ML20031D310
| ML20031D310 | |
| Person / Time | |
|---|---|
| Site: | Haddam Neck File:Connecticut Yankee Atomic Power Co icon.png |
| Issue date: | 02/28/1975 |
| From: | CONNECTICUT YANKEE ATOMIC POWER CO. |
| To: | |
| Shared Package | |
| ML20031D303 | List: |
| References | |
| NUDOCS 8110130232 | |
| Download: ML20031D310 (34) | |
Text
,
. = _ _. _. _ _
4 2
4 4-l 5
I, -
)
i.
t 4
i 4
1 1
1 l
i SPECIAL REPORT i
l I
J EFFECTS OF A HIGH ENERGY PIPING SYSTEM BREAK OUTSIDE OF CONTAINMENT I
T I
CONNECTICUI YANKEE
\\
k i
3 i
t T
3 l
i 1
1 i
February, 1975 8110130232 811002 PDR ADOCK 05000223 P
PDR 1
l
TABLE OF CONTENTS Page I.
Introduction 1
II.
Criteria 1
III. High Energy Systems 3
IV.
Plant Shutdown Methods 6
V.
Effects of High Energy System Ruptures 12 A.
Pipe Whip, Jet Impingement, Environmental 12 B.
Compartmental Pressurization 15 C.
Flooding 18 VI.
Original Design Criteria 19 VII. Conclusions 21
(
1 l
l
Page 1 I.
INTRODUCTION Criterion No. 4 of the Atomic Energy Commission's General Design Criteria listed in Appendix A of 10 CFR Part 50, in summary, requires that a nuclear plant be designed such that the reactor can be shut down and maintained in a safe shutdown condition in the event of a postulated rupture, outside primary containment, of a piping system containing high energy fluid, including the double-ended rupture of the largest pipe in the main steam and feedwater systems.
A detailed study of the effects of a posts. lated break in a high energy piping system, on other systems, structures, cables and components necessary to place the plant in a safe shutdown condition has been completed. The study included:
A.
Identification of those systems in the plant which meet either the pressure or temperature requirements or both, thereby qualifying them as high or moderate energy fluid systems and subjecting them to further analysis.
B.
A discussion of three (3) independent methods of placing the plant in a cold shutdown condition including the systems and components required to do so.
C.
A discussion of the effects of a postulated piping reflure and its effect on the ability to place the plcnt in a cold shutdown condition.
D.
A conclusion of the effects of pipe rupture including changes to existing equipment which will mitigate the consequences of a postulated pipe rupture.
II.
CRITERIA The following criteria and assumptions, taken from the AEC's " General Inforration Required for Consideration of the Effects of a Piping System Break Outside Containment," have been used in the analysis.
Selection of break locations is based upon Branch Technical Position - MEB No. 1 entitled " Postulated Break and Leakage Lscations in Fluid System Piping Outside Containment."
A.
High energy fluid systems are those systems which have a service temperature of 2000F or greater and/or a service pressure of 275 psig or greater.
B.
Those piping systems carrying fluids with service conditions of 2000F or greater and 275 psig or greater are to be analyzed for pipe whip, jet impingement, compartment pressurization, and related environmental effects.
C.
Those piping systems carrying fluids with service conditions of 2000F or greater or 275 psig or greater are to be analyzed for environmental effects on required safety related equipment in the vicinity of the break.
Page 2 D.
Safe shutdown of the reactor is defined as a cold shotdown for the purpose of this report.
E.
Operating conditions prior to the rupture are considered normal steady state.
F.
Other passive failures in addition to the postulated pipe break are not assumed credible.
C.
Only those high energy systems which are in service during normal operations are assumed te r pcure.
H.
Offsite power is assumed available during normal operation.
I.
Coincident with the postulated pipe break, single failure in an active component of a required safety related system is assumed.
J.
Pipe breaks are postulated to occur at the following locations:
1.
Terminal ends.
Extremities of piping runs that connect to structures, components or pipe anchors that act as rigid constraints to piping thermal expansion. A branch connection to a main piping run is a terminal end of the branch run.
2.
Each intermediate pipe fitting, welded attachment and valve.
(See attached TMR drawings SK-2008-1 and Sa 2008-2).
K.
Pipe Rupture Orientation The pipe rupture orientation at each postulated design basis break location is taken to be either the circumferential or longitudinal type, regardless of the state of stress at the break location.
Circumferential breaks are postulated at the locations des-cribed in II.J. in piping runs exceeding one inch nominal pipe size. Circumferential breaks are assumed to result in pipe severance and separation and are perpendicular to the pipe axis with the break area equivalent to the internal cross-sectional area of the ruptured pipe.
Longitudinal breaks, assumed to occur at locations specified in II.J., are parallel to the pipe axis and oriented at any point around the pipe circumference. The pipe break area is equal to the effective cross sectional flow area upstream of the break location. Longitudinal breaks are considered in piping runs of four inch nominal pipe size and larger.
A single open crack at the most critical location (s).with regard to essential structures and systems is postulated in moderate energy piping systems greater than one inch nominal pipe size. The crack is taken as one-half the pipe diameter in length and one-half the wall thickness in width.
