ML20206U065

Forwards Addl Info Re NUREG-0737 Item II.D.1 Re Performance Testing of Relief & Safety Valves,Per NRC 860422 Requests. Response to Question 10 Revised to Incorporate New Info Re Safety Valve Ring Settings

ML20206U065
Person / Time
Site:	Wolf Creek, Callaway, 05000000
Issue date:	09/26/1986
From:	Petrick N STANDARDIZED NUCLEAR UNIT POWER PLANT SYSTEM
To:	Harold Denton Office of Nuclear Reactor Regulation
References
RTR-NUREG-0737, RTR-NUREG-737, TASK-2.D.1, TASK-TM SLNRC-86-09, SLNRC-86-9, NUDOCS 8610070289
Download: ML20206U065 (19)

Text

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SNUPPS Standardized Nuclear Unit Power Plant System 5 Choke Cherry Road Nicholas A. Petrick Rockville, Maryland 20s50 Executive Director (3011 see solo September 26, 1986 SLNRC 86-09 FILE: 0278 SUBJ: NUREG-0737, Item II.D.1 Mr. Harold R. Denton, Director Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Washington, D.C. 20555 Docket Nos.: STN 50-482 and STN 50-483

References:

1. NRC letter (P. O'Connor) to Union Electric Company (D. Schnell) dated April 22, 1986: Request for Additional Information NUREG-0737, Item II.D.1 Performance Testing of Relief and Safety Valves

2. NRC letter (P. O'Connor) to Kansas Gas & Electric Company (G. Koester) dated April 22, 1986: Request for Additional Information NUREG-0737, Item II.D.1 Performance Testing of Relief and Safety Valves

3. SLNRC 86-07, June 30, 1986: Same Subject

Dear Mr. Denton:

References 1 and 2 requested that additional information be provided in support of the NRC review of NUREG-0737, Item II.D.1 for the SNUPPS plants--Callaway Plant and Wolf Creek Generating Station.

Reference 3 provided a partial response to the NRC staff questions and committed to providing the remaining responses by September 26, 1986.

Responses to the remaining questions are enclosed. In addition, the response to question 10 has been revised to incorporate new information concerning safety valve ring settings.

Ver truly yours,

-e% < \e

- Nicholas A. Petrick MHF/dck/7a3 Enclosure cc: D. F. Schnell UE G. L. Koester KGE J. M. Evans KCPL B. Little USNRC/ CAL f J. E. Cummins USNRC/WC , 0 f,l W. L. Forney USNRC/RIII e i i E. H. Johnson USNRC/RIV k .

P. W. O'Connor USNRC 8610070289 860926 PDR ADOCK 05000482 P PDR

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RESPONSES TO NRC QUESTIONS RE NUREG - 0737, ITEM II.D.1 PERFORMANCE TESTING OF RELIEF AND SAFETY VALVES l QUESTION 2:

Results for the EPRI tests on the Crosby safety valves indicate that the test blowdowns exceeded the design value of 5% for both "as installed" and " lowered" ring settings. If the blowdowns expected for SNUPPS also exceed 5%, the higher blowdowns could cause a rise in pressurizer water level such that water may reach the safety valve inlet line and result in a steam-water flow situation. Also the pressure might be sufficient-ly decreased such that adequate cooling might not be achieved for decay heat removal. Discuss these consequences of higher blowdowns if in-creased blowdowns are expected.

Response

Evaluations were performed using sensitivity analyses for a 4-loop reference plant to determine the effects of blowdowns greater than 5%.

The results, which are applicable to the SNUPPS plants, showed no sig-nificant adverse effects on the conclusions of the FSAR analyses (i.e. no safety limits are violated) for blowdowns ranging up to 14%. The higher blowdowns resulted in increased pressurizer water level, lower reactor coolant system pressure and increased inventory loss through the safety valve. However, adequate decay heat removal was maintained and water relief did not occur for the loss of external load and single reactor coolant pump locked rotor events.

Plant-specific ring settings for safety valves are adjusted during pro-duction testing at Crosby. The ring settings for the Model 6M6 valves shipped to the SNUPPS plants resulted in blowdowns of 5% as measured at Crosby. During EPRI testing, the maximum blowdown measured for Crosby 6M6 valves using typical ring settings was 12.7%. Therefore, the ex-pected blowdowns at the SNUPPS plants are within the range of blowdowns analyzed as having no significant safety effects.

