ML18092A746

Rev 0 to Pressurizer Relief & Safety Valve Piping Qualification During Postulated Rapid Valve Actuation.

ML18092A746
Person / Time
Site:	Salem
Issue date:	04/30/1985
From:	Ward M ABB IMPELL CORP. (FORMERLY IMPELL CORP.)
To:
Shared Package
ML18092A739	List: ML18092A738 ML18092A740 ML18092A741 ML18092A745 ML18092A746 ML18092A747
References
02-0140-1325, 02-0140-1325-R00, 2-140-1325, 2-140-1325-R, NUDOCS 8508280296
Download: ML18092A746 (52)

Text

PUBLIC SERVICE ELECTRIC AND GAS COMPANY SALEM UNIT NO. 1 PRESSURIZER RELIEF &SAFETY VALVE PIPING QUALIFICATION DURIN.G POSTULATED RAPID VALVE ACTUATION

• REPORT No. 02-0140-1325 REVISION 0 PREPARED BY:

IMPELL CORPORATION APRIL, 1985 r 8508280296 850819

• 1 I . PDR *

• ADOCK 05000272

! .p .. *:. .. .* :.. . * *PDR* . *

• I IMPELL CORPORATION I NEW YORK REGIONAL OFFICE REPORT APPROVAL COVER SHEET I

I Client: PUBLIC SERVICE ELECTRIC AND GAS COMPANY SALEM 1 PRESSURIZER RELIEF AND SAFETY VALVE PIPING QUALIFICATION I Project:

Job No.: 0140-*022-1641 I Report Title: PRESSURIZER RELIEF AND SAFETY VALVE PIPING QUALIFICATION DURING POSTULATED RAPID VALVE ACTUATION

~ Report Number:

02-0140-1325 Rev. No.:

0

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The work described in this Report was perfonned in accordance with the Impell Corporation Quality Assurance Program. The signatures below verify the accuracy of this Report and its compliance with applicable quality assurance requirements.

Prepared By: Date: 8/ f I sr-Reviewed By : Date: -n---,lz-/a-.~--

• Approved By: oate: _'~..;..?J~t_/R_~_-._._

Concurrence By: Date:

d!. I anager 9lr£ REVISION RECORD REV. I APPROVAL I NO. PREPARED REVIEWED APPROVED !CONCURRENCE DATE REVISION I I I-

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PSE&G; Salem l 02-0140-1325 Impell Corporation Re vision O Page 2 TABLE OF CONTENTS Page APPROVAL COVER SHEET -l-TABLE OF CONTENTS 2 l.O ABSTRACT 5 l.l Required Evaluation 5 l .2 Co nc l usi o ns 5 l.3 Modifications Instituted 5 l.4 Acceptability 5

2.0 INTRODUCTION

6 2.l Background 6 2.2 System Description 7 2.3 System Functional Requirements 7 2.4 Evaluation of Original Analysis 8 2.4. l Safety Valve Loop Seal 8 2.4.2 Westinghouse Procedure SSDC l.21 9 2.4.3 RELAP 5 Mod. l 10 2.4.4 Adequacy of Original Piping System 10 2.4.5 Options for Modifications ll 2.4.6 Loop Seal Heating 12 2.4.7 Insulation Box Loop Seal Heating 13 3.0 CODE OF RECORD 14

3. l Piping 14 3.2 Pipe Supports 14 4.0 ACCEPTANCE CRITERIA 15 4.l Piping and Pipe Supports 15

4. l .. l Background 15 4.1.2 Discussion 15 4.l.3 Stress Criteria 17 4.2 Valve Operability 17 5.0 METHOD OF ANALYSIS 21 5.l Thennal Hydraulic Effects of Rapid Valve Actuation (RVA) 21 5.l. l Thennal Hydraulic Loading 21

5. l . 2 RE LAP Ana ly sis 21 I

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PSE&G; Salem 1 02-0140-1325 Impell Corporation Revision O Page 3 TABLE OF CONTENTS (CONT 1 D)

Page 5.2 SUPERPIPE Pipe Stress Analysis 22 5.2.l Description of SUPERPIPE 22 5.2.2 Direct Integration Force Time History 23 5.2.3 Damping for Direct Integration Time Hi story 24 5.3 Pipe Support Assembly Structures 25 5.4 Stress Analysis Model 25

- 6.0 SPECIAL TECHNICAL TOPICS 26

6. l Relief and Safety Valve Parameters 26

,. 6.2 Safety Valve .Opening Time Sensitivity Study 26 6.2.l Background 26 6.2.2 Discussion 26 6.2.3 Conclusion 27 6.3 Pipe Temperature Considerations 27.

6.3. l Design Temperatures 27 6.3.2 Normal Plant Operation (NPO) 27 6.3.3 Normal System Operation (NSO) 27 6.4 Sei smi c Anchor Movement (SAM) 28 6.5 Structural Damping 28 6.5. l For Direct Integration Force Time History Analysis 28

6. 5. 2 For Seismic Analysis 28 6.6 Modal Combination in Seismic Response Spectrum Analysis 28 I 6.7 6.8 Combination of RVA and Earthquake Load Stress Intensification of Latrolets and 3x2 29 Reducers 29 6.8.l Latrolets 29 I 6.8.2 3 X 2 Reducers 29 6.9 Functionality of Pipe Anchor at Elev. 131 1 -4 11 29 I 6.9. l Requirements 6.9.2 Acceptance Criteria 29 30 6.9.3 Concurrent Loading 30 6.9.4 Maximum Operating Temperature 30 6.9.5 Damping Valves 30 6.9 .. 6 Conclusions of Anchor Functionality 31 I

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PSE&G; Salem l 02-0140-1325 Impell Corporation Revision 0 Page 4 TABLE OF CONTENTS (CONT'D) 7.0 RESULTS AND CONCLUSIONS 32 7.1 Piping 32

7. 1. l Analyses 32

7. 1. 2 Results 32 7.2 Pipe Supports 33 7.3 Valve Operabi.lity 33 8 .0 REFERENCES 39 APPENDIX A - Selective References 41 FIGURES 4.1 PSE&G/Salem l Pressurizer Discharge Piping-Limits of Service Level 11 B11 vs. Service Level 11 C11 Stress Allowables 18 I

,. TABLES 4.1 4.2

7. 1 7.2 Piping Load Combinations and Stress Allowables Pipe Support Load Combinations and Stress Allowables Pipe Support Drawing Index .

Pipe Stress at Piping Adjacent To Relief and 19.

19 35 I Safety Valve Interfaces 7.3 Maximum Calculated Bending Moments at Relief and 37 Safety Valve Inlet and Discharge Interface 38 I

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PSE&G; Salem 1 02-0140-1325 Impell Corporation Revision O Page 5

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I 1.0 ABSTRACT

1. l Required Evaluation In compliance with USNRC NUREG-578, 666 and 737 Item II Dl, PSE&G Salem Unit No. 1 Pressurizer Relief and Safety Valve p1p1ng was evaluated for the dynamic shock effects of rapid valve actuation (RVA) of the Relief and Safety Valves, bounding the cases of steam, two-phase and solid water discharge from the Pressurizer. Current state of the art analytical techniques were applied, which are in keeping with test results derived by the Electric Power Research Institute ( EPRI) *.

1.2 Conclusions It was concluded that a two-fold modification was required, namely*

heating the Safety Valve inlet piping loop seal to enable flashing .... j during discharge; and to strengthen existing pipe supports, and judiciously add new pipe supports to control pipe stresses and dynamic loads on the Relief and Safety Valves.

1.3 Modifications Instituted The following modifications were instituted:

1. Insulation boxes were furnished, encasing the Safety Valv.e loop seals with a local segment of uninsulated Pressurizer wall.

This utilizes the Pressuriz~r as a passive heat source for.the loop seal piping.

2. Two (2) additional rigid supports and 12 additional snubbers were furnished. Two (2) supports were relocated to more I efficient locations. All supports were qualified to the new 1oadi ng. A11 required strengthening modifi cati ans to existing supports were implemented.

I l.4 Acceptability With the above noted modifications, the p1p1ng is ASME Code I qualified for all load combinations suggested in the reference 4.1 Guidelines generated by an EPRI subcommittee on piping (labeled 11 Appendix E11 ) . Additionally, the RVA shock loading on the Relief and Safety Valves is sufficiently modest to assure valve I operability.

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PSE&G; Salem 1 02-0140.:.1325 Impell Corporation Revision 0 Page 6 INTRODUCTION

2. 1 Background As part of the Three Mile Island Action Plan, the U.S. Nuclear Regulatory Commission (NRC) issued NUREG-578, 666 and 737, which require qualification of the Reactor Coolant System Relief and Safety Valves. Proper operation of Reactor Coolant System Relief and Safety Valves is vital, since failure of one or more of these valves to function could impair the Reactor Cool ant Pressure Boundary ( RCPB).

Salem Unit No. l Pressurizer Safety Valve inlet* piping includes loop seals, such that there is always water immediately upstream of the valves when they are in their normally closed position. Upon Safety Valve actuation, the slug of water within the loop seal is discharged, followed by-Pressurizer fluid. The Relief Valve inlet piping does not include a loop seal, and therefore, upon Relief Valve actuation the discharge does not include a water slug, but consists of only Pressurizer fluid.

During valve actuation, the discharging Pressurizer fluid is normally saturated steam from the top portion of the Pressurizer.

Under unusually rare conditions transients or accidents can be postulated, which may result in increasing the Reactor Coolant temperatures expanding the coolant volume, so that the Pressurizer fi 11 s with water. In this unlikely event, the Pressurizer fluid upstream of the reli~f and safety valves is two-phase or solid water.

