flow detectors) 876 loop flow 1.0 Undervolta5e trip 686 nominal 1.5 Turbine trip Not applicable 2.0 Iow low steam generator 18% of narrow range 2.0 water level level span Total time daley (including RTD and therswell time response, trip circuit 57 a and channel electronics delay) from the time the temperature difference in the coolant loops exceeds the trip setpoint until the rods are free to fall. 15.0 20 Amendment 57

.._-___-__m_._.__,______

p._ ATTACHMENT. 3 ' SI'HL AE. 2409 ) STP FSAR PAdE 3_ OFJ 66 j i to the turbine following a loss of exterval load occurs due to automatic fast closure of the turbine control valves in approximately 0.3 seconds. Following a turbine trip event, termination.of steam flow occurs via turbine stop valve closure, which occurs in approximately.0.1 seconds. Therefore, the transient in primary pressure, temperature, and water volume will be leas severe for the loss of arternal load than for the turbine trip due to a slightly' slower loss-of heat transfer capability. A block diagram summarizing various protection sequences for safety actions 2 required to mitigate the consequences of this event is provided in Figure : Q. 15.0-10. 211.6 The protection available to mitigate the consequences of.a' loss of external load is the same as that for a turbine trip, as listed in Table 15.0-6. 15.2.2.2 Analysis of Effects and Consequences. , Method of Analysis L Refer to Section 15.2.3.2 for the method used to analyze the limiting tran-1 sient (turbine trip) in this grouping of evente. The results of the turbine trip event analysis are more severe than those expected for the loss of exter-nal load as discussed in Section 15.2.2.1. Normal reactor control systems and engineered safety feature (EST) systems are not required to function. The Auxiliary Feedwater (AFW) System may, however, be automatically actuated following a loss of main feedwater; this will fur-ther mitigate the effects of the transin t. The RTS may be required to function following a complete loss of external' load to terminate core heat input and prevent departure from nucleate boiling (DNB). Depending on the magnitude of the load loss, pressurizer safety valves i_ and/or steam generator safety valves may be required to open to maintain sys-tem pressure below allowable limits. No single active failure vill prevent i operation of any system required to operate. Refer to Reference 15.2-2 for a discussion of anticipated transients without trip (ATWI) consideration. 15.2.2.3 Radiological 1 Consequences. There are only-minimal radiological consequences associated with this event,.therefore, this event is not. 43 limiting. The radiological consequences resulting from atmospheric steam dump are less severe than the steam line break event discussed in Section 15.1.5. 15.2.2.4 Conclusicy,. Based on results obtained for the turbine trip event (Section 15.2.3) and considerations described in Section 15.2.2.1,.the applicable acceptance criteria for a loss of external load event are met. l43 15.2.3 Turbine Trip 15.2.3.1 Identification of Causes and Accident Description. For a tur-bine trip event, the reactor would be tripped directly (unless below 50 43 percent power) by a signal derived from the emergency trip fluid pressure and turbine stop valves. The turbine stop valves close, rapidly (typically 0.1 second) on loss of trip fluid pressure actuated by one of a number of turbine. 43 trip signals. Turbine trip initiation signals are discussed in Section 10.2 ~5.2-3 Amendment 43 1 __._.__.__-__mu_.

ATTACHMENT. 3 l ST HL Ag. 2409 STP FSAR y{4,pp 66' l'pon initiation of stop valve closure, steam flow to the turbine stops l abruptly. Sensors on the stop valves detect the turbine trip and initiate turbine bypass and, if ab'ove 50 percent power, a reactor trip. The loss of 43 steam flow results in a rapid rise in secondary system temperature and pres- -i sure with a resultant primary system transient as described in Section 15.2.2.1 for the loss of external electrical load event. The turbine" trip event is analyzed because it results in the most rapid reduction in steam flow. 43 The automatic Turbine Bypass System would normally accommodate the excess l steam generation. Reactor coolant temperatures and pressure do not signifi-cantly increase if the steam dump control system and pressurizer pressure l43 l control system are functioning properly. If the condenser is not available, l the excess steam generation would be dumped to the atmosphere and main feed-l water flow would be lost (since the condenser is used for steam generator feed pump turbine exhaust). For this situation, steam generator level would be 43 maintained by the AFWS to ensure adequate residual and decay heat removal l capability. Should the Turbine Bypass System fail to operate, the steam gen-erator safety valves may lift to provide pressure control. See Section 15.2.2.1 for a further discussion of the transient. A turbine trip is classified as an ANS Condition II event, fault of. moderate frequency (see Section 15.0.1). The plant systems and equipment which are availtble to mitigate the conse-l quences of a turbine trip are discussed in Section 15.0.8 and listed in Table-15.0-6. l l l 15.2.3.2 Analysis of Effects and Consequences. Method of Analysis In this analysis, the behavior of the unit is evaluated for a complete loss of. ) steam load from 102 percent of full power without direct reactor trip primarily to show the adequacy of the pressure relieving devices and also to l i demonstrate core protection margins; that is, the turbine is assumed to trip l without actuating all the sensors for reactor trip on the turbine stop valves. ,l This assumption delays reactor trip until conditions in the RCS result in a l trip due to other signals. Thus, the analysis assumes a worst case transient. In addition, no credit is taken for turbine bypass. Main feedwater flow is 43 terminated at the tine of turbine trip, with no credit taken for auxiliary feedwater to mitigate the consequences of the transient. The turbine trip transients are analyzed by employing the detailed digital computer program i l LOFIRAN (Ref. 15.2-3). The program simulates the neutron kinetics, RCS, pres-surizer, pressurizer relief and safety valves, pressurizer spray, steam gener-ators, and steam generator safety valves. The program computes pertinent plant variables including temperatures, pressures, and power level. Major assumptions are summarized below: 1. Initial Operating Conditions The initial reactor power and RCS temperatures are assumed at their maxi-mum values consistent with the steady state full power operation 1 l 15.2-4 Amendment 43 l