QUESTION 7:

Bending moments are induced on the safety valves and PORVs during the time they are required to operate because of discharge loads and thermal expansion of the pressurizer tank and inlet piping. Make a comparison between the predicted plant moments with the moments applied to the tested valves to demonstrate that the operability of valves will not be impaired.

Response

The operability of safety and relief valves was evaluated by comparing calculated in-plant bendi ng moments with those obtained during EPRI testing. The EPRI testing demonstrated operability with bending moments up to 298,750 in-lb for the safety valves and 34,000 in-lb for the relief valves. The corresponding worst-case values for the SNUPPS design are less than 115,000 in-lb and less than 30,000 in-lb for the safety and relief valves, respectively.

QUESTION 8:

The Westinghouse Valve Inlet Fluid Conditions Report states that liquid discharge could be expected through the safety valves for both the feedline break and extended high pressure injection events. The EPRI 6M6 test safety valve experienced some chatter and flutter while dis-charging liquid at certain ring settings. Testing was terminated after observing chattering to minimize valve damage. Inspection revealed some valve damage which was presumably caused by the valve chatter and flutter. Liquid discharge for the SNUPPS plants may conceivably occur for longer periods of time than the EPRI testing. Thus, longer periods of valve chattering may cause severe valve damage. Discuss the implica-tions this may have on operability and reliability of the SNUPPS plant safety valves. Identify any actions that will be taken to inspect for valve damage following safety valve lift events.

Response

The feedline break (FLB) is analyzed in Section 15.2.8 of the SNUPPS plant FSARs. The results of the FLB analysis are different from those discussed in WCAP-10105, Section 2.1, because the SNUPPS plant evalua-tion has been performed to assume control and protection system interac-tion (CPI). For the CPI accident scenario, a small feedline rupture is assumed to occur in the feedline between the check valve and the steam generator (SG) which is located inside containment at the SNUPPS plants.

The main feedwater control system is assumed to be exposed to an adverse envi ronment. The main feedwater control system is assumed to fail due to the adverse environment such that the water levels in all SGs are assumed to decrease equally until the 10-10 SG level reactor trip set-point is reached. Af ter reactor trip, a double-ended rupture of a feedwater line is assumed. These assumptions conservatively bound the most limiting feedwater line rupture that can occur. The transient is modeled such that credit is only taken for reactor trip on SG lo-lo level. This results in a reactor trip much later than that in the WCAP-10105 analyses where the SG 10-10 level trip setpoint is reached in the faulted loop shortly after the double ended feedline rupture.

t After reactor trip, in both accident scenarios, the decrease in core

heat flux results in a reduction in pressurizer water volume. The pressurizer water volume continues to decrease until steamline isolation occurs on lo steamline pressure. Time to reach the lo steamline pres-sure setpoint is also, in part, a function of steam generator type.

Once steamline isolation occurs, the primary side heatup and expansion increase the pressurizer water volume until the pressurizer eventually

, becomes water solid. This occurs earlier in the CPI transient--at l approximately 7 minutes for both Wolf Creek and Callaway, in accordance l with the current FSAR analyses (or at approximately 14 minutes, in accordance with the analyses supporting fuel cycle 2 for Callaway Plant);

i the CPI transient response is more severe than the transient referred to in WCAP-10105 because of the steam generator secondary liquid inventory in the intact steam generators at the time of reactor trip.

The FSAR analysis is performed using several additional conservative assumptions such as a 60-second delay in the startup of the Auxiliary Feedwater System (AFS) and the single failure of one motor-driven AFS pump. Also no credit is taken for a reactor trip on high pressurizer pressure or containment high pressure. No credit was taken for operator action to terminate safety injection (SI) flow. Continued SI flow maintains the reactor coolant system (RCS) pressure at the safety valve setpoint. No credit is given for operation of the Steam Generator Atmospheri c relief valves or the power-operated relief valves on the pressurizer. Also, the assumed break location (between the feedline check valve and the steam generator) is a limiting assumption since an FLB elsewhere will affect the RCS only as a loss-of-feedwater event which does not result in water relief from the pressurizer relief or safety valves. ,

As discussed above, the insurge of water into the pressurizer results from a combination of RCS heatup, after the main steam isolation valves close, and the addition of SI flow to the RCS following SI on a low steamline pressure signal. As shown in FSAR Figures 15.2-18 and 15.2-i 23, the heatup of the RCS is terminated at approximately 30 minutes (with offsite power available) or 15 minutes (without offsite power).