~
Page 3 III. High Energy Fluid Systems Piping systems outside the primary containment at Connecticut Yankee which have a service temperature of 2000F or greater, and/or a service pressure of 275 psig or greater, were subjected to an analysis to determine the effects of a postulated rupture on safe plant shutdown. Where operating conditions vary, as for example the rising pressure characteristic of steam and feedwater under reduced load in a pressurized water nuclear plant, the operating conditions were selected at either a low or a high load, whichever was the more conservative. Hence, the pressure and temperature values listed are not necessarily for the same load. Those systems meeting the above criteria and consequently analyzed are as follows:
Maximum Maximur Operating Operating Type of System Terminal Pressure, Temperature, Failure System Name Points Psig JF Postulated Main Steam to Turbine Reactor Containment 910 535 Break Reheaters, and Steam Penetrations to Bypass Turbine Inlet, Including Safety Valve Inlets Auxiliary Steam in 36 In. Main Steam 910 535 Break Turbine Building Header to Conden-ser Air Ejectors Auxiliary Steam in Enclosure Wall Pene-910 535 Break Auxiliary Feedwater tration to Auxiliary Pump Enclosure Turbine Drivers Feedwater Steam Generator reed 1,100 360 Break Pumps to No. 1 Feedwater Heater No. 1 Feadwater 1,100 428 Break Heater to Reactor Containment Penetrations Auxiliary Feedwater Auxiliary Feedwater 1,000 90 Environment in Auxiliary Feed-Pump Discharge to water Pump Enclosure Enclosure Wall Condensate Main Condensate Pumps 390 92 Environment to No. 6 Feedwater Heater No. 6 to No. 5 Feed-390 150 '
Environment sater Heater
Page 4 Maximum Maximum Operating Operating Type of System Terminal Pressure, Temperature, Failure System Name Points Psig oF Postulated No. 5 to No. 4 Feed-390 190 Environment water Heater No. 4 to No. 3 Feed-390 240 Break water Heater No. 3 to No. 2 Feed-390 290 Break water Heater No. 2 Feedwater Heater 390 370 Break to Steam Generator Feed Pumps Turbine Extraction Turbine to No. 1 Feed-335 432 Break Steam water Heater Turbine to No. 2 Feed-160 371 Environment water Heater Turbine to No. 3 Feed-46 294 Environment water Heater Turbine to No. 4 Feed-11 242 Environment water Heater Turbine to No. 5 Feed-
-5 165 Excluded
- water Heater Feedwater Heater No. I to No. 2 Feed-335 380 Break Drains water Heater No. 2 Feedwater Heater 160 365 Environment to Drain Receiver No. 3 to No. 4 Feed-46 250 Environment water Heater No. 4 to No. 5 Feed-11 200 Environment water Hester No. 5 to No. 6 Feed-
-5 164 Excluded
- water Heater Feedwater Heater Drains Same as affected Excluded **
to Condenser heater above Turbine Moisture Moisture Separator to 165 373 Environment ~
~
Separator Drains Drain Receiver
. ~., - _ _ _.. _
Page 5 Maximum Maximum Operating Operating Type of System Terminal Pressure, Temperature, Failure System Name Points Paig 0F Postulated Turbine Reheater Turbine Steam Reheater 910 535 Break Drains to Drain Tank Control Valve to No. 1 335 432 Break Feedwater Heater Auxiliary Steam Head-6 In. Header in Pri-110 344 Environment er in Primary Aux-mary Auxiliary iliary Building Building Charging Lines in Volume Control Tank 15-50 115 Excluded
- Primary Auxiliary to Charging Pumps Building Suction Charging Pumps Dis-2,700 115 Environment charge to Flow Control Valve Flow Control Valve 2,100 115 Environment to Penetrations Bleed (Letdown) Lines Penetrations to Let-2,000 258 Break in Primary Auxiliary down Orifices e
5 Building Letdown Orifices to 200 258 Environment Nonregenerative Heat Exchanger Nonregenerative Heat 200 110 Environment Exchanger to Pres-sure Control Valve
)
Pressure Control 15-50 110 Environment Valve to Volume Control Tank Steam Generator Blow-Reactor Containment 910 535 Break down Lines in Pri-Penetrations to mary Auxiliary Pressure Control Building Valves Pressure Control Atmospheric 212 Environment Valves to Blowdown Tank Safety Injection High Pressure Pumps 1,200 90 Excluded **
Lines in Primary Discharge to Pene-Auxiliary Building trations
Page 6 Maximum Maximum
~
Operating Operating Type of System Terminal Pressure, Temperature, Failure System Name Points Psig 0F Postulated Lou Pressure Pumps 330 90 Excluded **
Discharge to Pene-trations
- Excluded since below both minimum pressure and temperature limit.
- Excluded since not normally in operation.
Drawing No. 11/26.24-EP-2001A, Main Steam, Feedwater, and Auxiliary Steam Piping, is included and shows an isometric view of these systems between the reactor containment penetrations and the turbine building.
IV.
PLANT SHUTDOWN METHODS Three (3) independent methods of plant shutdown are available to bring the plant to a safe knn2 condition if a pipe break incident were to occur. Although M
,Js II and Methods III are written as if the control room is available, these methods can be implemented both from the control room, or else manually if the control room is uninhabitable. Only Method 1 requires that the control room be available for functional activities.
1 METHOD I - MOTOR DRIVEN STEAM GENERATOR FEEDWATER PUMPS i
A.
Pr(requisites for Cooldown 1.
Reactor tripped 2.
Normal sources of AC and DC power available 3.
Condenser Air Removal System available 4.
Condensate System available a.
One (1) Condensate Pump b.
One (1) Gland Seal Pump 5.
Feodwater System available a.
One (1) Steam Generator Feedwater Pump l
b.
Feedwater Bypass Flow Control Valves 6.