j ST.HL AE.2409 I PAGE 5__op 65' j i ($ including allowances for salibratton and instrument errors (4.7'T uncer- + tainty). De initial RCS pressure is assumed at a =M== value' consis-57 tent with the steady state full r operation _ including allowances for calibration and instrument errors ( psi uncertainty)'.. This assumption l57 results in the maximum power difference for the load less and the minimum margin to core protsetion limits at the. initiation of the socident. 2. Nederator and Doppler Coefficients of Reactivity, Temperature and Power 57-The turbine trip is analysed with both a least asgative moderator temper-ature coefficient and a large negative moderator. temperature coefficient. large (absolute value) Doppler coefficients of reactivity are used for j the maximum reactivity by feedback cases and small (absolute value) 57 1 coefficients are used for the minimum reactivity feedback cases. (See j , Figure 15.0-2). j 3. Reactor control i i q From the standpoint of the maximum pressurea attained, it is conservative to assume that the reactor is in manual control. If the reactor were in automatic control, the control rod banks would move prior to trip and-reduce the severity of the transient. 4 Steam Release ] No credit is taken for operation of the Turbine' Bypass System or, steam l43 generator power-operated relief valves. The steam generator pressure / rises to the safety valve setpoint where steam release through safety 1 valves limits secondary steam pressure to the setpoint value, 5. Pressurizer Spray and Power-Operated Relief Valves Two cases for both the minimum and maximum moderator feedback cases are ) analyzed. a. Full credit is taken for the effect of pressurizer spray and 1 power-operated relief valves in reducing or limiting the coolant pressure. Safety valves are also available. b. No credit is taken for thu effect of pressurizer spray ahd power-operated relief valves in reducing or limiting the coolant pressure. Safety valves are operable. 6. Feedwater Flow Main feedwater flow to the steam generators is assumed to be lost at the time of turbine trip. No credit is taken for, auxiliary feedwater flow since a stabilized plant condition will be reached before auxiliary feed-water initiation is normally assumed to occur. The auxiliary feedvater j flow would remove core decay heat following plant stabi,11sation. 7. Reactor Trip Raactor trip is actuated by the first RTS trip setpoint reached with no credit taken for the direct reactor trip on the turbine trip. Trip sig-I nals are expected due to hi h pressurizer pressure, overtemperature AT. S and hi h pressurizer water level. S i 15.2-5 Amendment 57 q j

l A'TACHMENT 3 l ~ ST.HL AE. 2409 t STP FSAR PAGF A OF 65 ( I Plant characteristics ano tuttial conditions are further discussed in Section 15.0.3. i 57 Except as discussed above, normal reactor control systems and S$F systems are l not required to function. Several cases are presented in which pressurizer i spray and power-operated relief valves are assumed, but the more limiting j cases where these functions are not assumed are also presented. I The RTS may be required to function following a turbine trip. Pressurizer safety valves and/or. steam generator safety valves may be required to open to s maintain system pressures below allowable limits. No single active failure will prevent optration of any system required to function. A discussion of ATVT considerations is presented in Reference 15.2-2. 1 Results I i The transient responses for a turbine trip from 102 percent of full power operation are shown for four cases: two cases for minimum moderator feedback ( and two cases for maximum moderator feedback (Figures 15.2 1 through 15.2-8). l For the minimum moderator feedback cases, the core has the least negative I moderator coefficient of reactivity. For the maximum moderator feedback I cases, the moderator temperature coefficient has its highest absolute value. The calculated sequence of events for the accident is shown in Table 15.2-1. Figures 15.2-1 and 15.2-2 show the transient responses for the turbine trip l with minimum sLoderator feedback, assuming full credit for the pressurizer -l spray and pressurizer power-operated relief valves. No credit is taken for the turbine bypass. The reactor is tripped on the high pressurizer pressure I 57 signal. The minimum departure from nucleate boiling ratio (DNBR) remains well 1 above 1.30. The pressurizer safety valves are actuated and maintain primary 18 system pressure below 110 percent of the design value. The steam generator safety valves limit the secondary steam conditions to saturation at the safety valve setpoint. M k,l 4 kW p fMW+4 Figures 15.2 3 and 15.2-4 show th respo ses for the turbine trip with maximum M N =derator feedback. AIMehw p1 t par eters are the same as the above mo

t S t the reactor is tripped the cc
:tq: retr: ^"' trip signal.

DNBR increases throughout the transient and never drops below its initial. The 57 value. Pressurizer relief valves and steam generator safety valves prevent overpressurization in primary and secondary systems, respectively. The pres-surizer safety valves are not actuated for this case. The turbine trip accident was also studied assuming the plant to be initially operating at 102 percent of full power with no credit taken for the pressuriz-er spray, pressurizer power-operated relief valves, or turbine bypass. The reactor is tripped on the high pressurizer pressure signal. Figures 15.2-5 43 and 15.2-6 show the transients with minimum moderator feedback. The neutron flux remains essentially constant at 102 percent of full power until the rese-tor is tripped. The DNBR increases throughout the transiant. In this case the pressurizer safety valves are actuated and maintain system pressure below 110 percent of the design value. Figures 15.2-7 and 15.2 8 show the transients with maximum moderator feedback with the other assumptions being the same as in the preceding case. Again, g the DNBR increases throughout the transient, and the pressurizer safety valves are actuated to limit primary pressure. 15.2-6 Amendment 57