Therefore, the longest period of water relief through the safety valves is 23 minutes assuming that the operator will act to terminate SI flow at or before 30 mintues.

In accordance with EPRI Report NP-2296, Section 5.2, the range of liquid temperature during water relief for the SNUPPS plants is 613.4*F to 632.7 F and the peak surge rate is 2512.5 gpm (835,650 lb/hr at 610 F).

EPRI conducted two liquid relief tests of the Crosby 6M6 safety valve:

tests 931 and 932. These tests were evaluated for applicability to the SNUPPS plants based on EPRI guidelines for determining applicability using ring settings, backpressure, inlet piping pressure drop and inlet fluid conditions. Based on this evaluation, the inlet fluid temperatures for test 932 render this test inapplicable to the SNUPPS FLB event.

The inlet temperature range for test 932, which was terminated because of excessive valve chatter, was 455-532*F. The inlet liquid temperature for test 931 (640-656*F) more nearly agrees with the predicted temperatures following a postulated FLB at the SNUPPS plants. Also, test 931 was a loop-seal transition to steam then to liquid which would conform to the expected scenario for an FLB. Test 931, which exhibited valve chatter or flutter on loop seal passage then stable operation, demonstrated accept-able valve performance. Based on the above discussion, the SNUPPS safety valves are expected to perform acceptably for the water relief conditions predicted in the FSAR FLB analysis.

If credit were taken for the pressurizer power-operated relief valves (PORV), which are safety-grade in the SNUPPS design, liquid relief from the safety valves would not occur. In accordance with Table 4.10.1 of EPRI Report NP-2628-SR, the relief capacity of the Garrett PORV demonstrated during water testing was 813,600 lb/hr at 648'F. Therefore, the relief capacity of the two PORVs greatly exceeds the predicted peak surge rate into the pressurizer following an FLB (835,650 lb/hr).

The limiting extended high pressure injection (HPI) event is the spur-ious actuation of ECCS at power. In accordance with EPRI report NP-2296, Section 5.3, the range of liquid temperatures for safety valve water discharge would be 567-572 F. However, spurious actuation of ECCS at power, as well as other events which increase RCS inventory , are analyzed in Section 15.5 of the SNUPPS plant FSARs. These transients are analyzed in the FSAR to demonstrate that there is adequate time for operator action to prevent filling the pressurizer. Thus, based on the acceptable results of the FSAR transient analyses, water relief by the safety valves is not predicted for the extended HPI event.

The SNUPPS Utilities routinely evaluate actual plant transients which may occur including those which would result in safety valve lift. Based on these evaluations, appropriate actions would be taken to assess valve and piping integrity.

The SNUPPS Utilities are also following the program of the Westinghouse Owner's Group to ' assess safety valve performance under liquid relief conditions. If the Owner's Group program results require a revision in the response to this question, a revised response will be submitted.

QUESTION 10:

The SNUPPS safety valves are Crosby 6M6 and were tested by EPRI. EPRI testing of the 6M6 was performed at various ring settings. The submittal did not provide details discussing the applicable EPRI tests which demonstrates the operability of the plant safety valves. The submittal did not provide the present SNUPPS plant safety valve ring settings. If the plant current ring settings were not used in the EPRI tests, the results may not be directly applicable to the SNUPPS safety valves.

Identify the SNUPPS safety valve ring settings. If the plant-specific ring settings were not tested by EPRI, explain how the expected values for flow capacity, blowdown, and the resulting back pressure correspond-ing to the plant-specific ring settings were extrapolated or calculated from the EPRI test data. Identify these values so determined and evalu-ate the effects of these values on the behavior of the safety valves.

Identify the applicable EPRI tests representative of these ring settings.

