SNRC-1283, BWR Owners Group Rept on Operational Design Basis of Selected Safety-Related Motor-Operated Valves
| ML20215C877 | |
| Person / Time | |
|---|---|
| Site: | Shoreham File:Long Island Lighting Company icon.png |
| Issue date: | 09/30/1986 |
| From: | Howard R, Reich R, Sawabe J BWR OWNERS GROUP |
| To: | |
| Shared Package | |
| ML20215C844 | List: |
| References | |
| NEDC-31322, SNRC-1283, NUDOCS 8610100510 | |
| Download: ML20215C877 (88) | |
Text
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BWR OWNERS' GROUP .
REPORT.ON THE OPERATIONAL i
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NEDC-31322 DRF-E12-00100-75 CLASS 1 SEPTEMBER 1986 BWR OWNERS' GROUP REPORT ON THE OPERATIONAL DESIGN
_ BASIS OF SELECTED SAFETY-RELATED MOTOR-OPERATED VALVES Prepared by: mM R.W. howard, Principal Engineer
.%9. bd J.K. Sawabe. Engineer N 4 RT. Reich, ~ Senior . Engineer Approved by: AM -
R.S. Vij, Manager NUCLEAR ENERGY SUSINESS OPERATIONS
- GENERAL ELECTRIC COMPANY SAN JOSE CALIFORNIA 9612$
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IMPORTANT NOTICE REGARDING CONTENTS OF THIS REPORT ll
.j PLEASE RZAD CAREFUU.Y This document was prepared by the General Electric Company. The information contained in this report is believed by General Electric i i
to be an accurate and true . representation of the facts known,
![ obtained or provided to General Electric at the time this report was
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prepared.
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Neither the General Electric Company nor any of the contributors to
! this document makes any representation or warranty (express or implied) as to the completeness, accuracy or usefulness of the l -
information contained in this document or that such use of such information may not infringe privately owned rights; nor do they assume any responsibility for liability or damage of any kind which may result from such use of such information.
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NEDC-31322 TABLE OF CONTENTS
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- 1. INTRODUCTION * '
1.1 Background 1 1.2 Objectives 1 1.3 Scope 1 1.4 Approach 2 5
- 2. SYSTEMS DESCRIPTION 2.1 HPCS System 7 2.2 HPCI System 7 2.3 RCIC System 7 2.4 System Valve Configurations 8
~ 9 3.
~ EVALUATION OF SYSTEMS MOTOR-OPERATED VALVES 3 _ 3.1 Valves Reqdired to be Tested in Accordance with the ASME 11 11 Section XI Code 3.2 FSAR Events Requiring Systems Operation for Safety-Related 11 Funetions 3.3 Determination of MOVs Safety-Related Functions. Actions and 13 Maximum Operating Differential Pressures 3.3.1 BWR Design Basis Assumptions 13 3.3.2 HPCS System NOVs 14 3 3.3 HPCI System MOVs 19 3.3.4 RCIC Systen MOVs 31
- 4. VALVE TESTING AND TEST METHODS 4.1 Introduction 45 45 4.2 Valves that Perform Active Safety Actions 45 4.3 Valves to be Tested 4.4 Valves Not Required to be Tested 45 4.5 Testing Methods 46 4.5.1 General 48 4.5.2 Type Testing 48 48 4.5.3 Testing by System operation 49
- 5. REFERENCES i
51 APPENDICES A
Participating Utilities - BWR Owners' Group, IEB 85-03 Committee A-1 B
Valve Opening / Closing Differential Pressure Due to Steam /h'luid Acceleration / Deceleration B-1 ,
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.3 NEDC-31322 LIST OF TABLES Table Title g 1 Plant Design Basis Events that Result in HPCS, HPCI and 53 RCIC Systems Operation 2 HPCS System Valves 56 3 HPCI System Valves - Fluid and Steam 57 4 RCIC System Valves - Fluid and Steam 61 O'
5 Definition of Terms and Notes Used in Tables 2, 3, and 4 65
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_ LIST OF ILLUSTRATIONS Flaure Title a Page, 1 HPCS System Motor-Operated Valves 69 2 HPCI System Pump Suction and Discharge Motor-Operated Valve 70 3 HPCI Systen Gland Seal System Component / Piping 71 4 HPCI System Pump Suction and Discharge Motor-Operated Valves on Dresden 2 and 3 and Quad Cities 1 and 2 72 5 HPCI System Steam Lines Motor-Operated Valves 73 l 6 RCIC System Pump Suction and Discharge Line Motor-Operated i Valves 74 7 RCIC System Pump CST Test Return Motor-Operated Valves 75 8 RCIC Systen Steam Lines Motor-Operated Valves 76 9 Illustration for Definition 'of Terms in Tables 2, 3 and 4 77 l h-1 Systen Fluid Velocity vs Time B-3 B-2 L1 /L2 Distance Illustration ,
B-4 v/vi _ _ _ _
s o NEDC-31322 EXECUTIVE
SUMMARY
The Nuclear Regulatory Commission IE Bulletin 85-03 (Motor-operated Valve Common Mode Failure) requested that owners of light water reactors develop and '
implement a program to ensure that switch settings on selected safety-related !
t actor-operated valves (MOV) are selected, set and maintained correctly to cccommodate the nazimum differential pressures expected on these valves during both normal and abnormal events within the approved design basis.
A Boiling Water Reactor (BWR) Owners' Group (BWROG) program was undertaken to develop a common BWR methodology for individual BWR utilities to utilise in responding to the IE Bulletin. Affected systems were identified cud system documentation for all participating BWRs was reviewed to identify offected valves in accordance with IE Bulletin direction. The BWROG Committee's means of establishing this methodology was based on the review of cristing, previously approved design bases events presented in FSARs (i.e.,
previously accepted FSARs). In addition, the evaluation of system HOVs
! included consideration of pipe breaks in the design basis review. Final Safety Analysis Reports (FSAR) of each class of participating BWR were reviewed to identify the events that required the systems to perform their safety-related functions. Considering the affected valves' functions and cetions during the various postulated events, the condition, within the cyproved design basis, under which each of the valves were subjected to the cazimum expected (worse case) differential pressure was determined.
Methodology has been established for use by participating utilities to calculate 'their specific valve maximum expected differential pressures in res-ponse to action ites (a) of IE Bulletin 85-03. Valves that are required to be tested in compliance 'with the IE Bulletin have been identified. Justifica-tion has been provided for those valves considered to be generically
- exempt C1his kWkOG report was intended to review the impact of Reference 1 on the typical BWR product lines and, therefore, presents a " generic" BWR view rather than a plant-specific evaluation. Hence, positions of exemption.
testing and differential pressure calculation methodology stated herein are >
BWR generic. In responding to the NRC on the required Bulletin actions, individual participating BWR utilities may be required to deviate, in some instance,s, f rom these positions to reflect their plant-specific conditions. .
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t NEDC-31322 from maximum differential pressure operational readiness testing (e.g., actual testing of MOVs under pipe break conditions). Suggested test methods for verifying valve operational readiness (i.e., ability to operate against the mawimum expected differential pressure) have also been identified for those valves not considered exempt from such verification testing.
1; It was the intent of this BWROG program that the data and methodology presented in this BWROG report be used to support plant specific efforts by
.. individual participating utilities in calculating maximum expected differ-ential pressures requested by action (a) of IE Bulletin 85-03. The calcula-tion of actual plant-specific valve differential pressures and the responses to action items (b) through (f) of the Bulletin remain the responsibility of
_~ the individual BWR utilities.
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- 1. INTRODUCTION l
1.1 BACKGROUND
On November 15, 1985, the Nuclear Regulatory Commission (NRC) Office of Inspection and Enforcement issued IE Bulletin 85-03: " Motor-operated Valve
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j Common Mode Failures'During Plant Transients Due to Improper Switch Settings" (Reference 1). Reference 1 requested owners of light water reactors to develop and implement a program to ensure that switch settings on selected
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safety-related motor-operated valves (HOV) are selected, set and maintained correctly to accommodate the maximum differential pressures expected on these
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valves during both normal and abnormal events within the design basis.
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Affected systems are those determined to provide high pressure reactor inventory makeup when the normal feedwater system becomes unavailable.
This report was prepared by General Electric (CE) for the Boiling Water Reactor Owners' Group (BWROG). It was prepared at the direction of the BWROG utilities who funded this effort and collectively participated in the devel-l opsent of this report. These utilities are listed in Appendix A.
1.2 OBJECTIVES The principal objective of this BWROG program was to review the spectrum of BWR/3, BWR/4, BWR/5 and BWR/6 high pressure reactor inventory makeup systems and develop a generic methodology for BWR participating utilities to
- use in determining their maximum (worse case) differential pressures for valves aetermined to be subject to IE Bulletin 85-03. Additionally, the program was to identify a common basis for selecting the valves that are required to comply Gith the Bulletin and to suggest generic testing methods.
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s NEDC-31322 1.3 SCOPE IE Bulletin 85-03 contains six actions, summarized below:
, s. Determine the maximum differential pressure across the subject MOVs that can potentially occur during events that are included in the approved design basis. Document the valve design basis.
- b. Using the differential pressures from (a), establish motor operator switch settings. (This requires other parameters in addition to maximum differential pressures.)
- c. Demonstrate the valve's operability by either testing the valve at maxikum differential conditions or justifying an alternative to such valve testing.
- d. Revise the switch setting procedures as required.
- e. Submit a written report documenting (a) and containing a program schedule to address (b) through (d).
- f. Submit a final report upon program completion.
The scope of the BWROG program was to establish a generic common basis
! covering the following specific elements:
- a. Identify the hWR system valves that are generically subject to IE i Bulletin 85-03, t
- b. Identify the conditions (events), within the approved design basis, under which each of the affected valves is subjected to the maximum (worse case) differential pressure,
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- c. Develop a generic methodology for participating BWR utilities to use in determining their maximum fluid differential pressures across the affected valves, and
- d. Recommend generic guidelines for valve testing.
Response to itInns (b) though (f) of IE Bulletin 85-03 was not included in this BWROG program and remains the responsibility of individual BWR utilities.
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A review by the BWROG to identify the systems that are considered to be within the scope of Reference 1 concluded that, for the BWR, these systems
.. include the High Pressure Core Spray (HPCS) system, High Pressure Coolant Injection (HPCI) system innd the Reactor Core Isolation Cooling (RCIC) system.
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The basis for this conclusion is that Reference 1 states that the valves in i
high pressure coolant injection / core spray and emergency feedwater systems
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(RCIC in BWKs) which are required to be tested for operational readiness in cecordance with 10 CFR 50.55a(s) are to be considered in response to the Bulletin.
l The BWROG Committee has determined that the Isolation Condenser System (ICS) should not be included in the MOV testing program specified by Reference 1 for the following reasons:
- a. The ICS is not an emergency auxiliary feedwater system; the ICS does
- not supply feedwater, l b. The ICS is used only for pressure decay and residual heat removal, I I
and .
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- c. ~ The ICS is not an Emergency Core Cooling System (ECCS).
The designs of specific BWR systems considered in this report are those installed in the BWKa listed in Appendix A. '
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, This report provides the following information for safety-related MOVs in the hPCS, HPCI and RCIC systems:
- a. Identification of safety-related MOVs required to be tested in
- accordance with Section XI of the ASME Boiler and Pressure Vessel Code,* .
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- b. Design basis safety functions and actions,
- c. The combined plant and system operating condition and valve action that results in the maximum expected (worse case) differential
. pressure across the valves when they are required to operate during normal and abnormal events within the design basis,
- d. Methodology for calculating the maximum expected operating y differential pressures during normal and abnormal events, and
- e. Identification of valves that are within the scope of and are required to be tested in compliance with Reference 1. Valves that are within the scope of Reference 1 but are generically not required to be tested and the associated basis for not testing are also iden-tified. Generic methodology for testing some of the MOVs are l recommended.
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l The contents of this report are intended to be generically applicable to the BWR product lines 3, 4, 5 and 6. However, the applicability of the contents of this report to a specific plant may vary depending on the design ll and operatiing progedures of individual plants. Therefore, when referencing f this report in response to IE Bulletin 85-03, participating BWR utilities must l[ confirm the applicability of its contents to their plant. -
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- The valves that are required to be tested under this Code may vary on a plant-specific basis due to individual plant operational and design characteristics
! but could include all of the system MOVs identified in this report.
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NEDC-31322 1.4 APPROACH The following approach was used to satisfy the objectives stated in 1.2 and to meet the scope requirements of 1.3 above:
1.
Selected systems design documentation was reviewed to identify MOVs that are required to be ' tested in accordance with Section XI of the i
ASME Boiler and Pressure Vessel Code *. These are the valves that are considered to be within the scope of Reference 1.
2.
