ML20147D314

Steam Generator Tube Rupture Event Operator Action Times Using Vogtle Simulator

ML20147D314
Person / Time
Site:	Vogtle
Issue date:	02/28/1987
From:	SOUTHERN COMPANY SERVICES, INC.
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References
NC-7002, NCA-7002, NUDOCS 8803030285
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ENCLOSURE 2 SGTR Event Operator Action Times Using Vogtle Simulator NCA-7002 b

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Southern CompanyServices

, a, ,.c,,.,,. ,, c .. m 8803030205 080229 PDR ADOCK 05000424 P pop , ,,

l SGIR EVENT 04'ERATOR ACTION TIMES USING VC,7tLE SIMilATOR r

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4 February 1987 l i

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Nuclear Core Analysis Nuclear Safety and Fuel Southern Company Services, Inc.

P.O. Box 2625 i Birmingham, AL 35202 l

i IMIORTAE NOTICE This report was prepared by Southern Company Services (SCS) for use by Georgia Power Company (GPC). The infomation contained in this report is believed by SCS to be an accurate and true representation of the facts

)nown, obta:eed, or provided to SCS at the time this report was prepared. i.._ use of this infomation by anyone other than CPC, or for cny purpose othei chan that for which it is intended, is not authorized.

With respect to unauthorized use, neither SCS nor any contributor to this document: (a) makes any warranty, express or implied, with respect to tie use of any infomation, apparatus, method, or process disclosed in this report or that .uch use may not infringe privately owned rights; or (b) assumes any liabilities with respect to the use of, or for damages resulting f rom the use of, any lafomation, apparatus, method, or process disclosed in this report.

CONTENTS PAGE SECTION 1

1. I h~1RODUCT I ON . . . . . . . . ., . . . . . . . . . . . . . . . . .

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2. SELECTION OF SGTR SCENARIOS 4

3. SGTR RECOVERY OPERATIONS . . . . . . . . . . . . . . . . . . . .

4. C0FiPILATION OF f fEASURED DATA . . . . . . . . . . . . . . . . . . 7 4

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5. ANALYSIS OF OPERATOR ACTION TIrcS. . . . . . . . . . . . . . . .

6. CONCLUSIONS. . . . . . . . . . . . . . . . . . . . . . . . . . . Il

7. REF ERENCES . . . . . . . . . . . . . . . . . . . . . . . . . . 12 i

~ - - - - - - _ _ _ -_______ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __

TABLES PAGE TABLE SGTR SCENARIO LIST 14 1

15 2 TIhE INTERVALS FOR SGTR RECOVERY ACTIONS 16 3 MEASURED SGIR OPERATOR ACTION TDES FOR BASE CASF & LOOP EFFECTS FEASURLJ SGIR i PERATOR ACTION TBES FOR SINGLE 17 4

FAILURE EFFECTS ON BASE CASE MEASURED SGTR OPERATOR ACTION TIMES NR li2P 18 5

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, 6 FEASURED SGTR OPERAIDR ACTION TDES FOR BASE

! CASE 6 LOOP EFFECTS FEASURED SGTR OPERATOR ACTION TIhES FOR SINGLE 20 7

FAILURE EFFECTS ON BASE CASE 21 8 SG1R OPERATOR ACTION TDES 22 9 DELAY TIMES IN OPERATUR ACTION AND/0R SYSTB1 RESPONSE DUE TO SINGLE EQUIBENT FAILURES ii

1. IRIRODUCTION The analysis of the design br sis steam generator tube rupture (SGTR) accident for Plant Vogtle is presented in Chapter 15 of the Final Safety Analysis Report (FSAR) documented in Reference 1. The accident is the complete severance of a single steam generator tube that results in the leakage of reactor coolant into the secondary side of the steam generator. Consistent with the current Westinghouse design practice, it is assumed in the FSAR that the accident diagnostics and isolation procedure can be completed by the operator within 30 minutes of the tube mpture initiation. Howe ve r, following the SG event that occurred at the Ginna Plant in January 1982, it appeared that the time reasired for the operator to teminate the leak into the ruptured steam generat )r was longer than 30 minutes. Therefore, the validity of the traditional assumptions, particularly that of operator action time, has been gjestioned. In addition, the gialification of certain ecpipment that is used to mitigate a SGTR may not confom to the licensing basis criteria.

The consemences of a Sm event depend largely on the ability of the operator to take the necessary actions to teminate the primary to secondary leakage. If the leakage continues significantly beyond the 30 minutes assumed in the FSAR accident analysis, the secondary side of the steam generator (SG) may become filled and water may enter the steam line. If the leakage continues, the release of limid through the secondary side relief valves to the atmosphere could result in an increase in the radiological doses. The stmetural integrity of the main steam lines may also be of concern due to the accumulation of water in the steam line.

The concern over the potential for overfill and its consegiences was expressed strongly by the Nuclear Regulatory Commission (NRC) to the extent that they initially considered the resolution of the SGTl issue a condition for licensing plants under construction. (The NRC has recently sof tened their position and extended the time for the resolution of this issue until the first refueling outage. ) In order to resolve the SGIR issues, a subgroup of utilities in the Westinghouse Owner's Group (WOG) was fomed to address the issues on a generic basis. The subsecuent Westinghouse generic analyses of a SGTR event with the inclusion of operator action times are documented in WCAP-10698, "SG'IR Analysis Methodology to Determine the Margin to Steam Generator Overfill," (Reference 2), Supplement I to WCAP-10698, "Evaluation of Of fsite Radiation Doses for a SGTR Accident," (Reference 3), and WCAP-11002, "Evaluation of Steam Generator Overfill due to a SG'IR Accident," (Reference 4).

The Westinghouse methodology for inclusion of operator actions used in KCAP-10698 and its supplement are based primarily on the operator T action times taken during tM simulation of SGIR recovery operations. The simulations were perfomed as part of the validation of Revision 1 of the Emergency Response Guidelines (ERGS) using the Seabrook Plant training simulator. Extended operator i action times were used in KCAP-11002 to postulate an overfill e vent . Plant Vogtle's Emergency Operating Procedures (EOPs) are 1

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also based on Revision 1 of the ERGS. However, plant-specific differences in design and ecnipment could impact the operator ac*lon times and plant response time re(pired to complete the recovery operations as a result of a postulated single failure. For instance, the accessibility of the block valve on the ruptured steam generator power-operated atmospheric relief valve (POARV) which is failed open, i.e., stuck open, can significantly affect the operator action times and subsecpent recovery operations.

The plant-specific differences have also been addressed by the NRC in their draf t Safety Evaluation Report (SER) on Eupplement 1 of WCAP-10698 (Reference 3). In addition, the SGTR analysis for t k SNUPPS reactor (Reference 5) recently submitted tc the NRC for approval has indicated that there are significant differences in the operator action times between SNUPPS and WCAP-10698 and the Supplement 1 to WCAP-10698 analyses. The SNUPPS analysis used simulator-derived operator action times with plant-specific procedures which are also based on Revision 1 of the ERGS.

Recogni:ing the importance of the plant-specific differences and their impact on operator actions, a plan was fomulated and used to monitor and record response times of the Plant Vogtle operator training students. The response times were recorded during a series of simulated SM events using the Plant's training simulator.

Details of the plan are presented in Reference 6 and the recorded data are documented in Reference 7. The Sm event simulation scenarios were incorporated into operator training exercises and carried out over a period of one week using six different operator training crews. In addition to the nominal base cases, the SGTR scenarios included a selected set of single egiipment failures identified in WCAP-10698 (Reference 2). It may be noted that at t he time of the recordings none of the operator training students were licensed for Plant Vogtle, thus the resulting response times should be viewed as conservative.

The objective of this report is to compile the recorded operator actions times and, more importantly, to de:emine a realistic set of plant-specific on:rator action times for the base case scenario.

Also detemirnd are the delays in operator action times associated with the i+ atification of the single egiipment failures and correct vt actions taken during the Sm recovery operations. The operator action times described herein can be used as input f or t he plant-specific SGIR analyses to resolve the licensing cuestions concerning Plant Vogtle. The above operator action times can also be compared directly with those of WCAP-10698 (Reference 2) to provide a measure of differences between Plant Vogtle and the plant used in the generic study. The scenarios for which operator actions were recorded are described in Section 2. Section 3 presents the Sm recovery operations and Section 4 provides the compilation of the recorded data. The detemination of major operator actions that represent those of Plant Vogtle is given in Section 5, 2

2. SELEGIM OF SG1R SCENARIOS A list t SG'IR scenarios for which operator actions were recorded is given in Table 1. The SGIR accident occurring at hot full power (HFP) followed by a loss of offsite power (WOP) coincident with the reactor trip was considered to be the base case scenario as shown in Table 1. It was conservatively assumed that the accident is the complete severance of a single tube, and it was placed at the end of life (EOL) conditions in all scenarlos. The WOP assumption tends to prolong the recovery operations, such as reactor coolant system (RCS) cooldown and depressurization, which increases the total primary to secondary leakage and is thus conservative also. The base case scenario was repeated four times using different operating crews and different operating shif t intervals. The reason for using four different crews in different intervals was to determine a set of statistically meaningful operator response times for the base ca:e event.

Hot full powei scenarios, ^th.-. than the base case, were repeated only twice each a order to evaluate the effects of offsite power and emipment failure on the operator action times. The effects of WOP were evaluated both on plant response and operator action times by comparing the LOOP cases (Scenario #1) with those of no LOOP cases (Scenario #2). Tir single emipment failure scenarios were chosen f rom those considered in Reference 2 which were shown to be limiting or potentially limiting. The first single failure scenario shown in Table 1 (Scenario #3) was shown in References 2 and 3 :o be the most limiting in tems of the radiological cose release to the envi rorment. The second, third, and fourth single failure scenarios in Table 1 (Scenarios 34, #5, and #6) were shown in Reference 2 to be almost emally limiting with respect to decrease in margin to overfill (the margin to steam generator overfill is defined as the steam space volume remaining below the steam generator outlet no::le when the primary to secondary leak is teminated).

A f ailure to close the main steam line isolation valm J6IV) on the ruptured steam generator has also been shown in Reference 2 to be as limiting as the above three cases with respect to decrease in margin to overfill. KNever, it was not considered here since Plant Vogt le is emipped with no MSIVs per stean line; the generic plant

analyses assuu d only one MSIV per steam line. Therefore, its consideration would be; beyond the single failure criteria. In addition, a failure in 'he main feedwater control valve to the f aulted steam 3enerator r,s been shown in Reference 2 to be potentially limiting. The affects of this failure on the affected SG is similar to the fallute 4 'he auxiliary feedwater (AFW) .

control valve (shown as scenati.e #4 in Table 1) which can increase the feedwater delivery to the ruptured SG, thereby increasing water level. Considering the periods of operations for these two systems, it is shown in Reference 2 that the f ailure of the AFW control valve is bounding. Thus, the failure of main feedwater was not included here.

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In view of the fact that for a given water level the liquid inventory of a steam generator at low reactor power is more than that of the HFP, it was of interest to examine operator action times for a SG'IR event initiated for low power. Therefore, Scenarios #7 and #8 shown in Table 1 as hot :ero power (HZP) cases were included in the plan to address the operator action times at a very low power level with and without IDOP. However, since in a low-power case the operators are expected to diagnose and isolate the ruptured steam generators earlier than that of HFP, the fomer is not considered to be a base case scenario, and, as such, the single failures are not included here. The exclusion of the low power level as the base case scenario is based on the shorter operator action times (see Section 4) and is consistent with the conclusions of WCAP-10698 (Reference 2).

3. SGIR RECOVERY OPERATIONS In the event of an SGTR, the operator is required to take actions to s stabill:e the plant and teminate the primary to secondary leakage.

\ The actions which the operator is required to perfom to recover f rom a SGTR event are specified in the plant E0Ps. Plant Vogtle's E0Ps (Reference 8) are based on Revision 1 ERGS which represent the most recent and comprehensive guidelines for emergency response to SG'IR events and other accidents. The Revision 1 of the ERGS was issued in September 1983 (Reference 9) and was validated in November 1983 (Reference 10) using the Seabrook Plant training simulator. As stated in Section 1, the generic analysis of the SGTR event perfomed by Westinghouse used eperator action times which had been detemined as the result of this validation effort.

For an event resulting in a reactor trip or safety injection (SI)  :

initiation, the operator enters the ERGS with the E-0 guideline.

The E-0 section of Plant Vogtle's emergency guidelines car. be found in Appendix A. The operator actions in E-0 include the verification of automatic actuations and diagnostics to detemine the appropriate recovery procedure. If symptons of an SGTR exist, the operator is directed to the E-3 guideline which contains the actions for the recovery f rom an SGTR. The E-3 section of Plant Vogtle's emergency guidelines is provided in Appendix B which shows a detailed description of the steps that the operator is expected to take in the event of an SGTR. The steps involved in E-3 include the actions recpired to emalize the RCS and ruptured steam generator pressures, and thus to teminate the primary to secondary leakage. When the instructions provided in E-3 are completed, the plant should be cooled and dapressurized to cold shutdown conditions using the gpropriate sections of the plant E0Ps. Ilowever, since these actions are implemented af ter primary to secondary leakage has been stopped, they are not considered in the evaluation of major operator action times addressed here. There are five major actions required in order to stop primary to secondary leakage which are provided for in the steps in E-3. The five major recovery actions are discussed below.

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a. Identify the Ruptured SG High secondary side activity, as indicated by the air ejector radiation monitor, steam generator bl adown line radiation monitor, or main steam line radiation monitor, typically will provide the first indication of an S:TR event. The ruptured steam generator can be identified by high activity in the corresponding steam generator blowd:En line, main steam line, or water sample. For an SGTR that results in a high power reactor trip, the steam generator water level will decrease of f-scale on the narrow range for all steam generators. The auxiliary feedwater (AFW) flow will begin to refill the steam generators, typically distributing approximately equal flow to all steam generators. Since primary to secondary leakage adds additional inventory which accumulates in the mptured steam generator, level will return to the narrow range in that steam generator significantly earlier and will continue to increase more rapidly. This response provides confimation of an SGTR event and also identifies the ruptured steam generator. In some cases, the ruptured steam generator may be obvious prior to re tctor trip due to steam flow / feed flow mismatch alams or steam generator level deviation alams,

b. Ise ate the Ruptured SG Once a tube rupture has been identified, recovery actions begin by .solating the ruptured steam generator f rom the intact steam generator and stopping feedwater flow to the ruptured steam generator. In addition to minimi:ing radiological releases, thi3 also red"ces the possibility of filling the ruptured steam gene 7ter with water by 1) minimizing the accumulation of feeds ater flow and 2) enabling the operator to establish a pressure differential between the ruptured and intact steam gent tators as a necessary step toward terminating primary to secondary leakage,

c. Co< 1down the RCS

. iter isolation of the ruptured steam generator, the RCS is o oled as rapidly as possible to less than saturation at the ruptured steam generator pressure by dumping steam f rom the intact steam generators. This ensures adequate subcooling in the RCS af ter depressuri:ation to the ruptured steam generator pressure in subse ment actions. With offsite power available, the nomal steam dump system to the condenser will provide sufficient capacity to perfom this cooldown rapidly. If offsite power is lost, the RCS is cooled using the POARVs on the intact steam generators since neither the steam dump valves nor the condenser would be available. It is noted that RCS pressure will decrease during the cooldown as shrinkage of the reactor coolant expands the steam bubble in the pressurizer.