The effects of Rapid. Valve Actuation with valves discharging steam from the Pressurizer (RVA-S) is considered to be possible and must I be evaluated. The effects of Rapid Valve Actuation with valves discharging two-phase, or solid water from the Pressurizer (RVA-W) is considered to be remote for Salem Unit No. 1 and need not be evaluated. However, as a conservatism, for Salem Unit No. 1 the I* Pressurizer relief and safety valve piping system was evaluated for both RVA-S and RVA-W loading conditions.

I In compliance with USNRC requirements, PSE&G participated in the Electric Power Research Institute (EPRI) Pressurized Water Reactor (PWR) Safety and Relief Valve testing program. EPRI performed tests of various prototypical configurations of Relief Valves I (RV 1 s) and Safety Valves (SV 1 s) and associated inlet and discharge piping, simulating expected operating conditions for design basis transients. Furthermore, EPRI reviewed Computer Codes for deriving I the time-hi story of loading on the valve inlet and discharge piping due to the thermal-hydraulic effects of rapid valve actuation (RVA). As a result, EPRI endorsed RELAP 5 Mod 1 to provide I sufficiently accurate load predictions.

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PSE&G; Salem l 02-0140-1325 Impell Corporation Revision 0 Page 7 It is required that each nuclear power plant must provide the documentation and analytical investigation necessary to qualify valve operability of its unique configuration, based on the EPRI prototype tests, using an EPRI endorsed Computer code to establish the RVA time-hi story loads.

To that end Impell Corp. provided an evaluation for the PSE&G Salem Unit 1 Pressurizer Relief and Safety Valve piping, utilizing the plant specific piping configurations. This evaluation considered time-hi story loads due to RVA, using the EPRI endorsed Computer Code RELAP 5 Mod l for both steam discharge (RVA-S), as well as postulated solid water discharge (RV-A-W).

2.2 System Description

The Pressurizer overpressure protection system for Salem Unit No. l consists of two po\\Er operated relief valves, three pressure activated safety valves, a Pressurizer Relief Tank, and connecting discharge piping. The po\\Er operated relief valves are located on three inch branch lines, connected to the Pressurizer through a common four-inch line. The three* pressure activated safety valves are each independently connected to the Pressurizer by six-inch lines and include loop-seal piping to ensure flooding of the valve seats, which is a manufacturer specified requirement for this valve. The discharge piping from the power operated relief valves and the pressure activated safety valves combine into a common 12-inch line which is anchored to the floor at Elev. 131 1 -4 11 and then continues to the Pressurizer Relief Tank at Elev. 85 -3 11

• 1 The purpose of the po\\er operated relief valves is to limit the system pressure for large power mismatches, thus preventing the actuation of a high pressure reactor trip and subsequent undesirable opening of the pressure activated safety valves. The re 1i ef va 1ve s a re set to open automatically at 100 psi g above the normal operating pressure of the Pressurizer.

I Should the pressure in the Pressurizer exceed 250 psi above normal operating pressure, the three spring-loaded safety valves will I automatically open to relieve the overpressure and protect the Reactor Coolant System.

I The system is shown on PSE&G drawings 267PCL and 267PDL (ref. 2.1),

as well as Impell Isometric drawings 0140-022-01 (one sheet) and 0140-022-02 (2 sheets) (references 2.2 and 2.3 respectively).

2.3 System Functional Requirements

.1 Pressurizer Relief and Safety Valve (R/SV) Inlet p1p1 ng and the Relief and Safety Valves are RCPB and must remain operational.

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PSE&G; Salem l 02-0140-1325 Impell Corporation Revision 0 Page 8

• .2 R/SV Discharge piping is important only as it affects R/SV operability, but is otherwise expendable *

• 3 R/SV inlet and discharge piping to the Pressurizer Relief Tank affects RVA loading and is therefore included in the RELAP 5

• thermal hydraulic analysis, which establishes time-hi story loads due to RVA on the various piping legs *

• 4 R/SV discharge piping between the R/SV's and the first downstream piping anchor at Elev. 131' affects RCPB loading and is therefore included in the pipe stress analysis and piping evaluation *

. 5 Discharge piping between the piping anchor at Elev. 131 1 and the Pressurizer Rellef Tank is isolated from RCPB by this p*ipe anchor, and is therefore excluded from the pipe stress analysis and evaluation, except as it affects the functionality of ~he piping anchor at Elev. 131 1

• 2.4 Evaluation of Original Analysis 2.4.l Safety Valve Loop Seal The Salem Unit l Pressurizer utilizes three (3) Safety Valves manufactured by Crosby Valve and Gage Co. These are nozzle type safety valves size 6M6, Style HB-BP-86, Type E.

For this particular valve, the manufacturer requires the valve seats to be flooded during normal plant operation, i.e., water upstream of the valve rather than steam.

Safety valve seat flooding was accomplished by configuring the valve inlet piping to trap condensate from the Pressurizer by means of piping loop seals. The loop seal piping was uninsulated to enhance formation of condensate.

The resulting slug of water within the inlet loop seal piping was therefore at Containment ambient temperature of approximately 12QOF.

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PSE&G; Salem l 02-0140-1325 Impell Corporation Revision O Page 9 2.4.2 Westinghouse Procedure SSDC 1.21

.l Background Transient thermal hydraulic forces are imposed at various bends and area change locations within the Pressurizer Relief and Safety Valve piping system when the valves are suddenly opened. These transient loads vary with time, until the oscillations are damped out, and steady state flow is achieved within the piping system.

In-1972 Westinghouse developed an analytical technique to predict these. transient loads, and published "it as Procedure SSDC 1.21. Specifically, this *procedure develops a *gradually increasing (positive) force on each piping leg, corresponding to flow being .accelerated at the piping elbow of the particular piping leg. This is followed by a gradual force reversal reaching a peak negative value and decay to zero as steady state develops. Three (3) hydraulic parameters affect the

• analytical results as follows:

a. Water Seal Volume

b. Valve flow area

c. Length of piping in each leg Procedure SSDC 1.21 was based on Westinghouse s previous 1

analytical experience with blowdown during a postulated loss of coolant accident, and was favorably received in the i ndu stry and oy the NRC, as bei ng sufficiently accurate to adequately predict thermal hydraulic loads on piping systems due to RVA.

PSE&G utilized this procedure in the original design of the Pressurizer Relief and Safety Valve piping .

• 2 Current Acceptance Status of Westinghouse Procedure*ssoc

l. 21 In 1972, Westinghouse planned an experimental program to test safety valves with water seals and confirm the anticipated effect of RVA on the piping. The results of this program were intended to verify the design approach of Procedure SSDC 1.21. It was hoped that these tests

....ould define the magnitude of conservatism of SSDC 1.21, or at worst, some minor modification could be made*to the procedure.

PSE&G; Salem l 02.:.0140-1325' Impell Corporation Revision 0 Page 10

• In 1977 Westinghouse issued Re vision l of SSDC 1. 21.

This revision deleted the original method of deriving RVA loads, and did not substitute another method. The 1977 revision to SSDC 1.21 merely provided a general statement that transient hydraulfc forces have to be included in the piping system evaluation, but omitted all references and recommendations for specific analytical procedures.

The results of the recent EPRI tests were compared with analytically derived results, applying the Westinghuse Procedure SSDC 1.21 for the EPRI test configuration.

The c.ompari son of test vs. analysis showed that the Westinghouse Procedure SSDC 1.-21 loads do not correlate

• with the measured EPRI test loop results. The

• Westinghouse Procedure consistently under-estimates the peak values of applied force and provides different time relation of loading.

Based on the above, it was concluded that SSDC 1.21 should not be used to predict RVA loading; and that a more sophisticated analytical technique is required to predict thermal hydraulic loading due to RVA.

2.4.3- RELAP 5 Mod 1

.1 RELAP 5 Mod l is a Computer program which derives thermal hydraulic time-history related pressure and fluid ~elocities. With use of a fairly simple post-processor program to develop forces from the pressures and velocities, this constitutes a reasonably sophisticated and easy to use analytical tool. RELAP 5 and the post-processor program used for this project is discussed in Section 5.1 below*

• 2 EPRI endorses RELAP 5 Mod 1 as providing reasonably representative load time hi story predictions. This program is also acceptable to the USNRC .

• 3 It was therefore, decided that any future analytical work would utilize RELAP 5 Mod 1 for derivation of RVA time-hi story loads.

2.4.4 Adequacy of Original Piping System

. l Salem Unit l Pressurizer Relief and Safety Valve (R/SV) piping was studied in detail. The conclusions of this study were applied to both Salem Units l and 2 piping systems .

• PSE&G; Salem 1 02-0140-1325 Impell Corporation Revision 0 Page 11

.2 RVA time-history loads were developed for the existing piping assuming cold loop seal water, as was the case for an uninsulated loop seal exposed to Contai nnent ambient temperatures of about 120oF .

. 3 These RVA time-history loads were applied to the existing piping system configuration including the existing pipe support locations in a force time history pipe stress analysis. The computer program SUPERPIPE was utilized for this evaluation *

. 4 The results of this evaluation showed that the cold loop seal RVA loading on the existing piping system causes excessive support loads and pipe stresses which exceed Code allowables by-a large margin *

• 5 It was therefore concluded, that some modifications are required to the p1ping, supports and/or equipment, in order to provide a Code compliant piping system.

2.4.5 Options for Modifications Impell Corp. prepared a detailed evaluation of various options available to PSE&G, to resolve this problem (see reference 2.4) The following four options were evaluated:

1. Option A utilizes the present loop seal, heated *to permit flashing of the water slug upon opening the Safety Valve. This would minimize the pipe loading and I eliminate any piping configuration change. Option A was separated into Option Al, involving passive heating from the Pressurizer (using a common i nsu 1ati on box) and I Option A2, involving active heating by use of electrical heat traces.

2. Option B involves a warm loop seal obtained by adding I pipe insulation. This would slightly reduce the RVA loading from the cold loop seal condition. However, a considerable number of support additions and piping I modifications are likely to be required. Additionally, the magnitude of pipe support loading might be so large as to make this option unfeasible.