... A.-- -. ~ ~ ~~- ATTACHMENT 3 GT.HL AE. 2409 STP FSAR Y-Reference 15.2-4 presents additional results of analysis for a_ complete loss of heat sink including loss of main feedwater. This analysis shows theLover-pressure protection that is afforded by the pressurizer and steam generator. safety valves. 15.2.3.3 Radiological Consequences.. There are only minimal radiological-consequences associated with this event, therefore, this event is not limiting.. The radiological consequences resulting from atmospheric' steam dump are less-severe than.the steam line break-event discussed in Section.15.1.5, 15.2.3.4 Conclusions. Results of. the analyses, ' including those in Refer-ence 15.2-4, show that the plant design is such that a turbine trip without a direct or immediate reactor trip' presents.no hazard to the integrity of.the RCS or the main steam system. Pressure relieving devices incorporated in the two systems are adequate to limit the maximum pressures to within the design limits. [. The DNBR remains above 1.30 for all cases analyzed; thus, the 'DNB ' design basis f as described in Section 4.4 is met. The above analysis demonstrates the 10, ability of the NSSS to safely withstand a full load rejection. 15.2.4 Inadvertent closure of Main Steam Isolation Valves i The inadvertent closure of main steam isolation-valves would cause a' turbine .i ~ trip and other consequences as described in Section 15.2.5 below'. 15.2.5 Loss of Condenser Vacuum and Other Events Causing a Turbine Trip loss of condenser vacuum is one of the events that can cause a turbine trip. Turbine trip initiating events are described in Section 10.2. A loss of condenser vacuum would preclude the use of turbine bypass to the condenser; 43 l 3 however, since turbine bypass is assumed not to be available in the turbine ~ t trip analysis, no additional adverse effects would result if.the turbine trip were caused by loss of condenser vacuum. Therefore, the analysis.results and conclusions contained in Section 15.2.3 apply.to' loss.of. condenser vacuum..In addition, analyses for the other possible causes of a turbine trip, as listed in Section 10.2, are covered by Section 15.2.3. Possible overfrequency = 4' effects due to a turbine overspeed condition are discussed in Section 15.2.2.1 and are not a concern for this tvpe of event. s 15.2 6a. Amendment 54

.,. 3 ;7....., .a . ~. - ATTACHMENT 3 . ST HL AE 2409 PAGg 8 op 65 STP FSAR (. TABLE 15.2

  • TIME SEQUENCE OF EVENT 5 FOR INCIDENTS WHICH CAUSE A DECREASE-IN HEAT REMOVAL SY THE SECONDARY SYSTEM Accident Evert Time (sec),

Turbine Trip h3' 1. With pressurizer Turbine trip, 0.0. pressure control loss of main ~ (minimum moderator -feedwater flow 1.~ feedback) b,t ) Bish Pressurizer pressure. M 57 i reactor trip point'is reached. i Initiation of 7.0 steam release .~ i from steam gen-erator safety valves (

6. 8 Rods begin to M

57-drop Minimum DNBR (1) J occurs j i Peak pressurizer 9.5 pressure occurs 2. With pressurizer Turbine trip, 0.0 '3 pressure control loss of main (maximum moderator feedvater flow feedback) yu pmg psw

  1. A4.ht,11CtP ft,Ali a t.dbEb

'7-l ";.;;..,.;:.: = = Li Sc6' tri; ; t ::: d:f $y Initiation of 7.0 57-steam release from steam gen-erator safety 34 valves 9.1 Rods begin to g 57 drop ( 15.2-20 Amendment 57

1 ,g,-. , j,_,,,,, - - ATTACHMENT 3 - 1 o . ST.HL.AE. 2409 l PAGE.9 OF. 6 f~ STP FEAR TABI2 15.2 1 (Continued) l TIME SEQUUCE OF EVENTS FOR INCIDENTS WHICH CAUSE A DECREASE IN HEAT REMOVAL SY THE SECONDARY SYSTEM J Ae.cident M Time (soci 1 Minimus DHER (1) eeeurs Peak pressurizer-8.5 57 pressure occurs. 18 l 3. Without pressurizer Turbine trip, 0.0 pressure control loss of main 43 (minimum' moderator feedwater flow feedback) al.(o Bigh pre'asurizer g 57 pressure reactor trip point reached (,.e Rods begin to fa 57 drop Minimum DNBR (1) occurs ( Initiation of 7.0 57 steam release l from steam gen-erator safety valves 80 Feak pressurizer J4 57 pressure occurs 4. Without pressurizer Turbine trip, 0.0 pressure control loss of main 43 (maximum moderator feedwater flow feedback) 44 Bigh pressurizer p 57 pressure reactor trip point reached l l e t 15.2-21 Amendment 57

f 'STP FSARL ATTACHMENT.3 E.24 . ST.HL.p0 M j9 PACF g = - - 1 TABLE 15.2 1 (Continued) TIME SEQUENCE OF EVENTS FOR INCIDENTS t/HICH CAUSE A' D IN HEAT REMOVAL BY THE SECONDARY SYSTEM ' l Accident Event Time (sec)

3 Rods begin to 5~

drop j. Minimum DNBR 1 < j (1) occurs l Initiation of l . 7,0. SUI steam release from steam gen-erator safety valves J Peak pressurizer -7.0 l57'! pressure occurs Loss of Normal ) Main feedwater Feedwater Flow '10.0 I flow stops l Low-low steam gen- '63.2 l 43 54 erator water level trip Rods begin to 65,2 54 l drop = Reactor coolant 67.2' . pumps begin to 54 coastdown(2) Peak water volume 71.0. in pressurizer occurs Two auxiliary feed-123.2 ' I water pumps start and-supply 2 steam generators 54 Core decay heat ~2600 decreases to auxiliary-feedwater heat removal capacity 15.2 22 Amendment 57 P4 ________._--__------K------- - - - - - - - - ~ ^ - ^ ' ^ ~ ^ ^ ~ ' ^ ~ .__u-