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d. Depressurize the RCS When the cooldown is completed, SI flow will increase RCS pressure until break flow matches SI flow. ConseqJently, SI flow must be teminated to stop primary to secondary leakage.

However, adequate reactor coolant inventory must first be assured. This includes both sufficient reactor coolant subcooling and pressuri:er inventory to maintain a reliable pressuri:er level indication af ter SI flow is stopped. Since leakage from the primary side will continue af ter SI flow is stopped until RCS and ruptured steam generator pressures eq2alize, an "excess" amount of inventory is needed to ensure pressurizer level remains on span. The "excess" amount req 11 red depends on RCS pressure and reduces to zero when RCS pressure ecpals the pressure in the ruptured steam generators. To establish sufficient inventory, RCS pressure is decreased by condensing steam in the pressuri:er using nomal spray if the reactor coolant pumps (RCPs) are rur.ning. This will increase SI flow and will reduce break flov to refill the pressuri:er. With RCPs stopped, nom 31 pressuri:er spray will not be available.

In that case, the RCS is depressuri:ed using either a pressuri:er PORV or auxiliary pressuri:er spray in order to restore pressuri:er inventory,

e. Teminate Primary to Secondary Leakage The previous actions will have established adeq2 ate RCS subcooling, secondary side heat sink, and reactor coolant inventory following an SGTR to ensure that SI flow is no longer needed. When these actions have been completed, 31 t! sw must be stopped to prevent repressuri:ation of the RCS and to teminate primary to secondary leakage. Primary to secondary leakage will continue af ter SI flow is stopped until RCS pressure and ruptured steam generator pressures eqJalize. Normal charging flow, letdown, and pressuri:er heaters will then be controlled to prevent repressuri:ation of the RCS and reinitiation of leakage into the ruptured steam generator.

Since these major recovery actions will be modeled in the SGTR analysis, it is necessary to establish the times req 11 red to perfom these actions. Although the intemediate steps between the major actions will not be explicitly modeled, it is also necessary to account for the time req 2 ired to perfom these steps. It is noted that the total time reg 11 red to cenplete the recovery operations consists of both operator time and system, or plant, response time.

For instance, the time for each of the major recovery operations (i.e. , RCS cooldown, RCS depressuri:ation, etc. ) is primarily due to the time req 2 ired for the system response, whereas the operator action time is reflected by the time regiired for the operator to perfom the intemediate action steps and to initiate the major recovery operations. Thus, the time which is regaired to complete each of the major recovery operations will be deterv4ned, as well as the operator action time regiired for the actions in the intervals between each of the major recovery operations. The time intervals 6

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for the major recovery operations, and for the operator actions l between the major recovery operations, are illustrated in Table 2.

The times which are determined for each of these intervals will then be used as the basis for the SGTR analysis to determine the margin to steam generator overfill.

4. COMPILATION OF MEASURED DATA This section provides the compilation of data obtained as the result of the implementation of a program (Reference 6) designed to monitor and record or erator response times using Plant Vogtle's training simulator. The response times were recorded during a series of simulated SGTR scenarios discussed in Section 2. As stated earlier, the SGTR scenarios were incorporated into operator training exercises and involved the use of six different student crews. The scenarios were conducted f rom October 27 to November 3,1986, and the recorded data are documented in Reference 7 The exercises were conducted at random so that the students did not have any prior knowledge of the scenarios being examined. The training schedule including the SGTR scenarios is found in Appendix C. As mentioned in Section 3, tte operator actions beyond the termination of break flow was not considared here; therefore, the exercises were terminated af ter operators were able to ecpali:e the RCS and ruptured SG pressures.

Tables S-5 give the measured operator action times for all the SGTR scenarios recorded. These data were determined f rom the readings recorded in Reference 7 with respect to the time of the tube ruptu re. Table 3 shows the results for Scenario #1 (four cases),

which is the base case, and the effect of LOOP represented by Scenario #2 (two cases). Table 4 indicates the effects of single failure scenarios (2 cases each) on the base case. Table 5 presents the operator action times for the low power cases. It is noted that the description of operator actions given in Tables 3-5 is broken into more detailed intervals than the major actions shown in Table

2. Tre more detailed intervals were used to measure the operator action times in order to aid post measurement analysis. Some of these subintervals will be combined in Section 5 to determine a set of realistic major operator actions that could be used as input in the analyses of SG'IR events.

As shown in Table 3, the operator action times are not significantly different f rom each other within a given category, nor are they affected considerably by whetter or not offsite power is available.

Table 4 shows that even the occurrence of single ecpipment failures does not significantly alter the operator action times to terminate the break flow. Tle maximum time for break flow termination is about 39 minutes for all cases. It should be noted that in the case of Scenario #3, where the ruptured SG POARV is failed to close (stuck open), it was assumed that it would take eight minutes for an operator to manuallv close the block valve. In five trials documented in References 11 and 12, the eight minutes was the naximum time t ha t it had taken for an operator to lease his station 7

and travel to the location of the stuck open valve and manually close the associated block valve. Because of this delay to isolate the escaping steam f rom the ruptured SG in Scenario #3, the pressure in the ruptured SG is dropped significantly lower in this case than in other cases. Therefore, the period of RCS cooldown in this scenario is considerably longer than others. In the case of Scenario #4, the impact of the f ailure of one intact SG P0ARV to open is that it takes slightly longer RCS cooldown time since there are only two operable intact SG FOARVs available. In the case of Scenarios #5 and #6, there are no appreciable differences in operator action times between these and the base case. It seems that the operator could glickly recognize the failure of the AIM flow control valve to the mptured SG and of the pressurizer FORV (stuck open) and take the appropriate corrective actions.

Table 5 skws the operator action times during recovery f rom a SGTR ovent initiated at a very low power level designated as ICP (see c

action 2). In these cases, the reactor is tripped first followed by establishing the nomal water level in all SGs before the tube rupture simulation was initiated. This is the reason for the Not As noted in Table 5, Applicable (N/A) signs shown in Table 5.

following the tube rupture, the affected SG is identified and isolated much earlier than thase of IFP cases. In these cases, an unexpected increase in the ruptured SG water level starts much earlier than that in IEP, which is a confirmatory sign for identifying the ruptured SG, Two reasons for the earlier water level rise are: 1) at ifP conditions, the reactor and turbine trips occur four to five minutes af ter the initiation of the tube mpture

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during which the nain feedwater flow maintains the ruptured SG water level, and 2) at HFP conditions, there is a significant amount of vapor (void) under the SG water mixture level. The total time to terminate the break flow is also considerably shorter than the IEP cases. Therefore, the low power cases will not be considered in the next section where a set of bounding operator action times will be de te rmined.

Tables 3-5 establish the compilation of al? measured operator action times recorded during SGTR exercises. Other information maintained as part of the documentation of each SG'IR exercise are a videotape of the entire recovery operation, a magnetic tape generated by the sinulator sof tware, operator log sheets, and a set of special foms (see Reference 6). The times on the videotape and magnetic tape were synchroni:ed, and the clock time recordings were based on the videotape timer displayed on the TV monitor. The clock time recordings taken on special foms provided the basis for the data documented in Reference 7 and the information presented in this report.

5. ANALYSIS OF OPERATOR ACTION TIMES Relatively detailed operator action times for all SGTR scenarios recorded were given in the previous section. The relevant data presented in Section 4 is combined in this section to determine a 8

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,k b set of realistic major operator action times for Plant Vogtle. Also [ k detemined are the delays in operator action times associated with g98 the identification of single ecpipment failures discussed in g,cW -

Sections 2 and 4 and subseqJent corrective actions. The operator y$p

- action times detemined in this section can then be used as input in  % A:

the plant-specific analyses of SGIR events to address licensing h -s I qJestions concerning Plant Vogtle. @... ". '., "

F Tables 6 and 7 present the measured time intervals rounded off to ' .g l the nearest minute between major operator actions obtained f rom the e ~ s. .

data shown in Tables 3 and 4, respectively. The descriptions of 3 i

i operator actions are similar in fomat to that shown in Table 2 j%! t 1 except that the first three intervals shown in Table 2 are combined '[( $".

k and shown as the first time interval in Tables 6 and 7. Plant Vogtle's current E-3 guidelines (see Appendix B) direct the operator

%s to identify a ruptured SG by either an unexpected rise in any SG m

narrow range level or high radiation f rom any SG steam line. In all 5 scenarios examined, the high radiation level indications were

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received shortly af ter the initiation of the tube rupture, and the

! unexpected water level rise was used to confim the identification er of the mptured SG. However, since the identification of the l

s mptured SG and ultimately its isolation is of particular interest here, these functions have been combined into a single time interval.

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@ As stown in Table 6, availability of the offsite power does not seem

= to result in observable differences in the operator action times.

E- This is interesting because they involve the use of different

egalpment during recovery operations. Fer example, in the base case a (i.e., Scenario #1) the E0Ps direct the operator to use the intact SG FOARVs for RCS cooldown as opposed to using the steam dunp valves L in the case where offsite power is available (i.e., Scenario #2).

In addition, a closer look at the single ecpipment failure cases _

a shown in Table 7 reveals that, except for a few time intervals, the

effects on operator action times are very comparable to those of the g(pj. -]r F base case. For the cases where there are rather large differences r in a given time interval, there are clear indications of the impact 4.sa. f 1 of the corresponding ecpipment failure. For example, a large period of cooldown for Scenario #3 in Table 7 compared with the base case fd8 f5 in Table 6 can be explained by a larger pressure differential 1.h y$ r-h-

- between the RCS and ruptured SG introduced by a stuck open relief  %~ wo e' n'

E- valve. Additionally, the isolation of the ruptured SG in Scenario E #5 in Table 7 can be corrected to account for a one minute delay E associated with the identification of a failur- in the AFK flow control valve and the subseglent corrective action (also see Table L

9).

? The above observations imply that the data associated with the single failures in Table 7 can be used not only to evaluate the effects of ecpipment failures, which will be discussed shortly, but 5 also to expand the data base in the statistical analysis cf operator action times for the base case. Table 8 shows the average, standard deviation, and maximum expected operator action times to recover

- f rom a SGTR event for Plant Vogtle. They were obtained by combining data in Tables 6 and 7 while excluding or correcting the time a

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intervals in Table 7 for which the effects of single failure could be isolated. The footnotes in Tables 6 and 7 identify the time RI @ M.

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intervals which were corrected or not included in the statistical du analysis. Also shown in Table 8 for comparison is the corresponding operator action times used in the generic study perfomed by Westinghouse (MCAP-10698); as mentioned earlier, these operator action tices were obtained as part of the validation of Revision 1 of the ET.Gs using the Seabrook simulator.

It is note.d in Table 8 that the average operator action times are in good agreement with those of WCAP-10698 except for the period of RCS depressurization. The period of depressuri:ation of RC3 in ..

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WCAP-10698 is given as eight minutes. The examination of the .~ 5 Westinghouse calculated depressurization time interval indicates 9 y-that it does not exceed two ninutes which is in agreement with the Vogtle simulator predictions. This finding does not invalidate the .

SGTR analyses of WCAP-10698 because the period of depressurization b e was actually calculated in the Westinghouse analysis. However, i t m is does imply that either the Seabrook procedures for RCS depressurization is too restrictive or the pressuri:er relief is limited in capacity. It is also possible that the Seabrook t_ ___ *_-

simulator sof tware is too slow in response during this period, g

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Even though the average operator action times for Plant Vogtle are .

bounded by those of WCAP-10698, the "maximum" measured times are -

recommended for use in connection with the plant-specific analyses.

Since the average times and their standard deviations stown in Table 8 represent only the estimates of the tme means and standard deviations for those time intervals, the tolerance limit statement can only be made with a given probability attached. Assuming a nomal random variable for all time intervals in Table 8, thi s probability is expressed in "at least a proportion P of the normal population is lecs than x + ks with probability (confidence) ecpal to p," wh m x is the sample mean (average), s is tre sample standard deviation, and k is the factor for one-sided tolerance limits for a normal distribution (Reference 13).

Using the reconmended (or maximum) expected operator action times shown in Table 8 as the upper tolerance limits, it can be stated that at least 75 percent of the operator action times are lower than 4 maximum with 95 percent confidence. The last column in Table 8

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.g shows an extremely conservative upper tolerar.re limit for the same samples identified by 95/95 confidence level. This can be '

interpreted as at least 95 percent of the action times are below those values with 95 percent confidence. It should be noted that the limited ntnber of samples used to determine the averages and standard deviations is the reason for relatively large values of operator action times in this category. They are provided as reference only. In fact, it may not be possible to adhere strictly to these very conservative time intervals because it might cause

adverse operating conditions in conflict with the plant E0Ps. For .

example, the RCS cooldown for a period longer than necessary ;ould overcool the RCS unrealistically beyond the conditions prescribed by the E0Ps. As stated earlier, tre recommended or maximum times given o

10 il 21 7,

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in Table 8 provide a set of bounding, yet realistic, operator

response times that can be used for plant-specific analysis of SGTR events.

e Table 9 gives the estimated delay times in operator action and/or system response due to single eq2ipment failures. The delay in 1 operator actions includes the time it takes for the operator to identify a single eglipment failure and to take corrective actions.

The delay in system response includes the extra time it takes the E system to respond due to a degraded condition induced by the i eglipment failure. For example, as pointed out earlier, in the case v of a stuck open SG P0ARV on the ruptured SG (Scenario #3), it takes an additional five minutes for RCS cooldown because of the increased 4 g difference between the RG and ruptured SG pressures due to the _ _ _

l 8 f ailed relief valve, Y s&. , e o; r It should be noted that, except for the delay time in operator T actions for Scenario #3, the data stown in Table 9 is estimated $1[,L

& ,6 based on engineering judgment and comparisons of Tables 6 and 7. As @.

mentioned previously in Section 4, in the case of Scenario #3 there . M ~ ;ig g was an eight minute time lapse allowed for an operator to manually J/ D) "

• isolate the failed valve. It is reali:ed that a major portion of P, M l

=

this eight minute time lapse overlaps with the 12 minutes (maximum) isolation time of the ruptured SG shown in Table 8. However, for 4' g"i E conservatism it is assumed that the eight minute delay occurs beyond the isolation time interval. Other delay times shown in T.* ale 9 were also estimated in the conservative direction to prolong recovery times and maximi:e the break flow in each scenario, n The ref ore, there was no credit taken wPen the egiipment failure

{5 resulted in reducing any of the recovery intervals. In cases where .

some delays were expected, such as that in Scenario #6, a i k conservative estimate of one minute was used even though the Wg' "

y recorded data was not clear in showing such a delay. This type of ,

- conservatism was introduced to of fset the round-off errors. _

q g Table 9 shows that a given equipment failure can result in delays in

= both operator actions as well as system response. The g identification of the type of delay is important because, in the i plant-specific analyses of SGIR events, only the operator action _ - - - -

times and their associated delays are directly input in the f  ?

themohydraulic calculations. The system response and its 3.3 q ;,M z{p 6 corresponding delays will be predicted as part of the analytic ,

g calculations. Q ..gl i_

1 6. (DNCIA!SIONS h2f '3 r .:

Plant Vogtle's operator training students were monitored during a l' J :

series of simulated SGIR events using the plant's training simulator 9 .4-and E0Ps. The measured operator action times during the SGTR " . , .i "

_ recovery operations were compiled and a set of conservative, yet f . ,

realistic, operator response times were established. Also g :f a detemined was the delay times in recovery operations introduced by 'W-

,x ;.3. .v ..

y

~

11 s

c E

-f

. 11

a set of single egalpment failures. The evaluation of operator action times has resulted in the following conclusions:

o The average operator action times for Plant Vogtle ac- bounded by those used in the generic SGTR study reported in WCAP-1660.

which were based on the validation of Revision 1 of the ERGS on the Seabrook simulator.

o The maximum operator action times which are recommended for use as input for the plant-specific analyses are comparable to those of WCAP-10698. Though slightly longer in a few subintervals, the total operator action times for termination of the break flow is still bounded by that of WCAP-10698. -

o The loss of offsite power and single eq2ipment failures did not seem to have very significant effects on the operator response times, except in the case of Scenario #3 where the ruptured SG POARV block valve was to be closed nanually.