Response

The safety valve ring settings for the SNUPPS plants are as follows:

Plant Serial No. N.R. G.R. " Level Position"

-260 Wolf Greek N60446-00-0001 -18 -140 0002 -18 -265 -159 0003 -18 -230 -148

Callaway N60446-00-0004 -18 -230 -149 l 0005 -18 -230 -146 l 0006 -18 -225 -144 l

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~ __ ____ _ . _ , _ _ _ .

F~

e When the above guide ring settings are adjusted to account for the

" level" position, which was used by EPRI as the baseline for ring settings, the guide . ring settings f all in the range of -81 to -120 notches. These values approximate the EPRI test ring settings for the Crosby valve tests with " reference" ring positions as identif.ied in EPRI NP-2460-SR, - Table 4-7. Therefore, SNUPPS valve performance should be similar to. the EPRI. tests with " reference" ring positions.

(It is noted that one of the test valves--test 1419--exhibited chatter on closure. This stability concern is addressed under question number 5 in the previous submittal--SLNRC 86-07, dated 6/30/86.)

QUESTION 12:

The Westinghouse WCAP-10105 report states that for the feedwater line break and extended high pressure injection events, liquid discharge only occurs after- the pressurizer is liquid filled such that water reaches the safety valve inlets. The length of time to fill the pressurizer is plant dependent and varies from 20 min to 6 h. Estimate the time to fill the SNUPPS plants' pressurizer based on the worst case of the two events. Since the safety valves were originally specified and designed for steam service only, discuss the effects of liquid discharge on valve operability. Provide a discussion addressing the pressurizer fill. time and if there is sufficient time for the operators to take corrective action to prevent liquid discharge through the safety valves for these events.

Response

Refer to the response to question 8 above.

QUESTION 13:

The submittal states that -a hydraulic analysis of the safety / relief valve piping system has been conducted. To allow for a more complete -

evaluation of the methods used and the results .obtained from the thermal hydraulic analysis, ' provide additional discussion on the thermal hydrau-lic. analysis that contain at least the following information:

(a) Evidence -that the analysis was performed on the fluid transient cases producing the maximum loading on the safety /PORV piping system. The cases should bound all steam, steam to water, and water flow transient conditions for the safety and PORV valves.

l (b) Identification of important parameters used in the thermal hydrau-

lic analysis and rationale for their selection. These include peak

! pressure and pressurization rate, valve opening time, fluid condi-

tions at valve opening, time step, and valve flow area.

(c) A sketch of the thermal hydraulic model showing the size and number

of fluid control volumes.

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. _. .. - _ . _ _ _ _ . _ _ _ . . _ _ . . - _ . ,_.._._._.m . _ , _ _ _ _ . _ . . _ _ . . - _ . . _ . _ . - _ . . _ . . . _ . _ _ . . .

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Response

The Pressurizer Safety and Relief Line Piping and Support Evaluation report for the SNUPPS plants was submitted to the NRC in SLNRC 83-002, dated January 7,1983. In the piping and support evaluation, various fluid transient analyses were performed for the pressurizer safety and relief valve piping system. Operation of the safety valves during power operation, operation of the relief valves at power operation and actu-ation of the relief valves to mitigate cold overpressurization were cases evaluated. Transition flow through the safety valves and power operated relief valves was also considered. In general, the three safety valves opening simultaneously and discharging without PORV flow and the two PORV's opening simultaneously without safety valve flow are the limiting design cases. A combination of the cold overpressurization water solid case and relief valve discharge at power case are limiting for the piping section near the relief valve. Typically, the worst case valve discharge case (S0T p ) is the triple safety valve discharge transi-ent for the safety valve piping, including the inlet, outlet and common region piping and the double relief valve discharge transient for the relief valve inlet and outlet piping. The initial conditions for the safety valve water slug discharge included:

P(Upstream) = 2575 psia h(Steam, Upstream) =

1110 Btu /lb h (Water, Upstream) = Enthalpy based upon a temperature profile consistent with EPRI safety valve discharge test #917, i.e.,

approximately 300 degrees F at the valve inlet and saturation temper-ature at the steam-water iaterface.

P (Downstream) = 14.7 psia The pressurizer conditions were held constant for the transient at 2575 psia and 1110 Btu /lb.