Circulating Water System available i
a.
Two (2) Circulating Water Pumps 7.
Main Steam System available Steam Dump Flow Control Valves to Co.
iser a.
b.
Atmospheric Steam Dump Valve 8.
Service Water Systcm available 1
a.
Service Water Pump
..y,
Page 7 9.
Component Cooling Water System available a.
Component Cooling Water Pumps b.
Component Cooling Water Heat Exchangers 10.
Residual Heat Removal System available a.
Residual Heat Removal Pumps b.
Residual Heat Removal Heat Exchangers 11.
Control Air System available a.
Control Air Compressors a
12.
Turbine Building Closed Cooling Water System available 13.
Reactor Coolant System available a.
Reactor Coolem: Pumps 14.
Charging and Volume Control System available a.
Chargi-o Pumps 15.
Primary Water System available a.
Primary Water Pumps 16.
Boric Acid System Available a.
Boric Acid Pump 17.
Adequate supply of secondary makeup water is available i
a.
Demineralized kater Storage Tank b.
Primary Water Storage Tank i
B.
PROCEDURE i
Immediate Action 1.
Verify Reactor tripped.
2.
Verify operation of Resctor Coolant Pump #3 or #4 for pressurizer spray capability.
a.
If not available use auxiliary spray from Charging System.
Subsequent Action 1.
Borate Reactor Coolant System to cold shutdown concen-
~
tration.
a.
One Reactor Coolant Pump should be operating during boration for ideal mixing conditions.
4 e
Page 8 2.
Set up automatic makeup control for proper ratios of boric acid and primary water. Monitor Volume Control Tank level during cooldown.
3.
De-energize all pressurizer heaters.
4.
Commence cooldown of primary plant by initiation of steam dump to the condenser. Monitor cooldown rate.
5.
Fatablish pressurizer spray to commence cooling of the pressurizer.
a.
Monitor cooldown rite of pressurizer.
6.
Monitor and adjust Reaccor Coolant Pump seal water supply flows during coc idown.
7.
Monitor condenser hotwell level and Demineralized Water Storage Tank levels during cooldown to insure adequate supply of steam generator makeup water.
8.
When pressurizer steam phase temperature reaches 450 F, go solid in pressurizer, maintain approximately 500 psig in Reactor Coolant System and continue using spray to further cool down the pressurizer.
9.
When the pressurizer reaches 300 F, shutdown the Reactor Coolant Pump and place the Residual Heat Removal System in operation.
10.
Change over to atmospheric steam dump to continue the cooldown and decay heat removal.
11.
Discontinue steam dump to condenser.
Break vacuum and take out main steam.
12.
Continue fa cooldown the primary system to less than 200 F using the Residual Heat Removal System.
13.
Shutdown the Steam Generator Feedwa*er Pump and continue to cooldown the Steam Generators by feed and bleed using the Condensate Pump and 2" Steam Generator Drain Valves to the Blowdown Tank.
METHOD II - EMERGENCY STEAM GENERATO't FEED WATER PUMPS (STEAM TURBINE DRIVEN)
A.
Prerequisites For Cooldown 1.
Auxiliary Steam Generator Feedwater System Available n.
Demineralized Water Storage Tank with adequate supply of water.
Page 9 b.
Auxiliary Steam Driven Feedwater Pump.
c.
Feedwater line from discharge of auxiliary steam driven feedwater pumps through MOV-35, containment penetration to the main feedwater lines downstream of the main feedwater line check valves or from discharge of Auxiliary Steam Driven Feedwater Pumps to the main feedwater bypass lines upstream l
of the bypass flow control v.21ves.
2.
Main Feedwater System available, a.
Inside the containment between check valves and steam generators, or b.
Inside the turbine building from the main feedwater head-r to the steam generators inside the containment.
3.
Auxiliary Steam Generator Feedwater Pump steam supply l
l lines.
l 4.
Emergency diesel genr.rator "A" or "B".
l 5.
Emergency 4160V Bus "8" or "9" associated with its corresponding diesel generator.
6.
Emergency electrical buses and equipment associated with its corresponding diesel generator.
7.
Charging System available.
Charging Pump associated with its corresponding i
a.
diesel generator and 4160V bus.
B.
Procedure 1.
Immediate Action-a.
Verify reactor tripped, b.
Verify diesel generator start and electrical power supply restored to respective buses and equipment.
c.
Push reactor trip buttons.
d.
Verify reactor tripped by monitoring nuclear instrumentation.
2.
Subsequent Action a.
Determine status of primary and secondary systems.
~
b.
If pressurizer pressure and temperature have reached the core cooling set point, place High Pressure or Low Pressure Safety Injection Pumps in service
Page 10 gtif. S e""~#h ~
- c ;is.~i (depending on system pressure) and r9 store pres-surizer level.
c.
Change over suction to Charging Pumps from Volume Control Tank to Refueling Water Storage Tank.
d.
Start Charging Pump and commence feeding Reactor Coolant System to maintain pressurizer level within observable ranges.
e.
When control of pressurizer level has been achieved with the Charging Pump, shut down the Safety Injection Pumps.
f.
Using Auxiliary Steam Driven Feed Pumps establish feed rate to steam generators to restore and maintain levels for heat removal.
g.
Borate system to cold shutdown concentration using Boric Acid Transfer Pumps and Charging Pump.
h.
Commence or continue cooldown of Reactor Coolant System to 250-300 degrees F using Auxiliary Steam Driven Feedwater Pump for feed.