I 3. Option C involves elimination of the loop seal by rerouting portions of the existing piping. This would significantly reduce the RVA loading as the water loop I seal will be eliminated. In order to accommodate sealing with steam rather than water at the inlet side of the valve, the valve internals would have to be I modified. Al so, si nee the safety valve inlet piping would be modified, the Reactor Coolant Boundary *

(including the Reactor Vessel) would have to be hydrate sted agai n.

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PSE&G; Salem l 02.:.0140.:.1325 Impell Corporation Revision 0 Page 12

4. Option D, involves draining the existing loop seal. In view of the complexity of furnishing new systems, controls, and other problems related to control of draining Reactor Coolant, this option was considered least feasible and was therefore not pursued.

2.4.6 Loop Seal Heating

.l In this option, the safety valve inlet piping is heated, so that the water within the loop seal is at a sufficiently elevated temperature to achieve flashing, thereby decreasing the thermal hydraulic loading on the discharge piping. The design must be such that the Safety Valve i *s maintained at 300°F or below, as per the valve manufacturer requirements *

. 2 Two methods of loop seal heating were considered.

Active heating by means of electric heat tracing of the loop seal piping was rejected in.favor of passive heating from the Pressurizer.

3. Active heating of the Safety Valve Inlet Piping Loop Seal would involve furnishing electric heat tracing to heat the loop seals. Since the loop seal temperatures affects the Safety Valve loading due to RVA; .and since the SV's comprise Reactor Coolant Pressure Boundary (RCPB); therefore, the heat tracing system would require sufficient safeguards to assure reliable operability.

This might include full system redundancy; temperature I monitoring with redundant remote read-out in the Control Room; would affect the Plant Technical Specification for system operating instructions as well as possible I requirements for shutdown and repair in the event of a malfunction; and would require in-service inspection .

. 4 Passive heating of the Safety valve Inlet piping loop I seal comprises locally removing Pressurizer insulation panels and constructing new insulation boxes to encase the loop seal piping in common with the locally I uninsulated Pressurizer surface. The Pressurizer surf ace which is at 65QOF to 68QOF during normal plant operation, heats the trapped air within the insulation box, which in turn heats the loop seal I piping, including the stagnant water contained within the loop seal piping.

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PSE&G; Salem l 02-0140-1325 Impell Corporation Re vision 0 Page 13

• 5. Use of insulation boxes to provide possible heating of the safety valve/loop seals was chosen in favor of electric heat.tracing, si nee the insulation box system is reliable; requiring no monitoring instruments after

• initial confirmatory temperature measurements taken; does not affect the Plant Technical Specification or the

!SI Program; and is more economical than heat tracing.

2.4.7 Insulation Box Loop Seal Heating It was agreed to provide passive heating of the Safety valve inlet piping by utilizing an uninsulated portion of the Pressur_i zer as the heat source, and by constructing new insulation boxes to encase the loop seal piping in common with the locally uninsulated Pressurizer surface .

. It was understood, that pipe support modifications would also be required. This option was selected, because it has the least impact on plant.operation; on-line availability during construction; negligible maintenance requirements; inherent reliability; relative ease of implementation; and relative cost to the utility.

PSE&G; Salem l 02-0140.:.1325 Impell Corporation Revision 0 Page 14

.0 CODE OF RECORD

3. l Piping

'The Code of Record for this piping system per FSAR Section 3.9.2 is USAS 831. l (1967) 11 Power Piping Code 11 and was used in the evaluation;* except that the primary pipe stresses incorporate a factor of 0.75 (i), as introduced into ANSI 831. l (1973) and the ASME Code Section III, Subsection NC (1974).

In addition, this evaluation also includes the concept of Service Levels A (Normal), 8 (Upset), C (Emergency) and D (Faulte_d) loading combinations, and their appropriate stress limits, as introduced in the* ASME Code,Section III, Subsection NC (Winter 1976 Addenda).

Thus, the allowable stress of 1.2 Sh, 1.8 Sh and 2.4 Sh are used for Service Levels 8, C and D loading combinations respectively. Sh is as listed in Tables I-7.1 and I-7.2 of ASME Code Section III (1974).

3.2 Pipe Supports The ASME Code Section III does not apply to the original plant design (See FSAR Section 3.9.16). Ho\\ever, for the current effort, ASME Code Section III and AISC Eighth Edition .were generally used for design of new supports and for- major modification of existing supports. Existing support components requiring no or qnly minor modification for requalification under current loading, have been evaluated, using the above criteria or have used AISC Sixth Edition and 831. 1 1967 for acceptance criteria.

Component standard supports were chosen by use of the load rating as established by the manufacturer of the component standard support *

• PSE&G; Salem 1 02-0140-1325 Impe 11 Corporation Revision O Page 15

.0 ACCEPTANCE CRITERIA 4.1 Piping and Pipe Supports

4. 1. 1 Background For Salem Unit 1, the Rapid Valve Actuation (RVA) time history loads within the Pressurizer Relief and Safety Valve piping were derived for simultaneous blowdown of the two (2)

• Relief Valves (RV's) and the three (3) Safety Valves (SV's). It was postulated that blowdown for all five (5) valves is concurrently initiated, althqugh these valves are actually set to blow in 1 stages. Time hi story loads for separate b1owdown of RV s only, or for* SV 1 s only, were not derived.

In February 1983, the Reference 4.1 recommended EPRI Appendix E was introduced as criteria for this project.*

This document addresses RVA loading for separate blowdown of the RV's only (FRv), and for the SV's only (Fsv).

Whereas all discharge piping subjected to (P + D + Fsv) may meet Service Level C stress limits; the piping should meet the more stringent Service Level B stress limits for (P

+ D + FRv) loading. In order to use the referenced

• criteria verbatim, separate FRv and Fsv loads would be required, but these separate loadings_ were not derived for this project.

4. 1. 2 Discussion

.1 Using RVA loading due to simultaneous blowdown of all valves (F) and meeting Service Level B stress limits, constitutes a conservative approach to the reference 4. 1 EPRI document, but results in an excessive number of snubber additions. On the other hand, using the less stringent Se.rvice Level C stress limits for all piping due to (P + D + F) dictates plant shutdown and I

inspection after either an RV or an SV blowdown event.

Since the SV 1 s are rarely, if ever, actuated, plant I shutdown and inspection after an SV blowdown event poses no undue hardship. However, si nee the RV 1 s may be actuated occasi anally, inspection after an RV blowdown I would constitute an imposition on normal plant operation .

. 2 Use of load (F) due to simultaneous blowdown of all SV's and RV' s as derived for this project is justified by the I following conservatisms:

a. Heat losses from the piping to the surrounding atmosphere were neglected. According to the Re"ference 4.2 IT! report, neglecting heat losses results in over-prediction of loads.

PSE&G; Salem l 02-0140-1325 Impell Corporation Revision 0 Page 17

b. Thi s ri ser i s a f ai r ly rigid component, which functions as a virtual anchor to the SV and RV branches, and thus effectively decouples the dynamic structural response of these branches.

4. l.3 Stress Criteria For load combinations which include RVA effects (F), the SV and RV Inlet piping, as well as the RV Discharge piping shown shad~d on Fig. 4.1, were evaluated against Service Level B stress limits; whereas the SV discharge piping shown unshaded on Fig. 4. l, was evaluated against Service Level C.

stress limits.

• The specific load combinations evaluated, and the applicable allowable stresses are shown on Tab.les 4. l for piping and

4. 2 pipe supports.

4.2 Valve Operability Calculated stress of piping at the Relief and Safety Valve junctions was used as a measu*re of severity of valve* loads and determination of valve operability. The severest combination of pressure, deadweight OBE and RVA effects was considered. The Nalves are considered acceptable for calculated pipe stresses not exceeding l.2 Sh, whicp is the allowable pipe stress for Service Level B load combinations (ref ASME Code Section III subsection NC 1980; paragraph NC3652.2, Equation (10) for occasional loads). For the loads combination of pressure, deadweight, SSE and RVA effects, the maximum calculates pipe stress not exceeding l.8 Sh for Service Level C is considered acceptable.

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PSE&G; Salem l 02.:.0140-1325 Impell Corporation Re vision O Page 16

b. RV 1 s are actually actuated at 2330 psi, whereas the analysis assumes them to be actuated *at 2500 psi.

The higher actuation pressure results in an over-prediction of loads.

c. RV opening time (per EPRI tests) is in the order of 500 to 970 milliseconds. The analysis assumes a 150 millisecond opening time, which results in a significant over-prediction of loads.

d. RV's and SV's.will be actuated sequentially with the RV 1 s blowing considerably before the SV 1 s. Thus, the SV' s will discharge into the 12 11 riser, which has been pressurized by the previous RV discharge.

The analysis postulates atmospheric pressure in the riser during the beginning of SV di sch_arge, which results in over-prediction of SV discharge loads .

• 3 RV blo\\down has a small effect on SV discharge piping and vice versa. The following discussion is presented:

a. A review of the hydrodynamic loads (F) in the RV.

discharge piping, away from the 12 inch riser pipe, shows peak loads of approximately *equal magnitude.

In the immediate vi ci ni ty of the riser, the peak loads decrease, but only by 10%. This local change is attributed to the backpressure in the riser from the postulated SV discharge event. It is concluded that the backpressure in the riser does not significantly affect the RV discharge pipe loads.

b. In the vi ci ni ty of the l 2 i nch ri ser, a bl owdown of the RV's imposes a negligible loading on the SV piping, si nee the RV blowdown momentum forces the discharge in the direction of the Pressurizer Relief Tank.

c. Within the 12 inch riser pipe the SV load peaks at 250 milliseconds, whereas the RV load peaks at 300 milliseconds. Thus the peak magnitude of these loads are not additive, and for all practical purposes, the SV and RV loads are decoupled .