The Final Safety Analysis Reports (FSAR) of typical BWR product J
lines 3, 4, 5 and 6 were reviewed to identify normal and abnormal events that require operation of the HPCS, HPCI and RCIC systems.
- 3. For each of the valves identified in 1. above, the following was
( established:
- a. valve function,
- b. active safety action of the valve (i.e., open and/or close),
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the events in 2. above that impose the maximum expected (worse case) valve operating differential pressure,
- d. the system operating scenarios (sequence and/or operation state), within the identified events in Item 3.c above, which I impose the maximum expected valve operating differential pressure and the location of the maximum expected pressure i relative to the valve (i.e., upstream or downstream).
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aThe valves that are required to be tested by this Code may vary on a plant-specific basis due to individual plant operational and design characteristics but could include all of the system MOVs identified in this report.
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- e. The assumptions and associated generic methodology to determine the maximum expected operating differential pressures for the
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operating conditions identified in 3.d above.
- 4. Valves required to be tested were identified. Valves that are
- within the' scope of Reference 1 but are generically not required to be tested and the associated basis for not testing were identified.
- 5. Generic test methodology for valve testing was recommended.
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- 2. SYSTEMS DESCRIPTION The impact of IE Bulletin 85-03 on BWR high pressure water makeup systems is influenced by the system and valve functions and configurations during both normal and abnormal operating conditions. While the configuration of each of the affected plant systems may vary between specific plants, a general descrip-tion of system operation and typical configurations are provided in this Sec-tion to familiarize the reader with BWR HPCS, HPCI and RCIC system operation.
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2.1 HPLS SYSTEM The HPCS system is an energency core cooling system provided on BWRs 5 and 6.
~ It is required to provide reactor vessel inventory makeup over a pressure range from zero psig up to a pressure corresponding to the lowest
- Losinal spring setpoint of the reactor safety / relief valves.
The system's normal suction source is the condensate storage tank (CST).
The system can also take suction from the suppression pool. The system is capable of being flow tested with suction from and discharge to either the CST or suppression pool.
The system automatically initiates into the reactor injection mode upon r:ceipt 'of a low reactor water level or high drywell pressure signal. Reactor injection is automatically stopped upon receipt of a high reactor water level signal. Manual system control is also possible. The system's main pump is '
i cctor driven and operates at constant speed. It is supplied with power from both on-site and off-site sources.
t 2.2 HPCI SYSTEM The HPCI system is an energency core cooling system provided 'on BWRs 3 cad 4.
It is required to provide rated system flow to the reactor over a pressure range from approximately 150 psig up to a pressure corresponding to the lowest nominal spring setpoint of the reactor safety relief valves.
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NEDC-31322 The system's normal suction source is the CST. The system can also take suction from the suppression pool. The system is capable of being flow tested with suction from and discharge to the CST.
The system automatically initiates into the reactor injection mode upon
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receipt of a low reactor water level or high drywell pressure signal. Reactor i
injection is automatically stohped upon receipt of a high reactor water level signal. The system automatically isolates on a low reactor pressure of
, approximately 100 psig. Manual system control is also possible. The system's main pumps are driven by a variable speed steam turbine.
2.3 RCIC SYSTEM The RCIC system is a reactor inventory makeup system provided on BWRs 3, 4 4, 5 and 6. It is required to provide rated system flow to the reactor vessel over a pressure range from approximately 150 psi up to a pressure i
corresponding to the lowest nominal spring setpoint of the reactor safety /
relief valves. The system is capable of operating down to a reactor pressure of approximately 50 psig.
The system's normal suction source is the CST. The system can also take suction from the suppression pool. It is capable of being flow tested with suction from and discharge to the CST.
The system automatically initiates into the reactor injection mode upon receipt of a low reactor water level signal. Reactor injection automatically stops upon receipt of a high reactor water level signal. The system i
automatically isolates on a low reactor pressure of approximately 50 psig. -
Manual system codtrol is also possible. The system's main pump is driven by a a variable speed steam turbine.
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NEDC-31322 2.4 SYSTEN VALVE CONFIGURATIONS Typical BWR configurations of the HPCS, HPC1 and RCIC system's valvos are illustrated in Figures 1 through 8. MOVs typically insta n ed on these systems in the plants listed in Appendix A that are required to be tested in compliance with Section XI of the ASME Boiler and Pressure Vessel Code are illustrated in Figures 1 through 8. However, due to plant unique variations, come of the valves illustrated are not installed on all BWRs. Other system valves such as check valves, and relief valves are not shown for purposes of ciaplic'ity. Howevey, the presence of these other valves has been considered in evaluating the MOVs maximum expected operating differential pressures.
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- 3. EVALUATION OF SYSTEMS MOTOR-OPERATED VALVES The BWROG Committee's means of establishing the methodology for deter-mining the differential pressures under which BWR HPCS, HPCI and RCIC system MOVs should be able to operate was based on the review of existing, previously cpproved design bases FSAR events (i.e. previously accepted FSARs). In addi-
. tion, the evaluation of system MOVs included consideration of pipe breaks in the design basis review. This section presents the evaluation of the HPCS, HPCI and RCIC systems MOVs in accordance with these considerations and the cpproach discussed in Section 1.4.
3.1 VALVES REQUIRED TO BE TESTED IN ACCORDANCE WITH THE ASME SECTION XI CODE The Piping and Instrument Diagrams (P& ids) for the BWRs listed in Appendix A were reviewed to identify a collective list of typical BWR MOVs installed in the systems. Other selected system design documents considered
" typical" of the various BWRs were also reviewed and engineering personnel at utilities were contacted as required to establish the function and actions
. required of the system's MOVs. Based on these reviews and contacts, the valves required to be tested in accoMance with Section XI of the ASME Boiler ana Pressure Vessel Code
- were identified. Tables 2, 3 and 4 provide a list of these MOVs.
3.2 FSAR EVENTS REQUIRING SYSTEMS OPERATION FOR SAFETY-RELATED FUNCTIONS
'1he FSARs of BWRs considered " typical" of BWR 3, .4, 5 and 6 were reviewed to identify the " normal and abnormal events" that result in operation of the HPCS, hPCI or RCIC systems (References 2, 3, 4 and 5). These events are summarized in Tabfe 1. These events were then reviewed to establish the required active safety action of the systems valves'during the events.
- The valves that are required to be tested by this Code may vary on a plant-specific basis due to individual plant operational and design characteristics but could include all of the system's MOVs identified in this report.
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NEDC-31322 BWK " normal events" as used in Reference 1 are considered in this report to be synonymous with " normal operations" as defined in the FSARs. The PSARs reviewed also defined " normal operations" as being " planned operations" defined as follows: Normal station operation under planned conditions in the absence of significant abnormalities. Operations subsequent to an incident (transient, accident, or special event) are not considered planned operations until the procedures being followed or equipment being used are identical to those used during any one of the defined planned operations. The following
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planned operations are identified:
- s. refueling outage,
. b. achieving criticality,
- c. heatup,
- d. power operation,
- e. .
achieving shutdown, and l
- f. cooldown r.
The planned operations can be considered as a chronological sequence:
refuelf.ng outage -- achieving criticality -- heatup - power operation --
achieving shutdown -- cooldown -- refueling outage. ,
Based on the above definitions, the events in Table 1 are not normal events. Therefore, it is concluded that the HPCS, HPCI and RCIC systems are not required to perform active safety action / functions during normal events.
The events in Table 1 are therefore considered "cbnormal events" for the l purpose of this report. The events in Table 1 that require the systems valves to perform an active safety action are those events that require the systems to operate in the reactor vessel injection mode in order for the system to provide reactor invantory makeup.
In addition to the events identified in Table 1, the FSAR identifies some of the system's HOVs as containment isolation valves. MOV operation to provide the containment isolation function is considered a system /MOV active safety action / function when determining valve maximum expected operating differential pressure.
NEDC-31322 During plant normal operation (i.e., planned operations), the system 1
valves are actuated as required to place the system into or recove it from its standby mode and are routinely operated to perform system and component test.
These are the " normal events" that involve operation of the systems valves.
3.3 DETERMINATION OF MOVs SAFETY-RFmED FUNCTIONS, ACTIONS AND MAX 1 MUM OPERATIhG DIFFDLENTI/1 PRESSURES The FSAR events in Section 3.2 were reviewed to establish, for each of
.. the valves identified in Section 3.1, the valve's active safety functions and actions, etc. listed in Section 1.4 (3). This section summarizes the results
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of tnat review in the text that follows and in Tables 2, 3, 4 and 5.
3 - 3.3.1 BWR Design Basis Assumptions The following accepted BWR design basis assumptions were used to evaluate the MOVs required active safety actions based on the systems required functions in Section 3.2 above.
3.3.1.1 Valve Position Valves are assumed to be in and remain in their normal standby position during an abnormal event (i.e., the valve positions indicated in Figures 1 through 8) unless the event can result in the valves changing position.
3.3.1.2 System Testing l
The evaluations of the plant response to the events in Table 1 that are presented in the plant FSARs assume that the HPCS, HPCI and RCIC systems are in their normal standby condition at the start of an event (i.e., not running and with their valves aligned as shown in Figures 1 through B). This
, assumption is made because of the low probability of the system being in a test mode or out of service during the occurrence of an abnormal event.
Consistent with this assumption used for FSAR evaluations, the required active safety actions of the valves are established assuming the systems are in their 13 -__ _____ _ ..._ _ ______ _ _ _ _ . _ . . _ . _ . , - - _ _ -
NEDC-31322 normal standby condition at the start of an event and, hence, are not assumed to be in a test mode.
3.3.1.3 Inadvertent Valve Operation BWRs are provided.with a network of redundant systems that are separated El electrically and mechanically such that, following a single failure in any system or any single operator error, adequate core and containment cooling is available. The individual systems that comprise this network are not required to remain operable following a single failure in that system because the redundant systems are available to provide the required cooling function.
Therefore, a system is not required to regain operability following an
_ operator error that results in inadvertent closing and/or opening of a valve.
3.3.2 HPCS System MOVs 3.3.2.1 Injection Valve Valve number 1 in Figure 1 functions as the system's injection valve.
Its active safdty actions are to both open and close during abnormal plant
, events. During an abnormal event, the valve is required to open in order for the system to provide reactor inventory makeup. The valve must close to terminate system injection, and provide reactor and containment isolation.
The maximum expected opening and closing differential pressure across the valve occurs during abnormal events in which the system is required to provide inventory makeup to the reactor. It occurs when the system is signaled to either initiate or terminate reactor injection when reactor pressure is near or at zero psig. The maximum expected pressure occurs upstream of the valve.
The methods to be utilized to calculate the valve marinum expected opening and closing differential pressure are presented in Table 2. The following assumptions apply in determining these differential pressures:
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NEDC-31322 1.
Suction is from the condensate storage tank (CST) and the CST is
, full.
2.
The pressure in the reactor is near or at zero psig.
3.
The system is initiated and the injection valve is signaled to open when the system is operating at rated speed and before the minimum 1
flow bypass valve opens.
3 4.
During closing, the minimum flow bypass valve does not open before the EPCS injection valve is fully closed.
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3.3.2.2 Minlaum Flow Bypass Isolation Yalve Valve number 2 in Figure 1 functions as the system minimum flow bypass
( isolation v'alve.
Its active safety actions are to both open and close during abnormal plant events.
During an abnormal event, the valve is required to cpen when other discharge line valves are closed to avoid damage to the main cystem pump due to overheating. The valve is required to close to (a) provide containment isolat[on, and (b) cause all system flow to be delivered into the i reactor ie.ssel.
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The naminua expected opening and closing differential pressure across the l valve occurs when the main pump is running and the system injection valve is closed or opened (e.g. , during a LOCA). The maximum expected pressure occurs )
3 upstream of the valve.
The methods to be utilized to calculate the maximum expected opening and closing differential pressure are presented in Table 2. The following casumptions apply in determining these differential pressures:
1.
Suction is from the CST and the CST is full.
2.
During valve opening, the injection valve closes before the valve starts to open.
- 3. The valve closes wha the flow in the main line is equal to the :
required minimum bypass flow rate.
3.3.2.3 CST Suction Valve Valve number 3 in Figure 1 functions as the system CST suction shutoff valve. The active safety action of this valve is to close during abnormal events when system suction is transferred from the CST to the suppression pool. Closure of the valve is required to ensure system operation when system suction is transferred to the suppression pool.
i The maximum expected pressure occurs upstream of the valve when the system suction is automatically transferred to the suppression pool due to high suppression pool water level. The transfer occurs while the system is ,
injecting into the reactor.
i :. j The method to be utilized to c.alculate the maximum expected differential I pressure during valve closing is presented in Table 2. The following I assumptions apply in determining this differential pressure:
- 2. The system is operating to provide makeup water to the reactor vessel.