(1) Allow the level in the steam generators to increase to 95% then establish a feed and bleed through the 2" steam generator drain lines to the blowdown tank.
(2) When feeding of steam generators cannot be maintained because of low steam pressure, close steam generator drait. 2alves.
(3)
Steam pressure will rise as decay heat transfers from RCS to steam generator water and will provide a steam supply for operating the auxiliary feed-water pumps again.
Reactor coolant system temperature will fluctuate between approximately 212 degrees F and 250 degrees F.
(a) When a source of power is available for a service water pump and RHR pump, place RHR system into operation and cooldown reactor coolant system to less than 200 degrees F.
METHOD III - FEEDING OF COOL WATER DIRECT TO THE REACTOR COOLANT SYSTEM (RCS) THROUGH THE EMERGENCY CORE COOLING SYSTEM (ECCS)
A.
Prerequisites for Cooldown 1.
Emergency Diesel Generator (EDG) A or B.
2.
Emergency 4160V Bus 8 or 9 associated with corresponding EDG.
i
I Page 11 3.
Emergency electrical fuses and associated equipment.
4.
Emergency Core Cooling System equipment, piping and valves.
B.
Procedure 1.
Immediate '.ction a.
Trip reactor b.
Verify diesel generator starting and restoration of electrical power supply to emergency buses and equipment.
c.
Monitor nuclear instrument action to verify reactor trip and shutdown.
2.
Subsequent Action a.
Monitor instrumentation and determine status of Primary and Secondary systems.
b.
Line up charging pump suction from the Refueling Water Storage Tank (RWST) and isolate from the Volume Control Tank (VCT).
c.
Start a charging pump and control charging rate to maintain or restore pressurizer level to normal.
d.
When RCS pressure falls below shutoff discharge pressure of the high pressure safety injection (HPSI) pumps, start one HPSI pump, e.
Shutdown the charging pump and control feed to the RCS via one or more loop safety injection MOV's to maintain pressurizer level and pressure as RCS temperature decreases due to natural circulation and lifting of Secondary Safety Valves.
f.
When RCS temperature and pressure decrease to discharge pressure of the Low Pressure Safety Injection (LPSI) Pumps, start one LPSI Pump.
g.
Shutdown the HPSI Pump and maintain a solid system at LPSI Pump discharge pressure (295 psig) via core deluge connections.
3.
Followup Action a.
If RCS temperature and pressure are above RHR system limits, line up service water to the Component Cooling System to proviue cooling to the Non-Regenerative Heat Exchanger, transfer Charging Pump suction to VCT, start a Charging Pump and
Page 12 commence feed and bleed of system via normal Letdown and Charging Systems.
b.
If or when RCS temperature and pressure is less than RHR system limitations lineup Service Water to RHR Heat Exchangers and place RHR system in service and cool RCS to less than 200 degrees F.
V.
EFFECTS OF HIGH ENERGY FLUID SYSTEM RUPTURES A.
Pipe Whip, Jet Impingement, Environmental 1.
Main Steam System For the purpose of this analysis, the main steam piping is defined as the piping leading from the reactor con-tainment penetrations through the main steam non-return valve area (unenclosed), across the plant yard, to the turbine building, through the heater bay area and to the turbine stop valves.
The postulated main steam break locations are shown on Drawing SK-2008-1.
A main steam pipe break within the non-return valve area could result in the loss of both auxiliary feedwater pumps in the enclosure directly below the main steam valve crea. This eliminates shutdown Method 2.
Normal shutdown (Method 1) is also eliminated due to the postulated loss of offsite power. The charging and safety injection pumps (Method 3) would be available to initiate shutdown.
A break in the main steam yard crossing could eliminate only normal shutdown (Method 1) as none of the equipment needed for the other two methods could be affected.
A main steam pipe break inside the turbine building could result in loss of the switchgear room either from steam environment or from impact of a whipping pipe.
In addition, the control room could become uninhabitable due to turbire building environmental conditions. Shutdown Method 2 would remain available.
2.
Feedwater System The main condensate system is defined as the piping leading from the discharge of the main condensate pumps to the suction of the main steam generator feed pumps via the air ejectors, gland steam condenser, and feedwater heaters Nos. 2 to 6.
A pipe break in this system would have no effect on equipment vital to safe shutdown.
Only the normal feed pumps (Method 1), are in this vicinity and this method would remain available since a break in the suction or dicharge line of one pump would not affect the same size pipe in an adjacent pump. However, Method 1 is eliminated by definition due to the loss of offsite power.
Safe shutdown Methods 2 and 3 would not be affected.
Page 13 The feedwater system is defined as the piping leading from the main steam generator feedwater pumps through the No. 1 feedwater heaters outside and over the roof of the service building, across the yard, through the main steam non-return valve area (unenclosed), to the reactor containment penetrations. The postulated feed-water break locations are shown on Drawing SK-2008-2.
A feedwater pipe break inside the turbine building could result in the loss of the switchgear room and the control room from environmental effects, however, Method 2 would remaJn available. A feedwater line break in the auxiliary Lay of the turbine building could take out electritsi teeds to the 4 kV switchgear which supplies the main conlensate and feed pumps eliminating normal shutdown (Mechod 1), however, the remaining shutdown Methods 2 and 3 would not be affected.
A feedwater pipe break in the yard could result in the loss of only shutdown Method 1.
A feedwater pipe break at the main steam non-return valve area could render the auxiliary feedwater pumps inoperable thus eliminating shutdown Method 2.