It may be noted that at the time of the measurements, none of the operator training students participating in this project were licensed for Plant Vogtle. Therefore, even though the results are a reflection of the gjality training programs at Plant Vogtle, it also implies a degree of inherent conservatism in the operator response times.

7. REFERENCES

1. "Vogtle Electric Generating Plant Unit I and Unit 2 Final Safety Analysis Report," VEGP-FSAR-15.6.3.

2. WCAP-10698, "SGTR Analysis Methodology to Determine the !!argin to Steam Generator Overfill," December 1984.

3. Supplement I to WCAP-10698, "Evaluation of Offsite Radiation Doses for a SGIR Accident," March 1986, 4 WCAP-11002, "Evaluation of Steam Generator Overfill Due to SGTR Accident," February 1986.

5. "Steam Generator Single-Tube Rupture Analysis for SNUPPS Plants Calloway and Wolf Creek," December 1983.

6. "A Plan for Measuring SGTR Event Operator Action Times Using the Vogtle Simulator," Southern Company Services, NCA-7001, October 1986.

7 "Plant Vogtle - Units 1 6 2, SGTR Operator Actions," letter f rom G. Bockhold, Jr. to J. A. Bailey dated November 14, 1986.

8. Vogtle Electric Generating Plant Emergency Operations Procedures.

12

i

9. "Westinghouse Owners Group Emergency Response Guidelines -

Revision 1," September 1,1983,

10. "Emergency Response Guidelines Validation Program Final Report,"

C. E. Meyer, WCAP-10599, June 1984

11. "Plant Vogtle - Units 1 6 2, SG1R Operator Actions," letter f rom G. Bockhold, Jr. to J. A. Bailey dated August 14, 1986.

12. "Plant Vogtle -Units 1 6 2, Operator Response Time - SGTR Events," letter f rom W. F. Kitchen to P. D. Rushton dated  ;

September 15, 1986.

13. "Factors for One-Sided Tolerance Limits and for Variables Sampling Plans," D. B. Owen, Sandia Corporation, U.S. Department of Commerce, National Technical Information Service, SCR-607, March 1963.

s 13

a= .

TABLE I SGTR SCENARIO LIST (DESIGN BASIS SINGLE TUBE RUPTURE AT EOL CONDITIONS)

SCENARIO a SCENARIO IO DESCRIPT?ON I SGTRIA HFP with LOOP SGTRfD 4 CASES (Ba5E CASE) 5GTRIC SGTRIO 1

2 **

HFP without LOOP SGTR2e l i

i i

3 $GTR3A 2 Cases HFP With LOOP & Fallure SGTR35 of Ruptured SG POARV to Close once Opened (Stuck Open) 4 5GTR4A 2 Cases HF P Wi t h LOOP & Fallure $GTR4B of Intact SG POaRV to Open 4

5 5GTR5A 2 Cases HFP With LOOP & Failure SGTR58 of AFW Flo Control valve to Ruptured SG to Close Once Opened (5tuch Open)

HFP with LOOP & Fatture 6 5GTR6A 2 Cases SGTR68 of Pressurizer PORV to Close Once Opened (5tuch Open)

HZP with LOOP 7 SGTRTA 2 Cases SGTR78 HIP W e t he',c LOOP 8 SGTR8A 2 Cases SGTR88

n o

t n t o a i r t t a r n n u i o n s m S i w s r N t o e e O a d r t I l l p T o o e 1 C s o d 5 A I c o e Y e e t t R t t e e E e e t l V G l l t t O S t t t t C t t n n E d n n i i R e i i r G o o 2 R T t u o t S

t o t S C

t E G p d e R e n L S u e e e m m o B r m r m i f i i A R i u i t o t t T O f t t t a F o p n n n z n u no S o o o i S n o r C t i i l L o i i R t t t a A i t f t c s c u q

V t c o c f p s a R a a a o t e E c n n r n T t r o r n o u o e s

N f o t o w t s t r I t t t t o t s t u t a e a ld a e e s E n r l r r r r s M e e o e o peo p e e I d p s p e p r T I O I O C O D O P 1 2 3 4 5 6 7 9 9

• n eO

TABLE 3 MEASURED SGTR OPERATOR ACTION TIMES FOR BASE CASE & LOOP EFFECT5 TIME 5 (MIN 5EC)

I OPERATOR l SCENARIO ID ACTION l DESCRIPTION SGTRIA SGTR18 SGTRIC SGTRID SGTR2A SGTR28 A. $G TUSE RUPTURE OCCURED 00:00 00:00 00:00 00:00 00:00 00:00

8. REACTOR TRIP VERIFIED 03:40 02:26 01:49 05:50 05:20' 03:30 C. E-O GUIDELINES OF THE EOP 03:41 02:30 02:03 06:00 05:15* 03:32 ENTERED D. STILL IN E-0 IMMEDIATE (a) 03:54 04:30 08:00 07:40 (s)

OPERATOR ACTIONS COMPLETED E. THE E-3 GUIDELINES OF THE 09:46 06:58 06:28 10:55 t0:24 07:26 EOPS ENTERED F. PER E-3 THE RUPTURED SG 10: 19 07:13 06:43 18:13 10:38 08:02 IDEN)IFIED G. PER E-3 ISOLATION OF THE 10:25 07:07 06:48 11:28 10:49 08:10 RUPTURED $G BEGAN H. PER E-3 ISOLATION OF THE 11:30 08:11 07:47 12:24 ft:40 09:45

p. RUPTURED SG COMPLETED Ch I. PER E-3, RAPID COOLDOWN OF 17:25 15:23 12:35 89:25 19:00 14:40 RCS SEGAN J. PER E-3. RAPID CDOLDOWN OF 23: 15 87:53 18:25 24:30 25:18 23:20 RCS COMPLETED j M. PER E-3, RAPID RCS DEPRES- W4:43 20:03 19:49 26:05 26:30 22:25 '

SURIZATION 3EGAN L. PER E-3, RAPID DEPRES- 27:10 22: 12 21:41 27:24 28:20 24:30 SURIZATION COMPLETED M. PER E-3, BEGAN STOPPING 28:34 23:00 22:25 28:42 29:10** 25:30 ALL ECCS FLOW N. PER E-3, COMPL ETED STOPPING 30:17 28:52 24:20 30:00 30:55** 27:15 ALL ECC5 FLOWS

0. PRE 55URIZER AND RUPTURED SG 35:00 31:04 27:59 35:00 28:15** 38:45***

PRES 5URES EQUALI2ED (a) Could not be determined.

• Reactor trip mes doctored efter the E-O had entered.

• • The RC5 and feutted SG pressures were actually equel et 28:15 es shoon. BIT (ECCS) mes not Isoleted untti 30:55 by procedure.

• • • At 3t:00 cree seemed more concerned =lth subcooling and cooldoun rete then matching RCS and SGs4 pressure. At 33:27 STA reported 100 PSID between RCS and SGs4 At 34:30 RO empertenced problems piscing letdown in servtce. At 38:45 crew terminated esercise et 50 pold.

I

e O e N @ N e n ~ O O O e w Q N T N N Q = @ Q @ e g m = m n fi.

. . =e>

>. O N N a D D D  % @ N n @ @.. e e ew=

0 C Q Q w w w w Q = N N N N N N e3= D e e 3C4 e 4 Oe 3 =

w eEw e 6 u =

C ee O e

4 O M O @ @ h @ @ @ O 9 @ @ O M - D

@ Q O O = n 4 @ = @ = @ = N n Q CCe **

g O eee

• e O N N @ G e e m @ N N 9 @ h N e S O O O O O O O Q Q = N N N N N f4 g ea O e 3 >e> C

= =su u e e e C >eQ e w == 6& B e e O O O @ N N O O O O O h e @ O Ce 4 @ O M @ t Q t D n N 9 N = M O M ** OCC g es e

^

H y g - O

> 0 m M @ p @ @ O M Q == #9 9 0 k C O *U W O O O O O O O O = = N N N N N N eN eU e e au% bW e e uC 3w

< o e e a 3-e e e e e e es e4 0W Z e e e C e > * *

• O 4 0 0 @ @ @ @ M @ O @ @ M O = N 8 C US

@ Q = = Q = N Q Q N fi T M N = 0 ee * = .

e g 0.. .. g gae

> > 0 T T @ N N N fi @ u h e O N m = *O

• Gb N N m N O

• 3e u

w U a

w O e*QQO O

Q = ** * = = N f7 O

u V=w e=

CD ee 6

6 e == e e me > EB e e 0 e. a. I O w - e e en e ee LI O O O w Q O e .Z == c O e O C @ N @ N O @ @ @

• 9 O = w = = 9 M @ T = a 9 Q Q Ce4 e-w 3 2 ee g w 4 g N.. O.. . - - - - - e - 3 ha C

3 Z > O M M @ h e e e = m O N

fi N

w @-

N N w .V B Od eO

.a e w 0 Q C Q Q O O Q Q *= =

== w U e 6 > =Z e 3 6 0 6 e' e ee a == a Oe& V e

• O **

w e ea ee J d O M e @ @ @ O m @ O e @ O 9 e = b e e 0 w C N N @ = N M = fi f4 @ @ #9 C ede * * =

T Z E * ** ** ** ** ** ** ** -- - ** C - Q** ** +* > Qe O 3e

== > 0 mm @ h h 5 e N O = T @ @ = 0 = C3 w e 0 Q Q Q Q Q Q Q Q = N N N N N f4

• PW =0 e M O Ge

.J c & w I @f

• h eh c Q o N N == =

> m e p Q9e O=

e M e O C O O OO O O O O OO O OO C =3 =e w m Q Q Q Q Q Q Q Q Q Q O Q Q o - ** = C 3 3 g .. - Q- 6 q .= e ew

== > 0 m f5 @- e e e @ M M 9 @ h e @ e E 3u

> 0 Q Q Q 3 o o O C = N N N N N n * * . ee De e C6 V4 0 2 99 e w Qe o t C + Qb

== ee eve 4

> e 6 en aee f5 5 U e O = @ O OO O N @ e = @ O e e O Oe4 -

4 m Q QQ M N @ @ @ = N fi f7 @ Q == C e e g T. .. .. . oO > .O. en e aW 5 > O @ @ h @ O O = m O ** M T @ e &* eb 3

Q O O Q Q Q Q = = = = n M M M M n en e *

> e eu O>= De 4 Ce 4= ee a O == 9 ee w =bVaeE Ob .

a ee oet3- == Q e Q ~ we*DeC* W b e a 6 ** e d3 g d 0 6 O=Ee heV

> 0 E E I Z e Ceu3 4 = e 0 & ww w w Q Q H = a a e e e en -Uu aeO e Q >I O I I w & O w O 6 e. &

O w ww> @ > > Z Z a 0 a w w e =3*b O w > .a 3 3 4 I Z Q m e t- ** >**a*= 4 w a O w 4at O E ECO O w e =

• 3 ** O00m50u3 a 3 w I == 3 Q w Q QwQ Q Q WQ4 e > e CH4=@eeh 3 v == > QQ R > .J .J Ewa &O ==C Q2= == a e U E wWe 3 Z ZwQ Q @ &>Q O 3w VQOeN&a@>

< Q = k 3 w > Q Z Q .J Q Q U WW> w eE*

g0begde **EIb eCe w Z a O 202 a m e o. a u u m 2 Q .a e > M N.

o 3 Q w w == Z = 3 k0>3 4 A w O .J buee e = Q e **

E = a > d O .J a tweQO O C003Z .4 w a Z e O C C 084 e QZ> 3 w *=w .a e .J u == == 0 = w == Q e B & 3 a 3 u e = a w N =* e=

>Q& > & 2 QWCOW O Q & awamav003Q O eOED=t Cou 4==== a == == i U == w I e0e0e e>e a w .J Q .J E w bC6 C@ heeE=

=

EWE 3 E J W 4 Q E m O *= H as e g awaZEZemumw e 0 0 en ee wUV E > w uw w Z .J Q Q Ne ** D w u e = 0 e e **

ase Q ZS > * = = *O *O ** *a *= == *e e d == w O- ee**Ce-C4C Q w w & - O == O M Z m E M w f9 w m 0 M 3 fi > m > m u f9 U m a ZQUd4*Uu>>3 Q c 0 :* w == a w e =

• m I or awI OI eeeeuev33 3 > OzJew www3w3wewwwNwNWwwwee

> U w .J E e Z > > == == 0e ma 4 Q > = w w & E w E & E & E 6 5 O E E E E 2 .J E .J w w em ee *

• d m e Z w a I Q w O w D w 3 w w w v w 3 w D w .s w .J E z ww e*

e a wweQ>wa=asamaa4aheadaestaa e 4 e v O. w w 0 I. = 7 * = 1. 2 0 17

~ _ . _

~_-_ -

. TABLE 5 MEASURED 5GTR OPERATOR ACTION TIMES FOR HZP TIMES (MIN 5EC)

OPERATOR SCENARIO 10 ACTION l DESCRIPTION SGTR7A SGTR78 SGTR84 SGTR88 A. SG TUBE RUPTURE OCCURED 00:00 00:00 00:00 00:00

8. REACTOR TRIP VERIFIED N/A N/A N/A N/A C. E-O GUIDELINES OF THE EOP N/A N/A N/A N/A ENTERED D. STILL IN E-0 IMMEDIATE N/A N/A N/A N/A OPERATOR ACTIONS COMPLETED E. THE E-3 GUIDELINES OF THE 03:38 07:56 02:09 03:49 EOPS ENTERED F. PER E-3 THE RUPTURED SG 04:08 07:56 02:17 04:17 IDENTIFIED G. PER E-3 ISOLATION OF THE 05:30 06.22 02:24 04:28 RUPTURED SG BEGAN H. PER E-3 ISOLATION OF THE 06:42 09:00 (e) 06:03 RUPTbRED SG COMPLETED

,, I. PER E-3. RAPID COOLDOWN OF I4:15 13:00 04:29 12:01 DO RCS BEGAN J. PER E-3 RAPID COOLDOWN OF 20:13 19:50 14:28 19:56 RCS COMPLETED M. PER E-3 RAPID RCS DEPRES- l 23:03 20:24 15:26 (b)

SURIZATION BEGAN H L. PER E-3 RAPID DEPRES- 24:54 21:40 15:57 (b)

SURITATION COMPLETED M, PER E-3 BEGAN STOPPING 26:18 23:29 16:30 (c)

ALL ECCS FLOM N. PER E-3 COMPLETED STOPPING 28:33 23:40 16:36 22:41 ALL ECC5 FLOMS O. PRE 55URIZER AND RUPTURED SG 31:18 25:58 18:54 28:01 PRES 5URES EQUALIZED (e) Not CDepleted.