- 3. Wetwell pressure is zero psig.
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- 4. Reactor . pressure is zero psig and the system is operating at its maximum flow rate.
- 5. Suppression pool water reaches its maximum permissible level.
- 6. System suction is automatically transferred from the CST to the suppression pool by valve number 4 opening and then valve number 3 closing.
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l NEDC-31322 3.3.2.4 Suppression Pool Suction Isolation Valve Valve number 4 in Figure 1 functions as the system suppression pool suction isolation valve.
Its active safety actions are to both open and close during abnormal plant events.
The valve is required to open in order for the system to take suction from the suppression pool. The valve is required to close to provide containment isolstion.
The maximum expected pressure during opening occurs downstream of the valve when the system is not running and suction is manually transferred fros the CST to the suppression pool due to low CST water level.
The suction is
, transferred in order to maintain the operability of the system. The maximus cxpected pressure during closing occurs upstress of the valve during a LOCA
- when the valve is closed to provide containment isolation.
The methods to be utilized to calculate the marinua expected opening and closing differential pressures are presented in Table 2 and are based on the following assumptions:
For valve opening:
- 1. The system is not running.
- 2. Suction is from the CSI.
3.
The reactor is at its normal operating pressure.
- 4. Wetwell pressure is sero psig.
5.
The suppression pool is at its minimum permissible water level.
~
6.
The CST suction check valve and suppression pool suction isolation valve number 4 do not leak. The suppression pool suction check valve leakage is such that there is no differential pressure across it.
. - - . - . - - - - - - - - - - 17
=
- 7. Minor leakage of the injection valve number 1 and check valves in the discharge line results in pressurization of the suction piping and components to the suction line relief valve actuation set pressure.
- 8. The CSI supply becomes unavailable and the suppression pool suction isolatiod valve is manually signaled to open to maintain the operability of the system.
For valve closing:
.' 1. During a LOCA, when suction is from the suppression pool, an active failure in the system results in significant leakage downstream of the valve (e.g., the pump mechanical seal starts leaking significantly).
- 2. Wetwell pressure is at,its maximum LOCA design value.
- 3. Suppression pool water is at its nazimum LOCA design level.
- 4. The pump is shutdown.
- 5. The valve is ranually signaled to close.
3.3.2.5 CST Test Return Valves i
! Valves number 5 and 6 in Figure 1 function as the system CST test return shutoff valves. During an abnormal event, the valyce are required to remain ,.
l closed so that all system flow will be to the reactor vessel. The valves are
[
l normally closed and are only opened for system flow testing. Based on the BWR design basis assumptions in Sections 3.3.1.1 and 3.3.1.2 above, the valves l perform no active safety function during the FSAR design basis events.
Therefore, these valves have no active safety action / operation requirements.
l l
\
These valves are open during plant normal operations when the system is l
being tested to verify flow capability. 1 Yalve operation during the flow test '
deronstrate the capability of these va3ves to operatee maximum against th differential pressures that occur during the test.
Therefore, testing to comply with Reference 1 is not required for the plant normal operating actuations of these valves.
1 3.3.2.6 - Suppression Pool Test Return Isolation Valve Valve number 7 in Figure 1 is normally closed and functions e as th suppression pool test return isolation valve.
During an abnorasl event, the v:1ve is required to remain closed in order to (a) provide containment
,o -
1:clation, and (b) ensure shat all system flow' is directed t vacsel. .
o the reactor It is intended to be opened for system surveillance flow testi ng when
' the plant is in a normal shutdown condition.
Based on the BWR design basis cccuaptions in Sections 3.3.1.1 and 3.3.1.2 above, the valve is not require I to perform a active safety function during the FSAR design b asis events.
Therefore, the valve has no active safety action / operation r equirements.
Valve operation during the flow test demonstrates the capabilit y of the valve the test.to operate against the maximum differential pressures ng that occur dur TMrefore, testing to comply with Reference 1 is not required or f
tha plant normal operating actuations of this valve .
3.3.3 _HPCI System MOVs 3.3.3.1 Injection Valve Valves number 1 and la in Figure 2 and valve number 1 in Figure 4 all function as the system injection valve (s).
The active safety action.6f these valvas is to open during abnormal events.
During an abnormal event, the valve j
is k:up. rsquired to open in order for the system to provide reactor nventory i
On some BWRs where valve number 1 anda reactor la function as both
! .ad ccatainment isolation valve, the active safety action of the valves also includes closure in order to provide the isolation function.
P
, NEDC-31322 The maximum expected opening and closing differential pressure across the valve occurs during abnormal events when the system is required to initiate (valve opening) or terminate (valve closing) inventory make-up to the reactor vessel. The magnitude of the maximum espected opening and closing differential pressure is dependent on whether or not the system injection valve is opened and closed when the turbine is operating or only opened and closed when the turbine is not running and/or is only operating at a low speed.
3.3.3.1.1 Opening or closing the HPCI System Injection Valve while the HPCI Turbine is Operating 4
For plants that (a) manually open or close the HPCI System injection valve (s) while the HPCI turbine is operating, or (b) have HPCI System automatic initiation logic which initiates the opening of the HPCI System injection valve after the HPCI turbine stop valve has started opening and has not implemented any HPCI turbine start-up transient reduction modifications
( (such as the HPCI turbine hydraulic bypass modification), the maximum expected differential pressure occurs upstream of the injection valve. The method used to calculate this maximum expected differential pressure presented in Table 3 is based on the following assumptions:
- 2. Ptessure in the reactor is equal to the HPCI system steam supply pressure low isolation setpoint.
- 3. During opening, (a) the turbine reaches its maximum normal speed before the injection valve starts to open, and (b) the injection valve starts to open before the minimum flow bypass valve starts to ,
open. '
- 4. During closing, (a) the operator closes the injection valve before
- the turbine is tripped, (b) the turbine reaches maximum normal speed I
before the valve closes, and (c) the minimum flow bypass valve has not started to open when the injection valve closes.
20
l
~
NEDC-31322 3.3.3.1.2 \
l Opening the HPCI System Injection Valve prior etoHPCI Starting th !
l Turbine or When the HPCI Turbine is Operating eed orat Low Sp Closing the HPCI System Injection Valve af ter Turbine Tripping e HPCI th 1 For plants that (a) aanually open the HPCI system i j n ection valve prior
\
to ct.arting the HPCI turbine, (b) have HPCI system a t t:hich opens the HPCI system injection valve immedi u omatic initiation logic !
initiation signal, (c) have HPCI system automatic initiatiately upon receipt of an on logic which i
initiates 'the opening of the HPCI system injection valve tiurbine stop valve has started to open and has imafter l the HPCI p emented an HPCI turbine start up transient reduction modification, or (d) manually clo i se the HPCI cystca injection valve after tripping the HPCI turbine, the maximum expected
{
dilforential pressure occurs downstrema of the valvs The method used to eniculate this maximum expected differential pressure presented i bar:d on che following assumptions: n Table 3 is \
l.
- 1. i The reactor is at the pressure corresponding to the lowest nuclear boiler system safety / relief valve spring setpoint .
2.
The HPCI system ie aligned to draw suction from the supp ression pool \
and the suppression pool is at the icw water level limit .
- 3. ,
When opening, the pump discharge pressure is negligibl e when the inject. ion valve is starting to open. {
- 4. \
When closing, the pump discharge pressure eiswhen negligibl the injection valve is nearly fully closed. !
3.3.3.2 Minimua Flow Bypass Isolation Valve lyparc Valve number isolation valve. 2 in Figures 2 and 4 functions as the system minimun flow g obnormal plant events.Its active safety actions are to both open and close p n then other discharge line valves amage aretoclosed the to avoid dDur' a cystes pump due to overheating.
The valve is required to close to
NEDC-31322 (a) provide containment isolation, and (b) cause all system flow to be delivered into the reactor vessel.
The maximum expected opening and closing differential pressure across the valve occurs when the main pump is running, the turbine is operating at its maximum normal speed, and the system injection valve is closed or opened. The maximum expected pressure occurs upstream of the valve.
The methods to be utilized to calculate the maximum expected opening and
~~
closing differential pressures are presented in Table 3. The following assumptions apply in determining these differential pressures:
.~
- 2. During opening, the injection valve closes before the valve starts opening.
- 3. The valve closes when the flow in the main line is equal to the required minimum flow rate.
3.3.3.3 CST Suction Valve Valve number 3 in Figures 2 and 4 functions as the system CST suction shutoff valve. The active safety action of this valve is to close during abnormal events when system suction is transferred from the CST to the
! suppression pool. Closure of the valve ir required to ensure system operation j when system suction is from the suppression pool. i The maximum expected pressure during closing occurs upstream of the valve i Nhen the system suction is automatically transferred from the CST to the sup-pression pool due to high suppression pool water level. The. transfer occurs while the systen is injecting into the reactor.
i 22
NEDC-31322 The method to be utilized to calculat pressure during valve closing isepresent d ie the maximum expected differen n Table 3. The fdllowing cccumptions apply in determiningn this differe a pressure: ti l 1.
Suction from the CST and CST is full .
2.
The system ta operating at its rated fl water to the reactor vessel. ow rate to provide makeup 3.
Wetwell press ure is zero psig. ;
4.
Suppression pool water reaches its m aximum permissible level.
5 System suctics is transferred from th opening and then valve number 3 closing be CST by valve numbers 4 and suppression yool water level. ecause of the high 3.3.3.4 Suppression Pool Suction Isolation a ves Vl Vcives number 4 and 4a in Figures 2 cuppracsion pool isolation valves. and 4 function as the system
- cud c1cce during abnormal plant eventsThe active are safety actions to both open
!erdar fer the system to tak The valves are required to open in era r: quired to close to provide ation. containment The isole valves suction from the The maximum expected pressure during i p1vac when the system is not running and suctiopening occurs downstrea M CST to the suppression pool due to low CST on is manually transferred nsforr d in order to maintain thewater level. The suction is operability of the system.
ccura during closing occurs upstream of the v lThe maximum tha velV* g, ci sed to provide co t i a ve during an abnormal event n a nment isolation
- 1
) 'o ccthod_s to be utilized to cal culate the maximum 3 differential owing casumptions: pressure,s are presented in Table 3 expected opening and and are based on the
NEDC-31322 For valve opening:
- 1. The system is not running
- 2. Suction is from the CST.
- 3. The reactor is at its normal operating pressure.
- 4. Wetwell pressure is zero psig.
- 5. The suppression pool is at its minimum permissible water level.
~
_ 6. The CST suction check valve and suppression pool suction isolation valves numbers 4 and 4a do not leak. The suppression pool suction check valve leakage is such that there is no s differential pressure across it.
.I
- 7. Minor leakage of the injection valve number 1 and check valves in the discharge line results in pressurization of the suction piping and components to the suction line relief valve actuation set pressure.
- 8. The CST supply becomes unavailable and the suppression pool suction isolation valves are manually signaled to open to maintain the operability of the system (for valve 4, assume valve 4a opens first; for valve 4a, assume valve 4 opens first).
For . valve closing:
- 1. During a LOCA, when suction is from the suppression pool, an active failure in the system results in significant leakage downstream of the valves (e.g., the pump mechanical seal starts leaking significantly).
- 2. Wetwell pressure is at its maximum LOCA design value prior to j system isolation.
~ 1
NEDC-31322 3.
Suppression poc1 water is at its maximum LOCA evel. design l
- 4. The pump is shutdown.
5.
The valves are manually signaled to close (for, valve assume 4
valve 4 is cicsed first; for valve 4a, assume valve 4a is closed first).
3.3.3.5 ' CST Test Return Valves Valves number 5 and 6 in Figures 2 and 4 are normally clo cs the system CST test return shutoff valves. sed and function During an abnormal event, the
.yalves are required to remain closed.so that all system flow will be to racetor vessel.
Based on the BWR design basis assumptions n in Sectio s 3 3
. 1.1 cud 3,3.1.2 above, the valves are not required to perform e safety an activ metion during the FSAR design basis events.
'cctive safety action / operation requirements. Therefore, these valves have no These valves are open during plant normal operation when th e system is bsing tested to verify flow capability.
dSscustrates the capability of these valves to cperateValve operation du l against the maximum difforential pressures that occur during the test .
i comply with Refdrence 1 is not required for the plant normalTherefore, testing to cctuationsofthesevalhes. operating 3.3.3.6 Suppression Pool leolation and Test Bypass Flush e Valv Vcive number 7 in Figure 2 is normally closed and functi ons as the supprs:sion pool isolation and test bypass flush valve .
During an abnormal cy:nt, it is required to remain closed to provide containment a on. isol ti Baccd Cn the BWR design basis assumptions in Sectio
)
valva is not required to perform an active safety function
.gn basis events. uring the FSAR dns 3.3.1.1 and 3.3.1.2, th Therefore, the valve has no active safety ccticn/cperation requirements.