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Figures 15.4-1 shows~the neutron flux transient. overshoot the' nominal ful1~ power value. 'The neutron flux does not j The' energy release and the fuel temperature increases are relatively small.. The thermal flux response, of interest'for DNB considerations,'is shown on-Figure 15.4-2. is evidenced by a heat flux much lessthan the full power nomin ^ There'is a large margin to DNB during the transientJsince the rod surface heat I at all times in the core, flux remains below the design value, and there is a h fuel and cladding temperature. Figure 15.4-3. shows the response of the hot spot es to a value belov the nominal full power hot spot value.The hot spot fuel ave The minimum DNBR at all times remains above 1.30, 13' The calculated sequencs of events for this ' accident is shown in Table '15 41 With the reactor. tripped, the plant returns to a stable condition. may subsequently be cooled down further by following normal' plant shutdownThe plant procedures. 15.4.1.3 Radiological Consequences. There are no radiological conse. I quences associated with an uncontrolled RCCA bank withdrawal from'a sub-within the fuel rods and RCS within design limits. critical or low pow ) 15.4.1.4 Conc lus ions '. In the event of a RCCA withdrawal accident from the suberitical condition, the core and the RCS are not adversely affected sinc 3 the combination of' thermal power and the coolant temperature result J a DNBR which is well above the Ifmiting value of 1.30. in l basis as described in Section 4.4 is met. Thus, the DNB design 13 1 l 15.4.2 Uncontrolled Rod Cluster Control Assembly Bank Withdrawal at Power 15.4.2.1. Identification of Causes and Accident Description. trolled RCCA bank withdrawal at power results in an increase in the core h Uncon-flux. Since the heat extraction from the steam generators lags behind the eat - 1 safety valve setpoint, core power generation until the steam generator pressure reac j there is a net increase in the reactor coolant tempera-ture. Unless terminated by manual or automatic action, the power mismatch and resultant coolant temperature rise could eventually result-in DNB. in order to avert damage to the fuel clad, Therefore, designed to terminate any such transient before the DNBR falls below 1 30the j This event is classified as an ANS Condition II incident etate frequency) as defined in Section 15'0.1. (an incident of mod-The automatic features of the RTS which prevent core damage following the i postulated accident include the following: i l. Power ronge neutron flux instrumentation actuates a reactor trip if two out of four channels exceed an overpower setpoint. 2. Reactor trip is actuated if any two out of four AT channels exceed an overtemperature AT setpoint. axial power imbalance, coolantThis setpoint is automatically varied wi-against DNB. temperature and' pressure to protect 15.4-5 Amendment 5 .x

ATTACHMENT 3 . ST.HL AE A09 STP FSAR PAGF2kinFMk ) i l 3. Reactor trip is actuated if any two out of four AT channels exceed an j' overpower AT setpoint. This setpoint is automatically varied with axial J. power imbalance to ensure that the allowable heat generation rate (kW/ft) is not ex'ceeded. 1 1 43 4. A high pressurizer pressure reactor trip is actuated if any two out of four pressure channels exceed the setpoint. This set pressure is less i than the set pressure for the pressurizer safety valves. 5. A high pressurizer water level reactor trip is actuated if any two out of four level channels exceed the setpoint. l43 In adAition to the above listed reactor trips, there are the following RCCA witt.ecnuel blocks: 1. High neutron flux (one out of four); 2. Overpower AT (two out of four); and, 3. Overtemperature AT (two out of four). The manner in which the combination of overpower and overtemperature AT trips provide protection over the full range of RCS conditions is described in Chap-ter 7. Figure 15.01 presents allowable reactor coolant loop average tempera-tures and ATs for the design power distribution and flow as a function of pri-mary coolant pressure. The boundaries of operation defined by the overpower j AT trip and the overtemperature AT trip are represented as " protection lines" on this diagram. The protection lines are drawn to include all adverse instrumentation and setpoint errors so that under nominal' conditions trip would occur well within the area bounded by these lines. The utility of this diagram is in the fact that the limit imposed by any given DNBR can be repre-aanted as a line. The DNB lines represent the locus ef conditions for which the DNBR equals 1.30. All points below and to the left of a DNB line for a given pressure have a DNBR greater than 1.30. The diagram shows that DNB is ~ prevented for all cases if the area enclosed wich the maximum protection lines is not traversed by the applicable DNBR line at any point. The area of permissible operation (power, pressure, and temperature) is bounded by the combination of reactor trips: high neutron flux (fixed set-43 point); high pressurizer pressure (fixed setpoint); low pressurizer pressure 1 (fixed setpoint); overpower and overtemperature AT (variable setpoints). 15.4.2.2 Analysis of Effects and Consequences. Method of Analysis This transient is analyzed by the LOFTRAN code (Ref.15.4-3). This code simu-lates the neutron kinetics, RCS, pressurizer relief and safety valves, pres-surizer spray, steam generator, and steam generator safety valves. The code computes pertinent plant variables including temperatures, pressures, and power level. The core limits as illustrated on Figure 15.0-1 are used as input to IDFTRAN to determine the minimum DNBR during the transient. 15.4-6 Amendment 57 _ - _ - _ = _ -

7 ATTACHMENTS l fAGE_3LOF (6 ' .l . ST.HbAE #0c0 ,n g7,pggg i / I -(' Plant characteristics and initial conditions are discussed in Section'15.0.3.. d ~ N In~ order to obtain conservative results for'an uncontrolled rod. withdrawal at-power accident, the following assumptions-are made: 1. Initial conditions of maximum core power and reactor coolant average' temperature (+4.7'F uncertainty) and. minimum reactor coolant pressure 57 1 .f (X$ psi uncertainty), resulting in the minimum initial. margin _ to DNB'. 1 g 2. Reactivity Coefficients - Two cases are analyzed. a. ' Minimum Reactivity Feedback: -A least negative moderator temperature coefficient of reactivity and a least negative Doppler-only power coefficient of reactivity (See Fig.15.0-2) are assumed corre's?onde ing to the beginning of core life. b. Maximum Reactivity Feedback: A conservatively large' negative moder-ator-temperature coefficient and a most negative Doppler-onlyl power j coefficient are assumed. I. F 3. The reactor trip on high neutron flux is assumed to be actuated at a conservative value of 118 percent of nominal full power. The AT trips- .i include all adverse instrumentation and setpoint errors, while.the delays. for the trip signal actuation are assumed at their maximum values. 4. The RCCA trip insertion characteristic is based on the assumption.that the highest worth assembly is stuck in its fully withdrawn position. I '( 5. The maximua positive reactivity insertion rate'is' greater than that for \\ the simultaneous withdrawal of the combinations'of the two control banks having the maximum combined worth at maximum. speed. 6. The effect of RCCA movement on the axial. core power distribution is accounted for by causing a decrease in overtemperature'AT setpoint pro-l portional to a decrease in margin to DNB. 2 A block diagram summarizing various protection sequences for safety actions required to mitigate the consequences of' this event is provided in Figure Q211. 15.0-15. 6 Plant systems and equipment which are available to mitigate the effects of the accident are discussed in Section 15.0.8 and listed in Table 15.0-6. No sin-gle active failure in any of these systems or equipment will adversely affect the consequences of the accident. A discussion of anticipated transients without trip (ATWT) considerations is presented in Reference 15.4-4. Results Figures 15.4-4 through 15.4-6 show the transient response-for a rapid RCCA withdrawal incident starting from full power, Reactor trip on high neutron j flux occurs shortly after the start of the accident. Since this is rapid with respect to the thermal time constants of the plant, small changes in T'*V8 and pressure result and margin to DNB is maintained. 15.4-7 Amendment 57' 'l 'l