(b) RCS depressurtzetton not required since RC5 and s2 SG pressure almost equeltzed during the ACS cooldown.

(c) Could not be determined.

l i

llll 8 s 2 ) t R 9 5 7 I 2 I a s T ( y G l

$ a n

a l

A a 2 ' c R 2 7 6 9 2 I O i T 1 t S G s T S t C t E a F t F s E O I e P R 2 7 5 2 1 I 6 h O T 1 t O ) G L S S n E D i

& T I U d E N O e S I I C d A M R I u C ( A R 8 5 6 1 2 1 6 l N T c E S E G s S E C S e A M S S I y T .l R ) e O S 3w F I t R 8 3 7 2 2 1 8 Et S T La E G Bv M S A r I T e T s 6 en N eo E O A sc L I I (

B T R 2 6 7 l 2 1 7 s A C T 1 da T A G ew S t R ee O l u T pl A ma R ov E ,l1llt  ; ' gl1l c

P E s O R t i N U oh R O S nT T OI S ON S G TT C TO E n.

S A R I R o3 EN EZ ET P t D MW MI F MA tE E E I O I R O I N D eL R T TD T0 TI N rB U A L 5 N M A t A S N L NO 5 N5 O NR tT A O O OO C OE I OE N a E R I S IC R IR T IT O ue qe M ONT I T TP A T I N TOP G CE F CE Z C1 TO ES AII &S AT O AD I A5 AI RTR A R NT ECC YD Rl M RE U RE I A )

PAS FE Oi w OT 5 OT MZ a*

O E I R Ti O TA 5 TA RI (

D TU AN D AI E AI EL NT RI L RT R RT TA EP E O EI P EI U DU PO O PN E PN 1Q I R OT C OI D OI 5E 1 2 3 4 5 6 7 e

j I llll l l

TO3LE 7 MEASURED SGTR OPERATOR ACTION TIMES FOR SINGLE FAILURE EFFECTS ON BQ5E CO5E TIMES (MINUTES)

OPERATOR SCENARIO ID ACTION DESCRIPTION SGTR58 5GTR6A SGTR0e SGTR3A SGTR3B+ SGTR4A SGTR4D SGTR5A 12 9 8 9 13** 11** 9 (b)

1. IDfMTIFY & ISOLATE RUPTURED SG 7 4 4 3 6 3 7 (b)

2. OPERATOR ACTION TIME TO INITIATE COOLDOwN 11' 10' e' 8' 6 7 6 6

3. COOLDOwM OF RCS 1 2 1 8 I 4 OPERATOR ACTION TIME TO 1 1 1 INITIATE DEPRE55URIZATION 2 2 3** 9 2 1 2

5. OEPRE$50RIZATION OF RCS 2 1 1 (a) I 1 1 2

6. OPERATOR ACTION TIME TO 1 INITIATE SI TERMINATION ea 7. 51 TERMINATION AND 4 8 7 (a) O*** 3*** 7 2***

C) PRESSURE EQUALIZATION 1

I (a) Not roCorded (see TABLE 4).

(b) Did not complet e E-O ar t t ons bef ore entering E-3 (see TABLE 4). Because E-O and some E-3 octions were i

not completed the period up t o cooldown was not included tn the determination of operator action times.

+ The operator act4en times more recorded only in etnutes for this esercise as opossed to etnutJs and seconde (see TABLE 4). The length of time in each interwat =es then lletted to the mastmum for all other esercises.

• Long cooldoen intervals due to degradation in RCS cooldown per procedures. They were conservettwofy escluded from the stattsttCat analysic However, they were used to evaluate the effects of the equipment failures.

• • One etnute delay time for operator acttons were subtracted from these watues when used in the stattstical analysts.

• • • Escluded from stattstical analysts for conservatism.

l l lj ll 5

9

/ 5 9 8 2 2 I 2 9 5 1 1 4 9

8 )

9 o

_ 6 w

_ O t S 0 5 8 2 8 9 7 i t

_ - 1 d e P v

- r A

C e W s n

o c

y r

e

• v

• (

) M S u l e

S E u v E T I 2 7 7 2 2 2 8 0 M U M 3 4 e l

I N A T I M e M c N (

O n I S e T E d i

C M f 8 A I

• T . n E R - o L O D. 2 2 9 0 0 O 8 - c 8 T 5 -

A A 5 T R 9 E /

P 5 O 9 R o T E t G G g S A R 0 5 6 1 2 I 7 2 n E 1 3 i V d A n o

p s

e r

IR r o

c N

O t OI S ON i TT C TO .

m A R I N n i EN E2 ET O MW MI F MA I lo.l E IO I R O I N OT tt e TO TU TI NA le e. c T

A L 5 N M AZ

• a N L NO S N5 O NR I w 9 O O OO C OE I OE NL odr R I S IC R I R T IT OA dee ONT I T TP A T I U dl TOP G CE F CE Z C1 TQ dno AII &S AT O AO I A5 AE ret RTR A R N emu ECC VD RI N RE U RE IE dm-PAS FE OT W OT 5 OT MR noe ecp O E IR TI O TA 5 TA RU D TU AN O AI E AI E5 L t ep NT RI L RT R RT Y5 A SRU EP E O EI P EI E T DU PO O PN E PN 1R O IR OT C OI O OI 5P T ***

S 2 3 4 5 6 T 1

e 5

O t 4 E

O w

= a a O 4 w A 2 W w O O O O O = Q E u 3 e

.J o=

4 h

> m 5 3 -

3 @ > 3 4  % 4 w

== E >

3 O w e O = a >

w E O O 4 w w w 2

.J w = 0 = 0 0 0 C 0 u 2 e

=

e O

> a e

w W ^ a 3 > 3 3 0 3 e w w 2 4 > >

W = e H e 3 O > >

w == M M g w w M 4 e w Z O O = 0 = 0 O w 3 w

@ m = v

> d W 3

.J w e >

4 A

> > a M E O a a n > 3 0 m 4 w a >

% w M O.

. 4 >

0 E O +

2 4 w w 4 2 W E O 4 O O O O A

U 4

m O

> E 4 O a om A OE w >> U *O

& 4 G en E O WZ WN wp C 33 3 == 6 34 ==

2 W =0 == g O == Z O>

> >Q >3 >== Z4 4 J @ t 3 4H

@ E a 20 + EH O EE **

w Q O OO v 0w == 0w IJ 3 a = e == v a == a > => 04

== OF> == > >a 4 > =3

> >0& O VW w Uw N U ** >0

• • == ef d 4> Q to = 46 4w

> eke 4 8 2 4 wWv >O g oe 2 aw 3 RW =w

.J &4e ww Op o> A O> 3a w O w =a >= >4 H >< a3 O O >3 42 4 en W 4 == we Z> E == J E> E E> WW wa w O w ** a w == W 03 40 O az w az o= E

=a O> W Q == 0 0 == ea

= b b 4 b 22

APPBMX A

4 t

i t

VEGP EOP REY. 1 E-0 REACTOR TRIP OR SAFEIY INJECTION Note: During the recorded SGIR exercises conducted from October 27 to November 3, 1986, the Plant's E-0 procedure used by the student crews was Rev. 0. The current version (Rev.1) given here includes some minor changes compared with Rev. O.

4 i

4 I

l l

1

~~

• Vogtle Electric Generating Plant $9$d'o'.1

/M, i.i.

NUCLEAA OPERATIONS ,,,,,,,

1

/ gy7 unn 1 Georgia Power e.g. ;., g

'4 >r .

p .. .

f [p EMERGENCY OPERATING PROCFDURE

'_.. l'-

E-0 REACTOR TRIP OR SAFETY INJECTION PURPOSE This procedure provides actions to verify proper response of the automatic protection systems following manual or automatic actuation of a reactor trip or safety injection, to evaluate plant conditions, and to identify the appropriate recovery procedure.

SYMPTOMS / ENTRY CONDITIONS The symptoms are:

1. Any symptom that requires a reactor trip, as listed in Attachment A, if it has not occurred.

2. The following are symptoms of a reactor trips

a. Any reactor trip annunciator lit,

b. Rapid lowering of neutron level indicated by nuclear instrumentation.

c. All shutdown and control rods fully inserted (rod bottom lights lic).

3. The followfng are symptoms that require a reactor trip and safety injection, if one has not occurred:

a. PRZR pressure less than or equal to 1870 psig,

b. Steamline pressure less than or equal to 585 psig.

c. Containment pressure greater than or equal to 3.5 psig.

' 4. The following are sycptoms of a reactor trip and safety l injection:

a. Any SI annunciator lit.

b. SI ACTUATED BPLB window lit, l

i

.;wun 80. mevisioN PJGE No 19000-1 1 2 of 27 '

ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED NOTE l Foldout page should be continuously monitored for applicable actions taken.

IMMEDIATE OPERATOR ACTIONS

1. Verify Reactor Trip: 1. Manually trip reactor.

Rod bottom lights - LIT. IT reactor will NOT trip,  ;

e THEN manually open supply  :'

e Reactor trip and bypass Tied breakers to INB08 breakers - OPEN. and INB09. ,

e Neutron flux - IF reactor NOT tripped, LOVERING. TREN go to TV711-1, FR-S.1 E UCNSE TO NUCLEAR POWER '

GENERATION /AT7T.

2. Verify Turbine Trip: ,

a. All turbine stop valves - a. Manually trip turbine.

i SHUT.

3. Verify Power To AC a E=ergency Busses:

a. AC Emergency Busses - a. Try to restore power to at least one AC Emergency AT LEAST ONE ENERGIZED:

Bus.

e IAA02 e IBA03 E power can NOT be restored to at least one AC emergency bus, I THEN go to 19100-1, E 0.0 LOSS OF ALL AC POWER.

i

b. AC Emergency Busses - b. Try to restore power to de-energized AC Emergency ALL ENERGIZED. Bus while continuing with  ;

Step 4  !

l l

l

r ~ n.cuvat Nu. r,EVISloN PAGE No.

19000-1 1 3 of 27 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED l

4. Check If SI Is Actuated: 4. Check if SI is required:

e Any SI annunciator - LIT. IF one'or more of the Tollowing conditions is met:

e SI ACTUATED BPLB window - LIT. e PRZR pressure less than or equal to 1870 psig, e Steam line pressure less than or equal to 585 psig, e Containment pressure greater than or equal to 3.5 psig, e Any automatic alignment of ECCS equipment to injection phase.  ;

THEN SI is required.

IF SI is required, THEN manually actuate.

IF SI is NOT required, TREN go to 19001-1, ES-0.1 NEXUTOR TRIP RESPONSE.

5. Verify FW Isolation: 5. Manually shut valves as necessary, e MFIVs - SHUT.

e BFIVs - SHUT.

e MFRVs - SHUT.

e BFRVs - SHUT.

6. Verify Proper ESEAS 6. Manually actuate SI.

l Actuation:

l IF proper ESFAS actuation cIn NOT be verified,

a. MLB indications THEN continue with correct for injection

! phase after load 5tip 7.

sequencing,

b. Go to Step 14.

1 m

. .wosswne nv. CEVISION DAGE No.

19000-1 1 4 of 27 15 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED l l l l <

l l

7. Verify Containment 7. Manually actuate Phase A.

Isolation Phase A -

ACTUATED: IF slves do not shut, THEL manually shut,

a. CI-A MLB indicators -

COR ".T FOR SI.

3 -. Verify AFW Pumps Running:

a. MDAFW pumps - RUNNING. a. Manually start pumps.

q 3

?! b. SG blowdown isolated:

l 1

e SG blowdown isolation valva.s - SHUT.

e SG sample isolation valves - SHUT.

j c. Turbine-driven pump - c. Manually open TDAFW pump

, RUNNING IF ANY OF THE steam supply valve FOLLOWING CONDITIONS HV-5106.

EXISTS:

l' q e LO-LO LEVEL IN TWO OR h MORE SGs.

e BLACKOUT.

l l 9. Verify ECCS Pumps Running: 9. Manually start pumps.

e CCPs - RUNNING.

I e SI Pumps - RUNNING.

e RHR '? umps - RUNNING.

10. Verify CCW Pumps - TWO 10. Manually start pumps.

RUNNING EACH TRAIN.

11. Verify NSCW Pumps - TWO 11. Manually start pumps.

RUNNING EACH TRAIN.

- - -- PAGE No.

1 5 of 27 19000-1 1~

ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED

-12. Verify Containment Cooling Units:

a. Fans - RUNNING in low a. Manually start fans in speed: low speed.

e MLB indicators -

CORRECT FOR SI.

b. NSCW cooler' isolation b. Manually open valves.

valves - OPEN:

e MLB indicators -

CORRECT FOR SI.

13. Verify Containment Ventilation Isolation:

a. Dampers and valves - a. Manually shut dampers and SHUT: valves.

e MLB indicators -

CORRECT FOR SI.

14. Check If Main Steamlines Should Be Isolated:

a. Check one or more of a. Go to Step 15.

the following conditions:

e Any steamline pressure

- EQUAL TO OR LESS THAN 585 PSIG.

l e Containment pressure

! by recording - GREATER THAN 14.5 PSIG.

e Steamline depressurization rate - HIGH ON TWO OR MORE CHANNELS OF ANY STEAMLINE WITH STEAM PRESSURE SI BLOCKED.

b. Verify main steamline b. Manually shut val.ves.

isolation and bypass valves - SHUT.

l- __

........-..w. AEVsSloN PAGE NO-19000-1 1 6 of 27 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED

15. Check Containment Spray -

NOT REQUIRED:

a. Containment pressure - a. Perform the following:

HAS REMAINED LESS THAN 21.5 PSIG BY PRESEURE 1) Verify containment RECORDING. spray initiated. .

IF NOT, THEN manually actuaCe.

2) Verify containment spray pumps running.

3) Verify containment spray additive flowrate of approximately 40 gpm per operating CS pump.

16. Verify Diesel Generators - 16. Manually start both DGs.

RUNNING.

SUBSEOUENT OPERATOR ACTIONS NOTE 91001, EMERGENCY CLASSIFICATION AND IMPLEMENTING PROCEDURE should be implemented at this time.

17. Verify ECCS Flows:

a. CCP flow indicator - a. Manually align valves CHECK FOR FLOW THROUGH using Attachment B.

BIT.

b. RCS pressure - LESS b. Go to Step 18.

THAN 1625 PSIG.

c. Manually align valves I

c. SI pump flow indicators -

i CRECK FOR FLOW. using Attachment C.

d. RCS pressure - LESS TRAN d. Go to Step 18.

.00 PSIG.

a. RRR pump flow e. Manually align valves

' indicators - CHECK FOR using Attachment D.

FLOW.

e -wswa t W. P.EVISION PAGE NO.

'19000-1 1 7 of 27 RESPONSE NOT OBTAINED  !

ACTION / EXPECTED RESPONSE

13. Verify Total AFW Flow - 18. IF SG narrow range level GREATER THAN 570 GPM. greater than 4% (27% FOR ADVERSE CONTAINMENT) in any SG, THEN control feed flow to maintain narrow range level.

IF narrow range level less tEan 4% (27% FOR ADVERSE CONTAINMENT) in all SGs, THEN manually start pumps and align valves as necessary.

IF AFW flow greater than 370 gpm can NOT be established, THEN go to 19231-1 FR-H.1, RT570NSE TO LOSS OF SECONDARY HEAT SINK, Step 1.

19. Verify ECCS Valve 19. Manually align valves using Alignment - PROPER Attachments B, C and D as INJECTION LINEUP necessary.

