ML20151Y368
| ML20151Y368 | |
| Person / Time | |
|---|---|
| Site: | Vermont Yankee  |
| Issue date: | 04/27/1988 |
| From: | Varga S Office of Nuclear Reactor Regulation |
| To: | Paull P VERMONT, STATE OF |
| References | |
| NUDOCS 8805040433 | |
| Download: ML20151Y368 (18) | |
Text
\
a Apr$1 27,1988 i
Mr. Phillip Paull State Nuclear Engineer Department of Public Service 120 State Street @4g7[
Montpelier, Vermont 05602
SUBJECT:
LOGIC SYSTEM FUNCTIONAL TEST AT VERMONT YANKEE
Dear Mr. Paull:
On March 15, 1988, the NRC staff met with the Vermont Yankee Nuclear Power Corporation and you with respect to the proposed <:hant Yankee Technical Specifications regarding Logic System Functional testing.
The licensee's proposal would result in a more comphrensive testing o.
logic system once per coerating cycle rather.than testing the system every six months, as is presently required. At that meeting you requested the staff provide additional information regarding logic system reliability.
As you are aware, our review of the Vermont Yankee proposal is continuing.
Subsequent to the March 15, 1988 meeting the staff requested the licensee to provide specific information regarding logic system reliability at the Vermont Yankee facility. Enclosure 1 is the licensee's response, dated April 13, 1988. S. Newberry, of our Instrument and Cr ' ol Systems Branch, recently discussed with you the staff's view regardin s sgic system reliability. Enclosure 2 provides our consideration of logic system reliability on a generic basis.
As indicated in the enclosures, nuclear power plant logic systems, including Vermont Yankee's, are highly reliable. We believe the highly reliable logic system, coupled with the reduced potential for a plant challenge due to a human error during more frequent surveillance testing, lends support to the Vermont Yankee proposal.
Please contact the Vermont Yankee Project Manager, Mr. Vernon P.ocr.ey, at (301) 492-1440, if you have any questions.
Sincerely, Original signed byt Steven A. Varga, Director Division of Reactor Projects I/II
Enclosure:
As stated 8805040433 880427 PDR ADOCK 05000271 P PDR cc: See next page DISTRIBUTION PDI-3 r/f, Docket' File
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Mr. R. W. Capstick Vermont Yankee Nuclear Power Corporation Vermont Yankee Nuclear Power Station cc:
Mr. J. Gary Weigand W. P. Murphy, Vice President President & Chief Executive Officer and Manager of Operations Vermont Yankee Nuclear Power Corp. Vermont Yarkee Nuclear Power Corp.
R.D. 5, Box 169 R.D. 5, Box 169 Ferry Road Ferry Road Brattleboro, Vermont 05301 Brattleboro, Vermont 05301 Mr. John DeVincentis, Vice President Mr. Gerald Tarrant Commissioner Yankee Atomic Electric Company Vermont Department of Public Service 1671 Worcester Road 120 State Street Framingham, Massachusetts 01701 Montpelier, Vermont 05602 New England Coalition on Nuclear Public Service Board Pollution State of Vermont Hill and Dale Farm 120 State Street R.D. 2, Box 223 Montpelier, Vermont 05602 Putney, Vermont 05346 Vermont Public Interest Research Group, Inc. Mr. Walter Zaluzny 43 State Street Chairman, Board of Selectman Montpelier, Vermont 0560? Post Office Box 116 Vernon, Vermont 05354 William Russell, Regicnal Administrator Raymond N. McCandless Region I Office Vermont Division of Cccupational U.S. Nuclear Regulatory Commission and Radiological Petith 475 Allendale Road Administration Building King of Prussia, Pennsylvania 19406 Montpelier, Vermont 05602 Mr. R. W. Cap: 51 <. k Honorable John J. Easton Vermont Yankee NJclear Attorney General Power Corporat'en State of Vermont 1671 Worcester Road 109 State Street Framingham, Massachusetts 01701 Montpelier, Vermont 05602 John A. Ritscher, Esquire Ropes & Gray 225 Franklin Stt?et ,
Boston, Massachusetts 02110 I i
f, Vermont Yankee Nuclear Power Vemont Yankee Nuclear Power Station Corporation cc:
Ellyn R. Weiss, Esq. Resident Inspector Harmon & Weiss U.S. Nuclear Regulatory Comission 2001 S Street, N.W. P.O. Box 176 Washington, D.C. 20009 Vernon, Vermont 05354 David J. Mullett, Esq. Carol S. Sneider, Esq.
Special Assistant Attorney General Assistant Attorney General Vermont Depart, of Public Service Office of the Attorney General 120 State Street One Ashburton Place, 19th Floor Montpelier, VT 05602 Boston, MA 02108 Jay Gutierrez Geoffrey M. Huntington, Esquire Regional Counsel Office of the Attorney General USNRC, Region I Environmental Protection Bureau 475 Allendale Road State House Annex King of Prussia, PA 19406 25 Capitol Street Concord, NH 03301-6397 G. Dana Bisbee, Esq. Charles Bechhoefer, Esq.
Office of the Attorney General Administrative Judge Environmental Protection Bureau Atomic Safety and Licensing Board State House Annex U.S. Nuclear Regulatory Comission 25 Capitol Street Washinoton, DC 20555 Concord, NH 03301-6397 Dr. James H. Carpenter
', Administrative Judge Atomic Safety and Licensing Board Atomic Safety and Licensing Board U.S. Nuclear Regulatory Comission U.S. Nuclear Regulatory Comissien Washington, DC 20555 Washington, DC 20555 Mr. Glenn 0. Bright Adjudicatory File (2)
Administrative Judge Atomic Safety and Licensing Board Atomic Safety and Lii.ensing Board Danel Docket U.S. Nuclear Regulatory Comission U. i. Nuclear Regulatory Comission Washington, DC 20555 W 1hington, D.C. 20555 Helen F. Hoyt, Chairperson Oscar H. Paris Atonic Safety and Licensing Board Panel Atomic Safety and Licensing Board Panel j U.S. Nuclear Regulatory Comission U.S. Nuclear Regulatory Comission !
Washington, D.C. 20555 Washington, D.C. 20555 ;
i Frederick J. Shon l Atomic Safety and Licensing Board Panel !
U.S. Nuclear Regulatory Comission ;
Washington, D.C. 20555 l
I.