NEDC-31322 The valve is opened during plant normal operation to flush the system lines prior to system flow testing. Valve operation during these flushing operations demonstrates the capability of the valve to operate against the maximum differential pressures that occur during the flushing operations.
Therefore, testing to comply with Reference 1 is not required for the plant normal operating actuations of this valve.
3.3.3.7 Injection Valve Test valve
~'
Valve number 8 in Figures 2 and 4 is normally open and functions as the system injection valve test valve. It is only closed to perform operability testing of the system injection valve. During an abnormal event, it is
- required to remain open. Based on the BWR design basis assumptions in Sections 3.3.1.1 and 3.3.1.2, the valve is not required to perform an active I
safety function during FSAR design basis event. Therefore, the valve has no active safety a$ tion / operation requirements.
The maximum differential pressure across this valve during plant normal operation occurs when the valve is re-opened following its closure so that the injection valve operability stroke test can be performed. Valve operation t
during injection valve testing demonstrates the capability of the valve to actuate against the differential pressures that occur during plant normal operation. Therefore, testing to comply with Reference 1 is not required for the plant normal operating actuations of this valve.
4 3.3.3.8 Turbine Accessories Cooling Water Valve Valve number 9 in Figure 2 functions to control cooling water to turbine
~
accessories. The active safety action of the valve is to open during abnormal events. On plants with a barometric condenser gland seal system, the active safety action includes closure to prevent suppression pool wa'er t discharge to the clean radwaste system.
)
i 4
, , ,. -.----,-=---'~r' " ' " " * * " ' - " " " ~ ~ ' - - "
NEDC-31322 The maximum expected differential press a small LOCA break when the systemn is started a dure high. across occurs during the valve Maximum expected pressure occurs upstrea containment pressure is m of the valve.
The method to calculate the maximum prasented in Table :.
3 and is based on the follexpected differential pressure is owing assumptions:
1.
A small break LOCA occurs and system su
.- CST to the suppression pool. ction is transferred from the 2.
. The check valve on the discharge of val that the pressure upstream of the ch ve number 9 seals tight such valve number 9 opens.
eck valve can not increase until 3.
The system is signaled to start and the
' signaled to open. valve is immediately signaled to start but it takes approximatelyThe s also HPC develop sufficient oil pressure to st ten (10) seconds to stop valve.
significant turbine speed is reachedTherefore, e ore any va 4.
The valve is closed following system fl reactor water level 8. ow termination at high NOTE:
Valves number 10 and 11 are valves uniqu pating utility.
determined that these valves would report, it bBecause was of the time of their plant specific respon e addressed by that utility at the I se to Reference 1.
B.3.3.9 Steam Admission Valve T
Vcive number I in Figure 5 functions lts active safety function is to open das the system turbine admission i c3 to required to start. uring abnormal events when the
\
. \
e 4
The maximum expected differential pressure across the valve occurs during opening when the system is initiated to provide makeup water to the reactor.
The maximum pressure during opening occurs upstream of the valve. Table 3 presents the method of calculating the nazimum expected differential pressure I based on the following assumptions:
1 l
- 1. The reactor is isolated and maintained at pressure by relief valves operating on their spring setpoint. l
- 2. The system is signaled to start and the valve opens.
3.3.3.10 Steam Line Isolation Valves !
Valve number II and III in Figure 5 function as the system steam containment isolation valves. On most BWRs, these valves are normally open. '
However, on some plants, one of the valves is closed and valves number IV or V are normally open as required to maintain the downstream piping heated and pressurized. l The active safety action of the valve is to close in the event of a break in the downstream piping. If one of these valves is normally closed, then its :
)
active safety action is also to open in response to a system initiation signal. In all cases, the nazimum expected pressure occurs upstream of the :
valve. 1 The methods of calculating the maximum expected differential pressures l during valve opening and closing are presented in Table 3 and are based on the !
following assumptions:
For valve closure:
l l
- 1. The system is operating (i.e., valves are open).
I
- 2. A break occurs in the downstream piping. The break is large enough to reduce the pressure downstream of the valve to nearly l
t am )
NEDC-31322 atmospheric pressure when the valve is nearly closed but not large enough to result in significant reactor pressure reduc -
tion when the valve actually closes.
3.
The valves are signaled to close.
4.
Reactor pressure is equal to the spring setpoint of the reactor safety relief valve with the lowest nominal setpoint .
For valve opening (applicable only to those plants that h ave normally c1csed steam line isolation valves):
1.
The system is initiated and the valve is signaled en when to op reactor pressure is equal to P RSS as defined in Table 5.
The maximum differential pressure across these valves du i r ng plant normal cpar0 tion occurs when the valves are actuat'ed to place remove it from the standby mode. or the system into Valve operation during these alignment cetuations demonstrates the capability of the valvesnsttotheactuate agai differential pressures that occur during plant normal operation. Therefore, tcsting to comply with Reference 1 is not required f cparating actuations of these valves. or the plant normal
! 3.3.3.11 Bypass Valves for Steamline Isolation Valves Valves number IV and V in Figure 5 function as bypass valv es around valv00 II and III to permit heating of the downstream piping .
The valve's cctiva piping. safety function is to close in the event of a break in the d ownstream The maximum expected pressure on closure occurs upstream of the valves.
Tha method of calculating the maximum expected n a differe ti l pressure presented robleabove).
(3.3.3.10 3 is based on the same assumptions as utilized for valves II and
NEDC-31322 The maximum differential pressure across the valves during plant normal operation occurs when the valves are actuated to place the system into or remove it from t.he standby mode. Valve operation during these alignment actuations demonstrates the capability of the valves to actuate against the differential pressures that occur during plant normal operation. Therefore, testing to comply with Reference 1 is not required for the plant normal operating actuations of these valves.
.. 3.3.3.12 Turbine Exhaust Isolation Valve Valve number VI in Figure 5 functions as the turbine exhaust containment _
isolation valve. The s'fety-related a function of the valve is to close when
_" isolation is required.
The maximum expected differential pressure occurs when the operator manually signals;.the HPCI system turbine exhaust isolation . valve to close~
during a LOCA event. The maximum pressure occurs downstream of the valve.
The method of calculating the maximum expected differential pressure during
~
valve closure is presented in Table 3 and is based on the following assumptions:
- 1. The wetwell is at the maximum LOCA pressure.
- 2. An active failure results in leakage upstream of the valve.
- 3. The operator manually signals the turbine exhaust isolation valve to -
close.
I
^
3.3.3.13 Vacuum Breaker Line Isolation Valves n
Valves number VII and VIII in Figure 5 function as the vacuum breaker line containment isolation valves. The active safety action of the valves is to close to provide the required isolation.
I na
1
. l NEDC-31322 LOCA. The maximum expected differential pressure occurs during a large break valves. The maxiana expected pressure during closind occurs upstream e of th Table 3 presents the method of calculating the maximum expected differential pressure based on the following assumptions:
- 1. A large break LOCA occurs.
2.
HPCI starts on low reactor water level.
3.
Low reactor pressure results in shutdown and isolation of the system .
4.
. Valves VII and VIII are signaled to close.
( 3.3.4.1 Injection Valve Valve number 1 in Figure 6 functions as the system injection The .
valve active safety action of the valve is to open during abnormal events . During cn abnormal event, the valve is required to open in order for the system to prnvide reactor inventory make up. On some BWRs where the valve functions as o reactor and containment isolation valve, the active safety action of the valve also includes closure in order to provide the isolation function .
The maximum expected opening and closing differential pressure e across th valve occurs during abnormal events when the system is required to provide inv:ntory makeup to the reactor.
The magnitude of the maximum expected cpening and closing differential pressure is dependent on whether or not the cystem injection valve is opened and closed when the turbine is operating, or caly opened cperating and closed at a low speed. when the turbine is not operating and/or is 1
l 1
_ ---F ~- '-
f NEDC-31322 3.3.4.1.1 Opening or closing the RCIC System Injection Valve while the RCIC Turbine is Operating. l i
For plants that (a) manually open or close the injection valve when the i
kC1C turbine is operating or (b) automatically initiate the RCIC systea !
without the benefit of RCIC turbine start-up transient reduction modifications '
(such as bypass start); the maximum expected pressure occurs upstream of the ;
valve. The method used to calculate this maximum expected differential '
pressure presented in Table 4 is based on the following assumptions:
- 2. , Pressure in the reactor is equal to the system steam supply pressure
~
low isolation setpoint.
- 3. During opening, (a) the turbine reaches its maximum normal speed
!. before the injection valve starts to open, and (b) the injection valve starts to open before the minimum flow bypass isolation valve starts to open.
- 4. During closing, (a) the operator closes the injection valve before the turbine is tripped, (b) the turbine reaches maximum normal speed before the valve closes, and (c) the minimum flow bypass isolation valve has not started to open when the injection valve closes.
NOTE: The methodology presented in this Section 3.3.4.1.1 is considered to yield conservative results and may vary with specific plants.
i Individual utilities may, therefore, chose to perform their own plant-specific evaluation in order to more realistically define the valve opening maximum expected differential pressure.
o .
I no
NEDC-31322 3.3.4.1.2 Opening the RCIC System Injection Valve prior to Starting e RCIC th Turbine or When the Turbine is Operating at Low Speed ng or Closi the RCIC System Injection Valve after Tripping the RCIC Turbine.
For plants that (a) manually open the RCIC System injecti on valve prior to starting the RCIC turbine, (b) automatically initiate th e RCIC System with the aid of RCIC turbine start-up transient reduction modifi cations (such as bypass start), or (c) manually close the RCIC System injecti
' tripping the RCIC turbine,the assimum expected pressur on valve after the valve. e occurs downstream of The method used to calculate this maximum expected diff erential pressure presented in Table 4 is based on the followingns:assumptio 1.
~
The reactor is at the pressure corresponding to the lowest nuclear boiler system safety / relief, valve spring setpoint 2.
The RCIC system is aligned to draw suction from thepool ession suppr and the suppression pool is at the low water level limit .
3.
When opening, the pump discharge pressure is negligible e when th injection valve is starting to open.
4.
! When closing, the pump discharge pressure is negligible en the wh injection valve is nearly fully closed.
3.3.4.2 i Minimum Flow Bypass Isolation Valve Valve number 2 in Figure 6 functions as the system minim i icolation valve. um flow bypass oburrmal plant events.Its active safety actions are to both open and close durin
! During an abnormal event, the valve is required to cpan when other discharge line valves are closed to avoid damage to th e main cyct:n pump due to overheating. .
c:ntninnent ccctor vessel.
isolation, and (b) cause all system flow to be deliThe vered into the
, i' i
y
-l NEDC-31322 The maximum expected opening and closing differential pressure across the valve occurs when the main pump is running, the turbine is operating at its maximum normal speed, and the system injection valve is closed or opened. The maximum expected pressure occurs upstream of the valve.
The methods to be utilized to calculate the maximum expected opening and closing differential pressures are presented in Table 4. The following assumptions apply to determining these differential pressures:
- 2. During opening, the injection valve closes before the valve starts
- to open.
-3. The valve closes when the flow in the main line is equal to the required minimum flow bypass flow rate.
3.3.4.3 CST Suction Valve I
Valve number 3 in Figure 6 functions as the system CST suction shutoff valve. The active safety action of this valve is to close during abnormal events when system suction is transferred from the CST to the suppression pool. Closure of the valve is required to ensure system operation when system suction is from the suppression pool.
l The maximum expected pressure during valve closing occurs upstream of the valve when the system suction is transferred to the suppression pool due to high s'uppression pool unter level. The transfer occurs while the system is injecting into the reactor. l The method to be utilized to calculate the maximum aspected differential i pressure during valve closing is presented in Table 4. The following l assumptions apply in determining this differential pressure: l 1
l l
34 _
I i
- 1. The CST is completely full.
2.
The system is operating at its rated flow rate to provide makeup '
I water to the reactor vessel. E
- 3. Wetwell pressure is zero psig. - i i
- 4. Suppression pool water reaches its maximum permissible level.
5.
System suction is transferred from the CST by valve numbers 4 and 4a opening and then valve number 3 closing.
3.3.4.4 Suppression Pool Suction Isolation Valves Vcives number' 4 and 4a in Figure 6 function as the system suppression L suction isolation valves. The active safety actions are to both open and cleco during abnormal plant events. The valves are required to open in order fer the system to take suction from the suppression pool. The valves are
{ r quir:d to close to provide containment isolation.
The maximum expected pressure during opening occurs downstream of the valva when the system is not running and suction is manually transferred from the CST to the suppression pool due to low CST water level. The suction is trtnsforred in order to maintain the operability of the system. The maximum crpactsd pressure during closing occurs upstream of the valves during an cbnormal event when the valves are closed to provide containment isolation.