INDICATED ON MLBs.

i l

l l

l

emvvcuvMt w 'dEviSION WAGE NO 19000-1 1 8 of 27 l

ACTION / EXPECTED RESPONSE RESPONSI NOT OBTAINED

20. Verify RCS Average 20. IF temperature less than Temperature - STABLE AT II7*F and lowering, OR TRENDING TO 557'F. THEN:

a. Stop dumping steam.

b. IF cooldown continues, THEN lower AFW flow.

Maintain total AFW flow greater than 570 gpm until narrew range level greater than 4%

[27% for adverse containment) in at least one SG.

c. IF cooldown continues, THEN shut main steamline isolation and bypass valves.

IF temperature greater l tEan 557'F and rising, l

THEN:

e Dump steam to condenser.

-OR-e Dump steam using SG ARVs.

MOCEDURE No. CEVISION WAGE No.

19000.1 1 9. o f 2 7 -

ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED

21. Verify PRZR PORVs And Spray Valves:

a. PORVs - SHUT. a. IF PRZR pressure less than U15 psig, ,

THEN manually shut PORVs. I IF either valve can NOT be Hu t ,

THEN manually shut its bT6ck valve.

IF block valve can NOT be Eu t ,

THEN go to 19010-1, E-1 L'DT!I 0F REACTOR OR SECONDARY COOLANT.

b. Normal PRZR spray b. IF PRZR pressure less than valves - SHUT. H60 psig, THEN manually shut valves.

IF valves can NOT be shut, TREN stop RCP supplying TETTed spray valve.

F ge- , . , .--y---- -------y.. . - , .-.--w,-., , - - ---- ,r.--,,-- _e- y.---. , . -- - ~~.-.. ,-- - - - . - - - , - - - , . . . -

mcVissyN PAGE No.

19000-1 1 10 cf 27 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED NOTE Seal injection flow should be maintained to all RCPs.

22. Check If RCPs Should Be Stopped:

a. ECCS pumps - AT LEAST a. Go to Step 22d.

ONE RUNNING:

o CCPs or SI pumps

b. RCP Trip Parameter - b. Go to Step 22d.

RCS PRESSURE LESS THAN 1373 PSIG.

c. Stop all RCPs.

d. Verify at leas t one ACC'4 d. Start one ACCW pump.

pump - RUNNING

23. Check SGs Secondary Pressure Boundaries:

a. Check pressures in all a. Go to 19020-1, E-2 FAULTED SGs - STEAM GENERATOR ISOLATION.

e NO SG PRESSURE .

LOWERING IN AN UNCONTROLLED MANNER.

e NO SG COMPLETELY DEPRESSURIZED.

I 1

iI

'b - ,w.. wn e rev. CEVISION PAGE No 19000-1 1 11 of 27 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED 24 Check If SGs Tubes Are 24. Go to 19030-1, E-3 STEAM Intact: GENERATOR TUBE RUPTURE. l e Main steamline radiation - NORMAL.

e Cendenser air ejector radiation - NORMAL.

e SG blowdown radiation -

NORMAL.

25. Check If RCS Is Intact: 25. Go to 19010-1, E-1 LOSS OF REACTOR OR SECONDARY COOLANT.

e Containment radiation -

NORMAL.

e Containment pressure -

NORMAL.

e Containment emergency recirculation sump levels - NORMAL.

I l

...w.wi AAGENo 19000-1 1 12'of 27 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED

26. Check If ECCS Flow Should Be Reduced:

a. RCS subcooling monitor a. DO NOT STOP ECCS PUMPS.

indication - GREATER Go to Step 28.

THAN 28'F.

b. Secondary hect sink: b. Esatisfied, neither condition e Total Feed Flow To THEN DO NOT STOP ECCS SGs - GREATER THAN PUPJS.

570 GPM.

Go to Step'28.

-OR-e Narrow range level in at least one SG -

GREATER THAN 4%.

c. RCS pressure - STABLE OR c. DO NOT STOP ECCS PUMPS.

RISING. Go to Step 28.

d. PRZR level - GREATER d. DO NOT STOP ECCS PUMPS.

THAN 4%. Try to stabilize RCS pressure with normal PRZR spray.

Return to Step 26a.

27. Go to 19011-1, ES-1.1 SI TERMINATION.

28. Initiate Monitoring Of Critical Safety Function Status Trees.

l l

I

- .. . - - - . , , - . . --.. - - _ , -. . .. .- - ~ . . , , - - . , _ .- - -

PQoCEDURE No GEVISloN WAGE No.

19000-1 1 13 of 27 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTION Alternate water sources for AFW pumps will be necessary if CST level lowers to less than 15%.

23. Check SG Levels:

a. Narrow range levels - a. Maintain total AFW flow GREATER THAN 4%. greater than 570 gpm until narrow range level greater than 4 in at least one SG.

b. Control AFW flow to b. IF narrow range level in maintain narrow range any SG continues to rise in levels between 4% an uncontrolled manner, and 50%. THEN go to 19030-1, E-3 3TEXM GENERATOR TUBE RUPTURE.

30. Check Auxiliary Building 30. Evaluate cause of abnormal Leak Detection Systems: conditions.

a. Check Auxiliary Building IF cause is loss of RCS and plant vent radiation Inventory, monitors - NORMAL THEN go to 19112-1, ECA-1.2 GCX OUTSIDE CONTAINMENT.

e Selective cubicle monitors:

e RI-0024A e RI-0024B e Plant vent monitors:

e RE-12442A e RI-12442B e RE-12442C

b. Check Auxiliary Building break detection system on PCP - NO HIGH LEVEL STATUS LIGHT LIT.

I

stwsica pace so.

19000-1 1 14 o f 27 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED

31. Check PRT Conditions - 31. Evaluate cause of abnormal NORMAL:

conditions using Attachment E.

e PR*4R PORV and safety valve tailpipe IF cause of abnormal ,

temperatures - LESS conditions is a continuing THAN 190*F. loss of RCS inventory, THEN go to 19010-1, E-1 LOSS e Temperature - LESS UF REACTOR OR SECONDARY TRAN 115'F. COOLANT.

e Level - BETWEEN 57%

AND 88%.

e Pressure - BETWEEN 3 PSIG AND 8 PSIG.

CAUTION If offsite power is lost after SI reset, manual action is required to restart the following safeguards equipment if plant conditions require their operation:

e SI Pumps.

e RHR Pumps.

e CS Pumps, e ESF Chilled Water Pumps.

e Post-LOCA Cavity Purge Units.

32. Reset SI.

Check Secondary Radiation - 33. Go to 19030-1, E-3 STEAM 33.

NORMAL: GENERATOR TUBE RUPTURE.

e Direct chemistry to take periodic activity samples of all SGs.

~

PAOCEDUCE NO, REVISloN PAGE No.

19000-1 1 15 of 27 l ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED

34. Reset Containment Isolation Phase A:

a. Check containment area a. Go to Step 36.

radiation monitors - LESS THAN 100 R/H:

e RI-0005 e RI-0006

b. Reset containment isolation Phase A radiation monitors if necessary,

c. Reset containment isolation Phase A.

350 Establish Instrument Air To Containment:

a. Verify instrument air a. Start one air compressor pressure - NORMAL. by initiating 13710-1, SERVICE AIR SYSTEM.

b. Open instrument air to containment isolation valve:

e HV-9378 l

l 1

... . ... CEWSloN PAGE Wo.

19000-1 1 16 of 27 RESPONSE NOT OBTAINED

. ACTION / EXPECTED RESPONSE 1

CAUTION RCS pressure should be monitored. If RCS pressure '

-lowers to less than 300 psig, the RHR pumps must be manually restarted to supply water to the RCS.

36. Check If RRR Pucps Should Be Stopped:

a. Check RCS pressure:

1) Go to 19010-1, E-1 LOSS

1) Pressure - GREATER TRAN 300 PSIG. OF REACTOR OR SECONDARY COOLANT.

2) Pressure - STABLE OR 2) Go to Step 37.  ;

RISING.

b. Stop RER pumps,

37. Check If Diesel Generators Should Be Stopped:

a. Verify AC emergency a. WHEN offsite power busses - ENERGIZED BY available, OFFSITE POWER. THEN restore aower to Tiiiergency AC iusses by initiating 13427-1, I 4160V AC IE ELECTRICAL DISTRIBUTION SYSTEM.

l IF offsite power NOT available,  ;

THEN energize switchgear INEUI and INB10 from the emergency DGs.

b. Stop any unloaded DG and place in standby.

l

PICCEDUf E 40. r;EVISION FAGENO 19000-1 1 17 of 27 ACTION / EXPECTED RESPONSES RESPONSES NOT OBTAINED .

38. Return to Step 20.

END OF PROCEDURE TEXT l

l

PAoCEDURE No. f,EVISloN FAGE No-19000-1 1 18 of 27 Sheet 1 of 2 ATTACHMENT A SYMPTOMS REQUIRING REACTOR TRIP PARAMETER SETPOINT

1. Safety Injection NA

2. Power Range Neutron Flux High

a. High Setpoint 109%

b. Low Setpoint (P-10 interlock) 25%

3. Power Range Neutron Flux High Positive Rate + 5% in 2 sec.

4 Power Range Neutron Flux High Negative Rate - 5% in 2 sec.

5. Intermediate Range Neutron Flux High (P-10 interlock) 25% EICA

6. Source Range Neutron 5

Flux High (P-6 interlock) 10 cps

7. Overtemperature dT Displayed on TR-411

8. Overpower dT Displayed on TR-411

9. Pressurizer Pressure Low (P-7 interlock) 1960 psig

10. Pressurizer Pressure High 2385 psig

11. Pressurizer Water Level High (P-7 interlock) 92%

12. RCS Loss of Flow f a. Single Loop (P-8 interlock) 90%

b. Two or More Loops (P-7 interlock) 90%

i 13. Reactor Coolant Pump Bus Undervoltage (P-7 interlock) 9600V

PROCEtuRE No CEVISION WAGE No.

19000-1 1 19 of 27 Sheet.2 of 2 ATTACHMENT A i l

SYMPTOMS REQUIRING REACTOR TRIP PARAMETER S,ETPOINT

-14. Reactor Coolant Pump Bus Underfrequency (P-7 interlock) 57.3 Hz

15. Steam Generator Water 18.5%

Level Lo-Lo Narrow Range

16. Turbine Trip (P-9 interlock)

a. Turbine S top Valve Closure All Shut

b. Emergency Trip System Pressure Low 580 psig

17. Solid State Protection System Malfunction General Warning Alarm, Both Trains E

END OF ATTACHMENT A 1

I l

l l

l l

mtvisiUN r AGE NO 19000-1 1 20 of 27  ;

Sheet 1 of 2 ATTACHMENT B VALVE LINEUP FOR CCP COLD LEG INJECTION THROUGH THE BIT VALVE POSITION NUMBER FUNCTION POSITION INDICATION 1-1204-U4-207 RWST Supply To ECCS OPEN LV-112D CCP Suction From RWST OPEN M.309 LV-112E CCP Suction From RWST OPEN MLD10 LV-1123 CCP Suction From VCT SHUT MLB05 LV-112C CCP Suction From VCT SHUT MLB06 HV-8924 CCP To SIP Suction Cross- OPEN MLB01 connect HV-8471A CCP A Saction Isolation OPEN MLB01 HV-8471B CCP B Suction Isolation OPEN MLB02 HV-8508A CCP A Alternate Mini-flow OPEN MLB03 HV-8508B CCP B Alternate Mini-flow OPEN MLB04 HV-8110 CCP Combined Mini-flow SHUT MLB05 Isolation HV-8111A CCP A Mini-flow Isolation SHUT ML306 HV-8111B CCP B Mini-flow Isolation SHUT MLB06 HV-8116 Bypass Charging Supply SHUT MLB01 Isolation HV-8105 Normal Charging Supply SHUT ML306 Isolation Nor=al Charging Supply SHUT MLB05 HV-8106 Isolation CCP A Discharge Isolation OPEN MLB01 l HV-8485A MLB02 HV-8485B CCP B Discharge Isolation OPEN

" - " ~ P AGE No.

19000-1 1 21 of 27 Sheet 2 of 2 ATTACHMENT B (Cont'd.)

VAL'E POSITION NUMBER FUNCTION POSITION INDICATION HV-8438 CCP Discharge Cross Connect OPEN MLB02 HV-8801A BIT Outlet Isolation OPEN MLB05

,HV-8801B BIT Outlet Isolation OPEN MLB06 HV-8870A BIT Recirculation Supply SHUT MLB05 Isolation HV-8870B BIT Recirculation Supply SHUT MLB06 Isolation HV-8883 BIT Recirculation Return SHUT MLB05 Isolation END OF ATTACHMENT B

-mvvtyVMt NU AEVISioN r:AG E No.

19000-1 1 22 of 27 Sheet 1 of 1 ATTACMENT C VALVE LINEUP FOR SIP COLD LEG INJECTION VALVE POSITION NUMBER FUNCTION POSITION INDICATION 1-1204-U4-207 RWST Supply to ECCS Isolation OPEN HV-8806 Combined SIP Suction From RWST OPEN MLB04 HV-8923A SIP A Suction From RWST OPEN MLB01 HV-8923B SIP B Suction From RWST OPEN MLB02 HV-8807A SIP To CCP Suction Cross SHUT MLB03 Connect HV-8807B SIP To CCP Suction Cross SHUT MLB04 Connect HV-8814 SIP A Mini-Flow Isolation OPEN MLB03 HV-8920 SIP B Mini-Flow Isolation OPEN MLB03 HV-8813 Combined SIP Mini-Flow OPEN MLB04 HV-8802A SIP A Hot Leg Injection SHUT MLBil Isolation HV-8802B SIP B Hot Leg Injection SHUT MLB12 Isolation HV-8821A SIP A Cold Leg Injection OPEN MLB11 Isolation HV-8821B SIP B Cold Leg Injection OPEN MLB12 Isolation HV-8835 Combined SIP Cold Leg Injection OPEN MLB11 END OF ATTACHMENT C l

FMUGEDURE No REVISloN PAGE No. I 19000-1 1 23 of 27 Sheet 1 of 2 )

ATTACHMENT D VALVE LINEUP FOR RHR COLD LEG INJECTION ,

I VALVE POSITION NUMBER FUNCTION POSITION INDICATION 1

1-1204-U4-207 RWST Supply to ECCS Isolation OPEN l HV-8701A RHR Pump A Suction From Hot SHUT l Leg HV-8701B RHR Pump A Suction From Hot SHUT Leg HV-8702A RHR Pump B Suction From Hot SHUT Leg HV-8702B RHR Pump B Suction From Hot SHUT Leg HV-8811A RHR Pump A Suction From SHUT MLB03 Jump HV-8811B t-HR Pu=p B Suction Fron SHUT MLB04 bmp HV-8812A RHR Pump A Suction From RWST OPEN MLB03 HV-8812B RER Pump B Suction From RWST OPEN MLB04 HV-606 RHR Pump A Discharge Isolation OPEN MLB01 HV-607 RHR Pump B Discharge Isolation OPEN MLB02 HV-618 RER Hx A Bypass SHUT HV-619 RHR Ex B Bypass SHUT HV-8716A RHR Pump A Hot Leg Injection SHUT MLB03 Isolation HV-8716B RHR Pump B Hot Leg Injection SHUT MLB04 Isolation Combined RHR Hot Leg Injection SHUT MLB12 HV-8840

C AOCEcuRE No. P.EVISION PAGE No.