Loss of offsite power eliminates Method 1.
Use of the charging and safety injection pumps (Method 3) would be available for shutdown.
3.
Extraction Steam System The extraction steam piping is defined as the steam piping leading from various extraction outlets on the high and low pressure turbines to the feedwater heaters Nos. I to 6.
This piping is totally confined within the turbine building. Any rupture in this system for heaters Nos. 1 to 4 could result in the loss of the switchgear room and the control room from environmental effects.
Shutdown can be initiated by the use of shutdown Method 2.
Steam extraction lines to feedwater heaters Nos. 5 and 6 are enclosed in the condenser necks and rupture could not affect vfcal equipment.
4.
High Pressure Heater and Other Drains The high pressure heater drains system consists of several small drain lines connected to various heaters and the heater drain receiving tank, all within the turbine building.
It is considered that any pipe break in this system could result in a steam environment in the turbine building.
The environmental effect would be restricted to flashing of water into steam and hence would be small.
It is not considered possible that the control and switch-
~
gear rooms could be affected but, if they were, Method 2 would remain available.
Page 14 Pipe breaks in drains from the turbine crossover moisture separators and reheaters result in identical analyses as those from the high pressure heaters.
5.
Charging System Two centrifugal charging pumps as used in safe shutdown Method 3 are located in separate cubicles in the Primary Auxiliary Building.
The failure of any high energy line could not affect these pumps through whipping. The failure of the suction or discharge lines of any one pump could eliminate that pump only and would leave the other pump unaffected. All safe shutdown methods remain effective, except Method 1 which is eliminated by the loss of offsite power.
6.
Safety Injection System Four safety injection pumps as used in safe shutdown Method 3 are located in a single separate cubicle in the Primary Auxiliary Building. The failure of any high energy pipeline could not affect these pumps through whipping. The pumps are not normally in operation, and thus their own suction and discharge lines are not vulnerable to failure. All safe shutdown methods remain effective except Method 1 which is eliminated by definition.
7.
Steam Generator Blowdown System The steam generator blowdown system is defined as the piping from the reactor containment penetrations through the piping trench to the blowdown tank in the Primary Auxiliary Building. A piping break in the trench or blowdown tank cubicle would have no effect from whipping because of isolation characteristics and size (a whipping pipe cannot damage another of equal size or larger).
The steam environment would be limited to that resulting from flashing water.
This could render the Primary Auxiliary Building temporarily uninhabitable. This is not considered sufficient to eliminate safe shutdown i
Method 3, involving a total of six pumps, remotely started. Normal shutdown Method 1 is eliminated by definition only. Method 2 is also available to initiate a safe shutdown.
8.
Heating Steam This system runs throughout the plant providing low pressure steam for various purposes. As a result.of a plant survey, three areas were noted:
A 6 inch, 100 psig heating steam main enters the a.
Primary Auxiliary Building above ground grade near the west wall entrance. A crack in this line could impinge upon the two principal banks of cables under the steam line, eliminating shutdown Method 3.
Page 15 b.
The same 6 inch, 100 psig heating steam line passes under several racks of safety related cable trays located above the roof of the service building (within the turbine building). A crack in this line could eliminate some of the cable from service thus rendering Method 3 inoperable. Shutdown Method 2 would remain available.
c.
A 2 inch, 15 psig heating steam line is located in the reactor containment cable penetration vault. A crack in this line could result in the loss of Shutdown Method 3, however, shutdown Method 2 would remain operable.
9.
Auxiliary Steam The consequences of a break in the auxiliary steam line between the main steam header and the condenser air ejectors are identical to those of the extraction steam system.
A pipe break in the auxiliary steam piping which supplies the steam driven auxiliary feedwater pumps would eliminate the driving power for one pump, however, the remaining pump would have sufficient capacity to complete the shutdown by Method 2.
Shutdown Method 3 would remain available.
B.
Compartmental Pressurization Three structures housing safety related equipment contain high energy pipe lines which upon rupture could cause pressurization of these buildings. These structures are:
1.
The turbine building.
2.
The enclosure for the two steam driven auxiliary feedwater pumps.
3 The primary auxiliary building.
The calculated peak pressures in these structures are tabulated below. Pressure-time transient curve for differential pressure across turbine building is shown on curve No. 11726.24-P-3.
yn
-e-
~
w~g
,-,v
t
- 1. 5 r-7
't.O
)
r
/
/
/
s lE
.0 f
}
/
~
g
/
O
-s 0.01 0.1 l.O 10 0
.]
y TIME AFTER ACCIDENT, SECOND 4 STONE E. WEBSTER ENGINEERING CORPOR ATION M AY 23,19 73 TRAN31ENT PRESSURE DIFFERENCE ACROSS 8 8 72 6' 2 4-P- 3 g
WALL OF TURBINE BUILDING COANECTICUT YANKEE ATOMIC POWER PLANT HICH EN ERGY PIPELINE BREAK ACCIDENT l
i i
Page 17 Maximum Pressure Cross Difference Volume Vent Area Accident Across Wall, Building ft3 ft2 Condition psi Turbine Building 3.200,000 3,300 Double-Ended 0.32 Summer Condition Rupture (DER) of 36 in. steam pipe Manifold at 915 psia Turbine Building-3,200,000 700 Double-Ended 1.39 Winter Condition Rupture (DER) of 36 in. Steam Pipe Manifold at 915 psia Auxiliary Steam 10,400 49 DER of 24 in.
later Driven Feedwater Steam Line at Pump Enclosure 915 psia Primary Auxiliary 442,000 200 DER of 6 in.