VERMONT YANKEE NUCLEAR POWER CORPORATION RD 5. Box 169. Ferry Road. Brattleboro. VT 05301 ,,,,
gr ENGINEERING OFFICE 1671 WORCESTER RO AD
- A ANH AM M ASS ACWSEUS 01701 April 13, 1988 ' ' ' ' * " ' " "
FVY 88-028 United States Nuclear Regulatory Ceaunission Attention: Document Control Desk Washington, DC 20555
References:
(a) License No. DPR-28 (Docket No. 50-271)
(b) Letter, \'YNPC to USNRC, IVY 87-107, "Proposed Change to the Vermont Yankee Technical Specifications - Logic System Functional Test Intervals," dated November 30, 1987 (c) Letter, VMPC to USNRC, IVY 88-04, "Clarification to Vermont Yankee Proposed Change No. 142 - Logic System Functional Test Intervals," dated January 20, 1988 (d) Letter, USNRC to VYNPC, NVY 88-041, "Meeting Sumary,"
dated March 17, 1988
Subject:
Additional Information in Support of Vermont Yankee Proposed Change No. 142 - Logic System Functional Test Intervals
Dear Sir:
By letter dated November 30, 1987 (Reference (b)), Vermont Yankee submitted the subject proposed change to revise the Technical Specifications for trip system logie functional testing intervals as a result of the expanded testing methodology incorporated during the 1987 refueling outage. Pursuant to a recent discussion with the NRC staff associated with the review of the subject amendment request, Vermont Yankee has been requested to provide the information supporting our technical presentation during the March 15, 1988 meeting with the staff [ Reference (d)]. Specifically, the staff has requested additional'information regarding equipment (relay) reliability.
In accordance with the staff's request, we herewith provide, as Enclosure 1 to this letter, the information supporting Vermont Yankee's technical presentation at the March 15, 1988 meeting concerning relay reliability.
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United States Nuclear Regulatory Commission April 13, 1988 )
Attention: Document Control Desk Page 2 Should you have any questions or require further information concerning this matter, please contact this office.
2 Very truly yours.
VERMONT YANKEE NUCLEAR POWER CORPORATION
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1 R. W. Capstick l Licensing Engineer l l
RWC/25.525 l Enclosure l l
cc USNRC - Office of NRR i Mr. Vern Rooney, Senior Project Manager l Project D' setorate I-3 ,
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USNRC l Region I USNRC Resident Inspector
- ASLB Service List i
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i
m ENCLOSURE 1 VERNONT YANKEE RELAY RELIABILITY
SUMMARY
During the March 15, 1988 presentation at NRC of fices concerning the Vermont Yankee (VY) proposed Technical Specification change for Logic System functional test intervals, VY discussed the reliability of the relays utilized for these logic operations. The following supplemental information is provided in response to NRC's March 31, 1988 request:
Review of Vermont Yankee-Specific Relay Failures In an attempt to determine the reliability of relays utilized at 7Y within safety systems, a documentation review was performed to identify the number of relay failures experienced at VY. The following documents which identify relay failures were reviewed o Past Results of Logic System Functional Tests o License Event Reports (LERs) o Potential Reportable Occurrences (PR0s)
Review of LERs and PR0s extended as far back as 1980. All three of the abeve documents were reviewed for the years 1983 through 1987. The attached table (Table 1) summarises the results of these reviews for the past five years (1983 through 1987).
Althnugh a combination of General Electric HFA, and HGA relays make up the majority of the relays installed in safety systems, the documentation review addressed failures of any type of relay utilized at VY. A total of eight failures over the five-year period were identified for all relays (approximately 500) installed in safety systems at VY, reflecting the excellent reliability of this equipment. These failures included only 1 HTA relay and 0 HGA relays. yurther, the following considerations apply 6463R/20.519 l _ - _ _ _ _ _ _ _ _ _ _ _ - . _
O o Five out of the eight failures involved timing relays. This type of failure does not necessarily mean that the required functions would have failed. It could mean that required functions would be performed, but either earlier or later than administrative or Technical Specification limits.
o Three out of the eight failures were relays which were normally energised. These relays are designed to fail in the "safe direction." In all three cases, relays f ailed as-designed. In addition, these relays are the only relays out of the eight failures which were not timing relays.
o Two of the failed relays are not within the set of relays for which the ptoposed amendment would alter testing requirements.
o All the relay f6 8. lures were determined not to have adverse safety implications.
Review of Generie Relay Reliability To summarize, our review concerning the generic reliability of relays as discussed on March 15, 1988 involved reviewing the following documentst o "Nuclear Plant Reliability Data System (NPRDS) Search for HFA and HGA Relays."
o NEDC-30851P, "Technical Specification Analysis for BWR Reactor 2rotection System," by Generel Electric, dated May 1985 (HFA relays).
Results of both generic reviews indicated that subject relays have an excellent reliability.
The attached description (Attachment I) of the design and reliability of HFA and EGA relays was provided by General Electric (manufacturer of the relays) in response to recent questions regarding the reliability of these relays. The identification of 1 HFA failure and 0 HGA failures, as described 6463R/20.519
. in the W-specific documentation review, verifies the close correlation between the reliability of relays utilized at W, and the generic published reliability (Attachment I) of these relays. It is significant to note that the single HFA relay failure was due to the old-style HFA coil and not due to the newer Century Series HTA coil presently installed in W safety systems. f l
Other BWRs t J
As discussed during the March 15, 1988 presentation, W would like to l reiterate that the utilization of similar relays to those used at W by the majority of other BWRs provides a large population of equipment (several i
' hundred relays per plant) upon which reliability conclusions can be drawn.
Twenty-three of thirty other BWRs perform the Logic System Functional tests during refueling intervals or every 13 months. Furthermore, equipment at t older plants has been in service longer than the relays at W with no decrease in reliability due to any aging effects. Past and continuing experience with this equipment provides assurance that the equipment is indeed reliable over i long periods of operation, and is capable of providing reliable service over its 40-year design life.
Vermont Yankee Conunitment to Reliable and Safe Operation l
The reliability of relays or of any of the equipment utilized at W is j strengthened by W's attention to maintenance as an important contributor to i safe operation. This dedication was evidenced by W's progras, implemented over the years 1983 through 1986, to replace safety class HTA relay coils when the industry identified a generic problem with these coils back in 1982. The application and use of industry generic information regarding equipment problems has often precluded or eliminated the same problem from occurring at I
a specific plant. The real reliability of any component, therefore, should
~
1 take into account that anticipatory and preventative maint3 nance programs are j well organized and share a huge "database" of industry experience for just j about any component used in a nuclear power plant. In addition, the numerous detailed maintenance, operation, and testing procedures existing at W ensure j that commitments to reliable and safe operation are continuously implemented.