19000-1 1 24 of 27 Sheet 2 of 2 ATTACHMENT D (Cont'd.)

VALVE POSITION NUMBER FUNCTION POSITION INDICATION HV-8804A RHR Pump A Supply to CCP SHUT MLB03 Suction HV-8804B RHR Pump B Supply to SI Pump SHUT MLB04 Suction HV-8809A RHR Pump A Cold Leg Injection OPEN MLB11 Isolation HV-8809B RHR Pump B Cold Leg Injection OPEN MLB12 Isolation END OF ATTACHMEhT D C

.--- .. . REVISloN P AGE No.

19000-1 1 25 of 27 Sheet 1 of 2 ATTACEMENT E POSSIBLE SOURCES OF ABNORMAL PRT CONDITIONS RELIEF PATH INDICATION OF RELIEF RELIEF SPDS TO PRT PATH TO PRT PATH ADDRESS PRZR e Abnormal high tailpipe PV-455A -

PORV temperature. PV-456A T6262 e Valves not closed. ?V-455A ZD8548 HV-8000A ZD8542 PV-456A ZD8546 HV-80005 ZD8544 PRZR e Abnormal high tailpipe PSV-8010A T6263 SAFETY temperature. PSV-8010B T6264 PSV-8010C T6265 e Valve not closed. PSV-8010A ZD9263 PSV-8010B ZD9265 PSV-8010C ZD9267 RCP NO. 1 e Fluctuations in RCP no. 1 PSV-8121 -

SEAL seal leakoff flow.

LEAK 0FF RELIEF e Fluctuations in RCP no. 1 PSV-8121 -

seal differential pressure.

e Excess letdown aressure PSV-8121 -

150 psig with excess letdown aligned to VCT.

REACTOR e Indication of head vent KV-442A F9269 VESSEL flow with reactor head HV-442B F9270 HEAD vent isolated from excess VENT letdown.

e Reactor head vent to PRT HV-8095A ZD9298 throttle and isolation KV-8086A ZD9302 valves for a train - OPEN. HV-442A H5442 KV-8095B ZD9300 i HV-8096B ZD9302 HV-442B H5443 l

l l

t

. .-. PAGE NQ.

19000-1 1 26 of 27 ,

Sheet 2 of 2 ATTACHMENT E (Cont'd.)

RELIEF PATH INDICATION OF RELIEF RELIEF SPDS TO PRT PATH TO PRT PATH ADDRESS L RHR e RHR PUMP DISCHARGE PSV-8708A -

PUMP HI PRESS annunciation. PSV-8708B -

! SUCTION-RELIEF e RHR pump discharge PSV-8708A -

pressure 600 psig. PSV-8708B -

l e RCS pressure 450 psig PSV-8708A P5408

with RHR suction aligned PSV-8708B P5418 to RCS hot legs. P5428 P5438 l

l l

END OF ATTACHMENT E

l "KoCEDURE No REVISloN PAGE No.

19000-1 1 27 of 27 Sheet 1 of 1 FOLDOUT PAGE

1. RCP TRIP CRITERIA Trip all RCPs if BOTH conditions listed below occur;

a. CCPs or SI pumps - AT LEAST ONE RUNNING.

b. RCP Trip Parameter - RCS PRESSURE LESS THAN 1375 psig.

2. SI ACTUATION CRITERIA Actuate SI and go to 19000-1, E-0 REACTOR TRIP OR SAFETY INJECTION, Step 1, if EITHER condition listed below occurs:

o RCS subcooling monitor indication - LESS THAN 28'F (48'F FOR ADVERSE CNMT).

o PRZR level - CANNOT BE MAINTAINED GREATER THAN 4%

[34% FOR ADVERSE CNMT).

3. RED PATH

SUMMARY

a. SUBCRITICALITY - Nuclear power greater than 5%.

b. CORE COOLING - Core exit TCs greater than 1200*F.

-OR-Core exit TCs greater than 736*F AND RVLIS full range less than 3Y! with no RCPs running,

c. HEAT SINK - Narrow range level in all SGs less than 27% AND total available feedwater flow less than 570 gpm.

d. INTEGRlTY - Cold leg temperature lowers more than 100*F in last 60 minutes AND RCS cold leg temperature less than 250'F.

e. CONTAINMENT - Containment pressure greater than 52 psig.

4. AW SUPPLY SWITCHOVER CRITERION Switch AFW suction to alternate CST when operating CST lowers to less than 15%.

L APPENDIX B 4

l e

Y

VEGP E0P REY. 2 E-3 STEAM GENERATOR TUBE RUFIURE Note: During the recorded SGTR exercises conducted from October 27 to November 3, 1986, the Plant's E-3 procedure used by the student crews was Rev.1. The current version (Rev. 2) given here includes some minor changes compared with Rev. 1.

- - - - - _ - _ _ _ - _ _ - _ _ - _ _ _ _ _ _ _ _ _ __ _ _ _ _ _ _ ~~ ~ - - - - - - . _ - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

Vogtle Electric Generating Plant $9050-1 NUCLEAR CPE:ADONS , ,

c.:,

2 Unit i Georgia Power e...~.

/y 1 of 38 EMERGENCY CPERATING PROCEDURE E-3 STEAM GENERATOR TUBE RUPTURE . _ _ . . . .

PURPOSE This procedure provides actions to ter=inate leakage of reactor coolant into the secondary system fo11cving a steam generator tube rupture.

ENTRY CONDITIONS e 19000-1, E-0 REACTOR TRIP OR SAFETY Ibs;.CTION, Steps 24, 29 and 33.

e 19010-1, E-1 LOSS OF REACTOR OR SECONDARY COOLANT, Steps 3 and 4, and the Foldout Page. {

e 19012-1, ES-1.2 POST-LOCA C00LD0bT AND DEPRESSURIZAT!ON, Step 6.

s 19020-1, E-2 FAULTED STEAM GENERATOR ISOLATION, Step 6.

e 19031-1, ES-3.1 POST-SGTR C00LDOWN USING BACKFILL, Step 4 e 19033-1, ES-3.3 POST-SGTR C00LD0kW USING STEAM DLHP, Step 4 e 19131-1, ECA-3.1 SGTR WITH LOSS OF REACTOR COOLANT-SU3 COOLED RECOVERY DESIRED, Step 9.

e 19132-1, ECA-3.2 SGTR WITH LOSS OF REACTOR COOLAhT-SATURATED RECOVERY DESIRED, Step 4.

e 19133-1, ECA-3.3 SGTR WITHOUT PRESSURIZER PRESSURE CONTROL, Steps 2, 3, 4, and 5.

e 19233-1, FR-H.3 RESPONSE TO STEAM GENERATOR HIGH LEVEL, Step 7.

O _,

^ ^ ^ ' - - ___ _ _-________ __ _________ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

1 l

j p AGE No.

PpOCEcVRE NO.

l AEvl5lCN 19030-1 l 2 2 of 38 RESPONSE NOT OBTAINED ACTE]N/EXPECiTD RESPONSE NOTE e Foldout aage should be continuously monitored and applicab[a action taken, e Personnel should be available for sa=pling during this procedure.

e Seal injection flow should be =aintained to all RCPs.

1. Check If RCPs Should 3e Stopped:

a. ECCS pumps - AT LEAST a. Go to step 2. ,

ONE RUNNING:

e CCP or SI pu=ps,

b. RCP Trip Parameter - b. IF RCS pressure lowers to less than 1375 psig RCS PRESSURE LESS THAN 1375 PSIG. with no RCS cooldown initiated per Step 14, THEN do Step 1 and continue to step in affect.

Continue with Step 2.

c. Stop til RCPs.

Identify Ruptured SCs By 2. WHEN ruptured SGs

2. identified The Following Conditions:

THEN,da Steps 3 and 4 e Un2xpected rise in icy Continue with Steps 5 SG narrow range les ...

through 12. .

-OR-

e High radiation from any SG steamline. ,

4 n'e-e>e m ens p .e.

I

,__m_., _ , , _ ___ , _ _ _ _ _ _ _ _ _ _ _ _ .

PacCE:VPE No AEvi$icN PAGE No 1

19030-1 2 -

3 of 33 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED i

CAUTION e If the TDAFW puup is the only available source of feed flow, s t e art supply to the TDAFW pu=p =ust be

=aintained from at least one SG.

e At least one SG mut: 'ce maintained available for RCS cooldown.

l

3. Isolate Flev Frem Ruptured SGs:

a. Adjust ruptured SGs SG ARV controller setpoint to 1160 psig (pot setting 8.92),

b. Check ruptured SG b. WHTN ruptured SG pressure ARVs - Sh1TT. less than 1160 psig, THEN verify SG ARV shut.

IF the SG ARV is 30?

liliuc, THEN place TARV controller in =anual and shuc SG ARV.

1 IF SG ARV can NOT be shut, THEN locally isolate SG XRV-

! c. Shut steam supply valves c. IF at least one MDAFW from the ruptured SG co -pu=p running, the TDAFW pu=p THEN locally isolate the TDXW peep steam supply

, e HV-3009 (SG 1) from ruptured SGs.

e KV-3019 (SG 2)

d. Verify blowdown isolation d. Manually shut valves.

, valves frca the ruptured SGs - SHUT:

' e KV-7603A l e EV-7603B KV-7603C e

e HV-7603D W

CEVi$loN 4Gg No.

PeCCituRE NC.

19030-1 2 4 of 38 ACTION / EXPECTED RESPONSE RESPONSF NOT OBTAINED

e. Shut ruptured SGs =ain e. Perform the following:

steamline isolation and 1) Verify the following bypass valves. valves are shut:

e Steam dump valves :

o Status lightbeard ZLB INDICATES -

ALL STEAM DUMP VALVES SHUT.

e Condenser sparger system valve:

e KV-6194 e Steam jet air ejector valves e HV-4084B -

e EV-4085B e MSR steam supply control switches e HS-6030 - CLOSE e HS-6015 - CLOSE

2) Shut all remaining main steam line isolation and bypass valves.

3) Use intact SG ARVs for

' steam dump.

IF at least one intact SG l

can NOT be isolated from any ruptured SG, THEN go to 19131-1, EUIT3.1 SGTR WITH LOSS l OF REACTOR COOLANT-SUEC00 LED RECOVERY DESIRED.

l E _ _

PMUGEtuR E NO. afvislCN PAGE NQ.

19030-1 2 5 of 38 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED i

l CAUTION

!e This procedure should be perfor=ed in a ti=ely manner to assure that break flow to the ruptured SG is terminated before water enters the SGs =ain stea=  ;

pi;s.

- e If any ruptured SG is also faulted, feed flow to that

- SG should remain isolated during subsequent recovery ;

acticns unless needed for RCS cooldown. ,

4. Check ruptured SG(s) level:

a. Narrew range level - a. Maintain feed flow to GREATER THAN 4: ruptured SG until level (27 FOR ADVERSE Ch*MT). greater than 4" [27:

FOR ADVERSE CNMT].

WHEN ruptured SG level g: eater than 4" (17 FOR ADVERSE CNMT),

THEN stop feed flow to ruptured SG(s).

Continue with Step 5.

b. Stop feed flow to ruptured SG(s) E b

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, , . , - - - . - - - < ~ ~ - - , , - , . -r--w - - - - -

,%:vust No. AEvi$:CN not No.

19030-1 2 6 of 38

- ACTION /EXPECTTD RESPONSE RESPONSE NOT OBTAINED i

CAUTION i I

If any PRZR PORV opens because of high PRZR pressure, step Sb should be repeated after pressure lovers to less than 2315 psig.

5. Check PRZR FORVs And Block Valves:

a. Power to block valves - a. Restore power to block AVAILABLE. valves unless shut to isolate a leaking PORV.-

b. PORVs - SHUT. b. IF PRZR pressure less cEan 2315 psig.

THEN =anually shut PORVs.

IF any valve can NOT be sEut, THEN shut its block valve.

IF block valve can NOT be sEut, THEN go to 19131-1

• ICIT3.1 SOTR k'ITH LOSS OF REACTOR COOLANT-SU3 COOLED RECOVERY DESIRED.

'l

c. Block valves - AT LEAST c. Open at least one block ONE OPEN. valve unless it was shut to isolate a leaking

' PORV.

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i

.............. nevisics asce so.

19030-1 2 7 of 33 ACT!ON/ EXPECTED RESPONSE RESPONSE NOT OBTAINID

6. Check SGs Secondary Pressure Boundaries:

a.-Check pressures in all a. Verify all faulted SGs SGs - isolated unless needed for RCS cooldown:  ;

e NO SC PRESSURI e Steamlines '

LOWERING IN AN UNCONTROLLED MANNER. e Feed lines e NO SG COMPLETILY IF all faulted SGs NOT DEPRESSURIZED. Tiolated, THEN go to 19020-1, E-2

- 7XUCTED STEAM GENERATOR .

ISOLATION. l

] ,

P n

f I

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h. _.

t r%:WFs Nu. mEvtsio4 pAGE No 19030-1 2 a of 38 ACTION / EXPECTED RISPONSE RESPONSE NOT OBTAINED CAUTION Alternate water sources for AFW puces will be necessary if CST level lowers to less than 15%. i l

7. Check Intact SG Levels:

a. Narrow Range Level - a. Perform the following:

GREATER THAN 4

[27: FOR ADVERSE CNMT:.

1) Maintain total feed flow greater than 570 gpm until narrow range level is greater than 4%

(27 for adverse containment) in at least ene SG.

2) IF feed flow and Tivel can NOT be

=aintained to at least one intact SG THEN go to 19231-1 FKHT1 RESPONSE TO LOSS OF SECONDARY HEAT SINK.

b. Control feedflow to b. IF narrow range level in maintain narrow range Iny intact SG continues level between 4% (27: to rise in an uncontrolled manner, i FOR ADVERSE CNMT) and 50%. THEN return to Step 1.

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FaustJWat No afvi$1oN pAGE No 19030-1 2 9 of 33 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTION If offsite power is lost after SI reset, manual action is required to restart the following safeguards equipment if plant conditions require their operation:

e SI pu=ps.

e RHR pumps.

e CS pumps.

e ESF chilled water pu=ps.

i e Post-LOCA cavity purge fans.

8. Reset SI.

CAUT!ON l Repositioning Phase A isolation valves may cause radiation problems throughout the planc.

1

9. Reset Containment Isolation Phase A:

! a. Check containment area radiation monitors -

LESS THAN 100 R/HR:

, e RE-0005 e RI-0006

b. Reset containment isolation phase A radiation monitor if i necessary.

c. Reset containment isolation phase A.

~

8EV154eN *aos No.

P#0CEDumt NO.

19030-1 2 10 of 38 ACTION /EXPECTTD RESPONSE RESPONSE NOT OBTAINED l

'10. Establish Instrument Air To Containment:

a. Verify instrument air a. Start one air compressor pressure - NORMAL. by initiating 13710-1, SERVICE AIR SYSTEM.

b. Open instru=ent air to contain=ent isolation valver ,

o MV-9378

11. Perform the folleving:

11. Verify all AC Busses -

ENERGIZED BY OFFS!TE POWER.

a. Verify diesel generators have assumed the following loads.

e 2 NSCW pumps e 2 CCW pumps e 1 CCP e 1 ACCW pump 1

' e 1 MDATW pump e 4 containment coolers  :

e 480V AC Switchgear:  ?