The initial conditions for the relief valve slug discharge case inc-luded:

P (Upstream) = 2350 psia h (Steam, Upstream) = 1162.4 Btu /lb T (Water, Upstream) = 150 degrees F P (Downstream) = 14.7 psia The pressurizer conditions were held constant for the entire transient at 2350 psia and 1162.4 Btu /lb.

The adequacy of the thermal-hydraulic analyses can be verified by the comparison of analytical and test results for thermal-hydraulic loadings in safety valve discharge piping for EPRI Tests 908 and 917. This comparison was summarized in section 4.6.2 of the report submitted by i

i -

SLNRC 83-002. In that evaluation, node spacing.and time-step size were selected on the basis of stable solutions of the characteristic equa-tions and mapching of test data. The safety valve full open flow area of 0.022 ft was used in the model. This a than the Crosby M-orifice area of 0.025 ft[ea foristhe slightly testedsmaller valve, but results in a good analytical match of the tested fully open valve flow rate. Appropriate water temperatures were used. All pertinent data, including friction factors, loss factors, and flow areas were based upon representative calculations and the system layout. Modeling of the water was conducted with the water seal upstream of the valve prior to transient initiation. At time - 0+, the transient was initiated and the slug position was analytically calculated during and subsequent to valve opening.

The SNUPPS plant-specific thermal-hydraulic analysis was conducted taking the same approach as was taken for the comparison to test data.

Node spacing was picked consistent with the comparison and varied with pipe size and location. For the discharge cases, all node lengths were less than 3.9 ft. Time-step sizes were utilized consistent with values utilized in the comparison (0.003 seconds and 0.004 seconds for the safety valve slug discharge and relief valve slug discharge cases, respectively). Valve opening times, 0.020 seconds for the safety valves and 0.066 seconds for the Valve flow areas (0.025 ft{elief forvalves, werevalves the safety basedand upon actual 0.0174 ft pata.

for the relief valves) were selected based upon actual valve data with appropriate margins applied to account for flow rate uncertainties. All pertinent data, including friction factors, loss factors, and flow areas were based upon representative calculations and the system layout.

Modeling of the water slug f rom a temperature profile, considering initial location and movement post-transient initiation, was consistent with the comparison study. The pressurizer pressure was held constant through the transient at initial values. Choked flow is checked inter-nally and automatically every time-step to ensure the proper formulation is applied at every flow path. Sketches of the models and specific data are presented in Figures 1-A,1-B, 2-A, 2-B, and Tables 1 and 2.

QUESTION 14:

The submittal states that a structural analysis of the safety PORV valve piping system has been conducted. To allow for a more complete evaluation of the methods used and the results obtained from the struc-tural analysis, please provide reports containing at least the follow-ing information:

(a) An evaluation of the results of the piping support analyses includ-ing identification of overstressed locations and a description of modifications, if any.

(b) Identification of important parameters used in the structural analysis and the rationale for their selection. These include node spacing, time step, damping and cut off frequency.

(c) A sketch of the structural model showing lumped mass locations, pipe sizes, and application points of fluid forces.

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Response

As a follow-up activity to the piping and support evaluation submitted in SLNRC 83-002, the operability and structural integrity of the as-built system has been ensured for all applicable loadings and load combinations, including all pertinent safety and relief valve discharge ,

cases. All analyses are applicable to the as-built piping configu-ration. All overstressed support locations were identified and resolved in the design process prior to completion of the as-built analysis.

The structural analyses programs utilized in the static and dynamic analyses were described in WCAP-8252. This was reviewed and approved by the U.S. NRC (NRC letter, April 7,1981 from R. L. Tedesco to T. M.

Anderson of Westinghouse). Following is a discussion of key parameters used in the structural analyses of the dynamic events:

1. Damping - A conservative system damping of 1 percent was utilized for the OBE. 2 percent was utilized for SSE and the thermal hydrau-lic analyses. These are much lower than the actual expected values 4

and below the 10 percent damping used in the structural comparison to EPRI Test 908 and 917.

2. Lumping -- Lumped mass spacing was determined to ensure that all i appropriate mode shapes were accurately represented.

3. Supports - The structural supports were modeled in sufficient detail to analytically represent the system. The shock suppressors and struts were modeled by inputting a stiffness in series with the piping. Specifically calculated stiffness values were utilized.

All -supports were linear and a linear overall system analysis was conducted.