I i'
l 6463R/20.519 I
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i Conclusion Based upon the above discussions and the results of all subject reviews, it is concluded that the relays utilized at VY have proven, on the basis of active service and vendor testing, to be highly reliable components whose reliability is insensitive to testing frequency.
j
! ] 6463R/20.519 l -_ , . . _ _ _ _ _ _ _ - _ _ . - . _ _.-._. - .-.-. - _ -...-... . . .- _ _ _ _ _ . . ..
TABLE 1 Page 1 of 2 VERMONT YANKEE SPECIFIC RELAY FAILURES - 1983 TO 1987 Type
- How Was Would Logic How Was of Normal Type Of Failure Testing Have Failure Failure Relay Condition Failure Discovered? Detected Failure? Documented? Year Comments No.
CE CR120 DE-EN Timer logic Yes 1) Past Logic 1983 10A-K45A 1 N1 function. Functional Surveillance TDPU PGt Required Surveillance Test Result LER has Test INCOR ID
- 2) LER 83-17/3L ACASTAT DE-EN Timer Logic Yes 1) Past Logic 1983 13A-K42 2 Ndel 2412 Malfunction - Functional Surveillance Time Delay Timer h t Surveillance Test Result Setpoint out of i Adjustable. Test Administration l MR Required 2) PRO-38 Limits. Not out of T.S.
ACASTAT DE-EN Timer logic Yes 1) Past logic 1984 13A-K42 3
. Ndel 2412 Malfunction - Functional Surveillance Time Delay MR Required Surveillance Test Result i Test
, ACASTAT DE-EN Timer Out Logic Yes 1) Past Iogic 1985 13A-K42 -
Model 2412 Of Tolerance Functional Surveillance Time Delay-
- - Required Surveillance ,
Test Result h t Considered j Adjustment Test to be a Failure i
CL' CR120 Energized Coil 1/2 SCRAM h t Applicable 1) LER 87-01 1987 Proposed Change 4 (Control Relay Received RPS in Testing is l in the RPS MC ht Applicable i
Set) to This System CE HFA Energized Coll. 1/2 ISOL Yes 1) PRO-4 (1983) 1983 Fall Safe 5 Relay Replaced Received Old Style Coil 4
TABLE 1 Page 2 of 2 VERMONT YANKEE SPECIFIC RELAY FAILURES - 1983 TO 1987 l Type How Was Would Logic now Was Of Normal Type Of Failure Testing Have Failure Failure Relay Conditloc Failure Discovered? Detected Failure 7 Documented? Year Comments No.
l AGASTAT DE-EN Timer RCIC S1M Yes 1) PRO-56 (1983) 1983 13A-K7 6 Model E7014 Malfunction. Line High TD Timing Flow Mechanism Func./Calib.
Failed OP-4364 CE CR120 Energized Not Specified. During No. This Relay 1) PRO-18 (1985) 1985 16A-K16, 7 pet Required Ground Check is Exempt From This Failure Logic Testing Would Have Been per Vermont Detected During Yankee Once/ Operating Technical Cycle Testing Specification ACASTAT DE-EN Timer logic Yes 1) PRO-87-46 1987 10A-K50A 8 ETR Malfunction, Functional Timer Out Of Timer Reset Surveillance 2) Past Logic T.S. Limit Test Surveillance Test Result
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, APR- 1-00 FRI 15326 GE MCDD PURCHACING P.G2 GE24547 4
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New GE CENTURY Ser es
- AuxL lary AeLays Tspes HFA,HGA,ond HmA !
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4 U d. . G; 4... ;.. NEW GE CENTURY SERIES AU8LIARY RELAYS
'% r ne- M ' TYPES HFA, HGA and HMA .l 1
General Electric auxiliary relays such as EFA, HGA and HMA types, have a fine service record with very few failures. The service life of these rugged relays has been in the order of 30 to 40 years at 20'C average temperature, even when continuously ener-gized at rated voltage. With this design, the elapsed time to first failure (that is, the time when 14 of all suchexperience Service relays have of failed) is expected to be 10 to 12 years.
continuously energized HFA relays with ac coils has confirmed that expected life.
However, for nuclear stations, the Nuclear Regulatory Commission (NRC) is challenging the industry to design a cow criteria-not 40-year life, but 40 years with less than 14 failure. This is roughly four times longer than the present design which has an expected life of 10-12 years to 14 failure. Thus, 40-year life with less than it failure became the objective for a new GE auxiliary relay coil design.
The new design involves a change in the entire insulation struc- !
ture.
Relays with ac coils are the greatest challenge. These j e
- relays contain a shading ring on the pole piece to prevent chatter. Eddy currents flowing in the shading ring create localized heating. When continuously energized, the area of the coil spool near the shading ring runsFor even this reason, hotter l than coil temperature rise would suggest.
the spool material is the finest high temperature polymer that could be found to obtain long-term strength at elevated temperatures. Under accelerated life testing, it did not crack or exhibit brittleness, o The wire insulation has been changing to polyamide-imide film. Here the requirements were to retain insulation integritf and mechanical strength at continuous elevated temperatures, and also to be non-hydroscopic and fungus .
resistant. ,
! e These polyamide-imide insulated coils, wound on high-l temperature spools, are pre-baked to drive off all volatilo materials, vacuum-pressure impregnated with a solventless varnish, and then post-baked. The impregnation material j
J is also non-hydroscopic and has temperature expansion coefficients compatible with the spool and with the wire, so that stresses do not develop under temperature cycling. ,,
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'- Y plo,t:s j * 'the"nWdditKs hWe no t only met, but .have .exc.geded','.' the '
"' ' ' d'esign' objectivs'.Th's Wew coils have a life of 40 years to 14 failure not just at 20'c but at 55'c . . . that is 12'4'c continuously, i This predicted life is not just at rated voltage, but at 110%
rated voltage. At nominal conditions (that is at an ambient temper-ature averaging 20'C year rou'nd, day to night, winter to summar) when l energized continuously at 1004 rated voltage, we can expect 100 years-that's right-100 years average life even for ac coils l The basic differences in the CENTURY auxiliary relays are as follows:
e Spool - High thermal strength polymer. ,
e Wire insulation - Polyamide-imide wire coating (180*C rating) !
Tefsel insulation where required, such as leada. 1 e Encapsulation - Polybutadiene solventless impregnant.
e Modal No. - New but easy to determine. Simply add 100 to the old relay model number. Thus, MFA51A becomes RFA151A and NCAllJ becomes NGAll1J.
e Nameplate - Green, for easy visual differentiation
-, from standard life relays. l
($ Retrofit kits are now available for all prior design ralays. All l
l auxiliary relays now in service can be upgraded to the design life i of the CENTURY series. . 100-year average life under nominal '
conditions. .- .... .