TRAIN A TRAIN B 1AB04 1B506 ,

IAB05 13807 1AB15 IBB16 INB01 INB10

b. WHEN offsite power I available, THEN restore offsite power by initiating appropriate plant procedure.

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- --. .- RivtssCN pagg no -

19030-1 2 11 of 38 l

ACT!ON/ EXPECTED RESPONSE RESPONSE NOT OBTAINED '

CAUTION RCS pressure should be conitored. If RCS pressure lowers to less than 300 psig the RER pu=ps =ust be manually restarted to supply water to the RCS.

12. Check If RHR Pu=ps Should 3e Stopped:

a. RCS pressure - GREATER a. Go to Step 13.

TRAN 300 PSIG.

b. Stop RHR pu=ps.

CAUTION Isolation of the ruptured SGs should be complete before continuing to step 13 unless a ruptured SG is needed for RCS cooldown.

I

13. Go to 19131-1, ECA-3.1 SGTR

13. Check Ruptured SGs WITH LOSS OT REACTOR Pressure - GREATIR THAN COOLANT-SUBCOOLID RECOVERY 300 PSIG. i DESIRED.

p

. . . . . ~ . , noa 8o-19030-1 2 12 of 38 ACTION /EXPICTED RESPONSE RESPONSE NOT OBTAINED NOTE Low steamline pressure SI should be blocked when PRZR pressure lowers to less than 1970 psig and high steam pres 3ure rate alarms are clear.

CAUT!ON AFW ficw to intact SGs shculd be raised prior to maximum rate depressuritacien, to prevent re-initiation-;

of AW flow to ruptured SG.

14. Iniciare RCS Cooldewn:

a. Deter =ine required core exit temperaturer 7TGED SG l CORE EXIT l l

PRESSURE (PSIG) I TEMPERATURE ('F) '

Normal Adverse 531 503 1200 520  ! 492 1100 '

508 l 481 l

- 1000 496 - 468 900 _ , _

481  ! 454 800 l 466 l 439 700 I

449 ) 422 600 l 429  ! 403 500 400 405 l 381 376 351 300 4

PaygMQ 19030-1 2 13 of 38 ACTION / EXPECTED RESPONSE RISPONSE NOT OBTAINED

b. Dump steam to condenser b. Manually or locally dump from intact S0s at steam at maximum rate maxi =um race. ,

frem intact.SG ARVs.

IF no SG is available, TREN perform the ToITowing:

e Use faulted SG.

-OR-e Go to 19131-1 ECA-3.1 SGTR 'JITH LOSS OF REACTOR COOLANT-SU3 COOLED RECOVERY DESIRED.

c. Core exit TCs - LESS c. Return to step 14b. .

TMAN REQUIRED TEMPERATURE.

d. Stop RCS cooldown,

e. Control steam release to maintain core exit TC temperatures.

I

a m.vn noasor 19030-1 2 14 of 33 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED 1

b CAUTION RCS cooldown in step 14 should be ecmpleted before continuing to step 15.

Check Rup:ured SCs 15. IT differential pressure

15. 5etween ruptured and Pressure - STABLE OR RISING. intact SG is less than 100 psig.

-OR-IF RCS pressure continues to decrease less than 100 psig abovo intact SG pressure, THEN go to 19131-1. ECA-3.1 TCTK WITH LOSS OF REACTOR C00LAST - SUBC00 LED RECOVERY DESIRED. ,

16. Check RCS Subcooling 16. Go to 19131-1. ECA-3.1  ;

' Monitor Indication - SGTR WITH LOSS OF REACTOR GREATER THAN 48'F COOLANT-SUBCOOLED RECOVERY DESIRED.

(68'T FOR ADVERSE CNMT}.

i I

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L

, . - , - - . - ,,-e,--,,- - - - - ,-r- --,w- w - --r. - -, --- - - -

......... saca so 19030-1 2 15 of 33 i ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED i

17. Depressurize RCS To Mini =ize Break Flow /.nd Refill PRZR:

a. Nor=al PRZR spray - a. Go to step 18. OBSERVE AVAILABLE. CAUTION STATDfENT PRIOR TO STEP 18.

b. Spray PRZR with =axi=u= .

available sprav until ANY of the following conditions are satisfied e BOTH of the folleving:

l

1) RCS pressure -

. LESS TRAN RU?TURED SGs PRESSURE.

2) PT.ZR level -

GRIATER THAN 4:

[34: FOR ADVERSE CUMT).

-OR-e RCS subcooling

=enitor indication -

LI.SS THAN 28'T [48'T FOR ADVERSE CNMT1

-OR-e PRZR level - GREATER THAN 76% [55% FOR ADVERSE CNMr].

c. Shut normal spray c. Stop RCPs supplying valves. failed spray valve.

d. Go to Step 20. OBSERVE CAUTION PRIOR TO STEP 20.

i l McCEDURE NO. mEvi56CN a4GE80 19030-1 2 16 of 38 ACTION / EXPECTED RESPONSE RESPONSC NOT OBTAINED CAUTION e ~he PRT =ay ruature if a PRZR PORV is used to depressurizeebeRCS. This =ay result in abnormal contain=ent conditions, e Cycling of the PRZR FORV should be =ini=1:ed.

NOTE The upper head regien of the vessel =ay void during RCS depressurization if RCPs are not running. This will result in a rapidly rising PRZR level.

18. Depressurize RCS Using A

.P.BZFl 0RE ,To Mini =1:e_ ~

Break Flow And fifilT PRZR:

~

a. PRZR PORV - AT ' F.AST a. Establish auxiliary soray 1 ONE AVAILABLE. y and return to step 17b.

IT auxiliary spray can KUT be established.

THEN go to 19133-1.

E3.3 SGTR WITHOUT PRZR PRESSURE CONTROL.

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,#-,.g _. - __ , , ,

paociount No asvisios nos 8o 19030-1 2 17 of 38 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED e

b. Open ene PRZR PORV until ,

ANY of the following conditions satisfied e 30TH of the ToTIoving:

1) RCS pressure -

LESS THAN RUPnTED '

SGs PRESSURE.

2) PRZR level -

i GREATER THAN 4 i

[34% FOR ADVERSE CNMT].

-OR-e PR2R level - GREATER TRAN 76% [55" FOR ADVERSE CNMT).

.OR- -

e RCS subcooling

=enitor indicatien - l LESS TRAN 28'F. [48*F FOR ADVERSE CNMT).

c. Shut PRZR PORV. c. Shut PORV block valve.

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,._i, _. - _ r-

- _ = _ . _ - , ._ - . - _

r i

CEVI$loN PAGE No g-avsswmaNv 19030-1 2 18 of 38 -

ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED

19. Check RCS Pressure - 19. Shut PRZR FORV block valve.

RISING.

IJF,RCS pressure stabilizes or rises,

,THEN go to Step 20.

IT pressure continues to Tower, THEN perfom the following:

a. Monitor the following conditions for indication of leakage from PRZR '

PORV:

e Valve status indications.

e FORV discharge line temperature.

b. Go to 19131-1. ECA-3.1 SGTR WITH LOSS OF REACTOR C00LANTaSUBCOOLED RECOVERY DESIRED.

M i

i.

L 5

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l A(VISION # AGE No.

e nwwsswes ms.

19030-1 2 19 of 38 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTION ECCS FLOW MUST BE TERMINATED when termination criteria are satisfied to prevent overfilling of the ruptured SGs.

l l

l 20. Check If ECCS Flow Should Be Terminatedt

a. RCS subcooling monitor a. DO NOT STOP ECCS PUMPS.

indication - GREATER Go to 19131-1. ECA-3.1 TRAN 28'F [48'F FOR SGTR WITH LOSS OF RIACT07.

ADVIRSE CNMT). COOLANT-SUBCOOLED RECOVIkY DESIRED.

I

b. Secondary heat sink b. IF neither condition is satisfied, l THEN DO NOT STOP ECCS e Total feed flow to '.

SGs - GREATER TRAN FURPS.

( ,

570 GPM AVAILABLE.  !

Go to 19131-1. ECA-3.1 3

SGTR WITH LOSS OF REACTOR

C00LANT-SU3C00 LED

-OR.

RECOVERY DESIRED.

e Narrov range level

in at least one  ! r intact SG - GRFATER TRAN 4% [27% FOR ADVERSE ChWT].

4

c. RCS pressure - STABLE 2. DO NOT STOP ECCS PUMPS.

l OR RISING. Go to 19131-1. ECA-3.1 SGTR WITH LOSS OF REACTOR i

' COOLANT-SUBCOOLED RICOVERY DESIRED.

t

c. PRZR level - GRIATER d. DO NOT STOP ECCS PUMPS. ,

THAN 4% [34% FOR Return to step 13. I ADVERSE CNMT] .

l

macuns No. msvisioN nos so f 19030-1 2 20 of 38 l l

ACTION /CXPECTED RESPONSE RESPONSE NOT OBTAINED l

21. Stop ECCS Pumps And Place In Standby e SI pumps, e All but one CCP.

NOTE Without instrument air available charging should be established using Attach =ent A.

22. Establish Charging Flow:

a. Open CCP normal miniflow a. Go te Step 22c.

isolation valves,

b. Shut CCP alternate  !

miniflow valves.

c. Shut HV-182 seal flow control valve.  ;

b

d. Open charging line isolation valves: -

e HV-8105 i e HV-8106

e. Shut BIT discharge isolatien valves.

23. Maintain RCP seal flow.

24. Control Charging Flow To r Maintain PRZR Level.

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....swwns *w- AEVi$iCN PAGE No.

19030-1 2 21 of 33 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED

25. Verify ECCS Flow Is Not Required: .

a. RCS subcooling monitor a. Manually operate ECCS indication - GREATER pumps as necessary. Go THAN 28'T [48'T FOR to 19131-1, ECA-3.1 SGTR ADVERSE CNMT]. WITH LOSS OF REACTOR ,

COOLANT-SUBCOOLID RECOVERY DESIRED.

b. PRZR level - GREATER b. Manually operate ECCS THAN 4 [34 FOR pumps as necessary.

ADVERSE CNMT).

IF level can NOT be 13aintained, THEN go to 19131-1, E 3.1 SGTR WITH LOSS OF REACTOR COOLANT-SUBC00 LED RECOVERY DESIRED.

1

)

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..._--__. .~. . . _ . . _ _ _ . . _ _ _ , . _ _ _ , _ _ _ _ _ _ ,

PeOCEtymt No. 8EVISICN PAoE No 19030-1 2 22 of 38 RESPONSE NOT OBTAINED ACTION / EXPECTED RESPONSE NOTE Without instrument air available =akeup to the VCT is not available.

26. Check VCT Makeup Control 26. Adjust controls ss necessary Syste=: by initiating 13009-1, CVCS REACTOR MAKEUP CONTROL SYSTEM.

a. Makeup set for 2000 pp=

RCS boren concentracten (pot set at 5.1).

b Makeup set for automatic control.

NOTE Without instrument air letdown should be established using Attach =ent 3.

27. Check If Letdown Can Be '

Established:

a. PRZR level - GREATER a. WEEN PRZR level rises to THAN 21% (50: FOR greater than 21% (50:

TOR ADVERSE CNE],

ADVERSE CNMT]. THEN do Step 27b.

Continue with Step 28,

b. Establish letdown by b. Establish excess letdown initiating 13006-1, by initiating 13008-1, CMENICAL AND VOLUME CHEMICAL AND VOLLME CONTROL SYSTEM START-UP CONTROL SYSTEM EXCESS AND NORMAL OPERATION. LETDOWN.

. "E v '3tWN PAGENQ 19030-1 2 23 of 33  !

ACT!ON/ EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTION Without instrument air available CCP suction should remain aligned to the RWST.

28. Align CCP Suction To VCT:

a. Open VCT outlet isolation valves:

o -LV-1123 e LV-112C

b. Shut RWST outlet isolation valves:

e LV-112D e LV-112E

- CAUTION i

RCS and ruptured SGs pressures must be caintained less than the ruptured SGs ARV setpoint.

1

29. Control RCS Pressure And Charging Flow To Minimize

RCS-To-Secondary Leakage

a. Perform appropriate actions from tables L

P

-,-- , - - . ~ . , - , -- ,.- ,-, , -., - - - - - - , , - - ~ - ~ - - - - - - - , - - - . - -

mEVI$ ton 4GE No.

j moct:unt No.

19030-1 2 24 of 38 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED UFIURED SG RI5I!iG LOWERING OFF5CALE HIGH PRZR LEVEL _

LESS THAN e Raise RCS Raise RCS e Raise RCS 21: Charging Charging Charging Flow (LE55 IHAN 50I Flow Flow FOR ADVERSE CNMT]

e Depressuri:e e Maintain RCS RCS Using And Ruptured Step 29b SGs Pressures Equal BETWEEN Depressuri:e Energi:e Maintain RCS 21% AND 50% RCS Using PR2R And Ruptured

[AT 30I Step 29b Heaters SCs Pressures FOR ADVERSE CNMT] Equal BETWEEN 50% AND e Depressuri:e Energi:e Maintain RCS 76% RCS Using PRZR And Ruptured (BETWEEN 50I AND Step 29b Heaters SGs Pressures 55: FOR ADVERSE Equal CNTM) e Lower RCS Charging Flow GREATER TRAN Lower RCS Energi:e Maintain RCS 76 Charging PRZR And Ruptured T REATER THAli 55I Flow Heaters SGs Pressures FOR ADVERSE CNMT] Equal

, b. Use normal PRZR spray b. IF letdown is in service, per step 29a. TREN use auxiliary spray.

' IF letdown is NOT in Iervice, THEN use one PRZR PORV. -

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{peocteunt 50. *EvisioN #AG( NQ.

19030-1 2 25 of 38 i

ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED

30. Check If Diesel Generators Should Be Stopped:

a. Verify AC Emergency a. WHEN offsite power Busses - ENERGIZED BY available.,

OFFSITE POWER. THEN restore ' Dover to YEeigency AC susses by initiating 13427-1, 4160V AC 1E ELECTRICAL DISTRIBUTION SYSTEM. l IF offsite power NOT available.

THEN restore power to TH U1 and INB10 from emergency diesel generators.

b. Stop any unloaded diesel generator and place in standby.

c. Verify 1NB01 and 18B10 c. Manually energize 1NB01 energized. and INB10.

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revtECUME No. AEVISION P AGE No.

19030-1 2 26 of 38 ACTION / EXPECTED RISPONSE RESPONSE NOT OBTAINED

31. Minimize Secondary System Contamination By Performing The Following As Conditions Require e Dispatch operator to transfer :urbine SJAE vacuum exhaust to the HEPA filters:

1) Open HV-28753.

2) Open HV-2875C.

3) Shut EV-2375A.

e Isolate CST from the e Dispatch cperator to Hoewell by placing shut:

LIC-4415 in =anual and r.djusting to obtain e COND SYS LV-4415B a 50% demand signal. DNSTRM MANUAL ISO 1-1305-U4-045.

e Bypass the condensate polishing deminerali:ers -OR-by opening HS-30223B.

e COND SYS LV-4415B UPSTRM MANUAL ISO e Transfer auxiliary steam 1-1305-U4-044 to the auxiliary boiler by initiating 13761-1, AUXILIARY STEAM SYSTEM.

e Transfer loads to auxiliary boiler when available.