n ~. ATTACHMENT' 3 j , ST.HL AE M09 STP FSAR pgg ganty r l -The transient response'for a slow RCCA withdrawal from full power is shown on Figures 15.4-7 through 15.4-9. Reactor. trip 'on overtemperature AT occurs .),- after a longer period. Again, the minimum DNBR is greater than 1.3,0. l18 Figure 15.4-10 shows the minimum DNBR as a function of reactivity insertion f rate from, initial full power operation for minimum and maximum reactivity feedback. It can be seen that two reactor trip channels provide protection over the whole range of reactivity insertion rates. These are-the high neu - tron flux and overtemperature AT channels. The minimum DNBR is always greater than 1.30. 'l18 Figures 15.4-11 and 15.4-12 show the minimum DNBR as s' function of reactivity insertion rate for RCCA withdrawal incidents starting at 60 and,10 percent power,respectively. The results are similar to the 100 percent power case, M except as the initial power is decreased, the range over which the overtem-parature AT trip is effectiva is increased. In neither casa does the DNBR fall below 1.30. l18 The shape of the curves of minimum DNBR versus reactivity insertion rate in' f/ the referenced figures is due both to, reactor core and coolant system tran - sient response and to protection system action in initiating a reactor trip. Referring to the minimum feedback case in Figure 15.4-11, for example, it is noted that: -4 1. For high reactivitg3 insertion rates (i.e., between approximately # x 10 )(- Ak/cee and 1.0x10 Ak/sec) reactor trip is initiated by the high neu- 'i. tron flux trip. The neutron flux level in the core rises rapidly for ) these insertion rates while core heat flux and coolant system temperature j lag behind due to the thermal capacity of the fuel and. coolant system fluid. Thus, the reactor is tripped prior to significant" increase in heat flux or water temperature with resultant high minimum DNBRs during the transient. As reactivity insertion rate decreases, core heat flux and coolant temperatures can remain more nearly in equilibrium with the ~ neutron flux; minimum DNBR during the transient thus decreases with decreasing insertion rate. 2. The overtemperature 4T reactor trip circuit initiates a reactor trip when measured coolant loop AT exceeds a setpoint based on measured RCS average temperature and pressure. This trip circuit is described in detail in Chapter 7; however, it is important in this context to note that the H average temperature contribution to the circuit is lead-lag compensated in order to decrease the effect of the thermal capacil:y of the RCS in response to power increases. 3. With further decrease in reactivity insertion rate, the overtemperature AT and high neutron flux trips become equally 4 effective in terminating the transient (e.g., at approximately )( x 10 Ak/sec reactivity- )( insertion rate). ~ J 3 For reactivity insertjon rates between approximately)( x 10 Ak/see and M ~ approximately 5 x 10~ Ak/see the effectiveness of the overtemperatureAT~ ,2(.) - trip increases (in terms of increased minimum DNBR).due to the fact' that. with lower insertion rates the power increase rate is slower. the rate of 15.4-8 Amendment 43

4... ATTACHMENT 3 . ST.HL AEw900 STP FSAR PAM 330F G5 -rise of average coolant temperature is slower-and the system lags and delays become less significant. ~ -5 4. For reactivity insertion rates less than approximately 5.x 10 Ak/sec, the rise in.the reactor coolant temperature is sufficiently high so that the steam generator safety valve setpoint'is reached prior to trip.s Opening of these valves, which act as an additional heat load of;the RCS, sharply decreases the rate of. rise of RCS average temperature. This-decrease in rate of rise of the average coolant system temperature during the transient is accentuated by the lead-lag compensation causing the. overtemperature dT trip setpoint to be reached later with resulting lower. K j minimum DNBRs. For transients initiated from higher power levels (for example, see Figure 15.4-10)thiseffect,describedinItem4aboge,whichresultsinthe-sharp ~ peak in minimum DNBR at approximately 5 x.10 Ak/sec, does' not ' occur since f the steam generator safety valves are never actuated prior to trip. -l r L. Since the RCCA withdrawal at power incident is nn overpower transient, the 6 fuel temperatures rise during the transient until after reactor trip occurs. For high reactivity insertion rates, the overpower transient is fast with-respect to the fuel rod thermal time constant, and the core heat flux lags p behind the neutron flux response. Due to this lag,'the peak core heat. flux-does not exceed 118 percent of its nominal value (i.e., the high neutron flux trip setpoint assumed in the analysis). Taking into account the effect of the RCCA withdrawal on the axial core power distribution 'the peak fuel tempera-ture will still remain below the fuel melting temperature. For slow reactivity insertion. rates.the core heat flux remains more nearly in equilibrium with the neutron flux. The cvarpower transient is. terminated by 's the overtemperature AT reactor trip before a DNB condition is reached. The peak heat flux again is maintained below 118 percent of its nominal value'.. Taking into account the effect of the RCCA withdrawal on the axial core power distribution, the peak fuel temperature will remain'below the fuel melting temperature. Since DNB does not occur at any time during the RCCA withdrawal at power tran-j sient, the ability of the primary coolant to. remove heat from the fuel rod is not reduced. Thus, the fuel cladding temperature does not rise significantly above its initial value during the transient. / The calculated sequence of events for this accident is shown in Table 15.4-1. With the reactor trfpped, the plant eventually returns to a stable condition. The plant may subsequently be cooled down further by following normal plant shutdown procedures.. 15.4.2.3 Radiological Consequences. There are only minimal radiological consequences associated with an uncontrolled RCCA bank withdrawal at power event. The reactor trip causes a turbine trip and heat is removed from the secondary system through the' steam generator power-operated relief valves (PORVs) or safety valves. Since no fuel damage is postulated to occur, the radiological consequences associated with atmospheric steam release from this ( event are less severe than the steam line break event analyzed in Section 15.1.5.3. 15.4-9 Amendment'43