The methods to be utilized to calculate the maximum expected opening and clecing differential pressures are presented in Table 4 and are based on the fellcwing assumptions:
For valve opening:
- 1. The system is not running.
I
- 2. Suction is from the CST.
- 3. The reactor is at its normal operating pressure.
- 4. Wetwell pressure is zero psig.
- 5. The suppression pool is at its minimum permissible water level.
.. 6. The CST suction check valve and suppression pool suction isolation valves numbers 4 and 4a do not leak. The suppression
~
pool suction check valve leakage is such that there is no
, differential pressure across it.
- 7. Minor leakage of the injection valve number 1 and check valves in the discharge line results in pressurization of the suction piping and components to the auction line relief valve actuation set pressure.
- 8. The CST supply becomes unavailable and the suppression pool suction isolation valves are manually signaled to open to maintain the operability of the system (for valve 4, assume .
valve 4a opens first; for valve 4a, assume valve 4 opens first).
For valve closing: I
- 1. During a LOCA, when suction is from the suppression pool, an active failure in the system results in significant leakage downagream of the valves (e.g., the pump mechanical seal starts leaking significantly).
- 2. Wetwell pressure is at its maximum LOCA design yhlue prior to system isolation.
- 3. Suppression pool water is at its maximum LOCA design level.
- 4. The pump is shutdown.
5.
The valves are manually signaled to close (for valve 4, assume valve 4 is closed first, for valve 4a assume valve 4a is closed first).
3.3.4.5 CST Test Return Valves \
i t
Vaives number 5 aM 6 in Figures 6 and 7 are normally closed and function co the system CST test return shutoff valves.
During an abnormal event, the valves are required to remain closed so that all system flow will be to the rd:ctor vessel.
3 Therefore, based on the BWR design basis assumptions in
_Sictions 3.3.1.1 and 3.3.1.2, the valves are not required to perform an active i safety function during the PSAR design basis events.
Therefore, these valves have no active safety action / operation requirements. .
These valves are open during plant norati operations when the system is bning tested to verify flow capability. Valve operati,on during these flow testo demonstrate the capability of these valves to operate against the maximum differential pressures that occur during these tests. Therefore, testing to comply with Reference 1 is not required for the plant normal l cperating actuations of these valves.
3.3.4.6 Barometric Condenser Discharge Isolation Valve Valve number 7 in Figure 6 functions as a containment isolation for the barometric condenser vacuum pump discharge line to the wetwell.
The active cefoty function of the valve is to close for system isolation.
The maximum expected closing differential pressure across the val've i
. cccurs during a LOCA when the valve is closed to provide isolation. The anximum expected pressure occurs downstream of the valve.
i The method to calculate the maximum expected differential pressure is i proccated in Table 4 and is based on the following assumptions:
4
= _ _ .-- _ _ - __
- 1. A LOCA occurs.
- 2. Leakage upstream of the valve occurs.
- 3. The operator closes the valve to provide containment isolation.
3.3.4.7 Injection Valve Test Valve Valve number 8 in Figure 6 is normally open and functions as the system
.. injection valve test valve. It is only closed to perform operability testing or the system injection valve. During an abnormal event, it is required to remain open. Based on the BWR design basis assumptions in Sections 3.3.1.1 and 3.3.1.2, the valve is not required to perform an active safety function during FSAR design basis events. Therefore, the valve has no active safety action / operation requirements.
The maximum differential pressure across this valve during plant normal operation occurs when the valve is re-opened following its closure so that the injection valve operability stroke test can *oe, performed. Valve operation during injection valve testing demonstrates the capability of the' valve to actuate against the differential pressures that occur during plant normal operation. Therefore, testing to comply with Reference 1 is not required for the plant normal operating actuations of this valve.
3.3.4.8 Turbine Accessories Cooling Water Valve Valve number 9 in Figure 6 functions to control cooling water to turbine accessories. The active safety action of the valve is to open. On plants with a barometric condenser gland seal system, the active safety action includes closure to prevent suppression pool water discharge to the clean radwaste system. ,
The maximum expected differential pressure across the valve is dependent on whether or not the system is provided with startup transient reduction modifications, such as bypass start The maximum expected pressure occurs upstream of the valve.
NEDC-31322 The method. to calculate the maximum expected differential pressure is i
presented in Table 4 and is based on the following assumptions:
For valve openings i 1.
Suction is from the CST and the CST is full.
2.
The system automatically starts when the valve is closed.
- 3. The valve is signaled to open.
, For valve closing:
- 1. .
Suction is from the suppression pool.
i i
- 2. The system turbine is tripped.
- 3. The operator signals the valve to close.
3.3.4.9 Steam Admission Valve Valve number 1 in Figure 8 functions as the system turbine admission velve.
Its active safety function is to both opeu and close during abnormal ov:nts when the system is required to start or stop.
The maximum expected differential pressure across the valve during opening and closing occurs when the system is initiated to provide askeup water (v:1ve to the reactor (valve opening),or system flow to the reactor is stopped closing).
The maximum pressure during opening and closing occurs '
up tream of the valve.
Some plants automatically close the steam admission valve upon receipt of a high reactor water level signal. Other plants cutomatically trip the turbine on the high reactor water level signal. For
.tw plants that automatically trip the turbine, the differential pressure during closing would be negligible. i However, on these plants, the operator chould be capable of initiating closure of the steam admission valve prior to
turbine trip to improve the availability of the RCIC System. Table 4 presents the method of calculating the marinua expected differential pressure based on I the following assumptions:
- 1. The reactor is isolated and maintained at pressure by the reactor relief valves . operating on their opening setpoint.
- 2. The system is signaled to start and the valve opens.
- 3. High reactor water level 8 is reached and the valve is signaled to
, close. .
2
~
3.3.4.10 Steam Line Isolation Valves Valves number II and III in Figure 8 functions as the system steam
( containment isolation valves. On most BWRs, these valves are normally open.
However, on some plants, one of the valves is closed and valves number IV or V are ncraally open as required to maintain the downstream piping heated and pressurized.
The active safety action of the valves is to close in the event of a break in the downstream piping. If this valve is normally closed, then the active safety action of the valve is also to open in response to a systea
! initiation signal.
l The methods of calculating the maximum expected differential pressures during valve opening and closing are presented in Table 4 and are based on the following'assumpti,ons e
For valve closings *
- 1. The system is operating (i.e., valves are open).
- 2. A break occurs in the downstrema piping. The break is large
} enough to reduce the pressure downstream of the valve to nearly atmospheric pressure when the valve is nearly closed but not
____Q--:-'~-'" "'
NEDC-31322 large enough to result in significant reactorurepress reduction when the valve actually closes.
3.
The valves are signaled to close.
- 4. ~
Reactor pressure is equal to the spring setpoint of the reactor safety / relief valve with the lowest nominal setpoint .
Forvalveopen4ng(applicableonlytothoseplant closed steam line isolation valves): s that have normally 1.
_ The system is initiated and the valve is signaled reactor pressure is equal to P to open when
~
RSS as defined in Table 5.
- The maximum differential pressure across the val cparation occurs when the valves are actuated to place thves during plant n remove it from the standby mode. e system into or cetuations , demonstrates the capability of the valves toValve op differential pressures that occur during plant actuate against the testing to comply with Reference 1 is not r normal operation. Therefore, cparating actuations of these valves. equired for the plant normal 3.3.4.11 Bypass Valves for Steam Line Isolation sValve
! Valves number IV and V in Figure 8 function as b ypass. valves around valves 11 and III to permit heating of the downstream ng. pipi cctive piping. safety function is to close in the event of aThe
~
valve'si break n the downstream The maximum expected pressure on closure occurs Ih method of calculating the maximum expected upstreamdiffof the valves.
in Table 4 is based on the same assumptio erential pressure presented
( .3.4.10 above).
1 ns as utilized for valves II and III
,' .s NEDC-31322 The maximum differential pressure across the valves during plant normal operation occurs when the valves are actuated to place the system into or remove it from the standby mode. Valve operation during these alignment actuations demonstrates the capability of the valves to actuate against the differential pressures that occur during plant normal operation. Therefore, testing to comply with Reference 1 is not required for the plant normal operating actuations of these valves.
3.3.4.12 Turbine Exhaust Isolation Valve Valve number VI in Figure 8 functions as the turbine exhaust containment
~
. isolation valve. The active safety function of the valve is to close when
. isolation is required.
The maximum expected differential pressure occurs when the operator manually signals the HPCI system turbine exhaust isolation valve to close during a LOCA event. The maximum pressure occurs downstream of the valve.
The method of calculating the maximum expected differential pressure during valve closure is presented in Table 4 and is based on the following assumptions:
- 1. The wetwell is at the maximum LOCA pressure.
- 2. An active failure results in leakage upstream of the valve.
l 3. The operator manually signals the turbine exhaust isolation valve to Close. ,
3.3.4.13 Vacuum Breaker Line Isolation Valves Valves number VII and VIII in Figure 8 function as the vicuum breaker line containment isolation valves. The active safety action of the valves is to close to provide the required isolation.
l w
M NEDC-31322 LOC &. The maximum expected differential pressure occurs d \
\
valves. The maximum expected pressure during closing occ uring a large break Table 4 presents the method of calculating theurs upstream of the maximum expected differential pressure baeed on the following ons: assumpti 1.
A large break'LOCA, occurs.
- 2. /
RCIC starts on low reactor water level.
3.
Low reactor pressure results in shutdown system. a and isol ti on of the RCIC
_~ 4.
Valves VII and VIII are signaled to close .
3.3.4.14 Steam Admission Bypass Valve I
valve.Valve number IX in Figure 8 functions asamthe ste The valve's active safety action is to open whenadmiss,lon bypass system operation is r; quired in order to provide enough steam to the turbine t
' id10 speed prior to opening the main steam o bring it up to v31va's active safety action is also to close when em operation is no systadmission The valve 1cassr required in order to terminate steam disch arge to the turbine.
The nazimum expected pressure during opening and upstr:aa side of the valve. closing occurs on the maritua expected differential pressure o based on the f llTable 4 owing assumptions:
1.
The reactor is isolated and maintained at pressure y the reactor b
relief valves operating on their spring setpoint.
2.
The system is signaled to start and theens. valve op .
3.
The valve automatically closes once the steam fully open. f*
admission valve is
o l l
l 1
NEDC-31322 3.3.4.15 RCIC Turbine Trip and Throttle Valve i
Valve number X in Figure 8 functions as the RCIC turbine trip and throttle valve. The function and active safety action of the RCIC turbine trip and throttle valve is to trip closed when required to protect the turbine and pump. The closure of the valve, when tripped, is spring actuated. The actor operator on this valve is only used to reset the valve to the open position following a turbine trip.
The differential pressure across the RCIC turbine trip and throttle valve during opening is negligible. The basis for this is that, prior to resetting
[ the P.CIC turbine trip and throttle valve, the RCIC system steam admission valve located upstress of the trip and throttle valve would first be closed.
This action resets the RCIC system start-up logic (i.e., the ramp generator i
for the RCIC turbine). The RCIC turbine trip and throttle valve above seat
( drain upstream of the valve will vent steam that is trapped between the closed steam admission valve and the trip and throttle valve ,to the turbine exhaust line drain pot. This will reduce the differential pressure across the turbine trip and throttle valve to a negligible value prior to valve opening.
Some plants have included this valve in their ASME Section XI surveil-l
~
lance test program. It is, therefore, included in this report for the prupose of completeness.
o O
l l
=
VALVE TESTING AND TEST METHODS i 41 INTRODUCTION This section identifies the systems MOVs whose be verified in compliance with Reference .
1 operational readiness must r quired to be tested to actuate against a maxiThe systems MOVs that are n ,
I pr ::ure are identified and the associated mum expected j differential i
G;neric methods, that can be used toustification v is presented. t sycteas valves to actuate against maximumerify the capability of some of the clos described.
. expected differential pressure, are
~
42 VALVES THAT PDLFORM ACTIVE SAFETY ACTIONS t 'the valves that are required to pe f HPCS, HPCI and RCIC system a valves th tr orm an active safety action (s) are
- ti
- ns of either reactor vessel inventare required to actuate so the isolatita can be performed. ory makeup or reactor and containment Tha valves active safety action (s) ar
'ummariz d in Tables 2, 3 and 4.
e identified in Section 3 and are criga basis assumptions presented ...
in Section 3 31They were establi 03 V1.LVES TO BE TESTED c
R0fcrence 1 requires t$at valves perform that
\ ring pl:nt FSAR design basis events besafety an active t action (s) contrating their capability to open ested to the extent practical by and/or close when subjected to the
%um capected differential pressure (s) (i.e., those dete
\ hods presented in Tables 2, 3 and 4) y the
- These valves
<t hava cn active safety action as indicated invalv'es are all of the Table Br pti:3 cf those valves whose only active s 2, 3 an 4 with the o break in a stesa line. safety action is to close to 40 valves is discussed in Section 4 4The basis forreak not testing steam line b below.