. 4 The dynamic structural response of the SV and RV discharge piping branches have a negligible interactive effect on each other.

a. These branches all discharge into a vertical 12 inch diameter riser that is anchored at elevation 131 1 -4 11 , which is immediately below the lowest latrolet, and is provided with a two-way stop approximately 10 ft. above this location.

PSE&G; Salem 1 02-0140-1325 Impell Corporation Revision 0 Page 19 TABLE 4. 1: PIPING LOAD COMBINATIONS AND STRESS ALLOWABLES I LOAD COMBINATIONS I

LOJlDS TYPE SERVICE LIMIT II NO.

P+DW I Sustained A (Normal)

ALLOWABLE STRESS h

I. I I 2 P+Dw+F I Occasi ona 1 B (Upset) i.2 sh (RV piping)

I I c ( Erne rge ncy ) l. 8 sh (SV piping)

I I I 3 P+DW+OBE+F*I Occasi ona 1 B (Upset) i.2 sh (_RV inlet I I piping I I- c (Emergency) i. a s~ ( RV a; s-I I c arge piping)

I I 4 I P+DW+SSE+F*I Occasi a na 1 D (Faulted) 2.4 sh I I I I 5a I TE+SAM I Thermal B (Upset) SA I I - I Expansion 5b P+DW+TE+SAMI Sustained B (Up set) SA + Sh I plus therma 1 I Expansion

• Omit if this decreases the total load or maximum calculated stress.

Table 4.2: PIPE SUPPORT LOAD COMBINATIONS AND STRESS ALLOWABLES LOAD COMBINATIONS I I

NO. LOADS SERVICE LIMIT ALLOWABLE STRESS I I

DW+OBE+TE*+SAM B (Upset) S I I

2 DW+TE+F B (Upset) (RV Piping) S I C {Eiriergency) 1.33 S I (SV Piping) I I

3 DW+OBE +TE*+SAM+F* I B (Up set S I I (RV Inlet Piping) I I C (Emergency) 1.33 S I I (RV Discharge Piping) I I I D (Faulted) (SV Piping) I I I I 4 DW+SSE+TE*+SAM+F*I D (Faulted) I The greater of 150% I I I S; or 1.2 Sy; but natl I !greater than 0. 7 Su_I

• Omit if this decreases the total load or maximum calculated stress.

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PSE&G; Salem l 02-0140-1325 Impell Corporation Revision O Page 20 Definition for Tables 4. l and 4.2 TE = Thennal p = Pressure DW = Gravity F = Rapid valve actuation (RVA) effects of Pressurizer Relief and Safety Valve Discharge on the Relief and Safety Valve Piping, assuming concurrent valve actuation of all valves.

QBE = Operating Basis Earthquake (OBE), resulting from seismic ground surface acceleration of O. lg SSE = Design Basis. Earthquake (SSE), resulting from seismic ground surface* acceleration of 0.2g.

= Effect of differential seismic anchor motion due to OBE.

= Sh shall be as listed in Table I-7, Appendix I, ASME Code Section III (1974). *

= As defi ned in USAS B31. l ( l 967) *

= Allowable stress in accordance with the AISC Manual, 6th Edition. or 8th Edition, as applicable.

= Minimum specified yield stress at operating temperature.

= Minimum specified stress at operating temperature

PSE&G; Salem l 02-0140-1325 Impe 11 Corpora ti on Revision O Page 21 METHODS of ANALYSIS 5.1 Thermal Hydraulic Effects of Rapid Valve Actuation (RVA)

5. 1. l Thermal Hydraulic Loading The effects of Rapid Valve Actuation with valves discharging steam from the Pressurizer (RVA-S); as well as effects of the valves discharging two-phase, or solid water from the Pressurizer (RVA-W) were both evaluated.

5.1.2 RELAPAnalysis

.1 For the Salem Unit No. l Pressurizer Relief and Safety Valve Piping Qualification, Impell generated the time history loads due to rapid valve actuation (RVA),

utilizing the University Computing Company (UCC)/CYBER 176 facilities. Specifically, a version of RELAP, called RELAP5-REFORC, Version 2A, was utilized. This version is based on RELAP5 MOD 1, Cycle 14, which is a public domain program, but was modified to calculate forces on piping .

• 2 Thennal hydraulic transient properties of the flui*d in the piping system subjected to RVA were established by .

use of the analytical Computer Code RELAP5 MODl. For convenience of modeling, the analyses were divided into two (2) problems. One problem included Pressurizer Relief Valve (RV) piping from the Pressurizer nozzle through the RV 1 s, and then-to the 45° Latrolet juncture of the 6 i-nch RV discharge pipe with1 the 12 inch riser pipe at approximate Elevation 140 -3 11

• The second problem included Pressurizer Safety Valve (SV) piping from the Pressurizer nozzles through the SV 1 sand then to the 12 inch riser.pipe; and then continuing on to the Pressurizer Relief Tank at Elev. 85 1 -3 11 *

. 3 Control volume sizes were established by engineering judgment, based on RELAP 5 Users Manual recommendations for nodalization, takig due cognizance of sensitivity studies presented in the RELAP Manual and informal sensitivity studies performed by Impell *

. 4 RELAP5 provides transient fluid properties but requires a post-processor to obtain transient forces on the

• piping system. RELAP5-REFORC version 2A includes the basic RELAP program as well as the post-processor REFORC, to develop force-time history loading *

. 5 The results of the RELAP5-REFORC Version 2A, as installed at UCC in June 1982 was utilized to provide force time hi story results in the form of time dependent unbalanced forces at all required locations (e.g.

straight runs between elbows and reducers) between the Pressurizer nozzles and the Pressurizer Relief Tank at Elev. 85 1 -3.

PSE&G; Salem l 02-0l40-l325 Impell Corpor.ati on Revision O Page 22 5.2 SUPERPIPE Pipe Stress Analysis For this project the Impell Corporati.on proprietary pipe stress computer program SUPERPIPE was used to derive pipe stresses and pipe support loads for all applicable loads at all piping locations.

5.2. l Description of SUPERPIPE SUPERPIPE is a general purpose program which performs comprehensive structural analysis of linear elastic piping systems for deadwei ght, thermal expansion, seismic time-hi story or spectra, arbitrary force time-hi story and other loading conditions. Analyses are performed to ASME requirements for CJass l, 2 and 3 systems.

The program has various features for user ease in defining

• the piping system. These include automatic generation of node coordinates at curved segments or elbows, automatic cartesian/polar coordinates* transformation (translation/rotation), built-in data (including stress indices) for standard pipe components such as tees, elbows, reducers and valves, and built-in standard material properties and piping schedules. Various plotting capabilities and extensive di agnostic error and warning messages aid in checking the model.

The output o*f SUPERPIPE is arranged in stress report form with special summaries for support loads, break location evaluation, maximum stresses, flexible connection, and di sp l aceme nt s.

In addition to the basic capabilities for performing deadweight, thermal expansion, seismic response spectrum, and anchor movement analyses, SUPERPIPE offers a number of more sophisticated.analysis features for specialized piping analysis. These include modal superposition or direct integration techniques of time-hi story for shock loads associated with steam hammer and water hammer effects in piping systems, or other arbitrary force-time-history loadings, such as effects of rapid valve actuation.

• Static or dynamic equilibrium equations are formulated using the direct stiffness method, in which element stiffness matrices are formed according to virtual work principles and assembled to form a global stiffness matrix for the system, relating external forces and moments to joint displacements and rotations. Six degrees-of-freedom may be specified at each joint of the global system for both static and dynamic analyses *

• PSE&G; Salem 1 02-0140-1325 Im.pe 11 Corporation Revision 0 Page 23

• The program has a number of element types which may be used in any combination, these include straight pipe, curved pipe, valve, general beam, flexible coupling and arbitrary stiffness matrix elements. * - -

Static equilibrium equations are solved using Gaussian reduction techniques on the compacted stiffness matrix. For dynamic problems, the equilibrium equations may be solved using either step-by-step direct integration of the coupled equations of motion, or by first calculating natural frequencies and mode shapes, and tran*sforming the system into a set of uncoupled equations of motion. Natural frequencies and mode shapes are calculated using the determinant search technique~

The program has been thoroughly tested and verified for a comprehensive set of sample problems, including extensive comparison with several publicly-available programs and ASME benchmark problems. All verification analyses have been documented in accordance with established Impell Corporation Quality Assurance procedures.

5.2.2 Direct Integration Force Time History

. 1 The force time-hi story analysis option is intended for consideration of steam hammer effects, jet force loadings,

. and RVA effects. A step-by-step analysis is carried out for arbitrary dynamic forces acting at any points in the piping system. The force time-histories may be input either.from cards or from a tape with file name THIN. A results set (unsigned) for use in subsequent design checks is produced by enveloping the time-hi story results.

Selected time-histories of nodal displacements, cross-section forces, and/or support loads may be printed and/or saved on a tape, with file name THOUT, for subsequent plotting or other post-processing *

. 2 During the results set enveloping process, each component of displacement, force, moment, and reaction is enveloped separately, considering absolute values. Any stresses or stress ranges computed in subsequent design checking phases will be conservative, because the three separate moment components at any cross-section do not necessarily reach their maximum values simultan~ously .

• 3 Two alternative force time-history options are available, namely mode-by-mode analysis (FTHM option) and direct integration analyses (FTHI option). For this project, the (FTHI) option was utilized. This option considers all modes, including the high frequency modes, which may be

• significant for the time-hi story loading considered .

PSE&G; Salem l 02-0140-1325 Impell Corporation Revision 0 Page 24

• .4 For the direct integration option, the analysis is carried out directly on the coupled equations of dynamic equilibrium without uncoupling into normal modes. Hence, the high frequency effects are not truncated. With this option, however there is less freedom in specifying damping ratios and damping must be carefully specified to ensure that appropriate ratios are used for the frequency range of interest, particularly that the higher frequencies are not excessively damped. Excessive damping in the high or low frequency range may result in under estimation of pipe stresses and support loads.