No Appreciable Building Steam Header at Pressure Buildup 115 psia 3
i The calculated pressurization in any of these buildings would have no effect on the safe shutdown of the plant, since multiple means for accomplishing such exist and not more than two of the three methods could be simultaneously affected.
The auxiliary steam driven feedwater pump enclosure could suffer structural damage, however, loss of both pumps due to pressurization of the compartment is unlikely. Shutdown Method 2 would remain operable regardless of the damage extent.
The turbine building could suffer structural damage (loss of portions of the metal siding) from this calculated interior pressure.
The turbine building siding consists of insulated aluminum panels. Sections as large as 20 ft by 20 ft could become detached through tearing at the bolt type fastening, since this construction could not withstand differential pressure across the wall in excess of.75 psi. No safety related structure or equipment could be reached or penetrated by detached air-borne turbine building siding panels, with the possible exception of the circulating water screen and pump house.
These sections of light s',minum panels would have insufficient energy to penetrate tl.e pump house, which is 150 feet from the turbine building, and cause damage to any of the four (4) service water pumps.
Page 18 The foregoing was derived from CUPAT, a computer program for calculating pressure and temperature transients in nuclear power plant compartments and buildings, in the unlikely event of a high energy line breaking within the compartment.
Its principal use is to determine the peak pressure differ-ential across the compartment walls which could result from such an accident for purposes of design.
The program essentially applies the First Law of Thermodynamics to an open adiabatic system. The system consists of the com-partment atmosphere at any given time.
This includes any air, steam, or water droplets present, but not the walls, equipment or internal structure of the compartment itself. The system is open in the sense that mass and energy are allowed to flow into and out of the compartment; it is adiabatic, since there is no provision for heat transfer between the compartment atmosphere and the compartment walls.
The mass and enthalpy flow-rates into the compartment resulting from a postulated double-ended rupture (DER) of the largest high energy pipe within the compartment, are based on constant (with time), f rictionless Moody flow with a 0.6 discharge coefficient, (References 1 and 2).
A homogeneous vent flow model (Reference 3) is used to calculate flow out of th.-
compartment. The vent flow model is based on the flow of a steam-atomized ideal gas, as calculated, using the thermo-dynamics of compressible fluids (Reference 4).
References 1.
Moody, F.
J., " Maximum Flow Rate of a Single Component, Two-Phase Mixture," Journal of Heat Transfer, Trans.
ASME, 87, No. 1, February, 1965 - A paper mentioned in Proposed Appendix K to 10 CFR 50.
2.
Slater, C.
E., " Comparison of Predictions from the Reactor Primary System Decompression Code (RELAP3) with Decompression Data from the Semiscale Blowdown and Emergency Core Cooling (ECC) Project," IN-1444, Idaho Nuclear Corporation, December, 1970.
i j
3.
Johnson, B.
M., " Containment Systems Experiment, Part III, Mathematical Models of Pressure Tempcrature Transi-ents," BNWL-233, Battelle Memorial Institute / Pacific Northwest Laboratories, May, 1966.
4.
Shapiro, A.
H., "The Dynamics and Thermodynamics of Compressible Fluid Flow," Vol. 1, The Ronald Press Company, New York, 1953.
C.
Flooding The elevation of the plant site and the ground grade elevations of the various buildings is considered adequate protection to l
i
,,,..-.,-,.m-,-,w..
m._,.,,
.m,
,,_.-.r.,,
Page 19 the plant and to equipment against flooding from the Connecticut River, as the result of either spring run-off, high tide from Long Island Sound, or hurricanes. This subject is covered under Section 2.3, Facility Description and Safety Analysis.
The rupture of a high pressure water-carrying pipeline could damage certain vital motors required for safe shutdown, as listed under the methods available for safe shutdown of a plant. Not more than one of the several available methods could conceivably be eliminated from service at one time through this type of failure.
The rupture of a large water line in either the turbine building or the enclosure around the two auxiliary steam generator feed pumps will not affect any safe shutdown equipment through flooding, since water level cannot build up to a sufficient height at ground grade in either of these buildings to affect the operation of the motors.
In the Primary Auxiliary Building, a large water line break would flood the pipe trenches and the deep pits beneath the ground grade floor without affecting safety related equipment.
High pressure water lines associated with either the charging or the safety injection pumps could break within one of the cubicles and possibly flood the motor driver of a pump.
Flooding within a cubicle could take place only from the breakage of the suction or discharge line of the pump therein and since breakage has already removed that pump from service as an item of safe shutdown equipment, the flooding of that motor is of no consequence.
All m'otor drivers of pumps listed under the Lethods available for safe shutdown of the plant are of the drip-proof type.
Leakage of water directly over the motor would not remove it from service. This type of motor, however, is not protected against a break in a high pressure water line in which a spray or jet of water is directed at the motor. Such an accident could cause the motor to fail. However, any motor driver could be affected only by a break in the suction or discharge piping of the driven pump and since such break has already removed that driven pump from service as an available method for safe shutdown of the plant, the damage to the motor driver is of no additional consequence.
VI.
ORIGINAL DESIGN CRITERIA A.
Stress Analysis As part of the plant design, high energy pipelines were stress analyzed. Important large size high energy lines were given a tormal computerized stress analysis, determining force's, moments, thermal stress, and deflections at numerous points throughout the pipe run.
For small lines, stress concentra-tions at questionable points were checked by chart or nomogram.