The valves required to be i
i
- tested to demonstrate their capability of opening and/or closing against maximum expected differential pressure are listed below.
SYSTEM VALVES FIGURE HPCS .
1, 2, 3 and 4 1 EPCI 1, la, 2, 3, 4, 4a and 9 2 and 4
, I, VI through VIII 5 18 * * ' "' **d I O RCIC I, VI through IX 8 In addition to the valves in the table above, if HPCI and RCIC Systems' valves number II or III (Figures 5 and 8) are normally closed and must open to ensure system operation, they must also be tested to demonstrate their capability to open against the maximum . differential pressures that occurs during system initiation. However, if HPCI and RCIC valves II and III are normally open and are only required to close to isolate a break in a line, they are not required to be tested as discussed in Section 4.4 below.
4.4 VALVES NOT REQUIRED TO BE TESTED 4.4.1 Action iten e of Reference 1 states that
"... testing motor-operated valves under conditions simulating a break in the line containing the valve is not required. . .
. . . Notet This bulletin is not intended to establish a requirement for valve testing for the condition simulating a break in the line containing the valve. However, to the extent that such valve opera' tion is relied upon in the design basis, a break in the line containing the valve should be considered in the analyses prescribed in items a and b above. The resulting switch settings for pipe break conditions should be verified, NA
NEDC-31322 to the extent practical, by the same meth d other settings pressure. (if any) that are not tested at tho s that would be used to e maximum differential Each valve shall be stroke ~ tested, to the ext that the settings defined in item b above enth practical, to verify even if testing with differential pressure canave been properly implemented not be performed."
Based on the above Reference 1 statement cetion is to close to isolate a break in a line, valves whose only active safety to verify their capability of closing agai , are not required to be tested
.-differential pressure associated with break conditions.nst the maxim This exemption is c11 owed since it is not practical to perform ccaditions. a tests th t R3ference 1 requirements.However, the valves are required to meet a of the other Based on the above position, HPCI and RCIC S III, IV, and V (in Figures 5 and 8), whose ystems' valves number II, c1:se to isolate a line break, are not requiredonly active safety action is to capability of closing against the maximum expected difto be tested to veri ccrociated with a break.* ferential pressure 4.4.2 Valves that a) are not required to perform during the design basis events listed in Tabl an active safety action pr:bability of changing pcsition during these eve te 1 and b) have an extremel differential pressure test requirements of n s are exempt from the v:1ves to CST). reference 1 (e.g., test return
'Aha systems' valves that meet the above S ction 3 and Tables 2, 3, and 4, are HPCS S criteria, as determined from hPC1 System valves 5, 6, 7 and 8 (Figure 2 and 4)ystemvalves5,6and7 and 8 (Figures 6, 7). .
and RCIC System valves 5, 6 i
CTheco valves may vary betwee n specific plants.
~
NEDC-31322 4.5 TESTING METHODS 4.5.1 General This section discusses methods of testing some of the systems' safety-related MOVs to verify their ability to operate against maximum expected differential pressures '(i.e., demonstrate operational readiness). The systema
- valves to which these methods are potentially applicable are also
,. identified.
4.5.2 Type Testina 4
6 _- 4.5.2.1 Test Methodii
. Reference 1 is related to the " common mode" failure of selected It MOV would follow that " common mode" testing, for valves meeting "saae type" criteria, would be a valid means of assuring valve operational readiness on a
' plant-specific basis where valve switches are set by qualified personnel f ollowing the same procedures and techniques.
" Type Testing" is used extensively in the industry to verify the capability of similar equipment to function properly when exposed to the same limiting design basis conditions.
Testing of one " type" of valve to open or close against a differential pressure that is equal to or greater than the maximum expected operating differential pressures of other valves of the "saae type" can be performed to demonstrate the operational readiness of the other valves of the same type. For valves (including actuators) to be considered the "saae type", they must (a) be from the same manufacturer, (b) be the same model and/or type duaber, (c) have the same limit and same or higher torque switch settings as the valve actually tested (d) have the same type of spring pack (e) be installed in the same orientation, and (f) be provided with electrical power from comparable power buses and switchgear. Additionally, the location of the maximum pressure (i.e., upstream or downstreaa) must be the same.
I
\
4.5.2.2 Methods Applicability \
1 i
The method of type testing described in Section 4 5 2
. . 1 above is cpplicable to all systems' valves on identical units of multi permits the results of tests performed on one unit t unit BWRs. This id:stical valves on the twin unit. o be applied to the sy tem or systems that are the same type may be demon tThe oper ,
pr:sented in Section 4.5.2.1 above. s rated by the methods 4.S.3 Testing by System Operation p5.3.1 Test Methods System operations, such as system flow testing cning and/or closing against a maximum differential pressur, that results in e that is equal o er greater than the maximum expected differential pres it 10 required to operate to perform an active sure that occurs when to d:constrate the operational readiness safety action can be performed of the valve.
When a system #operational test simulates the sam cetuation sequences that occur during the design basis evente conditions an that is po:tulated to result in the maximum expected differe n a pressure ti l 2, 3 cud 4, the test demonstrates the operational r in Tables thotsh the differential pressures that occur d eadiness of the valve even the cciculated values determined from thees.tabluring the test may be less than
, pressures that result during these testa may beuesless than the valThe actu determined iros Tables 2, 3 and 4 due to the conse ,
rvative assumptions ccsociated with the tables. For example, the HPC1 or RCIC t urbine may not reich its maximum normal speed prior to opening of the I valve number 2 (Figures 4 and 6) as assumed in the dev lminimum flow bypass ,
$1fforcatial pressures shown on the tables. e opment of the Bf rential pressure that results during the test reflectsHowever, the spee the system actual oting characteristics and is the same as thatewhich uring a design basis event. expected would b '
Therefore, the system operational test would
- emonstrate the operational readiness of the valve to operate agai nst @ n
' ~
NEDC-31322 maximum expected differential pressure that would occur during the design basis event.
4.5.3.2 Methods Applicability 4.5.3.2.1 BPCS System, The system injection valve and minimum flow bypass isolation valve (valves number 1 and 2 in Figure 1) can be demonstrated to be capable of Operating against their maximum expected differential pressure by performing
~
reactor injection test with suction from the CST when the plant is in a cold
~
shut-down condition.
_ .s 4.5.3.2.2 hPCI and RCIC System
( HPCI and RCIC systems' minimum flow bypass isolation valve number 2 (Figures 2, 4 and 6) and the RCIC turbine auxiliary cooling water valve number 9 (Figure 6) can be demonstrated to be capable of operating against their maximum expected differential pressure by system flow testing to the CST.
i Valves number II and III-(Figures 5 and 8), that are normally closed and must 1
open during system initiation can also be demonstrated to be operable by i system flow testing.
i i
I 1
d
,- +, , , - , - , , - , - --
,,.__,,,.,,.,n,__--,,,,_-__,,--,,---,,--,,-.e-,,_._,-n,,. - -
__,n,,.,,,w._,. ,-.-.,n--,-,, ___.n-- ,. -,--- -. - , , _ , -
I
. - - _ _ _ t NEDC-31322
- 5. REFERENCES 1.
United States Nuclear Regulatory Commissionection Office and of Insp Enforcement, IE Bulletin No. 85-03, Titled " Motor-operated a ve Common Vl Mode dated November Failures During 15, 1985. Plant Transient Due to Improper e t ngs,"
Switch S t i 2.
Monticello Number 50-263.Nuclear Generating Plant Final Safety Analysi s Report, Docket 3.
,. Docket Number 50-341.Enrico Fermi Atomic Power Plant, Unit 2, Final Safe nalysis Report, 4.
Docket Numbers 50-373 and 50-374.LaSalle County Station, Unit s Report,
.5.
Docket Numbers 50-416 and 50-417. Grand nalysis GulfReport, Nuclear Station e
1 1
j .e 1 7 NEDC-31322 l l31' -
i N ,
ff;; Table 1 l- PLANT DESIGN BASIS EVENTS THAT RESULT IN HPCS, HPC1 AND RCIC SYSTEMS OPERATION t
y Anticipated (Expected) Operational Transients f ..
h, Systems q,, Expected y
g ,
to Applicable BWR
> Operate Product Line h5 NSOA* HPCS
{ Event or L'. -
.No. Event Description HPCI RCIC BWR6 BWR5 BWR4 BWR3 gj 8 Loss of Plant Instrument Service Air X X X
., Systems
- s *
- f. *
,,, 9 Inadvertent Startup of HPCS or HPC1 X X X X
!.E -
Pump
,l 12 Recirculation Loop Flow Control X X X X X l ., - Failure with Lecreasing Flow V
13 Recirculation Loop Pump Trip X X X X X
, - With One Pump J: - With Two Pumps
$ 14 Inadvertent MSIV Closure X X X X X X y, - With One Valve y' - With Four Valves
?.~
N 15 Inadvertent Operation of One X X X X X Safety / Relief Valve 8
- Opening / Closing
- Stuck Open i
16 RhRS - Shutdown Cooling Failure X X X Loss of Cooling
, 20 Loss of All Feedwater Flow X X X X X X
) 22 Feedwater Controller Failure X X X X X X ,
, Maximus Demand - Low Power V
. 23 Pressure Control Failure X X X X X X r - Open *
- i i 24 Pressure Control Failure X X X X X X
- Closed I
- Nuclear Safety Operational Analysis 53
, NEDC-31322 Table 1 PLANT DESIGN BASIS EVENTS THAT RESULT IN HPCS, HPCI AND RCIC SYSTEMS OPERATION (Continued)
Anticipated (Expected) Operational Transients (Continued)
Systems Expected to Applicable BWR Operate Product Line
.. hSOA* HPCS Event or No. Event Description HPCI RCIC BWR6 BWR5 BER4 BWR3
. 25 Main Turbine Trip With Bypass X X X X X System Operational 26 Loss of Main condenser Vacuum X X X X X X
{
27 Main Generator Trip (Load X X X X X Rejection) With Bypass Systea Operational 28 Loss of Plant Normal On-Site AC X X X X X X POWER - Auxiliary Transformer Failure 29 Loss of Plant Normal Off-Site AC X X X X X X
, POWER - Grid Connection Failure Abnormal (Unexpected) Operational Transients 30 Main Generator Trip (Load X X X X Rejection) With Bypass System failure
- 31 Main Turbine Trip With Bypass X X X X X Systen Failure 33 Recirculation Loop Pump Seizure X X X X X 34 Recirculation Loop Pump Shaft X X X . X X Failure 1
)
NEDC-31322 Table 1 PLANT DESIGN BASIS EVENTS REQUIRING HPCS
, HPCI AND RCIC OPERATION (Continued)
- Design Basis (Postulated) Accidents
- Systems Erpected to NSOA Operate Applicable BWR
~' Event _
Product Line HPCS __
No.