5.2.3 Damping for Direct Integration Force Time History

• .l For the Direct Integration Force Time Hi story the following damping matrix, C is used and is defined as follows:

[CJ = cl.JM] + ~ [K]

in which [M] = mass matrix, [K] = stiffness matrix, and Q...... , ~ = factors which control the amount of damping. In modal terms, this is equivalent to assuming modal dampfng with*the damping ratio varying with frequency, as follows:

in which f =frequency, and).. =corresponding damping ratio *

.2 It is required to choose two (2) frequencies (f1, f 2 )

and two corre spo ndi ng dampi ng ratios ( }-- l , )... 2). Tfie factors ol and ~ are then given by 4ir f 5~ (,,/\"\- - ~"'i\. ,)

( ~; - ~~)

l\.'-1~)

.3 Appropriate values of f1, f2 and~1.1.2 must be specified to provide a reasonable approximation to the required damping over the range of frequencies of interest, since damping at frequencies smaller than f1, and larger than f2, mc'zy be unconservative .

• PSE&G; Salem 1 02-0140-1325 Impell Corporation Revision 0 Page 25

• 5.3 Pipe Support Assembly Structures Pipe support assembly designs were generally accomplished by hand calculations, using standard engineering concepts. When pipe support assemblies were sufficiently complex and indeterminate, the public domain Computer Code STRUDL, (Georgia Tech Integrated Computer Engineering System 2.6A 7/28/83) was utilized in the pipe support des1 g n.

5.4 Stress Analysis Model The relief and safety valve inlet and discharge p1p1ng system is described in paragraph 2.2 above. The stress analysis mathematical model includes all piping from the Pressurizer to the pipe anchor at Elev. 131 1 -4 11

• Piping from this anchor to the Pressurizer Relief Tank at Elev. 85 1 -3 11 has no effect on the Relief and Safety valves, and was therefore, not included in the mathematical model, except as it affects the functionability of the Elevation 131 1 -4 11 anchor, which is discussed in paragraph 6.9 below.

In order to account for thermal expansion and seismic effects of the Pressurizer on the piping, the stress analysis mathematical model includes a mathematical representation of the Pressurizer to its base 'foundation at Elev. 104 11 -0 11

• In line valves were modeled to include eccentrically located masses. The analytical model includes pipe support flexibilities, based on manufacturer's recommendations, and engineering judgment .

• PSE&G; Salem l 02-0140.:.1325 Impell Corporation Revision 0 Page 26

• .0 SPECIAL TECHNICAL TOPICS

6. l Relief and Safety Valve Parameters As documented in reference 6.1 the Relief valve parameters used in the RELAP analysis were 150 msec opening time, 265, 700 l l:m/hour flow rate; and a pressure rise rate of 100 psi/sec. As described in paragraph 4. l.2.2b (above), a pressure of 2500 psi was conservatively assumed.

Safety Valve parameters used in the RELAP analyses were 30 msec opening time; 472,000 lbm/hour flow rate; 2,500 psia pressure; and a pressure rise of 100 psi/sec. The flow rate of 472,000 lbm/hour represents the EPRI test measured flows for this,. valve.

Valve friction factors for the RV's were as calculated by RELAP 5,*

using the abrupt area change option. Valve friction factors for the SV's were derived to account for the goo discharge direction change.

6.2 Safety Valve Opening Time Sensitivity Study

6. 2. l Background

• Conservatively neglecting valve simmering time at the beginning and at the end of safety valve actuation, the major portion of valve opening action occurs over a period of 15 to 50 msec.

6.2.2 Discussion

.l During the developmental stage of Salem 2 Pressurizer Relief and Safety Valve Piping qualification work, a number of trial RELAP analyses were generated, to account for the rapid valve actuation (RVA) of the Relief and Safety Valves, reflecting various conservatisms in their analytical model.

.2 At this time, two (2) trial RELAP models were.developed for RVA time hi story loading, which are preliminary models and are actu*ally too conservative, but are identical to each other in every way, except that the first model assumes a 15 millisecond Safety Valve opening time, whereas the second model assumes a 30 millisecond valve opening time .

. 3 This enabled an evaluation of the relative effects of safety valve opening time of 15 vs. 30 millisecond on the piping system. To that end, Impell performed two (2) separate pipe stress analyses for the same

• piping/pipe support configuration using the 15 and 30 millisecond RVA loads, respectively. No effort was made to optimize the new pipe support location at this time.

Thus, the calculated pipe stresses are sometimes very high. But these analyses did establish the relative effects on the piping system, which was the basic purpose of the study.

PSE&G; Salem l 02-0140-1325 Impell Corporation Revision 0 Page 27

.4 The calculated pipe stresses and pipe support loads for the two (2) trial RVA T/H loading, for 15 and 30 millisecond S/V opening time respectively, are documented in reference 6.2. The average ratio of stresses is 0.91 and the average ratio of support loads in 0.92, which is an average variance of 9% for stress and 8% for pipe supports.

6

• 2. 3 Co nc l u si on This variance is well within the degree of accuracy of a RELAP time-history analyses of this complexity. It is therefore, concluded that use of 15 or 30 millisecond S/V opening time is appropriate fo,r the Pressurizer Relief and Safety Valve piping qualification.

6.3 Pipe Temperature Considerations 6.3. l Design Temperatures Design temperatures for the Pressurizer Relief and Safety Valve piping are tabulated on the reference 2. l drawings.

6.3.2 Normal Plant Operation (NPO)

.l During normal plant operation (NPO), the Relief ari*d*

Safety Valves are closed and the discharge piping is at containment ambient temperature of*approximately l20°F .

. 2 However, the Pressurizer is heated to 6800 at plant startup. Since the Pressurizer is bottom supported, the top of the Pressurizer thermally expands approximately 2 3/4 11 upward *

. 3 NPO condition consists*of the combination of relatively cold valve discharge piping and vertically upward thermal displacement at its Pressurizer connection.

6.3.3 Normal System Operation (NSO)

.l When the Pressuri.zer Relief and/or Safety Valves are actuated, the discharging fluid heats the piping.

Design temperature of 470° was conservatively used for piping between the valves and the pipe anchor at Elev.

131 1 -4 11

• Piping downstream of this anchor was conservatively assumed to be 3600F.

PSE&G;. Salem l 02-0140-1325 Impel l Co rpo ration Revision O Page 28

• .2 The rapid valve actuation (RVA) shock loading caused peak stresses at 250 msec. to 300 msec., which were found to be dissipated in considerably less than one (1) second. Heating up of the pipe by the discharging fluid takes considerably longer. Therefore, maximum RVA induced stresses and NSO thermal expansion stresses do not occur concurrently .

. 3 For piping upstream of the Elev. 131 1 -4 11 pipe anchor, the NSO thermal effects and the RVA effects were conservatively assumed to be cumulative and concurrent.

6.4 Seismic Anchor Movement (SAM) l .

The effects of differential seismic movements of rigid pipe support attachments (SAM) may have a significant effect on some piping systems and must therefore be included in the e.valuation of any piping and its pipe support.

Impell prepared a study of the Salem Units land 2 Pressurizer Relief and Safety Valve piping (reference 6.3) which concludes, that for these particular piping systems, the actual SAM's are negligibly small, and could therefore be ignored in the analysis.

6.5 Structural Damping The ratio of critical structural damping as noted in the Salem l FSAR, Section 3. 7 .2, and as utilized for the original design of this piping was l/2%, and was also utilized in the current piping evaluation.

6.5. l For Direct Integration Force Time History Analysis The force time history direct integration analysis for RVA loading, used l/2% damping in the vicinity of the first natural frequency of the piping system and at 160 Hz.

Within this bracket, the computed damping value is less than 1/2%, thus providing con~ervative results.

6.5.2 For Seismic Analysis Seismic analysis utilizing envelopes of applicable seismic response spectra, used 1/2% damping, in keeping with the original design criteria for this facility.

6. 6 Modal Com bi nation i n Seismic Response Spectrum Ana ly si s For this project, the combination of modal responses was as described in reference 6.4, paragraph l.2.2 11 Ten Percent Method. 11

PSE&G; Salem l 02-0140-1325 Impe 11 Corporation Revision O Page 29 6.7 Combination of RVA and Earthquake Load The effects of RVA and Earthquake were combined by the SRSS method, on the basis that these are two (2) independent loading phenomena whose peak responses have only a random relationship to each other.

6.8 Stress Intensification of Latrolets and 3x2 Reducers 6.8.l Latrolets

.1 Just above the Elev. 131 1 -4 11 pipe anchor, all four (4) 6 inch Relief and Safety Valve discharge pipes join the 12 inch riser pipe by means of 450 Latro lets *

• 2 Stress Intensification factors for the 450 Latrolets were derived i n ref ere*nce 6. 6.

. 3 The largest numerical value of stress intensification factor was, conservatively used for all applied bending moments in the SUPERPIPE run.

6.8.2 3x2 Reducers

.1 The Relief Valves are 2 inch size and are furnished with 3x2 reducers at their i nterf.ace with the 3 i nch relief valve piping *

. 2 Since the Code furnished stress intensification factor for reducers is a function of the convergence angle, the as-built dimensions of the reducers were measured (reference 6.7) and utilized in a hand calculation to detennine the factor appropriate for the particular application. This stress intensification factor was used in the pipe stress analysis.

6.9 Functionality of Pipe Anchor at Elev. 131 1 -4 11 6.9. l Requirements .

• l Relief and Safety Valve discharge piping is not safety related except as .it affects the Relief and Safety Valves, which comprise Reactor Coolant Pressure Boundary

( RCPB). Thus, the discharge piping is important, si nee it provides reaction loads on the valves .