'If'GE Tyh "p ..IFA relays are now installed, just replace the coil, magnet assembly and nameplate with a CENTURY design modification kit.
If an HGA relay is now installed, just replace the coil and nameplate.
The entire' relay need not be replaced.
- In the case of the Type HMA relay, it is recommended that the entire relay be replaced with a CENTURY series HMA, since this relay cannot be readily disassembled.
In all cases, .new relays or retrofit, the green nameplate will serve as a reminder thst .this relay is a GE CENTURY series auxiliary relay.
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- An established method for translating accelerated life tests at elevated temperature to service-life predictions.
1 9
'l General Electric Company
- Power Systems Management Philadelphia, PA 19142 ' December 16, 1977 j
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Enclosure 2 LOGIC SYSTEM RELIABILITY
Background
On November 30, 1987, Vermont Yankee Nuclear Power Corporation proposed a change to the Logic System Functional Test requirements of the plant Technical Specifications. As described by the licensee this change would reduce the frequncy of testing, but would result in a more comprehensive test being conducted.
As discussed in their February 25, 1988 filing to intervene, the State of Vermont questions whether the proposed reduction in testing of the logic systems will compromise the reliability of the safety systems, especially during a period when the facility is aging. Such questions are valid when reviewing a proposal of this nature, however the test interval is only one aspect of the review of the Technical Specification change request.
Discussion Logic systems which actuate safety systems at nuclear power plants are required by the NRC to be designed, built and maintained to stringent standards. The NRC also requires periodic testing of this actuation logic.
One such test is the logic system functional test which tests all logic components of the logic circuit from sensor through and including the actuated device. These systems have operated in a reliable manner for years. While the NRC does not require quantitative system reliability studies, a number of reliability studies and assessments nave been performed over the years. One example is the Reactor Safety Study, WASH-1400, which models both Surry and Peach Bottom. The Peach Bottom plant is very similar to Vermont Yankee. This study models all of the safety systems including the actuation logic. An example is the low pressure coolant injection (LPCI) system.
The LPCI unavailability, or probability of failure to perform its intended function, is estimated to be 1.5 x 10- per demand. As discussed on pages 379-385 to App. II of WASH-1400, the LPCI system unavailability is dominated primarily by the system hardware (pumps, valves, etc.) performance rather than the actuation logic (relays). This is not surprising since the logicrelaysareveryreliabledevices-thedatafromiggustryindicatingan estimated probability of failure of approximately 1 X 10 per demand per relay (Table III 2-1, Appendix III). On page 384 of Appendix II, the negative contribution to the system unavailability resulting from the logic functional test while the reactor is operating is described. Since the test requires closing of motor operated valves in the injection paths, WASH-1400 estimates that the test actually reduces the availability of the LPCI function. (Copies of these WASM-1400 pages are attached).
WASH-1400 does not explicitly estimate the reliability benefit of the Logic Functional Test. However, with the small failure rate and the test intervals being considered for Vermont Yankee this benefit would also be quite small. From this, it can be concluded that the small reliability gain from the more frequent 6 month monitoring of the logic is offset and maybe even outweighed by the
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loss of reliability caused by the valving-out of the fluid injection paths of these systems. If we also consider the reduced opportunity for error with the once per-operating cycle test while the plant is shutdown and the value of the improved test itself, the proposed test will very likely improve safety overall.
We recently requested the licensee to document their relfy failure experience to confirm that the above generic insights would be app'ticable to Vermont Yankee. Their letter of April 13, 1988 indicates that Vermont Yankee's relay experience is typical in that very few failures have been observed in this equipment over the last five years.
While we have not required, nor have available, a plant specific system reliability model for Vermont Yankee to evaluate the proposed change, we believe the Peach Bottom model in WASH-1400 (along with the Vermont Yankee data) support our judgement in a more quantitative sense. There are uncertainties associated with the numerical estimates derived from such analysis. However, this information supports our judgement that the proposed amendment is an improvement in safety and should ultimately be approved.
Attachments: As stated
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+ Og(HPCIS) 6.4.2.2 System Description.
6.4.2.2.1 System Configuration. The
- O H(RCICS)
MCIS, by definition, is one of the I three operating modes of the R Heat Removal System ( RHRS) .gsidual In x (OTM(ADS) general, it is a low head, high flow :
system which can deliver rated flow to -
+OTM(LPECI-II)] the pressure vessel when the differen.
tial pressure between the pressure ves- 1 sel and the primary containment is 20 '
Using the estimated point values psi or less. The system can achieve a i in Table II 6-11 maximum output pressure of about 295 psig at minimum flow. 1 Q g (Case II) = 4.1 x 10'0 major I
The equipment of the LPCIS !
-6 consists of four AC motor-driven
+ 4. 5 x 10 centrifugal pumps, four heat exchangers ;
and interconnecting piping and valves ,
arranged as shown in Fig. II 6-32.
+ 2.0 x 10-8 The major equipment is grouped in two l
- 8.6 x 10-6 divisions, or loops. Each loop consists l of two pumps in parallel, two heat Common Mode contribution exchangers, associated piping and valves
- 3. and a connection to a main recirculation The common mode contribution, loop through two motor-operated valves; a check valve and a locked open Qcm(Case II) ist manually operated valve.
The major equipment divisions are locat-QCM (Case II) =QCM (Case I) ed outside the torus room in two widely separated compartments. One equipment division is located in the northwest 6.4.2 ' LOW PRESSURE COOLANT IMECTION quadrant of the reactor building, con-SYSTEM (LPCIS) tains components identified by "A* or "C" letters and is connected to recircu-6.4.2.1 Introduction. lation loop "A". The other division is located in the southwest quadrant of the Coolant Injection reactor bJilding, contains "B" and "D" The Low Pressure components and is connected to recircu- I Sys tem (LPCIS) is one of several engineered saf ety systems in a BWR used lation loop "B". Each pump is mounted to inject emergency coolant into the at an elevation which is below the water l reactor vessel in the event of a LOCA. level in the suppression pool and is !
The LPCIS operates alone or in combina. located, with its associated valves and tion with the Core Spray Injection heat exche.nger, in a separate room. The l System (CSIS) to deliver emergency two loops are cross-connected by a i
coolant following a large LOCA. The single line which contains motor-LPCIS and CSIS are also used to deliver operated valve MOV-20. The cross-emergency coolant to the reactor core connect is intended to make it possible ,
following a small LOCA if the high for the pumps of one loop to supply the !
pressure injection systems fail to other loop.
reflood the core within two minutes -
provided the reactor vessel pressure is The pumps are sized on the basis of flow reduced by the Automatic Depressuriza. required during LPCi', operation. Each '
tion System (ADS). All of these opera. is rated at 10,000 gpm at 20 paid. Each tions are described in more detail in section 6.4.1 of this appendix.