ATTACHMENT 3 ST.HL.AE G404 STP FSAR _ PAGF 34 0F. d ThehighneutronfluxandovertemperatuhATtrip 15.4.2,4 Conclusions. channels provide adequate protection over the entire range of possible reac-l i tivity insertion rates (i.e., the minimum value of DNBR is always larger than 1.30). Thus, the DNB design basis as described in Section 4.4 is met. l43 1 15.4.3 Rod Cluster Control Assembly Misoperation l43 15.4.3.1 Identification of Causes and Accident Description. RCCA mis-operation accidents include. 1. One or more dropped RCCAs within the same group; 30 1 l 2. A dropped RCCA bank; 3 3. Statically misaligned RCCA; 4. Withdrawal of a single RCCA. Each RCCA has a position indicator channel which displays the position of the l assembly-. The displays of assembly positions:are grouped for the operator's convenience. Fully inserted assemblies are further indicated by a rod at bottom signal, which actuates a local alarm and a control room annunciator. Croup demand position is also indicated. RCCAs are always moved in preselected banks, and the banks are always moved in DO 53 I the same preselected sequence. Each bank of RCCAs is divided into two groups. 43 The rods comprising a group operate in parallel through multiplexing thyris-tors. The two groups in a bank move sequentially such that the first group is always within one step of the second group in the bank. A definite schedule of actuation or deactuation of the stationary gripper, movable gripper, and lift coils of a mechanism is required to withdraw the RCCA attached to the machanism. Since the stationary gripper, movable gripper, and lift coils l 43l 53 associated with the four RCCAs of a rod group are driven in parallel, any single failure which would cause rod withdrawal would affect a minimum of one group. Mechanical failures are in the direction of insertion or immobility. 1 The dropped RCCA, dropped RCCA bank, and statically misaligned RCCA events are l53 classified as American Nuclear Society (ANS) Condition II incidents (incidents i of moderate frequency) as defined in Section 15.0.1. However, the single RCCA withdrawal incident is classified as an ANS Condition III event, as discussed below. l No single electrical or mechanical failure in the rod control system could lg cause the accidental withdrawal of a single RCCA from the inserted bank at full power operation. The operator could withdraw a single RCCA in the .I j control bank since this feature is necessary in order to retrieve an assembly l43 3 should one be accidentally dropped. The event analyzed must result from multiplewir{ngfailures(probabilityforsinglerandomfailureisonthe order of 10 / year; refer to Section 7.7.2.2) or multiple serious operator l57 errors and subsequent and repeated operator disregard of event indication. The probability of such a combination of conditions is very low. The 1 53 consequences, however, may include slight fuel damage. Thus, consistent with l 15.4-10 Amendment 57

a ATTACHMENT 13.' . ST HL AE 704 P W 3 G O F..(r 5 STP FSAR 9 Table 15.4-1 TIME SEQUENCE OF EVENTS FOR INCIDENTS WHICH CAUSE REACTIVITY AND POWER DISTRIBUTION ANOKALIES ' Accident. Event Time (sec.) Uncontrolled Rod Initiationofuncontrolged' O.0 Cluster Control rod withdrawal from 10~ Assembly Bank of nominal power e Withdrawal from a Suberitical or Low Power Startup Condition Power range high neutron 13.7 flux low setpoint' reached Peak nuclear power occurs 13.8 Rods begin to fall into 14,2' core Minimum DNBR occurs 15.6 Peak average' clad temperature 15.6 occurs Peak heat flux occurs 15.6 l Peak average fuel temperature .15.8 occurs Uncontrolled RCCA Bank Withdrawal at Power 1. Case A Initiation of uncontrolled 0 RCCA withdrawal at a high. reactivity insertion rate (70 pcm/sec) Power range high neutron flux 1.7 high trip point reached Rods begin to fall into core 2.2 Minimum DNBR occurs 3.2 15.4-37 Amendment 57

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57 'l Rods.begin to fall into core' 4-5 4,I Minimum DNBR occurs Lar989 k '.1 Startup of an Inactive In.itiation of pump. 0 l4'3 Reactor Coolant-Loop Startup Power reach'd P-8 interlock: 10.2 l43 l e s,etpoint, coincident with 'l low reactor coolant flow l -1 Rods begin to drop: 11.2 Minimum DNBR occurs .12.0 .ll4 Uncontrolled Boron Dilution 1. Dilution during Power range high neutron flux,~ 0 l startup low setpoint reactor trip due j to dilution I I 1 Shutdown margin, lost (if ~1200 dilution continues ' af ter trip) i l l l I l l 15.4-38 Amendment'5'l l t --__-___La_-_%___-______________.