• PSE&G; Salem l 02.:.0140-1325 Impe 11 Corporation Revision O Page 30

.2 Piping downstream of the pipe anchor at Elev. 131 1 -4 11 is isolated from the relief and safety valves by the anchor and is therefore expendable, except as it affects the functionality of the anchor at Elev. 131 1 -4 11 *

• 3 The subject pipe anchor is at a considerable di stance

.from the Relief and Safety Valves. Thus ariY local defonnation at the anchor will not affect the loads on the valves, with the proviso that the anchor components remain physically connected to the piping.

6. 9. 2 Acceptance Criteria

• l If it can be shown that the subject anchor remains phYsically connected to the piping then the system is acceptable.* *

.2 Impell 1 s evaluation utilized the conservative approach of using Service Level 11 D11 allowables.

6.9.3 Concurrent Loading

.l Since the RVA load is dissipated in less than a second; and si nee the piping does not heat up until long after the RVA effect ha.~e disappeared; therefore ( RVA) +

(NPO thermal) was considered but (RVA) + (NSO thermal) was not included *

• 2 Therefore the investigation includes the following t\\U load combinations:

a. Deadweight +Pressure+ SSE+ (NSO Thermal)

b. Deadweight +Pressure+ SSE+ (NPO Thennal) + RVA 6.9.4 Maximum Operating Temperature

• l Far piping above the Elev. 131 1 -4 11 anchor, NSO temperature was conservatively assumed to be 4700F *

. 2 For piping between the subject anchor and the Pressurizer Relief Tank, the operating temperature was conservatively calculated not to exceed 360°F (see reference 6.5).

6.9.5 Damping Values I .1 For evaluation of functionality of the Elev. 131 1 -4 11 anchor, the RVA induced anchor loads were derived by analysis, which utilized the proposed ASME Code Case

'*

I N4ll (see attachment to reference 6.5).

I

PSE&G; Salem 1 02-0140-1325 Impel l Corporation Revision O Page 31

.2 Si nee only anchor functionality is required; and si nee a conservative functionality criteria (Service Level 11 011 allowables) was used in the evaluation; this approach is justified.

6.9.6 Conclusions of Anchor Functionality

• 1 An anchor functionality study was prepared for Salem Unit 1. Computer runs were prepared to determine the anchor load from both up and downstream pi.ping due to RVA; thermal NPO; thermal NSO; O.W.; and earthquake (see references 6.7 through 6.10 inclusive). A final functionality.analysis was performed (see reference 6.11) .

.2 It.was concluded that since the anchor assembly meets

~ervice Level 11 011 limits, it will remain functional after a postulated Relief and Safety Valve actuation.

le I

I

PSE&G; Salem l 02-0140-1325 Impe 11 Co rpo ration Revision 0 Page 32

.0 RESULTS AND CONCLUSION 7.1 Piping

7. 1. 1 Analyses The Pressurizer Relief and Safety Valve inlet and discharge piping up to the anchor at Elev. 131 1 -4 11 was analyzed for the effects of rapid valve actuation RVA-S and RVA-W; deadweight; thermal stress during normal plant plant operation (NPO) as well as during normal system operation (NSO); and OBE and SSE loading. (See references 7.1 to 7.4 and 7.6 to 7.8 for the inlet.and discharge piping, re spec.ti ve ly )

• Code check analysis, providing calculated stresses for all appropriate load combinations.was also performed (See reference 7.4 for the inlet piping and reference 7.8 for the di sch a rge pi pi ng).

The piping as analyzed, is shown on the Impell drawings reference 2.2 for the inlet piping and 2.3 for the discharge piping. These drawings include the locations of all node numbers used in the stress evaluation. The piping material

....and design conditions for the analysis were taken from the reference 2. 1 PSE&G drawings.

7

• 1. 2 Re SU 1t s

• 1 Insulation boxes were installed as described in paragraph 2.4~7. These insulation boxes were fabricated by use.of mirror insulation. They encase the Safety Valve Loop Seals in common with a local segment of uninsulated Pressurizer wall. This arrangement utilizes the Pressurizer as a passive heat source to heat the loop seal piping, for the purpose of enabling the loop seal water to fl ash during safety valve discharge, thus mitigating the RVA time-history loading *

• 2 The final pipe support location requirement was determined by performing a number of pipe stress*

analysis iterations, changing the pipe supports in the analytical model, until adequately modest pipe stresses were achieved .

. 3 The following pipe support modifications were installed:

Pipe Supports Rigid Snubber Total Existing, which remain 16 27 43 Existing, which were re located -- 2 . 2 New, which were added 2 12 14

PSE&G; Salem l 02-0140-1325 Impel l Corporation Revision 0 Page 33

.4 With the above noted pipe support modifications, the analyzed piping is Code compliant and therefore is acceptable.

7.2 Pipe Supports

.1 Pipe support loads were derived in the pipe stress analysis for all applicable load combinations. These are tabulated in references 7.5 and 7.8 for the inlet and discharge pipe supports, respectively *

. 2 Calculations were prepared. for all supports, i ncludfng spring supports, as well as existing and new rigid, snubber and anchor supports for the new loads *

• 3 New supports were designed; and engineering drawings were prepared *

. 4 Modifications required for existing supports to withstand the new loads were designed. Drawings defining the required modifications were also prepared *

• 5 During construction, a number of pipe support relocations were made, to eliminate previously unforeseen physical interferences. After construction of the new and modified supports, new computer runs were prepared to account for the final support locations to verifiy that these changes do not affect the conclusion of adequacy. *calcul~tions and drawings were updated; and the Impell piping isometrics (references 2.2 and 2.3) were revised to reflect the final condition .

. 6 Table 7. l provides a list of.. all pipe support drawings fu_rni shed for this project *

• 7 Note that for modification drawings having sheets l and 2 of 2, that sheet l is an uncontrolled drawing, showing only the locations where modification is required. For these drawings only sheet 2 is a controlled drawing, since all structural modifications are shown thereon ..

7.3 Valve Operability

• l It is concluded that the Relief and Safety Valves remain operable after a postulated blowdown .

. 2 Loads on the Relief and Safety Valves from the inlet and I discharge piping were evaluated. Pipe stress was used as a measure of valve load acceptability *

. 3 Thus Load Case 3, which includes (Pressure+ Deadweight + OBE +

[RVA-S or RVA-W]) was compared against Service Level B I allowables of 1.2 sh .

. 4 Load Case 4, which includes (Pressure+ Deadweight +SSE+

I [RVA-S or RVA-W]) was compared against Service Level C allowables of l .8Sh.

I

PSE&G; Salem l 02-0140-1325 Impe ll Corpora ti on Revision 0 Page 34

.5 Results are shown in Table 7.2. All values of pipe stress are shown to be well within permissible values .

.6 Table 7.3 shows the calculated bending moments at the safety valve interfaces. This enables easy comparison with the maximum induced bending moments determined at the safety valve interfaces by the reference 7 .9 EPRI tests for this Crosby 6M6 valve .

• PSE&G; Salem l 02-0140-1325 Impell Corporation Revision 0 Page 35 TABLE 7.1 PSE&G; SALEM UNIT NO.

PRESSURIZER RELIEF AND SAFETY VALVE PIPING QUALIFICATION PIPE SUPPORT DRAWING INDEX Drawing No. Rev. Date Act1v1ty l-PRSN-3 0 03/23/~4 Modified l-PRG-6 0 04/06/84 Modified l-PRSN-7 0 03/23/84 Modified l-PRG-8&18 l 07/27/84 Modified l -PRSN-9 l 07 /27 /84 Modified l-PRSN-10&19 l 07/30/84 Modified.

l-PRSN-11 0 03/23/84 Modified l-PRSN-15 0 04/06/84 Modified l-PRSN-16 l 04/06/84 Modified l-PRSN-20 0 09/11/84 Deleted l-PRG-21 0 03/23/84 Mo.di fi ed l-PRG-22 0 03/23/84 Modified l-PRSN-23 2 07/31/84 Modified.

l-PRG-24 0 03/23/84 Modified l -PRSN-25 0 03/23/84 Modified l -PRG-26 0 04/06/84 Modified l-PRSN-27 0 03/23/84 Modified l -PRSN-28 0 09/11 /84 Deleted l-PRSN-29 l 04/05/84 Modified l -PRG-31 l 07/31/84 Modified l-PRSN-32 l 04/06/84 Modified l-PRG-35 l 07/31/84 Modified l-PRSN-38 2 08/01 /84 Modified l-PRSN-39 2 07/31/84 Modified l-PRG-41 l 07/31/84 Modified l-PRSN-42 0 03/23/84 Modified l-PRA-146 4 07/31/84 Modified l-PRA-150 4 07/31/84 Modified l-PRA-154 4 07/31/84 Modified l-PRA-155 0 03/23/84 Modified C-PRN-156 0 08/24/84 Modified l-PRA-158 l 04/13/84 Modified l-PRA-162 2 08/01 /84 Modified

PSE&G; Salem l 02-0140-1325 Impell Corporation Revision 0 Page 36 TABLE 7.l PSE&G; SALEM UNIT NO. 1 PRESSURIZER RELIEF AND SAFETY VALVE PIPING QUALIFICATION PIPE SUPPORT DRAWING INDEX (Cont a)

I Drawing No. Rev. Date Activity l-PRSN-IMPL-C03X 3 07/26/84 New l-PRSN-IMP-C03Z 2 07 /26/84 New l-PRG-IMPL-G4 0 03/23/84 New l-PRG-IMPL-D6X 2 07 /26/84 New l-PRSN-IMPL-Cl2Z 2 07/30/84 New l-PRSN-IMPL-C2lY 2 07/26/84 New l-PRSN-IMPL-C24X 2 04/07/84 New 1-PRSN-IMPL-C24I 3' 07 /26/84 New l-PRSN-IMPL-C32Y 3 07 /26/84 New l-PRSN-IMPL-C32I 2 07 /27 /84 New l-PRSN-IMPL-C33Y 1 03/23/84 New 1-PRSN-IMPL-C36Y 3 07 /26 /84 New l-PRSN-IMPL-C39Y 3 07 /26/84 New l-PRSN-IMPLOC39I 3 07 /26/84 New 1-PRSN-IMPL-C49Y 2 03/30/84 New 1-PRSN-IMPL-C79Y 2 07 /26/84 New 1-PRSN-IMPL-C79Z 2 07 /26/84 New 1-PRSN-IMPL-103Y 2 07 /26/84 New

TABLE 7.2 PIPE STRESS AT PIPING ADJACENT TO RELIEF AND SAFETY VALVE INTERFACE

('"') (/)

0 CJ

-s ......