4. Time-Step - The integration time-step is internally determined 4

within the structural program and is based upon convergence criteria that results in the stable solutions. The largest time-step ever used could be 0.0001 second. The time-step is automatically ad,just-ed such that the elative error of each modal coefficient is at least less than 10-

5. Cut-off Frequency - A cut-off frequency was used to ensure that all appropriate frequencies were included. For the thermal hydraulic cases, a cut-off frequency greater than 1000 HZ was used.

The model is illustrated in Figures 3-A, 3-B, and 3-C.

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LISTING OF REPORTS REFERENCED IN RESPONSES l

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1. WCAP-10105, Review of Pressurizer Safety Valve Performance as Observed in the EPRI Safety and Relief Valve Test Program, June 1982.

2. EPRI Report NP-2296, Valve Inlet Fluid Conditions for Pressur-izer Safety and Relief Valves in Westinghouse-Designed Plants, December 1982.

3. EPRI Report NP-2628-SR, EPRI PWR Safety and Relief Valve Test Program: Safety and Relief Valve Test Report, December 1982.

4. EPRI Report NP-2460-SR, EPRI PWR Safety and Relief Valve Test Program: Test Condition Justification Report, December 1982.

5. WCAP-8252, Documentation of Selected Westinghouse Structural Analysis Computer Codes, Rev.1., May 1977.

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. .. TABLE 1 -

SAFETY LINE HYDRAULIC DATA ,

(See Firures 1-A and ,1-B for Location of Semeents)  !

Segment Number of Nodes Pipe size Esgment. LangrA lf.t) _ PCsgen.t_ (Inch /3shedds) 1 1.25 1 6/160 2 3.25 1 6/160 3 3 5156 1 6/160 4 1.5 1 6/160 5 1 9375 1 6/160 -

6 5.2448 2 6/80s 7 9 9011 3 6/80s 8 3 9583 2 12/80s 9 8.4167 3 12/80s 10 3 5156 1 12/80s 11 1.2917 1 12/80s 12 4.0052 2 12/80s 13 1.25 1 6/160 14 35 . 1 6/160 15 3 5156 1 6/160 16 1.5 1 6/160 17 1 9375 1 6/160 18 2.4063 1 6/80s 19 11.8438 4 6/80s 20 3 0729 1 6/80s 21 1.25 1 6/160 22 3.5156 1 6/160 23 3 5156 1 6/160 24 1.5 1 6/160 25 1.9375 1 6/160 26 3 9219 2 6/80s 2T 11 724 4 6/80s -

28 0.625 1 12/80s 29 2.4166 1 12/80s 30 1.2917 1 12/80s 31 29 25 10 12/80s 32 6.75 2 12/80s 33 11.7135 4 12/80s 34 10.75 3 12/80s 35 7 7708 2 12/80s l 36 3.00 1 12/80s 37 18.1667 6 12/80s 38 6.25 2 12/80s i 39 14.75 5 12/80s l 40 5.5 2 12/80s 41 19.6979 6 12/80s 42 13 9635 4 12/80s 43 8.2344 3 12/80s l

44 6.125 2 12/40 (Below Relief Tank Flange 45 14.177 5 12/40 (Below Relief Tank Flange) i

. . ?.

TABLE 2 RELIEF LINE HYDRAULIC DATA

. (See figur.es 2-A..and .2-A .f.o.r. Locat_ipApf Sements)

Segment Number of Nodes Pipe Size segment Lennth (ft)* Per SeBEDA ... .(lRGhl3SDJdM)e).

1 0.8125 1 6/160 2 2.6979 1 6/160 3 9.6771 3 6/160 .

4 1.00 1 6/160 5 2.00 1 3/160 ,

6 14 3281 5 3/160 7 3 6667 1 3/160 8 2.5833 1 3/160 9 2.0208 1 6/80s 10 3 000 1 6/80s 11 4.5104 2 6/80s 12 2.1042 1 6/80S 13 2.1667 1 12/80s 14 8.4167 3 12/80s 15 4.8073 2 12/80s 16 4.0052 2 12/80s

. 17 1.2917 1 12/80s 18 29.25 *9 12/80s 19 6.75 2 12/80s 20 11.7135 4 12/80s 21 10 75 3 12/80s 22 7 7708 2 12/80s 23 3 00 1 12/80s 24 18.1667 6 12/80s .