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g . ATTACHMENTS . ST.HL AE WO4 ' PAAF S3 OF J5 SIP FSAR ( 15.6 DECREASE IN. REACTOR COO 1 ANT INVENTORY l Events which result in a decrease in reactor' coolant inventory as discussed in thi,s section are as follows. .i 1. Inadvertent opening of a pressurizer safety or relief, valve (Section 15.6.1) 2. Failure of small lines carrying primary coolant 'outside containment (Sec-tion'15.6.2). 3. Steam generator tube rupture (Section 15.6.3) 4. BWR piping failure outside containment (not applicable to South Texas ~l Project) (Section 15.6.4) l 5. Loss-of-coolant accident resulting from a spectrum of postulated piping-O breaks. within the reactor coolant pressure boundary (Section 15.6.5)- Items 1 and 2 above ase considered to.be'ANS Condition II events and Items 3' and 5 are considered to be ANS Condition IV events. ~ 15.6.1 Inadvertent Opening of a Pressurizer Safety or' Relief Valve 15.6.1.1 Identification of Causes and Accident Description. An acciden-tal depressurization of the Reactor Coolant System (RCS)~could occur as.a I result of an inadvertent opening of a pressurizer. relief or' safety valve. 1 Since a safety. valve is sized to relieve approximately twice the steam flow rate of a relief valve, and will therefore allow a much more rapid depressuri-zation upon opening, the most severe core conditions resulting from an.acci-dental depressurization of the RCS are associated with 'an inadvertent' opening of a pressurizer safety valve. Initially, the event results in a rapidly decreasin5 RCS pressure until the pressure reaches a value-corresponding to the hot leg saturation pressure. At.that time,.the pressure decrease is slowed considerably. The pressure continues to decrease throughout the tran- 'i sient. The effect of the pressure decrease is to decrease power via the mod-l erator density feedback; however, then reactor control system (if in the auto-matic mode) functions to maintain power throughout the initial stage of the transient. The average coolant temperature decreases slowly, but the pressur-izer level increases until reactor trip. l' The reactor may be tripped by the following Reactor Trip System (RTS) signals: ] 45 1. Overtemperature AT 2. Pressurizer low pressure A block diagra?n summarizing various protection sequences for safety actions Q211. required to mitigate the consequences of-this event is provided'in Figure 6-15.0-22. An inadvertent opening of a pressurizer safety valve is classified as an Amer-ican Nuclear Society (ANS) Condition II event, a fault of moderate frequency. (See Section 15.0.1)'. { l l l 15.6-1 Amendment 57

A

~ .) = ATTACHMENT 3 ] . ST.HL AE. 7109 STP FSAR pMF 54 OF _ E25 ' 15.6.1.2 Analysis of Effects and Consequences. The accidental ), dspressurization transient is analyzed by employing the detailed digital com-puter code LOFTRAN (Ref. 15.6-1). The code simulates the neutron kinetics, RCS, pressurizer, pressurizer relief and safety valves, pressurizer spray,- 1 dteam ;;enerator (SG;, and SG safety valves. The_ code computes pertinent plant variables including temperatures, pressures, and power level. Plant characteristics and initial conditions are discussed in Section 15.0.3. In order to give conservative results in calculating the departure from nucle-cte boiling ratio (DNBR) during the transient, the following assumptions are made. 1. Initial conditions ef maximum core power and reactor coolan temperature (+4.7'F uncertainty) and minimum reactor coolant pressure ( psi 57 uncertainty) are assumed. This results in the minimum initial margin to 1 departure from nucleate boiling (DNB) (see Section 15.0.3). j 2. A least negative moderator temperature coefficient of reactivity is assumed. The spatial effect of void due to local or subcooled boiling is not considered in the analysis with respect to reactivity feedback or core power shape. i 3. A large (absolute value) Doppler coefficient of reactivity is assumed 'l (Fig.15.0-2) se that the resultant amount of positive feedback is con-1 servatively high. This retards any power decrease due to moderater reac-tivity feedback. l Normal reactor control systems are not required to function. The rod control 7 system is assumed to be in the automatic mode in order to hold the core at .1 full power. longer and thus delay the trip. This is a worst-caso assumption; if the reactor were in manual control, an earlier trip could occur on low pressurizer pressure. The RTS functions to trip the reactor on the appropri. 45 ete signal. No single active failure will prevent the RTS from functioning j properly. Results_ The system response to an inadvertent opening of a pressurizer safety valve is shown on Figures 15.6 1 through 15.6 3. Figure 15.6-1 illustrates the nuclear power transient following the depressurization. Nuclear power is maintained ct the initial value until reactor trip occurs on overtemperature AT. The pressure decay transient and average temperature transient following'the reci-dent are given on Figure 15.6-2. Pressure drops more rapidly _after core heat ge5eration is reduced via ths trip, and then slows once saturation temperature 45 is reached in the hot leg. The DNBR transient is shown on Figure 15.6-3; DNBR remains above 1.30 throughout the transient. The calculated sequence of events for the inadvertent opening of a pressurizer safety valve incident is shown in Table 15.6-1. 15.6.1.3 Radiological Consequences' An inadvertent opening of a pres-surizer safety or relief valve releases primary coolant to the pressurizer relief tank; however, even assuming a direct release to the Conta1nment atmos-phere, the radiological consequences of this event would be substantially less ) 15.6-2 Amendment 57