-0 CD 03

~a1cu1atea ~"tress ~a1cu1atea ~tress -s CJ ~

( ksi ) Ratio = ( ksi ) Ratio = c+

......

VALVE l. 2Sh LOAD CASE 2 LOAD CASE 3 Stress/ LOAD CASE 4 Stress/ 0

l P+DW+RVA P+DW+OBE+RVA l. 2Sh P+DW+SSE+RVA l.8Sh s w s w s w Relief Valve 19.8 18.7 6.9 19.2 8.3 0. g,7 21. 7 13.9 0.73 1-PRl Relief Valve 19.8 11.0 11.4 11.3 11. 6 0.58 . 13. 3 13. l 0.45 l-PR2 Safety Valve 19.2 9.9 5.3 9.9 5.3 0.52 9.9 5.3 0.34 l-PR3 ,

ISatety Va Ive 19.Z 9. I  !:>. b 9. I ';J./ u. 'I-/  !:I. z ':J. I U.jz l-PR4

,atety va Ive 19.Z IU.4 b. / IU.4 b./ U.!:>4 IU .4 6.8 U.jb l-PR5 NOTES: l. Column 1111 $ 1111 designates combination including RVA-S; Column W designates load combination including RVA-W

2. The above stress tabulation was derived frqm references 7.4 and 7.8

3. The stresses tabulated above, represent the envelope of stresses at the inlet and discharge interfaces.

-c  :;o 0 CJ CD N lO CD _,, 0

< I Ul ~

w....1 * .i:::.

....... a o

l I

~

ow N

<J1

PSE&G; Salem l 02-0140-1325 Impell Corporation Revision O Page 38

• Table 7.3 MAXIMUM CALCULATED BENDING MOMENTS AT RELIEF AND SAFETY VALVE INLET & DISCHARGE INTERFACE (ENVELOPING RVA-S & RVA-W.)

(ENVELOPING LOAD CASES 2,3, & 4)

CALCULATED BENDING MOMENT VALVE (inch-kips)

INLET DISCHARGE Relief Valve 20.6 21.6 1-PR l Re1ief Valve 11. 3 14.4

. l-PR2

• Safety Valve l-PR3 Safety Valve l-PR4 294. l 317.5 48.2 47.5 Safety Valve 266.4 55.6 l -PR5 Note: Values were derived from references 7.6 through 7.8 inc lu si ve.

I I*

I I

PSE&G; Salem l 02-0140-1325 Impe 11 Corporation Re vision 0 Page 39 REFERENCES 2.1 PSE&G Drawings 267PCL & 267PDL showing the Salem Unit l Pressurizer Relief and Safety Valve Charge and Discharge Piping respectively 2.2 Impell Drawing 0140-022-01 Rev*. l 9/1/84 11 PSE&G/Salem l/RV&SV Inlet Pi pi ng 11

2. 3 Impe 11 Drawing 0*140-022-02 Sheet l Rev. 2 ( 3/14/84); & Sheet 2 Rev. l (9/1/84); 11 PSE&G/Salem l/RV&SV Discharge Piping" 2.4 PSE&G; Salem Unit l; Evaluation of Options for Qualification of Pressurizer Relief and Safety Valve Piping due to Rapid Valve Actuation Loading 11 Report No. 02-0140-1128, Rev. 0, prepared by Impell Corp. in Jan. 1983

4. l* Guidelines of Load Combinations and Acceptance Criteria for Pressurizer Safety and Relief11 Valve Piping generated by an EPRI Subcommittee on Piping, labeled Appendix E11 4.2 Interim Report titled 11 Application of RELAP 5 MOD 1 for Calculation of Safety and Relief Valve Discharge Piping Hydrodynamic Loads", submitted by Intennountain Technologies, Inc .* (IT!) to EPRI in March 1982

6. l EDS/Impell letter_Ol40-022-NY-Ol3 dated June 29, 1982 6.2 Impell letter.0140-022-NY-088 dated August 24, 1984 6.3 Impell Calculation No. 109, Rev. l dated 3/9/84; prepared for Salem Pressurizer Relief and Safety Valve Piping Qualification.

6.4 US NRG Regulatory Guide l.92, Rev. l; Feb. 1976; entitled: 11 Combining Modal Responses and Special Components in Seismic Response Analysi s 11 6.5 Impell Calculation 203 Rev. 0 5/6/85 "Functionality Study of Elev.

131 1 Anchor 11 11 6.6 Impell-Calculation 108 Rev. O 12/14/83; Latrolet Hand Calculation for*

SIF 11 6.7 Computer Run ACWYIIKX 02/ll/85 El. 130 Anchor Load; Thermal/Free@ 870

& 880.

6.8 Computer Run ACWYWVBM 02/ll/85 El. 130 Anchor Load; D.W.; Seismic.

6.9 Computer Run ACWYNSOC 02/19/85 El. 130 Anchor Load; RVAS; N4ll Damping

PSE&G; Salem 1 02-0140-1325 Impell Corporation Revision O Page 40

8.0 REFERENCES

( CONT'D)

6. 10 Computer Run ACWYMRLB 03/19/85 El. 130 Anchor Load; Thermal 470°F/360°F.

6. 11 Impell letter 0140-022-NY-070 dated 3/27/84.

7. 1 Computer Run ACWYGAB 11/23/84 Inlet Piping RVAS Loading.

7.2 Computer Run ACWYGR.R 11/28/83 Inlet Piping; RVAW Loading.

7.3 Computer Run ACWYKKOQ 11/29/83 Inlet Piping; D.W.; Thermal NPO, Thermal NSO.

7.4 Computer Run ACWYCZB 12/14/83 Inlet Piping; QBE & SSE loading; Code Check Ana ly si s.

7.5 Computer Run ACWYLOG 12/16/83 Inlet Piping; End Load and Support Load Summary.

7.6 Computer Run MIKEORG 03/15/84 Discharge Piping; RVAS Loading.

7.7 Computer Run MIKEOTA 03/22/84 Discharge Piping; RVAW Loading.

7.8 Computer Run MIKEONA 03/23/84 Discharge Piping; D.W.; Thermal NPO; Th~rmal NSO; OBE & SSE Loading; Code Check Analysis; Support Load Summary.

• 7.9* EPRI.PWR Safety and Relief Valve Test Program; Safety and Relief Valve Test Report EPRI NP-2628 SR Special Rep*ort December 1982; Paragraph 3.5. "Crosby HB-BP-86 6M6 (Loop Seal Internals)"

(pp. 3-69 and 3-71 ).

I I*

These references are included in Appendix A

PSE&G; Salem l 02-0140-1325 Impell Corporation Revision 0 Page 41 APPENDIX A SELECTED REFERENCES

• I.

I

.MPR ASSO~IATES. INC.

APPENDIX E LOAD COMBINATIONS AND ACCEPTANCE CRITERIA FOR THE

• PRESSURIZER SAFETY AND RELIEF VALVE PIPING SYSTEM

I

. I A. Purpose The purpose of this appendix is to provide suggested load combinations and acceptance criteria for the pressurizer safety and relief valve piping system.

During the course.of the EPRI valve program, an ad hoc group was established to provide technical input to EPRI regarding discharge piping considerations. The recom-mended load combinations and acceptance criteria provided in the following s*ection were developed by this group.

B. Discussion The recommended load combinations and acceptance criteria*

for the.pressurizer safety and relief valve piping system and supports are shown in Tables 1, 2A and 2B.

Tables* 2A and 2B are for the discharge, or downstream, piping ~nd supports. Table 2A applies to the portion for which seismic requirements apply. There are two possible approaches 'to this requirement. The entire downstream

• portion may be seismically designed, in which case, only*

• Table 2A need be used. If only a portion of the down-stream system is seismically designed (e.g., to the first downstream anchor, or enough supports and piping to effectivel*y isolate the s.eismic and non-seismic portions), then Ta~le 2A would apply for that portion, while Table 2B would apply to the rest of the downstream system.

,  :- '

TABLE

• **

. .

I LOAD COMDINATIONS AND ACCEPTf\NCE CRITERIA FOR PRESSURIZER SAFETY AND RELIEF VALVE PIPING AND SUPPORTS - CLASS l PORTION Plant/System Service Stress Combination Operatin9 Condition Load Combination Limit 1 Normal N A 2 Upset N + QBE + SOTU B 3 Emergency N + so~E c 4 Faulted N + MS/FWPB or DBPB D

+ SSE + SOTF 5 Faulted N + LOCA + SSE + SOTF D NOTES: 1.) Plants without an FSAR may use the ~roposed criteria contained in Tables *1-3.

Plants with an FSAR may use their original design basis in conjunction with the appropriate system operating transient definitions in Table 3; or they may.

use the proposed criteria contained in Tables 1-3.

2.) See Table 3 for SOT definitions and other ~oad abbreviations.

3.) The bounding number of valves (and discharge sequence if setpoints are signifi-cantly different) for the applicable system operating transient defined in Table 3 should be used.

• 4.) Verification of functional capability is not required, but aliowable loads and accelerations for the safety-relief valves must be met.

5.) Use SRSS for combining dynamic load responses.

I I

. ,, (

For the seismically.designed downstream piping and supports, less restrictive allowabies are suggested. Since satisfac-tion of allowable valve loading is part of the acceptance criteria, this.would appear to be acceptable.