I The analysis contained herein was based LPCIS as defined here applies only to ,
on the large LOCA Case I failure the initial injection of emergency l description (also described in section coolant required to reflood the core.
6.4.1). Where additional information or Long term operation of the system as evaluations are included that apply only used to keep the core reflooded and to to the large 14CA Case II failure remove decay heat is defined as the Lew description, the material is appropri- Pressure Coolant Rwcirculation System ately identified. (ItCRS) .
II-379
]
L a
] pump and associated motor-operated The initiating signals generated by a j valves receive AC power from separate large 14CA would almost instantly buse s : pumps from the 4KV vmergency satisfy both of the above described conditlons for starting the LPCIS pumps.
buse s and valves from the 480 VAC Conversely, if the postulated accident j amergency buses. Separate DC buses sup.
j ply control power to the two loops.1 is a small LOCA which has the immediate result of a rise in d rywell pressure 4 6.4.2.2.2 Systea Operation. In opera- only, HPCIS is initiated and the LPCIS 1 tion the four pumps take suction from pumps are not started until one of the i the suppression pool and discharge to following occurs: (a) the HPCIS suc-the reactor core through the jet pumps ceeds and vessel pressure is reduced or l
4 of the recirculation loop selected for (b) the HPCIS fails and causes low water I LPCIS injection by the LPCIS control level in the pressure vessel (and j l
logic. The flow path includes the shell subsequent low vessel pressure after the
! side of the heat exchangers (and the ADS is initiated). If the LPCIS pumps cross-connection for flow from the two are initiated by the low water level i pumps of the other loop) . Flow through which results from HPCIS failure, the i i
the tube side of the heat exchangers LPCIS injection valves will open when from the HPSWS is not required during vessel pressure falls below 500 psig.
4 ECI as core heat is being transferred to Coolant injection by the LPCIS will the primary containment and suppression comence when vessel pressure has been pool water through the break in the reduced to less than 295 psig by the l Reactor Coolant System (RCS) . Fluid ADS. ;
j lost from any of the lines within the pritaary containment returns to the Should the postulated large LOCA occur, ,
suppression chanber through the pressure the set of initiating signals generated suppression vent lines. by accident conditions will 6.4.2.2.3 Instruments and Controls. 1. Start LPCIS pumps A, B, C and D The LPCIS instrument and control system e is an electrical logic subsystem o 2. Open 1 the normally closed inboard l LPCIS. It receives initiation signals { injection valve mV-25 ( A or B) in '
frem various reactor and drywell the selected loop ;
sensors, logically determines the re- ;
quirement for the LPCIS and provides 3. Send an "Open" signal 1 to the d
inputs to the control logic circuits for normally open outboard injection
. specific pumps and motor-operated valves (thro ttling) valve N V-154 (A or B) l l of the system. Selection of the proper in the selected loop j i injection loop is also a function of the control system. The loop selection 4 Close the recirculation pump dis-logic has the function of selecting the charge valve MOV-53 (A or B) in the unbroken main recirculation loop for selected loop i LPCIS injection in the event of a IOCA i in one of the two loops. Sensors which 5. Send a closure signal to the normal- !
l input to the control system are typical- ly closed inboard injection valve in i ly connected to the control logic in a the unselected injection loop I one-out-of-two-taken-twice redundant i scheme. A Logic Diagram for the LPCIS 6. Close the normally open outboard j is shown in Fig. II 6-33. injection (throttling) valve in the 6.4.2.2.4 Initiating Signals. In the event of a LOCA, an initiating signal 6.4.2.3 Results.
, for the LPCIS pumps start is generated y by (a) a rise in drywell pressure The median and 90 percent upper and
]
coincident with low vessel pressure or lower bound estimates of LPCIS unavaila-(b) low water level in the pressure bility for the postulated LOCA 4
vessel. The injection valves require Case I failure descriptiongarge obtained
- (a) low vessel pressure coincident with through Monte Carlo simulation sres
! low water level in tl.e pressure vessel j or (b) low vessel pressure coincident ,
- with a rise in drywell pressure. )
i i
I ror details of Einetric Power distribu- 1 When reactor vessel pressure 1 500 tien see section 6.1 of this appendix. psig.
l 2
These same signals are used to initiate 2 the CSIS. See section 6.4.1 of this appendix, i 4,
! II-380 1 l l
Oggo = 1.5 x 10-2 contains the qualitatively significant O gg 1.0 x 10-2 faults and system interfaces is shown in
,, rig. II 6-34.
Following the reduction process, a Q
UPPER
= 2.3 x 10-2 quantitative evaluation was made of the fault tree to assesO the probability of system failure (unavailability). The To indicate the generic types of failure fault tree analysis activity resulted in mechanisms that could conceivably lead to LPCIS failure, the following table a. A list of initial assumptions.
lists the point estimate valuesl for single failures, doubles, test and main. b. Examination of system interfaces, tenance and common mode.
c.
Initial examination of potential Q
SINGLES
= 3.4 x 10 -3 faults. -
- d. Identification of system failure O
DOUBLES
=
4.4 x 10-5 modes.
Q4 EST ti MAIN.
=
1.7 x 10-2 e. An evaluation for system failure.
O = C 6.4.2.4.2 Initial Assumptions. The COMMON MODE analysis and evaluation of the LPCIS was based on the following assumptions:
Un:vailability due to potential hardware a. Only the defined requirements for failure (singles) is of the same order of magnitude as the estimated unavaila- low pressure ECI for a large LOCA bility due to test and maintenance. need to be considered in the LPCIS analysis.