25 6.25 2 12/80s 26 14.75 5 12/80s i 27 5.5 2 12/80s l 28 19.6979 6 12/80s t 29 13. % 35 4 12/80s i

30 8.2344 3 12/80s 31 6.125 2 12/40 (Below Relief- .

Tank Flange) 32 14.177 5 12/40 (Below Relief Tank Flange) 33 14 3281 5 3/160 '

34 2.4167 1 3/160 -

35 3.8333 1 3/160 36 1.0104 1 6/80s 37 1.0104 1 6/80s

(

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. SAFETY LINE A 22 -

21

i8010A 3

6 5g 4 23 13 l 14 8010C '

l 26 4 SAFETY LINE C SAFETY LINE al 5 -

24 (25 18

( q pl )B

! 17 i 19 i

FROM RELIEF l LINE f3 27 8 .

t I (128 4

l 9 29 1 20 30 I

10 11

{ ,

FIGURE l-A: SAFETY LINE ilVDRAULIC N00EL FROM PRESSURIZER.TO' ANCHOR A005 31 NOTE: The ntsnbers corresp6nd to the segmen'ts in Table 1. [ ,

i 34 3? 33 am

A001

- N .

42 43 PRESSURIZER ==

RELIEF Tang Al

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9 40 39 4

l 38 A005 -

35 37 A004 l . .

FIGURE 1-B: SAFETY LINE HYDRAULIC MODEL FROM ANCHOR A005 TO RELIEF TANK i

Note: The numbers correspond to the segments in Table 1.

i

FIGURE 2-A: RELIEF LINE HYDRAULIC

, MODEL FROM PRESSURIZER TO ANCHOR A005 3

l

. Note: The numbers correspond to the 4 h' segments in Table 2.

i Y

u l

1 i

6 .

33 FROM SAFETY LINE A 11 N 10 6 '3 .

3 FROM SAFETY LINE C I 35 I9  ; FROM SAFETY LINE 8 8 17 7 16 15 18 Y

d 0 21

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19 20 aans

f...... .

h001

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29 30 PRESSURIZER RELIE1 ma TANK

'28 27 26 El gg A005 22 24 A004 23 FIGURE 2-8: RELIEF LINE HYDRAULIC MODEL

'FROM ANCHOR A005 TO RELIEF TANK Note: The numbers correspond to the segments in Table g,

-_ y_-_.-- -y.. , _ _ _ _ - , - - -

f$2 _

SAFETY LD,E A a p" /' 22 8010A 3 21! \ '

m p

14

/ g3 23 10C O SAFETY LINE C

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SAFETY LINE B l59 .

l FIGURE 3-A:

I1 I0 S 1 )3 SAFETY LINE PORTION OF THE STRUCTURAL H0 DEL (T0 ANCHOR A005) l o

i  ? "

o o e - Ltaped Mass

+ Force Application Point FROM RELIE LINE 1 27 8 0 4 .

0 O , ,

28 9 9

\

N N 2

i,x '

10 . IL /

. 5 'S -

0 0

NOTE: The numbers correspond to the segments in Table 1. ll O' -

4 > - N 34 j A005

3

/ h '

2 Note: The numbers correspond to the 4/

segments in Table 2.

/M '

4 >

~

4 p .

6

,, 33 FROM SAFETY LINE A n x. '

t p3 ga 10 .

35 FROM SAFETY LINE C g4 FROM SAFETY LINE B -

34 A pN N

• l5

\ 0

/ x

16-FIGURE 3-B: < >l8 RELIEF LINE PORTION OF Tile STRUCTURAL H0 DEL (10 ANC110R A005) y ,

o 8- Lumped Hass ,

I' 21

+ - Force Application Point N

gg 20 N

A00s p

FIGURE 3-C:

,- STRUCTURAL MODEL FROM ANCHOR A005 TO

.,. THE RELIEF TANK e .,

1 0- Lumped Mass

. - Force Application Point O

dp O

. . O \29 0 -

30g f PRESSURIZER RELIEl TANK "g" 28

>27 26 a 0

21 . 25 A005 N I o\

l 22 24 Od -

A004

\,-

Note: The numbers correspond to the segments in Table 2.

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