Event Description or 35 Control Rod Drop Accident HPCI RCIC BWR6 BWR$ BWR4 BWR3 X X X c -. 3 7 X X X Loss-of-Coolant Accident Result- X ing from Spectrum of Postulated X X X X Piping Breaks Within the RPCB
.Insiae Containment 38 Small, Large, Steam and Liquid Piping Breaks Outside Containment X X X X X
- 39
- instrument Containment Line Break Outside X X X X 40 Feedwater Containment Line Break Outside X X X X 41 Gaseous Radwaste System Leak or Failure X X X X 42 Augmented Offgas Treatment System Failure X X X X X 46 Special (Plant Capability) Events Reactor Shutdown from Anticipated X X Transient Without SCRAM (ATWS) X X
47 -
Reactor Control Shutdown from Outside X Room X X X A4 Reactor Rods Shutdown Without Control X X X
e , ,
i Tabla 2' 8 i
! HPCS SYSTEM VALVES 1
l Maximum Expected Active Safety Method to Determine the Action Maximum Expected Differential Pressure
- Pressure Occurs j Valve j Number Function Open Close Opening Closing Upstream Downstream 1 Injection Yes Yes AP=PSOH - PEL AP = PSOH - PEL X l
, . Valve +PVEL.
j 2 Minimus Flow Yes Yes AP = PS3H + PEIjg AP = PMp + PEIJi X
- Bypass Isola- +PVEL 4 tion Valve ,
i '
j 3 CST Suction No Yes (a)* AP = PELD + Py X j Valve +PVEL f 4 Suppression Yes Yes AP = Pgy - PELS AP = PIDC + Ptog X X se j Pool Suction (closing) (opening) E i Isolation i
} Valve $
! U l 5 CST Test No No (a) (o) *
(a) (o) i Return Valve I
6 CST Test No No (a) (o) (a) (o)
Return Valve j 7 Suppression No No (a) (o) '
(a) (o)
- Pool Test
] Return Jeo-lation Valve .
l I
l *To assist in better understanding the methods developed to calculate the maximum expected differential i prsssures, several aids have been included. Table 5 provides a definition of terms used in the equations j licted in Tables 2, 3 an 4 and also includes the notes identified on these tables as well. Figure 9
{ (located at the end of Table 5) provides a visual illustration of the equation feras to further assist in
! understanding their relationship with each other. Finally, Appendix B has been provided to give more
, detail to the development of the Pygt term.
l l
i Tcbla 3 '
i HPCI SYSYEM VALVES - FLUID i
Active Safety VJIv2 Action Method to Determine the Maximum Expected Number _ Function Maximum Expected Differential Pressure Om Close Opening Pressure Occurs 1 Injection Closing _ Upstream Yes (b) _ Downstream Valve AP = PS
., - Pygo OH + PKF AP " PS KF I PEL(1)
- PI so ON P +P EL + PYEL (1) lo Injection AP " PRSS + PEL (m)
Yes Yes X Valve AP = PSOH + Pgp
-PIso - PEL(1) AP " PSON + PKF I AP = PRSS + PEL(m)
-PIso - PEL + PVE 2 AP = PRSS + PEL(s)L(1)
Minimum Flow Yes Yes X' j bypass Isola- AP = PSOH + PELM ,
tion Valve AP = Pyp + PELM t
+P VEL I E 3 7 CST Suction No Yes U l Valve (a) $
AP = PELD + Py X u 4 Suppression ' +PVEL X
- cad Yes Yes (Closing) (0pening) 4a Pool Suction AP = PRV - PELS AP = PLOC + Prog Isolation (e) X Valve j5 CST Test No No
! Return Valve (a) (o) i it (a) (0) !
- 6 CST Test No No i
Return Valve (a) (o) i (a) (o) i i
1 l
4 ld i 1 1
~
~
Table 3 HPC1 SYSTEM VALVES - FLUID (Continued)
Maximum Expected Active Safety Method to Determine the Action Maximum Espected Differential Pressure Pressure Occurs Number Function Open Close Opening Closing Upstress Downstream 7 Suppression No No (a) (o) (a) (o)
Pool Isola-tion and Test Bypass '
i Flush Valve )
8 Injection No No (a) (o) (a) (o) w Valve Test E Valve y e-9 Turbine -
Yes (f) AP(g) = Pc, AP(h) = Pe + Pi gg X O Accessories AP(h) = Pe+ +PVEI, Cooling Water Pygg Valve 10 Valves number 10 and 11 are valves unique to only one BlNt0C participating utility. Because of the cod generic nature of this report, it was determined that these valves would be addressed by that 11 utili,ty at the time of their plant-specific response to Reference 1.
l
i i ,
Table 3 '
i HPCI SYSTEM VALVES - STEAM Active Safety Valve Action Method to Determine the Marlaus Expected I gumber Maximum Expected Differential Pressure Function Om Close Opening Pressure Occurs 1 Steam _
Closing Upstream Yes No _ Downstream AP = Pgss Adalssion (a)
Valve X i 11 Steam Line
111 Steau Line (c) Yes
' Isolation (d) AP = Pgss AP = Pgss j Valve (d) AP = 0 X n I
IV Bypass Valves No Yes N
i for Steam Line (a) n u
Isolation AP = PkSS X Valve i
=V Bypass Valve No Yes for Steam (a)
AP = Pgss Line Isolation X ,
Valve
>V1 Turbine No i
Exhaust Yes (a) I i .
AP = PLOC Isolation ' N/A N/A Valve
- I I
- i
(
l 1
l
- ~
i Table 3 HPCI SYSTEM VALVES - STEAM (Continued)
Maximum Expected Active Safety Method to Determine the '"
Action Maximum Expected Differential Pressure Pressure Occurs V:1ve Upstream Downstream Function 'Open Close Opening Closing l Number VII Vacuum Breaker No Yes (a) AP = PC+PATM I Line Isolation Valve i VIII Vacuum Breaker No Yes (a) AP = PC+PATM I l Line Isolation
) Valve h
?
u u
M 4
i l
}
I
- l
)
4 i
1 e
D Tabla 4 9 RCIC SYSTEM VALVES - PLUID Active Safety Action Method to Determine the Maximum Expected Number Function Maximum Expected Differential Pressure h Close _
Opening Pressure Occurs
', 1 Injection Closing _ Upstream Yes (b) Downstream Valve " AP = PS
- - P iso OHPEL(1)
+ Pgy AP = PS s - Pygo ONP + PKF I
+ Py 1) i 2 AP = PRSS + PEL(m) AP = PR gg +EI, Pyy,(a i Minimum Flow Yes Yes X Bypass Isola- AP = PSON + PEW tion Valve +PKF AP = Pgp + PE m X
+P VE1, j 3
' CST Suction No Yes Valve (s) ,
2 AP=PELD + Py X O:
n 4 Suppression +PVEL 6 cud Yes Yes Pool Suction AP = PRV - PELS AP = P IDC + Prog U
43 Isolation X U Valve (e) X (closing) (opening) 5 CST Test No No (a) (o)
Return Valve (a) (o) 6 CST Test No No Return Valve (a) (o)
(a) (o) 7 Barometric No Yes Condenser . (a)
Discharge AP = PIDC X
Isolation Valve l
t
f *
, t ,
i . .
Table 4 RCIC SYSTEM VALVES - PLUID (Continued)
I Method to Determine 'the Maximum Expected Active Safety i Action Maximum Expected Differential Pressure Pressure Occurs V 1v2 ..
Number Function , Open Close Opening Closing Upstream Downstream 8 Injection No No (a) (o) (a) (o) 4 Valve Test Valve 9 Turbine Yes (f) +1+ AP(h) = PMC + PLOM X AP(k) " PSOH Accessory AP(h) = PSON + PKF +PVEL Cooling Water +PELC m; Valve aP(k) = Pggy +j+ AP(h) " PLOC + PLOM B AP(h) = Psol + PKF +PVEL i
+PELC h 0
J e
O 1
k l
l i
Tcbis 4 ,
RCIC SYSTEM VALVES - STEAM Active Safety Action Method to Determine the Maximum Expected Number Maximum Expected Differential Pressure 1
_ Func_ tion Om close Pressure Occura Opening Closing 1 Steam _ Upstream
+ Yes Yes Downstream Admiss1Bn AP = PRSS Valve 8 AP = PRSS X 11 1
Steam Line (c) Yes Isolation (d) AP = Pq;s
, Valve (d) AP = 0 AP = Pgss 'X t
111 Steam Line (c) Yes Isolation (d) AP = PRSS AP = PRSS Valve (d) AP = 0 X E 9
IV Bypass Valves $
' for Steam Line No Yes (a) g AP = Pgss u Isolation X Valve .
V Bypass Valve No
! Yes (a) for Steam .
AP = PRSS *i l
Line Isolation Valve
- V1 Turbine No
{ Exhaust. Yes (a) 1 Isolation ' AP=PLOC N/A
! N/A Valve .
1 i
I i
i I
8, . .
Table 4 RCIC SYSTEM VALVES - STEAM (Cont'inued)
Maximum Expected Active Safety Method to Determine the Action .,
Maximum Expected Differential Pressure Pressure Occurs hiva Upstream Downstream Number Function dpen Close Opening Closing VII Vacuum Breaker No Yes (a) AP = PC+PATM I Line Isolation Valve Yes (a) AP=PC+ PATH X 0111 Vacuum Breaker No Line Isolation Valve ,
5 IX Steam Yes Yes AP=PRSS AP = 0 X 9 u
Admission Bypass Valve h
n X Trip and No Yes (a) (n) N/A N/A Throttle Valve l
I I
e I
i
Table 5 DEFINITION OF TERMS AND NOTES USED,IN ANDTABLES 4 2, 3 I
DEFINITION OF TERMS
- 1 p a yp 5 w -- - ,a g ~_a_ u.
AP Vtava maximum expected operating differential pressure .
P MF -
Differential pressure develope.d by the system mainatpump a flow (s) rate equal to the required minimum bypass flow rate.
For steam turhima driven pumps assuma ==* ="=_ nozzal.turhine a W .
P
_ S0h Differential pressure developed by system main pump (s) at rate. zero flow speed. For steam turbine driven pumps, assume maximum normal turbi ne Pg Minimum hydrostatic pressure difference between suction e and sourc discharge due to elevation (assumes discharge elevation than suction). er is high P
- L W r**ct r pressure at which steam supply lines automaticall isolate. y P
The maximum discharge pressure of the pump that maintains the discharge line full by taking suction upstream of the acheck e in v lv the CST suction line and discharging downstream of the ch eck valve and upstream of the auction of the system pump.
This applies only to systems that have a line fill system as described .
P g
Maximum hydrostatic pressure difference between suction source and discharge due to elevation.
.VN Reactor pressure during normal power operation.
NEDC-31322 Table 5 DEFINITION OF TERMS AND NOTES USED IN TABLES 2, 3, AND 4 (Continued)
DEFINITION OF TERMS (Continued)
Pggg Reactor pressure corresponding to the spring setpoint of the reactor safety / relief valve with the lowest nominal spring set point. ,
Pg Hydrostatic pressure difference between CST and suppression pool assuming the CST to be full and the suppression pool water level at its maximum allowable normal level.
Py Velocity head in the suppression pool suction lina at the location where the CST line connects to it.
Pgy System suction relief valve actuation set pressure.
P g3 Hydrostatic pressure difference between the minimum suppression pool water level and the location of the relief valve on the pump suction line.
P LOCA watwell pressure when the system is isolated.
MC P
gg Hydrostatic pressure upstream of the valve due to maximum LOCA suppression pool water level.
C MaximumLOCAvetwellpressurewhensystemisrequiredtooperate!
P EC Hydrostatic pressure difference between CST and location of valve when the CST is full.
P 3gy RCIC pump discharge pressure at zero flow and a turbine speed of 2000 rps.
~_ _ __ _ - . :__ _ __ _.
s NEDC-31322 Table 5 DEFINITION OF TERMS AND NOTES USED IN TABLES e 2, 3, AND 4 (
DEFINITION OF TERMS (Continued)
P g73 Atmospheric pressure.
P g
Differential pressure associated with valve closure due to fluid velocity changes (i.e., water hammer type of pressure increase)
'inside the pipe as defined in Appendix B.
NOTES (c)
( The method to calculate the maximum expected differential e is not pressur presented or closing) because there is no active safety action (e.g., valve ng openi j (b)
Valve closure is considered to have an active safety action valve if the is a reactor or containment isolation valve.
(c)
An active safety action is to open if this valve is normally sed. clo (d) Differential pressure is equal to P open before this valve. g3 if the stesa admission valve can 4 The differential pressure is approximately zero if the steam admission valve is delayed from opening until s valve thi ,
comes off its seat.
(c)
The potential exists for a higher differential pressura toueoccur to d
the thermal expansion of the water between valves 4a. and 4
' Utilities should evaluate the potential pressure associated with nsion thermal expa t and implement corrective action as required to prevente unacceptabl pressurization.
Corrective action may involve changing the position of valve 4a to being normally open.
- l - - -
NEDC-31322 Table 5 DEFINITION OF TERMS AND NOTES USED IN TABLES 2, 3, AND 4 (Continued)
~
N0TES (Continued)
(f) Closure of the valve is an active safety action on plants with barometric condenser gland seal systems.
(g) Applies to plants with a gland seal system.
. (h) Applies to plants with a barometric condenser gland seal system.
I (1) Applies to plants without bypass start.
(j) Applies to plants with bypass start.
(k) Applicable to RCIC System whose turbines have gland seal air compressors.
(1) Pump operating during opening or closing of' valve.
(a) Pump not operating when the valve starts to open or when the valve is nearly fully closed.
(n) Closure is by spring actuation. Therefore, the method of calculating the diffe:ential pressure is not presented.
(o) The maximum expected differential pressure across valves during testing
. varies depending on plant test procedures. Because of the generic nature of this report, it was determined that these differential, pressures should be provided by the individual participating utilities at the time of their plant-specific response to Reference 1.
o NEDC-31322 l
l 1
TO REACTOR - ~
LJ VESSEL F '
CONDENSATE STORAGE TANK (CST)
/ N
?
pm/
7 L'
8 8 VN w2 w2 V M V 3 k2 w_ _
r_ cf.' "2 ii yp - e SUPPRESSION POOL A
I 5 h UP STREAM
k
! I DOWN STREAM
- FLOW g
= &2 DIRECTION 7 7 L NORMALLYCLOSED VALVE
> I 2
M 2 NORMALLY OPEN VALVE l
s l
I I
l Figure 1.
i HPCS System Motor-Operated Valves t
1
__ _ _ _ - _ - - - - , _ _ _ _ , _ _ - , . - ----- - - - - - - - ' ~ - ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
.o NEDC-31322 e s CONDENSAGE 2 STORAGE TANK (CST)
I IMOV6 -
J k i
74 ( E (PROM RCIC MOV 7 j g MOVS TO CORE _ & 2 SPRAY UNE ~ r' MOVla 2
f_
uNE EDWATER c II uoy i X Z (j p May a ,,,,
,,,,7,, l PUMP PUMP
> ~ wa r,
y MOV 2 SEE PiGURE 3 A Y .