Most of the computed ECI requirements for a unavailability small LOCA do not require the low crises from faults and maintenance on tha critical motor-operated values in pressure systems unless the HPCIS tha LPCIS. fails. No definitive information is available to accommodate various 6.4.2.4 Tault Tree Analysis. degrees of HPCIS performance when it is less than success therefore it 6.4.2.4.1 Analysis Procedure. A fault is conservative to assume that the required LPCIS performance when trce of the LPCIS was constructed based on detailed plant design information. needed for a small IDCA duw to HPCIS It begins with the undesired top event failure is the sane as for a large LOCA 4 "LPCIS fails to prcvide three pump flow to reactor core (when a large LOCA b. A design basis accident (large LOCA) occurs)* and works back through the has occurred. Its location is as-system from the reactor core to the sumed to be in the suction line of LPCIS pumps, thence to the suppression the "B" main recirculation pump pool. Faults postulated included fail. because: ,
ura of pipes, pumps , valves, etc. , con-trol circuit components, instrumenta. 1. The probability of a break in tion, components within the pressure the "B" loop is equal to the v:ssel and faults at interfaces with probability of a break in the oth:r systems, such as electric power. "A" loop.
raults related to the suppression pec i '
cnd human errors were also considered. 2. More components are required to actively participate in the Whare symmetry existed in control cir. selection of the "A" loop for cuits and/or piping, a typical subtree injection than are required for w:s constructed and evaluated. Account. the selection of the 'B' loop ing was made in the quantitative evalua. because the asymmetrical design tien for all syraetrical legs. of the logic circuits has the "B' loop preselected.
Th3 completed detailed fault tree was reduced as described in section 2.4 of 3. No other break location places this appendix. The reduced tree which greater demands on ECI.
A See section 3.6 for a discussion of the I see section 6.4.1.1.2 of this appendix, cpplication mate values, of median and point esti- (ECI Response to a small LOCA) for '
additional details. 6 II-381
' l l
l 1
and "D" receive power f rom the 4160
- c. System valving is aligned as shown "A", "B", "C" and "D" buses respec-in Fig. II 6-32. A succe1sful tively, and MOV-25A f rom the 480 i
response will therefore require "AC" swing bus, three of four LPCIS pumps to operate l and injection valve MOV-25A to open. Control power is supplied to each of the pump motor controls by separate i
- d. The required response time for 125 VDC buses. Controls for pumps A j system operation is too short to and B receive control power from the <
allow for manual response by the "A" and "B" buses respectively, and r
operator. No credit is given to pumps "C" and "D" receive control l manual intervention as a means of power from separate fuses in Unit
- j producing successful operation. No. 3.
a 6.4.2.4.3 System Interface considera- The two system logic channels are j tions. All interfaces with other fluid supplied 125 VDC power by separate systems, electric power supply buses ar.d buses. Logic channels A and B re- <
instrument control circuits were exam, ceive power from the "A" and "D" ,
ined to see if these interfaces could buses respectively. J cause LPCIS failure. The interface ,
examination developed the following re- Less of electric power can cause lationships between interface faults and LPCIS failure; therefore it is a p-potential LPCIS failure: propriately identified on the fault tree.
- a. An interface exists between the condensate / condensate service sys- d. Each of the LPCIS pumps has an in-a tems and the LPCIS be tween MOV-25A terface with the Emergency Service ;
Water System (ESWS) . This system and MOV-154A and between MOV-25B and provides cooling water to the pu. :p MOV-1548. The condensate / condensate service systems are required to room compartment coolers. Failure '
maintain the LPCIS pump discharge of the ESWS will not cause pump lines full of water f romtocheck valve failure during ECI because of the CV-48 (A, B, C and D) injection short duration of this phase of core i valves MOV-25(A & B) to prevent cooling. l I
water hamer when the LPCIS is
)
1 initiated. Failure of the conden- e. The HPSWS has two interfaces with sate / condensate service systems and the LPCIS. One is in the LPCIS heat
{~ subsequent water hamer in the LPCIS exchangers and the other is the ,
4 could result in rupture of the LpCIS HPSWS direct injection path from i injection lines or damage to the HPSWS "B" side to the LPCIS "B" loop injection valves. Examination of through motor-operated valves M V- l 176 and MOV-174 (both key-locked the condensate / condensate service systems revealed no single events closed) and check valve CV-177. T that could result directly in LPCIS Assuming the HPSWS to be inopera-l failure (i.e., LPCIS failure is tive, loss of LPCIS flow through thea 4
I clearly dominated by single faults direct injection path is not 7 l
Within LPCIS). significant systen failure node, re- as three separate failures are ,
- b. The suppression pool is common to quired. Loss of LPCIS flow in the i the LPCIS, CSIS and primary con. LPCIS heat exchangers from the shell I tainment. Several categories of side to the tube side is not faults relative to the suppression considered more likely than rupture pool were considered, including of the shell side, as a large number torus rupture and low water, but of tubes would have to be ruptured -
j evaluation shows that none are to cause suf ficient loss of flow to
' significant contributors to LpCIS impair LPCIS effectiveness. j i unavailability, If the HPSWS is in operation, both l
- c. The LPCIS interfaces with the AC and of the preceding cases become insig-
' DC power systens.1 operation of the nificant because a differential l pressure of 20 paid between the I
system pumps requires 4160 VAC powers the injection valves require HPSWS and the LPCIS is maintained 480 VAC pcwor. Purps ".. ', " B" , "C", in the heat exchanger by a heat ,
- exchanger coolant pressure control I j
- sy s tem. This system modulates a i valve at the HPSWS outlet of the
! heat exchanger to regulate the HPSWS ITor details of Electric Power distribu- pressure in the tube side of the 1'
tion, see section 6.1 of this appendix.
i II-382
W f
unavailability and as a basis for heat exchanger to a value 20 psi esticating the system median and 90 above the LPCIS pressure in the percent error bounds through Monte Carlo shell side of the heat exch ange r . simulation. A pictorial summary of the point value results is shown in Fig. II 6-35. Given the averaged and lumped 6.4.2.4.4 Potential Pault Examination. nature of the component failure rate A number of potential f aults were stud- data, and the variability in this data, during the development of the caution should be exercised in utilizing led detailed fault tree. These faults identified, were evaluated the conponent data in this section for systematically analyses other than the above.
qualitatively, and then either discarded f rom the analysis due to their insignif- Hardware Contribution. All icant contribution to system unavaila- 6.4.2.5.1 bility or retained and developed f urther the failures shown on the reduced tree as required. (Fig. II 6-34) are listed in Table II 6-
- 12. The tabulation includes failure rates, fault exposure time, unavailabil-In those cases where the fault areas examined are more preperly identified as ity and applicable error factors. All initial assumptions or system inter" equipment and human error failure rates faces, they are discussed in the and error f actors used are described in naragraphs of this repo rt on those Appendix III . Fault exposure timessystem were de te rmined by examination of sucjects. There is one remaining fault.