Stresses were determined to be less than the allowable stress
~
Page 20 range value and points of maximum stress were noted. Where necessary, piping layouts were modified to obtain greater flexibility and reduce stresses.
The following nystems were subjected to a formal thermal stress analysis:
Main Steam Feedwater Extraction Steam High Pressure Heater Drain Condensate Turbine Steam Bypass Pressurizer Relief Portions of the Safety Injection Portions of the Residual Heat Removal in general, high energy pipelines in the plant are not highly streseed.
A review of the stress analysis charts indicates that the stress at most points is only half the allowable stress or less. A few points are more highly stressed, but these are still less than the allowable. The following is a tabulation of maximum stress levels in several systems and the stresses in the main steam piping system.
Maximum Stress Levels Maximum Average Allowable Thermal Thermal Stress Stress Stress Range System (psi)
_Jpsi)
(psi)
Main Steam 20,800 7,000 22,500 Feedwater 11,090 4,000 22,500 Extraction Steam 13,500 5,000 18,000 High Pressure Heater Drains 13,500 4,000 18,000 Condensate 10,300 4,000 18,000 Turbine Steam Bypass 9,680 4,000 18,000 Pressurizer Relief 19,500 5,000 22,500 Safety injection 9,141 3,000 18,000 Residual Heat Removal 14,310 6,000 '
18,000
Page 21 f.
~VII.
CONCLUSIONS Based on the results of this investigation, it is concluded that for any postulated break in a high energy fluid system outside of containment, at least one method of plant shutdown will remain intact and available for Several plant modifications instituted to mitigate the consequences use.
of pipe breaks, by substantially reducing the probability of loss of safe shutdown methods, are presently completed or in the design stage.
The first two modifications were accomplished during the September 1973 refueling outage.
1.
Remove the 15 psig steam heater and 2 in. steam line f rcm the reactor containment cable penetration and provide an electric heater.
This will eliminate the potential loss of Shutdown Method 3, which could occur if a pipe break were postulated in f
the containment cable vault area.
i 2.
Provide impingement shielding for the following:
The cable trays near the west end wall of the Primary a.
Auxiliary Building adjacent to the 6 in.100 psig steam
- line, b.
The cable trays over the service building roof where the cable trays pass over the 6 in. 100 psig steam line.
The addition of impingement shielding at the above locations (see Figure SK-102 submitted October 26, 1973, Docket No. 50-213) will eliminate the potential loss of Shutdown Method-3, if a pipe rupture of the 6 in.
100 psig steam line is postulated.
The remaining modifications are planned for completion during the refueling outage tentatively schedule for June 1975:
1.
Provide encapsulation sleeves at selected potential break locations in the main steam and feedwater systems.
The design concept of the encapsulation sleeve will (1) prevent pipe whip due to postulated double-ended rupture and (2) also minimize jet impingement loadings associated with either circumferential and longitudinal splits.
Sufficient clearance between the system piping and the encapsulation sleeve will be provided to preclude restriction of normal thermal motion.
1 The encapsulation sleeves adjacent to the auxiliary feedwater pump enclosure (Figures 1, 2, 3) will eliminate the potential loss of Shutdown Method 2, if either a main steam, feedwater or auxiliary j
steam pipe rupture is postulated in that vicinity. Structural i
i modifications to the auxiliary feedwater pump enclosure walls (Figure 4) will provide the necessary reinforcement for dissipation of loads generated by the postulated pipe break.
I h.
Page 22 The system restraints, barriers and encapsulation sleeves in the area of the main steam manifold (Figures 5, 6) will preclude adverse effects on the switchgear and the cor.crol room, as described in Section V A.1, due to a postulated steas line rupture.
The modification of the control room access (Figure 7), involving leak tight doors, will segregate the control room and turbine i
building environments to enr.ure habite.bility of thL control room if a steam line rupture is 1 atulated in the turbine building.
The aforementioned modifications to systems and structures within or adjacent to ne turbine building will ensure the availability of Shutdown Method 3 under the postulated pipe breaks within the turbine building.
2.
As indicated in the report, the criteria for the selection of break locations includes welded attachments. At present there are several welded attachments, associated with sliding pipe supports, in both the main steam and feedsater systems. Rather tha.1 encap-sulating or restraining t'.ne piping systems at every welded attachment, a stress analysis using present day computer techniques of the subject piping system is being performed. Consistet.t with the above, welded attachments in the main steam and feedwater piping systems will be removed and redesigned pipe supports will be installed as shown in Figure 8.
In summary, a study was performed to determine the impact of postulated breaks in the high energy fluid systems outside containment on the capttility for safe plant shut-down. As a result, several modifications will be instituted, as described in this report, to ensure at least one method of safe plant shutdown under o condition of postuinted pipe ruptures in subject piping systems outside containmens. The proposed modifications are scheduled to be performed during the upcoming refueling outage in June 1975.
Based on the above, it is concluded that the proposed modifications outside of containment do not constitute an unreviewed safety item.
e
=-
m
a e
a e
4 4
e
\\ k m1 w%
3 O
D O NiM M
6W
)-
r e
k At o
t 0
%x e
9 e
\\w k
4 4
m
... r... $
i t
g
-......... 3-l i
u w%
1 i
<.g 9
l i
i l' l l
l
\\
tr
(
i 5
ll!'
y i
n..
r
~
Q i
a~k k
A
/
g 6
k-l q,h b~ '
bm
- i.