32. Energize PRZR Heaters As Necessary To Saturate PRZR Water At Ruptured SGs Pressure.

-4,  : *

.- M P. >l

.n.-

, _.' f.

i PROCEDURE No. AEvisioN 8 AGE No. '_,

',(. ;. g-l\;!

y 19030-1 2 27 of 38 g.jp.by m"&K

. j '

9 . ' :,. 3-y,'  ;-

W 's ~

ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED ;iS t ,

';'i.u, '

b jf&' .j

33. Check RCP cooling - NORMAL:

7.~%'..s'-

b.

l'

-;.7?

E-

a. Annunicator alar =: a. Establish normal RCP ACC*J D' .

M E ACC'4 RCP CLR LO FLO'4 - System flow by initiating Mi1 M $

i CLEAR. 13001-1. AUXILIARY a .

~-

) COMPONENT COOLING 'JATER A R F SYSTEM.

E [

" b. RCP seat injection b. Establish RCP seal

"_ flow - NORMAL. injection flow by

- initiating 13006-1.

L CHEMICAL AND VOLL*ME k CONTROL SYSTEM.

B 34 Check If RCP Seal Return F

e Flow Should Be Established:

I

a. RCS pressure - GREATER a. Go to Step 35.

THAN 100 PSIG.

T b. Establish flew:

y _ _ _ _

g-i

1) Open RCP seal return header isolation

/P -4 i '

2- valves: N.1.7 1 .' g-

> .g 5 e HV-8112 3.T;pm M'i !

it- e HV-8100 4 r . ^ 9,jf. & . .

Er 2) Verify seal return 2) Open RCP seal leakoff  ;:76..'., .

P from each RCP - valves as necessary: igJz.,,vit, NORMAL FOR RCP SEAL y.$ : .

$ NUMBER 1 DIFFERENTIAL e HV-8141A (RCP 1) ,.y' y' ;; .

e PRESSURE. e HV-8141B (RCP 2) .. .

E e HV-8141C (RCP 3) jf.;j.'W .

=-

e HV-8141D (RCP 4) r,. m. , , a, 4

[ N ,[ 'h i ,

.'n' Yi --o.

m if * * .

E

.: g ,..* .*-',.

p .. .

-.. {'

i I - '

' pr . &' , '

i. '

- l -%,

, , . p.

4 , - . , .

w l :. . . ;',

f $,* .. f i p

. . . -. '."' j. - ].

u ye.isv, x.s. '-.

c i

- - ~ .

I

. . .w w swwn s aw. AIVISIO N PAGE No 19030-1 2 28 of 38 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTION e If RCP seal cooling had previously been lost, the affected RCP should not be started prior to status evaluation, e On natural circulation, RTD bypass te=peratures and associated interlocks will not be accurate.

NOTE RCP 4 or RCP 1 should be run preferentially to provide nor=al PRZR spray.

35. Check RCP Status:

a. RCPs - AT LEAST ONE a. Try to start one RCP:

RUNNING.

1) IF RVLIS full range Indication is less than 98%,

THEN perfor= the IoTIowing:

o Raise PRZR level greater than 87:

(90% FOR ADVERSE CNMT).

o Raise RCS subcooling based on core exit TCs greater than 84*F. ,

2) Establish conditions for starting a RCP and start one RCP using Attach =ent C.

y .

= 'O , ' . ,,

a EVISICN PAGE No. e rwucEllURE No. -

p 'sf 9 +. P- . , . . .

19030-1 2 29 of 38 .-d > .-?

I 8@h,t.:

.6' y. .

4 ' ,' '

z

• v'

+5 w ,

ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED J:1, . ' ~., l '.

- f; . - i ; '

3) IF a RCP can not be . b' .[? -

b started, '.-

. f f- fja

~

( THEN verify natural

( !' 0t 1 circulation using Attachment D. -n y -(9' fy d IF natural circulation I RUT verified, $F/VM.

hp THEN raise rate of $ty.; #N -

du= ping steam unci 1

(;4p*,

- .. .e.J .-

E natural circulation '.:

j is verified. .Q is; j. -

d,' .y i ;j . . ~

4 4.

L b. Stop all but one RCP. $> %

ad. v j s m:.,..,

- - = __ :_m-f

36. Check If Source Range h

=- Detectors Should Be 1 Energized:

m

a. Check IR flux - LESS a. WHEN flur. is less than THAN 10-10 AMPS. 10-10 amps, h THEN do steps 36b and c.

I.

a-Continue with Step 37.

5 b. Verify SR detectors - b. Manually energi:e SR E ENERGIZED. detectors.

c. Transfer nuclear recorder to SR scale.

4 37. Secure Unnecessary Plant f Equip =ent:

o Coordinate with TSC to determine which equipment is not required at this ti=e.

_ - -. . m

R EviSICN PAGE NQ.

I #ACCEDURE NO.

19030-1 2 30 of 33 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED NOTE ES-3.1 POST SGTR COOLDOWN USING BACKFILL is the preferred recovery procedure. Consult TSC prior to using ES-3.3 POST SGTR COOLDOWN USING STEAM DLMPS.

38. Go To Appropriate Post-SGTR Cooldown Method:

e Go to 19031-1, ES-3.1 POST-SGTR C00LOOWN USING BACKFILL.

-OR-e Go to 19033-1, ES-3.3 POST-SGTR C00LDOWN USING STEAM DLMP.

END OF PROCEDURE TEXT

PACCE",yRE NO- A EvlSiC N pAGENo 19030-1 2 31 of 38 Sheet 1 of 3 AT~ACHMENT A ESTABLISHING CHARGING WITHOUT !NSTRUMENT AIR A. Establish Charging With Both Train A And Train B E=ergency Buses Energized:

1. Verify alternate miniflow isolation valves - OPEN:

e MV-8508A e HV-8508B

2. Verify one CCP - RUNNING.

3. Ve.eify charging isolation valves - OPEN:

e HV-8105 e HV-8106

4. Verify B1T isolation valves - SHUT:

e HV-8801A e HV-8001B

5. Dispatch local operators to do the follewing:

a. Open 1206-U4-136 CVCS SEALS FLCW CONTROL MV-182 BYPASS

b. Shut 1208-U4-134 CVCS SEALS FLCW CONTROL HV-182 INLET ISO

c. Shut 1208-U4-135 CVCS SEALS FLOW CONTROL HV-182 OUTLET ISO

d. Adjust to obtain 8 to 13 gpm RCP SEAL INJ NEEDLE VLVS 70 il SEAL:

e 1208-U4-414(RCP #1) e 1208-U4 >: 15(RCP #2) e 1200 U4-416(RCP #3)

= 1208-U4-417(RCP #4)

e. Adjust to obtain desired charging flow 1203-U4-136 CVCS SEALS FLOW CONTROL HV-182 BYPASS.

~_$

& ll; ; ~f 5' IPRoCECURE No. AEviSiON PAGE No -

h.; QM 7 EiiiEs' W C E 1903C-1 2 32 of 38 7,,85

,fhhki, s

~

Sheet 2 of 3 Q ',p:.

p ATTACHMENT A (Cont'd.) Oddh b,,-

D ,

i b ,* t k. I ,

B. Establish Charging With Train A Emergency Bus Energized: }.q( d q. ..

%.lw.3j E 1. Verify Train A alternate miniflow isolation valve HV-8508A - L sa we*

OPEN. #* W '

2. Verify Train A CCP - RUNNING. C5 -se

+uA

3. Verify Train A charging isolation valve HV-8106 - OPEN. .1 0 417 %

/06E7

,, 4. Dispatch local operators to do the following: V,Q."y[

= g y; ; .",

a. Shut CCP discharge crosstie isolatten valve HV-8438 Q:l.M /;;

P,A , 9'y

b. Verify Train B charging isolation valve HV-8105 - OPEN _- t .a t

f c. Open 1208-U4-136 CVCS SEALS FLCW CONTROL HV-182 BYPASS E d. Shut 1208-U4-134 CVCS SEALS FLOW CONTROL HV-182 INLET ISO E e. Shut 1208-U4-135 CVCS SEALS FLOW CONTROL HV-182 OUTLET g ISO

- f. Adjust to obtain 8 to 13 gpm RCP SEAL INJ NEEDLE VLVS TO 11 SEAL:

4.

e 1208-U4-414(RCP ll)

E e 1208-U4-415(RCP #2) e 1208-U4-416(RCP J3)

F e 1208-U4-417(RCP 14) 5' g. Adjust to obtain desired charging flow 1208-U4-136 CVCS SEALS FLOW CONTROL HV-182 BYPASS.

E a

Y M

E b

REW$iCN paGENo PaCCE0WAE No.

19030-1 2 33 of 38 Sheet 3 of 3 ATTACHMINT A (Cont'd.)

C. Establish Charging With Train B E=ergency Bus Energized:

1. Verify Train B alternate miniflew isolation valve HV-8508B -

OPEN.

2. Verify Train B CCP - RUNNING.

3. Verify Train 3 charging isolation valve KV-8105 - OPEN.

4. Verify Train 3 BIT outlet isolation valve HV-8801B - SHUT.

5. Dispatch local cperators to do the following:

a. Verify Train A BIT cutlet isolation valve HV-8801A - SHUT.

b Verify Train A charging isolation valve HV-8106 - OPEN

c. Open 1208-U4-136 CVCS SEALS FLOW CONTROL HV-182 BYPASS

d. Shut 1208-U4-134 CVCS SEALS FLOW CONTROL HV-182 INLET ISO

e. Shut 1208-U4-135 CVCS SEALS FLOW CONTROL HV-182 OUTLET ISO

f. Adjust to obtain 8 to 13 gpm RCP SEAL INJ NEEDLE VLVS TO #1 SEAL:

e 1208-U4-414(RCP #1) e 1208-U4-415(RCP #2) e 1208-U4-416(RCP #3) e 1208-U4-417(RCP #4)

g. Adjust to obtain desired charging flov 1208-U4-136 CVCS SEALS FLOW CONTROL HV-182 BYPASS.

END OF ATTACHMENT A

' n i' i

l 1

, ........... MtvisioN PAGEPeQ l

l 19030-1 2 34 of 38 Sheet 1 of 1 ATTACHMENT B ESTABLISH SATITY GRADE LETDOWN, CAUTION The PRT =ay rupture while perfor=ing safety grade letdowm,

1. Open Reactor Vessel Head Vent isolation valves e HV-8095A e HV-8096A e HV-8095B e HV-8096B

2. Open Reactor Vessel Head Vent flow control valves to obtain desired letdown flows e HV-442A e HV-4423 END OF ATTACHMENT B

F pmocggyng No, mEvasioN PA 3E No.

19030-1 2 35 of 38 Sheet 1 of 2  ;

g- ATTACHMENT C STARTING A REACTOR COOLANT PT,3 ,

1. Establish Initial Conditions:

a. 13.8KV power available to RCP. j p

h b. Steam bubble in PRZR. -

c. il Seal dP greater than or equal to 200 psid, j

d. Seal injection flow 8 to 13 SPm. ,

y e. Seal leakoff flow greater than or equal to 0.2 gpm. _

2. Check the following alar =s clear or establish conditions to E E'

7 clear those alar =s for the RCP to be started: j

a. RCP f.0WER OIL RSVR HI/LO LEVEL. -

b. RCP UPPER OIL RSVR HI/LO LEVEL.

j

"; c. VOLL'ME CONTROL TANK OUTLET TEMP HI.

B -

A d. VCT HI/LO PRESS.  !

l-E e. RCP STNDPIPE LO LEVEL. ,

RF l-_ f. RCP STNDPIPE HI LEVEL.

g. RCP MTR OVERLOAD.

h. RCP NO 2 SEAL LKOFF HI FLOW. j I 1. ACCW RCP CLR OUTLET HI TEMP.

[ .

j. ACCW RCP CLR LO FLOW.

k. ACCV RCP THERM BARRIER HX HI FLOW.

1. ACCV RCP THERM BARRIER HI PRESS.

r -

3. Verify all RCP ACCV ther=al barrier isolation valves open.

4 Start the associated RCP oil lift pump.

5. After two minutes of lift pu=p operation, start the RCP.

5

.- g

'paocttuht No. aEv' sics nos so 19030-1 2 35 of 38 Sheet 2 of 2 AT ACHMENT C (Cont'd.)

6. After approxi=ately one =inute check the following alar =s clears

a. RCP LOW FLOW.

b. RCP SHAFT VIBRAT!ON.

c. RCP TRAME VIBRATION.

d. Those alar =s in Step 2.

7. After one minute of RCP cperation, step the oil lift pu=p.

END CF ATTACHMENT C

2

.=iE pgyistos PAGE No. 3 g

$ 19030 1 2 37 of 38 -3_

. -i -

Sheet 1 of 1 7"

, ATTACHMENT D VERIFICATION OF NATURAL CIRCULATION =

% 2 The following conditions support or indicate natural circulation M

] a t-.;

flows gm 1 o RCS subcooling monitor indication - GREATER THAN 28'T Mw P

?

(48'T FOR ADVERSE CNMT]. kg e o SG pressures - STABLE OR LOWERING. --

o RCS hot leg te=peratures - STABLE OR LO'a'ERING. _t g o Core exit TCs - STABLE OR LOWERING. Jg-g;-

RCS cold leg temperatures - AT SATURAT!ON TEMPERATURE FOR SG im P o R PRESSURE, _%

h d

~

-=-

=

END CF ATTACHMENT D k5 -

, =,

? =

2 E Y

=

d -

.m

'k

!t 4

~.h. d

=

K)oCEDUCE 'NO. REvisiCN POGE No. t

19030-1 2 38 of 38 1

Sheet 1 of 1 FOLDOUT PAGE E

1. 3I REINITIATION CRITERIA Manually operate ECCS pumps as necessary and go to 19131-1, ECA-3.1 SGTR WITH LOSS OF REACTOR C00Wrr - SUBC00 LED i RECOVERY DESIRED, if EITHER condition listed below occurs:

P o RCS subcooling monitor indication - LESS THAN 28'F [48'F FOR ADVERSE CNMT) .

E o PRZR level - CANNOT BE MAINTAINED GREATER THAN 4% [34% FOR ADVERSE CNMT).

2. red PATH

SUMMARY

{ a. SUBCRITICALITY - Nuclear power greater than 5%.

b. CORE COOLING - Core exit TCs greater than 1200*F.

=

-OR-Core exit TCs greater than 736'F .

AND RVLIS full range less than 37I with no RCPs running.

c. HEAT SINK - NR level in all SGs less than 27% AND F total available FW flow less than ITU gPm.

h d. INTEGRITY - Cold leg temperature lovers core than 100*F

- in last 60 minutes AND RCS cold leg

- to=perature less than 250'F.

=

e. CONTAINMENT - Containment pressure greater than 52 7 Psig.

l-

3. SECONDARY INTEGRITY CRITERIA Go to 19020-1, E-2 FAULTED STEAM GENERATOR ISOLATION, if any SG pressure is lowering in an uncontrolled manner or has completely depressurized, and has not been isolated, unless needed for RCS cooldown.

7 4. COLD LEC RECIRCULATION SWITCHOVER CRITERION Go to 19013-1, ES-1,3 TRANSFER TO COLD LEG RECIRCULATION, if RWST level lovers to less than 45%.

5. AW SUPPLY SWITCHOVER CRITERION Switch AFW suction to alternate CST when operating CST lovers to less than 152.

~

=...

p i 1

i APPENDIX C ..

1

/

/

m-. . .

9 SOEDULED EXERCISES FOR OPERATOR TRAINING STUDENTS ON VEGP SIhf3LATOR 1

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