The rupture of branch piping of 3-inch operational, standby and test periods, diameter or less at the time of the LOCA er during injection may result in a. Single Failure Contribution ecolant less through the opening, but it will not significantly affect system The principal contribution to the cFe r a tion. LPCIS hardware unavailability is derived from all the single compo-6.4.2.4.5 LPCIS Failure Modes. The nent failures identified. The domi-qualitative assessment of system opera- nant centributorsMost are listed evident of in in identification of Table II 6-13.
tien resulted failure modes which would render the these are mechanical and electrical system inoperable or prevent it from faults associated with the notor-providing the flow of three pumps to the operated valves, reacter core. The system failure redes are listed below (See Tigs. II 6-32 and b. Double railure Contribution II 6-33) : The principal double faults which
- a. Tlew blockage in any of the main can lead to LPCIS failure arise from flow lines the need to have at least the flow of three pumps to achteve LPCIS suc-
- b. Ruptures in any of the main flow cess, i.e., f ailure of any two pump jue to failure of the lines legs pumps / valves / plumbing is systea Less of flow due to bypass through failure. For this four pump-leg c.
the system test lines system, there are six independent combinations of two failures that
- d. Ruptures in certain segments of the cause system failure. The compo-system test lines nents in one pump leg are listed in Table II 6-14. The threelist is similar and the
- e. Electric power bus failures for .the other unavailability for each is the same.
f* Logic system f ailures.
Therefore, the unavailability due to these double f aults becores 2
6.4.2.5 Quantification of the LPCIS OD" 01 Fault Trees.
The LPCIS system unavailability was where assessed based on Table II 6-12 and the og = the unavailability of one pump reduced tree, rig. II 6-34. The assess-leg ment includes consideration of common mode faults and test and maintenance not specifically identified on the reduced or tree. It also se rves to identify potential major contributions to LPCIS Op = 6(2.7 x 10"3)2 = 4.4 x 10-5 II-383 i
W60tWbk i
tiate signal by overriding 6.4.2.5.2 Test and Maintenance contri- the test in progress and any bution.
correctly positioning valves improperly positioned
- c. Test Contribution due to test. Failure of any improperly positioned valve
- 1. Test of Logie system _ Channels in the selected injection loop to function properly Logic System Tunctional Tests .ould result in systen are pe rf o rmed every six months failure.
and are estimated to require two hours to complete. Logic chan- Use of the typical motor-nels A and B arethe tested operated valve test timel of time. During testcne at a period 0.86 hours9.953704e-4 days <br />0.0239 hours <br />1.421958e-4 weeks <br />3.2723e-5 months <br />, a test f r equency the inboard and outboard motor. of once per month and an un-operated valves (MOV-2 5 and 15; availability related to to change respectively) in each injection valve failure on demand of loop are actuated one at a time state by the logic channel under test. 1.0 x 10-3 results in a cean when any particular valve is unavailability per demand of being tested, the other valve in a motor operated valve due the same injection loop is to test ofs closed. The valve so closed and (test frequency) its mate in the other injection are Q, =
loop (e.g., - 25A and B) ' (MOVI (time valve is then both electrically isolated unavailable) x f rom "open" commands from the (valve unavail-logic channel under test. In ability per the event of a LOCA during the demand) test, this arrangement could delay the opening of one valve in the selected injection loop
- 1 for a period of not more than (775) (0.86) ten minutes. This results in an estirated unavailability of the system due to test of (1.0 x 10~3) j
-6
= 1.2 x 10 QT1 = (time (test frequency) system is unavail-able) Trem the above described l test require ents: the demad CTl " TTTTUT 1
(1/6 + 1/6) unavailability of one LPCIS !
injection loopmotdue to test o r-ope r at ed I
of
-5 gheis estimated to bei
= 7.7 x 10 valves
- 2. Test of Motor-Operated Valves Q T2
- O T(MOV-154 A)
(a) Monthly operability Test and + Q IMOV-20)
System Flow Test Each LPCIS injection loop j critical 2(1.2 x 10-6) '
contains three The motor-operated valves. -6 i critical valves for loop *A" = 2.4 x 10 are valves 25A, 154A and 20 (which is common to loops
" A" and "B"). All three valves are tested monthly additional for operability. valve 154A 1 See A e dix III for is also operated during details.
monthly system flow tests.
these Feriods of Valve MOV-25A is not included in this During a ss e s s ment as it would not be improper-valve tests, the LPCIS could ly positioned by test.
respond to an automatic ini-II-384
(b) Test After Failure (TAF) 3. Te s t S umma ry Tests The estimated total test Plant Technical Specifica- contribution from the preceding tions allow reactor opera- subsections 1 and 2 is tion to continue for a limited time during the outage (unavailability) of Q7=QTl + QT2 + 0T3 certain ECI systens, subsys-tems or components, provided = 7.7 x 10-5 + 2.4 x 10-6 ,
that the availability of other specified systems or components is d emons tra ted a 7.9 x 10-5 on a specified schedule.
These availability demon- b. Maintenance contribution strations are more correctly I described as Test (s) After
- 1. Maintenance of Mot o r-ope ra ted V*1V'8 l Failure (TAF).
In case of the LPCIS, a TAF A maintenance requirement on any
( of the three critical valves of test is r equired whenever the unavailability of any of the LPCIS required for a given the following is discoveredt injection loop was assumed to i make the syrst em inoperable.
(1) either CSIS subsystem or Plant Technical Specifications (2) the NPCIS or allow such a condition to exist (3) one LPCIS pump-leg ,2 l for seven days provided that the availability of ooth CSIS sub-The LPCIS TAF is physically systems is demonstrated daily during the period.
the same test as the combination of the mon thly operability test and the Available datal on motor-operat-system ficw test described ed valve outages for maintenance gives a mean outage time t = 19 in (a) above. Since the TAF hours and a maintenance frequen-of the LPCIS results from a postulated unavailability of cy of 0.22 acts per month. This CSIS-A, CSIS-B, HPCIS or one results* in a mean unavailability LPCIS pump-l eg as above of motor-operated valves due to d e s c ribed , the estimated un- maintenance oft availability of LPCIS due to TAF is the sum of the
" t
- 19 products of the unavailabil- Og(MOV) ? 775 (0.22) l I
ities of CSIS-A, CSIS-B, I KPCIS and one LPCIS pump-le9 = 5.8 x 10' I with the unavailability of l the LPCIS due to valve test, l Qw. The result is an in- From the above described mainte-nance requirements; the unavail-significant contribution to system unavailability, as ability of the LPCIS due to maintenance of the MOV's is:
l 073 " OTAF
- OTV (Q (CSIS-A) Ogy(MOV) = 3Og(Mov) l
+ Q (CSIS-B) + Q(HPCIS)
= 3(5.8 x 10 3)
+ Q(one LPCIS pump-leg) ] = 1.7 x 10-2 ec 2. Maintenance of Pumps g Two cases of LPCIS pump outage The remaining a-tive components in the exist during which reactor oper-LPCIS are tested.