4 bW i
G.0
g e
4 e
O t
t i
bO
[
b I
.a
[
D N
o>
.e N
~N$
N aw e
N
.J
- C e
3 r-Z y
N z
.g T
a i
w e
0
/
,/
1 M
L 6
f'
'3 I
1 ammu
,.1
ELEVATION VIEW I7.08' ELEV. 38'O'
,as ggS' p
WSGDLML 4
N a ca.c:eere o
t o.
g enAM l
a 1,
h W lt X 9 2.
f ELEY.38'O - --
L
,,,e ELEV - Bl.s' M'
N P
=
'O fj V
( m *4m W
%k sTaet g
A i
CONNECTIOh! AT A4 6 wg gg,,
-ne ALLOW FOR ROTATLON.
g QWEEE;8 CONNECTioM ATC sTass CORTA#4.MEl(T ALLOWS FOR VER'TLA
/
WAL,L
( hor 170MTAL 4.o.eavence sHisto posmou p+g,
w s. rs' WALT.
McVEMEMT INTo hot s
r y
s 50 s
/
b p
ELEV.
d Tomm EW 2L8 g'ggg g*
N a
b O
1 q 9,o=
o,'
~
od to.5*.
N 5.o*
A s
~~
p O
E f b'UO E ".
fK~2008 3 3 *4%.
.w-N
A 6
4 e
e 6
e I
s M
i I
B 6
_J 1
g y
R
.i I
,J
~k
.y I
{
g 9
\\1 ----
y i
0
(
l k
s k,
D
\\4 5
J R
e h
g
._. V 5
! a
.j J
b s
I t(
J _ _ 3.
p
(
o
[ (C- %.j<$-
j l
s z
y
[
s
-y 1
l
\\
/
7 f
e J _2
-G l
l 8
I I
l
TV Pi CAL E LEVATtOM FOR STEEL PLATE LINER FOR.
SW ITCHlb1C, ROOM CONCEETE BLOCK WALL 20.O' I
,. j, fJ y
_/
STEEt. BEAM ASoJE i
i 1
y STEEL l
Cot UMN co umw4 I
cf18.0 (VARIES) i l
i STEEL PLATE W
APPD:W.. a m
D,_. - -
c 7
A floor.
\\ pg mE. r-on ete.4 nm
._ resu gu.
ff/Clys==
L%C Fi& W - 6 S t-z o o g --/ O c
N PRESSURE BARR\\ER
--fi.-
~f--
CONTROL R.coM
\\
S 1
\\i p E. LEVATOR
[
1
_.l. _..
,/
C BS ERVATIOh4 EITCHE4
.S(,
ROOM AREA
,\\
Jl
/,\\
L 1
b 1, n i
i A\\R SEAL Poor
- t. s c.
th ihr RGQFE -l
.f. % - 7 0 0 R - / /
1 k
i k
7 i
Q 3
k E
q
.x k
>d g-,-
c-f I
9 Y
I l
1 g
V l.-
C c
.a
's tr g
oU N
c E ::
g asi
~
~3 de 9
=-
Ch
~
0-d-a at Id e
I 11
>I u)
.J g
_r ao I
7 /
\\
/
/ l/
\\
N~%
s
\\
N
\\
/ s A\\\\\\\\\\\\\\\\ /Vg b
////Y M
,/
N
\\
j
/V g
\\
l N
/\\
j N
N g
j
/\\' h I
l \\
/
N
/\\
N
,/vg I
j su t____
s
% ///////
/
/\\
l s
r 4
\\
l
\\,
j/
g l
/
s s
l 2
/V %
l l
/ s
}
/
l l
b
\\
\\
~
1 I
y g
/ wg N
/,
v//////////> 3/\\
O
/
(/
s
%\\\\\\\\\\\\\\\\ /\\' %
\\
/
/\\
s I
/ \\
1
\\
/
/;/
s
. k l
M
-.y I
p
!j t;N 6
te 1
c e r
f
(___3 ll Il I
i.I I
.g a m I
]a j/
(lu s
e
- < h
.4 1:
x.
/
. '/
/-
~
3
/g(,'-(
3 n i*
1., [
e,f I
di.0
..s g
hddAd
'/'
W 7
~% p. 9 t
g L_,
i-t,' z.
T-
- f. 4,
,N q
,' /x
- q.,., t+
ya
, z'
,i s
s O
?
.v.\\x g',
f wx,
- ,\\
/
/
s
.,r l'N
'h
/
s' %
'l
.R
/
8\\
7 ([
/
/
-g f
8 s
l
,k%
((
.,.f,'
f k
(
g i
/'
z__ _
i
/
\\\\\\
\\ \\
/
-\\
', 5 '
- s
'.\\
')#
f>y y
/
y'
+
l
[
l
/
4 O
...ee---
_.n
- ~
g, T
- i
.)
i,t I
s l
l@2 ge n
er
[hiiid k
\\
Ilih x
! pn...
5
.i,bt
=
3 s\\
$ ;# -t 6
\\
~
g G
R
.J \\
vy's 't);
e,
- w j \\,
'*/'
I 2
,3-J'
,/x s/
s.
d.,,Tj
/
c N,
j
/
i!
p/
,/ g~f:'g n
j s
,. 1.
v
,s 7
l f
\\+
,?
g
.e
/
,e a
f
(
f,I g lLl'
\\
{!,;~'
_/'
a
.i
/\\
.f *,
/-
A-Y
%% ?'n?
N N
y.=
(
N*
N
,/ %. \\ 'y [f M
',; /
ll,
\\.
.ui
'/
~
N O
v