3-ATTACHMENT ST.HL AE MM - STP FSAR pgnp gnp (4 ' than that of a Loss of Coolant Accident-(LOCA) because less primary coolant is . released-and the activity is lower as fuel damage is not predicted as a result of this event, 15.6.1.4 Conclusions. The results of the analysis show'that the pres-l surizer low pressure and the overtemperature AT RTS signals provide adequate l _4 5. protection against the RCS depressurization event. ~The DNB design basis as-described in Section 4.4 is met. 15.6.2 Failure-of Small Lines' Carrying Primary Coolant Outside Containment 15.6.2.1 Identification of Causes and Accident Description. Several small lines in the plant carry primary coolant outside-the Containment. These lines are the sampla lines which conform to GDC 55 of 10CFR50, Appendix A,=and' 2-l the Chemical and Volume Control System (CVCS). letdown:line. There are no i l instrument lines which carry primary coolant outside'the Containment. Block diagrams summarizing various protection sequences for actions required 43: to mitigate the consequences of these events are provided in Figures 15.0.23 and 15.0-31. 9211*0 15.6.2.1.1 Accidant Description - Sample-Line Break: The sample lines and the. isolation.valvec inside'and outside Containment are open only when sampling is being performed. The. sample lines'are the pressurizer.. sample lines and the RCS hot leg sample lines. Outside Containment the isolation valves on these lines are pneumatically, operated; inside Containment the valves are solenoid operated. This accident is classified as'an ANS Condition II event, fault of moderate. frequency. The postulated failure of a sampling.line outside Containment would take place: between the isolation valve outside Containment and-the sample panel. A break-j 45 in this area would result in the release of primary coolant to the Mechanical Auxiliary Building (MAB). Since the isolation valves are open only.when sampling is being performed, the indication of the break to plant personnel is the loss of-sample flow at the sample panel an indication of increased RCS inventory loss. There:are multiple indications in the control room which will alert the operator to a possible primary leak in the MAB (MAB area radiation monitors, MAB air 57 i monitors, pressurizer level deviation alarms, charging-flow / letdown flow l alarms, etc.). Upon indication that a sample line break-has occurred, the 'I l operator will take action to close the containment isolation valve. The release of primary coolant through the isolation valves before closure is l limited by flow restrictors. located at the. junction of the. sample' line.and the sample point (i.e., the hot 166 or,the pressurizer). These restrictors limit the flow to an approximate maximum of 100 gal / min, well within the charging system capacity of 160 gal / min. -Offsite doses.are based on'the release of 3,000 gallons of fluid due.to the break. 15.6.2,1,2 Accident Description Letdown Line Break.The postulated failure of the CVCS letdown line outside Containment would result in the 15.6-3 Amendment'57-

ATTACHMENT 3 ST.HL AE d404 STP FSAR DAgFQs OF(45 - 1 Table 15.6 1 TIME SEQUENC5 OF EVENTS FOR INCIDENTS VHICH CAUSE A DECREASE IN REACTOR COO 1 ANT INVENTORY . ) Accident Event Time (sec) Inadvertent opening Safety valve opens fully 0.0 l of a pressurizer safety valve 5..r Overtemperature AT rer.ctor trip M setpoint reached [ 0.' O Sy Rods begin to drop M Minimum DNBR occur M (0.6 j i l ~l' l l \\ l l l* l - i 1 l 1 i e 4 1 1 i / I 15.6-24 Amendment 57 _ _ _________ _ ____1 ___ -._.:--_____u_.

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10. 15, 20. 25. 50. 55. 40. 45. 50. 55. 60.

TIME (SEC&JD$) 4He**ew >\\0 M LhM. $$. $ - l

...a. ATTACHMENT ' 3 . ST HL AEfky e (

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f I i l I I I I l l 1 1 I I l l l N. t [=00 w ~ , 1900 E l E 1600 I 1400 l E:i 00 1000 \\ / i 820 i <j i E 600 L l w I E 580 E u WD aC $ MO I ilE s m B== 1 I I I i 1 1 I I I I I o s 10 is 30 as 30 as 40 4s s0% ~eo es 70 TIME (SECONDS) \\ s E N' W Wuh0A % SOUTH TEXAS P'ROJECT -hn (t) juts UNITS 1 & 2 (' PRESSURIZER PRESSURE TRANSIENT & CORE AVERAGE TEMPERATURE TRANSIENT FOR INADVERTENT OPEN-ING OF A PRESSURIZER SAFETY VALVE i Figum 15.8 2 Arnandment 57

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TIME iSEC OW.D.5) ~ l l ? IM Rp IT.6-L {bt%cwe-) l 1 l

~- - ' \\ ' A"TACHMENT 3 o 1 i i S" HL AE A04 PAGEIG OFIe6 I i i (* l 45 l 4D 35 I 3D 1 i 35 ~ l I 2J = 93 I I I I I I I I I I I 12 ~ 00 \\ S 0 5 q0 15 20 25 30 35 40 '45 80 55 70 ~ TIME (SECONDS) ~ MlA/ h d SOUTH TEXAS P'ROJECT UNITS 1 & 2 DNBR TRANSIENT FOR ^ INADVERTENT OPENING OF A PRESSURIZER SAFETY VALVE f Figure 15.6 3 Amendment 57

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.t S ATTACHMENT .ST HL AE 2469 ? STP FSAR PAGE (o4 OF G5 l 1 .N 2. Typical maximum allowable time deleys in generating the actuation signal for secondary system break protection, in addition to the above, are: a. Steam line pressure (from which 0.6 seconds steam line pressure rate is ala,o derived and to which add 0.5 see) --{kemotde ti-,wt ow4ea

4. r voow b.

Tcold ( '---* '- r ':rh n cold ,$df seconds with flow i 4 ,u 185) Z i r s,__ .m % -- - __ n ;;, 43 c. Actuation signals for auxiliary 2.0 seconds feedwater pumps (steam generator l water level) l d. Primary loop flow 1.0 seconds l e. Feedwater flow 2.0 seconds 3. The time delay in generating the Containment ventilation signal for a l l fuel handling accident inside containment. is the total of the time 43 { l delay in the radiation monitors and the time delay in the Solid-State i Protection System to generate the Containment ventilation isolation j signal. The maximum allowable time delay 4s 12.5 seconds for the desi n 53 58 { 5 basis release analyzed in Section 15.7. 1 7.3.1.1.5.6.2 System Accuracies - l. Typical accuracies required for generating the reSuired actuation )[. . signals _for Reactor ~ Coolant _ System break _protaction mra- / l i.. .---.g..--~~ Pre ssurizer pressure " ' ' '~' ~ (uncompensated) 114 psi b. Containment presrure 11.8 percent of 57 full scale 2. Typical accuracies required in generating the required actuation signals for secondary system break ptotection, in addition to the above, are: a. Steam line pressure 12.5% of span b. T 1 eold c. Actuation. signals for auxiliary feedwater pumps (steam generator 12.3 percent of span 43 water level) d. Primary loop flow 12.75% AP span 13 l 7.3-8 Amendment 58 t

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