2
, The TAF test is also required when two LPCIS pump-legs are unavailable (i.e.,
LPCIS totally unavailable under the large LOCA Case I definition in section I See Appendix III for additional 6.4.1 of this appendix) . details.
II.J85
'M O
+ ...
- O g(PUMP D) ation is allowed to continue, as follows: (a) One LPCIS pump may x Q (PUMP-LEG A be inoperable for a period of 30 days provided that (1) the
+ PUMP-LEG B availability of the CSIS is demonstarted imediately and (2) + l' UMP-LEG C) the availability of the remain-ing active components of the = 40 g(PUMP)
LPCIS is demonstrated imediate-ly and daily thereafter during (3Q(PUMP-LEG))
the periods (b) Ivo LPCIS pumps may be inoperable for a period = 4 (5. 8 x 10'3) of seven days provided the availability of both CSIS sub- (3(2.7 x 10'3))
systems is demonstrated daily ,4 during the period. _ ,g g Case (b) above is aquivalent to a LPCIS failure under the large Case (b) - Two pumps inoperable:
LOCA Case I definition in sec-tion 6.4.1 of this appendix. It O MP2 contributes to the LPCIS una- " OM IPUE A) vailability here being consid-ered because reactor operation x Q M(PUMP B) is allowed when the condition . ,,, 4 g ggpygp c) exists.
Available datal on large motor- x QM(PUMP D) ope rated pump outages for main-tenance gives a mean outage time = 6(Qg (WM)] 2 t= 19 hours2.199074e-4 days <br />0.00528 hours <br />3.141534e-5 weeks <br />7.2295e-6 months <br /> and a maintenance frequency of 0.22 acts per = 6(5.8 x 10-3)2 month. This results in a mean unavailabili'ty of large motor-ope rated pumps due to mainte- = 2.0 x lod nance of The total pump maintenance con-tribution is estimated to be:
Og(Pur.p) = = (0.22)
MP " OMP1
- OMP2
= 5.8 x 10-3
= 1.9 x 10'4 + 2.0 x 10'4, Prom the above described mainte-nance requirements: the unavail- = 3.9 x 10~4 ability of the LPCIS due to maintenance of the pumps is es-timated to bei 3. Maintenance Su riary Case (a) - One pump inoperable The estimated total valve and AND failure of one of pump maintenance contribution to tTe remaining pump- LPCIS unavailability thi. s be-legs ecces:
Ogpg = Og (PUMP Al OM"OMV
- OMP g -4 x Q(PUMP-LEG B , y,7 g-2 , ) 9
+ PUMP-LEG C , g,7 g -2
+ PUMP-LEG D)
- c. Test and Maintenance Su.rtary The estimated total Test and Mainte.
nance contribution to LPCIS system t
See Appendix II for additional details. unavailability is:
II-386
outside the torus room in two widely The p umps of Q,,,g = QT +O g separated compartments.
subsystem are located in the nortn-
-2 one
= 7*9 x 10 ~S + 1.7 x 10 east quadrant of the reactor building, and those of the other subsystem are
-2 located in the southeast quadrant of the
= 1.7 x 10 reactor building. Each pump is mounted at an elevation which is below the water No the suppression pool and 6.4.2.5.3 Comon Mode Contribution.
comon mode faults were level in located, with its associated valves, in significant a separate roou. Provisions for CSIS AC identified. Power and DC control power for the pumps and associated automatic motor-6.4.3 BWR CORE SPRAv INJECTION SYSTEM operated valves are similar to those (CSIS) described for the LPCIS.1 Introduction. In operation, the two pumps of each sub-6.4.3.1 system take suction from the suppression The core spray injection system (CSIS) pool and discharge to the reactor core is one of several engineered safety through the spargers located above the The two s ubsys tems are not systems in a BWR used to inject emergen.the reactor vessel core. in cy coolant into interconnected, The CSIS operates the event of a LOCA. The CSIS Instrument and Control system alone or in cabination coolant with injection the low system is an electrical logic subsystem of the pressure (LPCIS) to deliver emergency coolant CSIS. It r9ceives initiation signals following a large LOCA. The two from various reactor and drywell sen-systems, operating in conjunction with sors, logica41y determines the require-the automatic depressurization system ment for CSIS ope ration and provides (ADS), are also used to inject emergency input to the control logic circuits for following specific pumps and motor-operated valves coolantsmall into the reactor
- OCA core p re ssure if the high of the system. Sensors which input to l a
the contorl system are typically con-injection systems fail to reflood the nected to the control logic n a one-core within two minutes. The combina-tion of CSIS and LPCIS subsystems and out-of-two-taken-twice redundant scheme. l pumps needed to reflood the reactor core A logic diagram for the CSIS is shown in l 6.4.1 of this are defined in section Fig. II 6-37.
appendix. In the event of a LOCA, the initiating The core spray and low pressure coolant signals for the CSIS are generated by injectica systems, as used for emergency the same conditions and the same sensors i coolant injection, are referred to as those that generate the LPCIS initia- )
herein as CSIS and LPCIS respectively, tion signals. The discussion of these following These same systers used items covering large LOCA and small LOCA reflood of the reactor core (i.e., for situations for the LPCIS in section ;
1r ng term cooling) are referred to as 6.4.2 also applies to the CSIS for !
core spray recirculation system (CSRS) initiation and injection.
and low pressure coolant recirculation occur, system (LPCRS). Should the postulated large LOCA I the set of initiating signals generated I The analysis contained herein was based by accident conditions will:
on the large LOCA Case I failure de. '
scription in section 6.4.1 of this
- 1. Start CSIS pumps A, B, C and D appendix.
- 2. Open the normally closed injection 6.4.3.2 System Descriptica. valves MOV-12 (A and B) 2 The major equipment of the CSIS consists 3. Send an "Open" signal to the nor-of four AC motor-driven centrifugal mally open outboard valves MOV-11 (A In pumps, two spray spargers in the reactor and B) in the two subsystems.
vessel above the core and interconnect-ing piping and valves. The equipment is arranged in two independent subsystems as .shown in Fig. II 6-36. Each subsys- 1 See LPCIS description in section 6. 4.2 tem contains two pumps in parallel and a of this appendix.
connection to one sparger through two motor-operated valves, a check valve and 2 When reactor vessel press ure <
~
500 a "locke. open* manually operated valve. psig.
The pumps of both subsystems are l>cated II-387
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