> =)
SEE PIGURE 3 N
MOV 3 If If SuPPRES$10N POOL MOV 4 MOV 4e UPSTREAM DOWNSTREAM .
[ PLOW DIRECTION L- 74 r NORMAUY CLOSED VALVE X r NORMAuy OPEN VALVE l
i Figure 2. HPCI System Pump Suction and Discharge Motor-Operated Valve (Does not include Dresden 2 and 3 and Quad Cities 1 and 2)
. a NEDC-31322 i
GLAND SEAL AIR CONDENSER SEE Y PlGURE2 A N/
- Lust 3 , . OIL COOLER j i jg SEE FIGURE 2
~ ,
GLAND SEAL CONDENSER
- m p
CONDENSATE PUMP sAROMETRIC CONDENSER SEE Y '
FIGURE 2 A N/ Luse i e Oit COOLER
- i SEE FIGURE 2 sAROMETRIC CONDENSER 4
1 i
-i U
CONDENSATE PUMP 1
Figure 3.
HPCI System Gland Seal System Component / Piping
e %
)
CONOENSATE l STORAGE TANK (CST) _
lf MOV6 FROM s 7 RCIC '
~
If MOV5 HPCI MAIN HPCI db pyur BOOSTER PUMP
~
~
TO =V ,
MOVS
( yl FE EDWATER uNE L2 77 Il LUBE p COOLING MgV 2 OIL WATER COOLER puup
_ s
~
%. 3r l
i t GLAND SEAL jk CONDENSER MOV 11 q ,
1f I E' CONDENSATE l
I PUMP
, MOV 10 2
SUPPRESSION d i MOV3 POOL '
L2 LJ V3 VM e ll MOv4 MOV4e b
Figure 4. HPCI System Pump Suction and Discharge Motor-Operated Valves on Dresden 2 and 3 and Quad Cities 1 and 2 T
l l
_ . _ _ _ l NEDC-31322 i
MOVIV MOV y i Ls r, '\/ g2 '
l r m
- FROM MAIN g STEAM UNE s M M i I
i MOV11 NOV lil '
4' i
- %e I
i wA
, g' MOVI I HPCI t* i TuRelNE i 1,
MOV vill --
e i 1
.I
' I i
MOV vis
~
Y l-MOV VI ,
i.
SUPPRESSION 1 POOL - i..
b l
1 l
Figure 5. !
HPCI System Steam Lines Notor-Operated Valves
0 NEDC-31322 s
- CONDENSATE g g STOR AGE TANK (CST)
. / /
SEE FIGURE 7 O O SEE o A FIGURE 7 -
/\ /\
1 r i
'MOVS d b
~~
TO INJECTION POINT h(
goyg yoyg
'g P RCIC MOV3 l l
~
w, PUM)P
~
(C ( jL
_ MOVF h(
MOV2 t 8 (
w- _- _-_
SUPPRESSION POOL a
kJ kJ VM VM MOV 4 MOV4e k
BAROMETRIC CONDENSER GLAND SEAL AIR COMPRESSOR LU,,
Olt l l OIL COOLER jlJLjL L2 V,
MOV9 i
. n [ LUBE OLER g; MOV9 VACUUM
/\ /\ PUMP A (E ( A (C ( '
O A l C <
UPSTREAM DOWNSTREAM F LOW OIRECTION
/
N h I r NORMALLY CLOSED VALVE (E (
g 1
i=
M NORMALLY OPEN VALVE CONDENSATE PUMP l l
1 Figure 6. RCIC System Pump Suction and Discharge Line Motor-Operated Valves )
l
I NEDC-31322 EST TEST RETURN UNE SHARED WITH HPCI
~
FROM HPCI X* --
/\
SEE FIGURE 6 D i A oR SEPARATE CST TEST RETURN UNE
>4 M V NO. 8 SEE FIGURE 6
/\
o A
SEE FIGURE 8 i
~
~
Figure 7.
RCIC System Pump CST Test Return Motor-Operated Valve
- - - - - - - - - - - - - . - n, -,--,,,--,,--,-----,,--,,-------,,,------,---,,w- . - - - - , - , , , , , ~ - , - - . - - - - ~ - - -
-Ne
~' '
FROM MAIN s STEAM UNE 5 w2 w2
. r, r,
, VM i.
N RCIC TUR81NE
M Ov vi M
U SUPPRESSION POOL Figure 8. RCIC System Steam Lines Motor-Operated Valves
NEDC-31322 REACTOR PRESSURE PASS,PRVN,Pago
J----------------
, PEL
. ?
%PATM k s a CST l
7 i U >
......... .. . N I d d h N M'AXIM'UM
~~'
I WETWELL PRESSURE WATER LEVEL y PiLC AOC, PC MINIMUM
% PEW w 2p-
' ' -~~I. WATER LEVEL _~~~
- 9'
[ F l MAIN PUMP (S) i m.
. _ _ . _ _ , , '_- ~p DIFFERENTIAL
% _ MAXIMUM . PRESSURE .
l ALLOWA8LE i PSOH, Pgp P30g l WATER LEVEL LOM y U N i
%^g-^ ^g^ ,g ^ - ^ pp '
- ~~
VELOCITY HEAD Py ALLOWA8LE WATER LEVEL g j[p,y jr D
h d jf -
4 4e t
WETWELL ,
! j l i Fi PUMP i
DIFFERENTIAL '
PRESSURE Pgp l ,
l 1 t
Figure 9.
Illustration for Definition of Terms in Tables 2, 3 and 4
,.,---rr eM'"* _ , _ _ _ . . , _ _ _ _ _ . - - - - -- --
NEDC-31322 APPENDIX A PARTICIPATING UTILITIES BR Owners' Group, IE Bulletin 85-03 Committee This report applies to the following plants, whose owners participated in the report's development:
BWR Owner Plant b:cton Edison company I Pilgria Crrelina Power & Light Company l Brunswick 1 & 2 Cicveland Electric 111uminating Company !
Perry 1 & 2
-Commonwealth Edison Company i Dresden 1, 2 & 3 '
Quad Cities 1 & 2
{
La Salle 1 & 2 ,
Jetroit Edison Company l Permi 2 G:crgia Power Company .l.
Hatch 1 & 2 Gulf States Utilities Company River Band 1 Icwa Electric Light & Power Company ;
Duana ' Arnold Long Island Lighting company l Shoreham Mis::issippi Power & Light Company l Grand Gulf 1 & 2 N0braska Public Power bistrict Cooper !
N:w York Power Authority PitzPatrick Nirgara Mohawk Power Corporation ;
Nine Mile Point 1 & 2 '!
Nsrthern States Power Company i
Monticello '
Philtdelphia Electric Company Peach Botton 2 & 3 '
Limerick 1 & '2 i
Tcanessee Valley' Authority Browns Ferry 1, 2 & 3 ,
Vcrm:nt Yankee Nuclear Power Corporation Vermont Yankee, hrhington Public Power Supply System Hanford 2 -
NEDC-31322 APPENDIX B $
VALVE OPENING / CLOSING DIFFERENTIAL PRESSURE DUE TO STEAM / FLUID ACGTM ATION/DECRTHATION ,
i The differential pressure that occurs across valves during valve opening or closing due to fluid or steam velocity changes is presented herein.
- 1. Valve Opening 5
~
The differential pressure across a valve during opening is decreased by i valocity increases in the fluid or steam. Additionally, the valve maximum :
cetuator load occurs before valves are significantly open. Therefore, these i j
_-effects are not included in the determination of the valve maximum expected '
) cpening differential pressure. ,
I
- 2. Closure of Steam Valves ,
I
> t The only steam line valves.that are potentially subject to significant l
differential pressure increases during closure due to velocity changes are valves II and III in Figures 5 and 8. The maximum potential steam velocity in these valves occurs following a postulated guillotine break in the piping dcwnstream of the valves. The maximum expected pressure increase during clecura due to velocity effects has been determined to be less than 30 psi. !
i The reactor pressure decrease during valve closure associated with such a l
large break would be greater than 30 psi. Therefore, the. effects of velocity i I i l changes on steam line valves' maximum expected closure differential pressure cro not significant.
- 3. Closina of Fluid Flow Valves 1
i The maximum expected differential pressure across a valve is' increased dua to deceleration of the fluid both upstrema and downstream of the valve.
Ihe diffsrential pressure due to the upstream and downstrema decelerations are '
datormined sepasately and then they are combined to obtain the total maximum czpected differential pressure.
d NEDC-31322 3.1 Upstream The maximum expected differential pressure due to deceleration of the upstream fluid is conservatively determined by the following equation:
PC AVy -
1 1443 3*1
,. where:
=
P y pressure (psi)
~
p =
density (1b/ft )
C. =
speed of sound in the fluid (ft/sec)
=
3 gravitational constant (ft/sec)
AV =
y maximum change in fluid velocity upstream of the valve (ft/sec) over a time period equivalent to the time it takes a pressure wave to travel up the pipe to the source of supply and back to the valve. This time period is equal to 2 Ly/C where Ly = the length of pipe upstream of the i
valve to the source of flow as illustrated in Figure B-2.
The following two steps are required to determine AV
- l 1)
Determine system flow velocity in the pipe as a function of time as the valve is closing.
2)
Determine the maximus AV y over a time period of 2 L /C as y
illustrated in Figure B-1 below.
6
- d s
,+ i.
a t
VELOCITY AV I IN THE OR 2Lg/C y
on
. 2L11C = =
TIME
- I Figure B-1.
System Fluid Velocity vs Time '
.i 3.2 Downstream The maximum expected differential pressure due to deceleration of the downstream fluid is conservatively determined by the following equation:
P = -
2 144g B.2 !
where:
i AV =
2 i maximum change in fluid velocity downstread of the valve I (f t/sec) over a time period equivalent to the time it takes '
a pressure wave to travel down the pipe to the system discharge location and back to the val $te.
This time priod is equal to 2 L /C where L 2 2 = the length of pipe downstream of the valve to the system discharge location as illustrated in Figure B-2.
The following steps are required to determine AV 2 and P28 l 1) Determine AV ,
2 over a tia* Period of 2 L2 /C as illustrated in Figure B-1 using the system flow velocity vs time from 3.1 above, e
i
e a af s
/ %
CST 3 !
}
L2 --^
}f gggg *** -L-1
"' 1 VE3Sk6 s I e
- PUMP MAIN
- 2 DISCHARGE X t UNE L2 Le i
SUPPRESS:ON POOL
/ N
, / PUMPSUCTION 4
W UNE OST ,
FROM SUPPRESSION r POOL WL*C 2 , L- 1 r,j l
l
)
I. '
BAROMETRIC !
CONDENSER
{
PUMP MAIN 8 g DISCHARGE UNE i
c l
X !
i lc L2
- L-t 1
.) '
I Figure B-2.
Ly /L2 Distance Illustration !
_. _. . _ . - - - - -- -- B-4_ . _ . . . - - - - - - - - - - - - - - - ' - -
o-j'.
- 2) Determine the absolute pressure downstream of the valve by subtracting P2 from the steady state pressure that would exist -
downstream of the valve when the valve is fully closed. If this pressure is less than the vapor pressure of the fluid in the line, set P 2 = P,y, - Py,p B.3 wheres P =
elo steady arate pressure downstream of the valve when the :
I valve is fully closed (psia). l I
Py ,p = vapor pressure of the fluid in the line (psia).
_~ i If P -P 2 elo is greater than Py ,p, set P2 equal t the value determined from equation B.2 above.
3.3 The total amrimum expected differential pressure due to velocity changes is the sum of Pyand P , hence:
2 P
=Py+P2 3*4 where:
1 Py ,y = pressure due to deceleration of fluid in the line.
3.4 For a typical HPCS minimum flow bypass isolation valve where L l
I
\
l L
y = 50 f t, '
2 = 20 ft, and V = 30 ft/sec, Py ,y 350 pai. This is approximately 20% of 8 3
the valve maximum expos:ted differential pressure during closing. Therefore, tha differential pressure across system fluid flow valves during closing due ,
to velocity changes has been included as appropriate in the maximum expected i
' differential pressure determination methods presented in Tables 2, 3 and 4. '
i 8
B-5/B-