For the non-seismically_designed portion of the downstream piping, it is recommended that the pipe support system be seismically designed to assure overall structural integrity of th~ system. It is suggested that Servi~e Level D limits be applied for all pipe support load combinations contain-ing OBE or SSE.

I

'*

I E - 2 I

• TABLE 2A

I

. ..

LOAD COMBINATIONS AND ACCEPTANCE CRITERIA FOR PRESSURIZER SAFETY AND RELIEF VALVE PIPING AND SUPPORTS - SEISMICALLY DESIGNED DOWNSTREAM PORTION Plant/System .service Stress Combination 0Eerating Condition Load Combination Limit 1 Normal N A 2 Upset N + SOTU B 3 Upset N + QBE + SOTU c 4 Emergency N + SOTE. c 5 Faulted N + MS/FWPB or DBPB D

+ SSE + SOTF

'

6 Faulted N + LOCA + SSE + SOTF D NOTES: 1.) Plants without an FSAR may use the proposed criteria contained in Tables 1-3.

Plants with an FSAR may use their original design basis in conjunction with the appropriate system operating transient definitions in Table 31 or they may use the proposed criteria contained in Tables 1-3.

2.) This table is applicable to the seismically designed portion of downstream non-Category I piping (and supports) necessary to isolate the Category I portion from the non-seismically designed piping response, and to assure acceptable valve loading on the discharge nozzle.

3.) See Table 3 for SOT definitions and other load abbreviations.

4.) The bounding number of valves (and discharge sequence if setpoints are significantly different) for the applicable system operating transient defined in Table 3 should be used.

5.) Verification of functional cap8.bility is not required, but allowable. loads and accelerations for the safety/~8lief valves must be met.

6:) Use SRSS for combining dynamic load responses.

• -* . (

TABLE 2B

• - --

LOAD COMBINATIONS AND ACCEPTANCE.CRITERIA FOR PRESSURIZER SAFETY AND RELIEF VALVE PIPING AND SUPPORTS -~

NON-SEISMI~LLY DESIGNED DOWNSTREA.~ PORTION PIPING Plant/System Service Combination Operating Condition Load Combination Limit 1 Normal N A 2 Upset N + SO'I'u B 3 Emergency N + SO'I'E *c 4 Faulted N + SOTF D SUPPORTS Plant/System Service Combination 02eratin~ Condition Load Combination Limit 1 Normal N -A 2 Upset N + SOTu :a 3 Upset N + QBE + SOTu D 4 Emergency N + SOTE c 5 Faulted N + MS/FWPB or D DBPB + SSE + SOTF 6 Faulted N + LOCA + SSE 0

+ SOTF NOTES: 1.) Plants without ari FSAR may use the proposed criteria con-tained in Tables 1-3. Plants with an -FSAR may use their original design basis in conjunction with the appropriate system operating transient definitions in Table 3; or they may use the proposed criteria contained in Tables 1-3.

2.) Pipe supports for the non-seismically designed down-stream piping should be designed for seismic load combinations

. to* assure overall structural integrity of the system.

3.) The bounding number of valves (and discharge sequence if setpoints a~e significantly different) for the applicable syst;em opera"ting transient defined in Table 3 should be use

4. ) Verification of functional capability is not reauired, but allowable loads and accelerations for the safety/

relief valves must be met.

5.) Use SRSS for combining dynamic load responses.

,. :,.

TABLE 3 DEFINITIONS OF LOAD ABBREVIATIONS N = Sustained Loads During Normal Plant Operation SOT = System Operating Transient SOT =Relief Valve Discharge Transient(l) 0

. (1)

SOTE = Safety Valve Discharge Transient SOTF =Max (SOTu; SOTE); or Transition Flow OBE = Operating Basis Earthquake SSE = Saf ~ Shutdown Earthquake MS/FWPB - Main Steam or Feedwater Pipe Break DBPB = Design Basis ~ipe Break LOCA = Loss of Coolant Accident (1) May also include transition flow, if determined that*

required operating procedures could lead to *this con-dition.

(2) Although certain transients (for example loss of load) which are classified as a service level B conditions may actuate* the safety valves, the extremely low probability of actual safety valve actu-ation may be used to justify this as a service level C condition with the limitation that the plant will be shut down for examination after an appropriate number of actuations (to be determined on a plant specific basis).

I NOTE: Plants without an FSAR may use the proposed criteria

~-

coptained in Tables 1-3. Plants with an FSAR may use their original design basis in conjunction with the appropriate system operating transient definitions in Table 3; or they may use the proposed criteria con-I tained in Tables 1-3.

EPRI/CE SAFETY VALV DATA TABLE 3.5 "AS TESTED" COMBUSTION ENGINEERIN CROSBY H6-BP~B6-6M6 (LOOP SEAL INTERNALS)

CONDITIONS AT VALVE OPENING TRANSIENT CONDITIONS TEST*, TEST VALVE RING INLET IN TANK 1 AT VALVE INLET PEAK PEAK INDUCED (2) HAX. STEADY NO TYPE SETTINGS PIPING TANK 1 BACK BENDING MOMENT . LIQUID FLOW UPPER MIODL"'E~L~OW~E=R CONFIG. FLUID PRESS. TEMP. PRESS. RATE f[(ff])lTIIP. PRESS. PRESS. OPENING/CLOSING (GPM)

(PSIA) (*F) (PSI/SEC) (*f) (PSIA) (PSIA) (IN.LBS.)

• 903 STEAM -136 -68 G STEAM 2490 (I) 291 STEAM (1) 2667 665 215, 100 N/A 906a LS -136 -66 G STEAM 2582 (1) 3.2 WATER (5) 2S82 554 256,925 N/A b STEAM 2455 31.5 STEAM (l) 2455 532 N/A c STEAM 2456 14:2 STEAM (1) 2456 520 N/A 908 LS -136 -66 G STEAM 2567 (1) 297 WATER (5) 2668 649 298,750 N/A

• 910 LS -136 -68 G STEAM 2480 (I) 375 WATER (5) 2634 227 209, l 25 N/A 913 LS - 44 -66 G STEAM 2550 (1) 375 WATER (5) 2735 242 239,000 N/A w *914a LS - 44 -66 G STEAM 2510 (1) 1.1 WATER (5) 2516 520 203, 150 (4)

I CJ) TRANS l.D (I) b STEAM 2400 21.8 STEAM 2400 330 (4) c STEAM 2360 (3) STEAM (I) 2400 (3) (4) 917 LS *136 -66 G STEAM 2458 (1) 291 WATER (5) 2732 245 227,050 N/A

• 920 LS -136 -66 G STEAM 2497 (I) 297 WATER (5) 2725 246 215, 100 N/A 923 LS -186 -68 G STEAM 2649 (1) 283

• WATER 91 2736 667 179,250 N/A N/A Uot Applicable NOTES:

(l) All tests were initiated at a nominal pressure of 2300 PSIA. For steam tests and steam/water transitlon tests the lnitlatlon temperature was the saturation temperature.

(2) The reported values are the maximum induced bending moments on the valve discnarge flange during openln!l or closing.

(3) Unstable conditions precluded reliable measurement.

(4) The test was terminated, interferinq with this measurement.

(5) The test instrumentation malfunctioned. No reliable measurement was available.

• The valve was disassembled, inspected, and refurnished as required; for representative test performance.

a

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EPRl/CE SAFETY VALVE T TABlE 3.5.1.b (Can't)

"AS TESTED" COMBUSTION ENGINEERING TEST MATRIX FOR. THE CROSBY HB-BP-86-6M6 (LOOP SEAL INTERNALS)

CONDITIONS AT VALVE OPENING TRANSIENT CONDITIONS PEAK PEAK INDUCED (2) HAX. STEADY TEST TEST VALVE RING INLET IN TANK l AT VALVE INLET BACK BENDING 14JMENT LIQUID FLOW PIPING TANK l NO. TYPE SETTINGS FLUID TEMP. PRESS. PRESS. OPENING/CLOSING (GPM)

CONF JG. FLUID PRESS. TEMP. PRESS. RATE (IN. LBS.)

UPPER MflfO[E LOWER (PSIA) (OF) (PSI/SEC) (Of) (PSIA) (PSIA) 2.0 STEAM (1) 2389 445 95,600 N/A

-68 G STEAM/ 2389 (l)

• 926a TRANS -186 WATER 1.6 STEAM (l) 2385 440 N/A b STEAM/

WATER 1.9 STEAM ( l) 2384 650 N/A c STEAM/

WATER 1.5 HATER 635 2271 585 2233 d WATER 319 WATER 90 2726 710 161,325 N/A 929 LS -71 -18 G

• STEAM 2600 (1) w 2.5 WATER 117 2578 725 203,150 2355 I -18 G STEAM/ 2570 (1) 93la LS -71

,_.

-..J TRANS WATER 247.~ 700 2.5 WATER 635 b

2520 650 107,550 (3)

-IB G WATER 2501. 515 3.0 WATER 463

• 932 WATER -71 325 WATER 147 2703 250 286,800 N/A

-18 G STEAM 2530 (l)

• 1406 LS -77 245 239,000 N/A STEAM 2410 (1) 300 STEAM (1) 2664

• 1411 STEAM -77 -18 G NIA (1) 360 WATER 290 2760 255 268,875 1415 LS -77 -18 G STEAM 2555 WATER 350 2675 245 256,925 N/A

-18 G STEAM 2464 (l) 360

• 1419 LS -77 N/A Not applicable NOTES: For steam tests and steam/water transition tests the initiation (I) All tests were Initiated at a nominal pressure of.2300 PSIA.

temperature was the saturation temperature.

The reported values are the maximum induced bending moments on the valve discharge flange dur1nq opening or closing.

(2)

(3) Unstable conditions preclude reliable measurements.

(4) These data were not available

• The valve was disassembled, inspected, and refurbished as required for re~resentatfve test perfonnance.

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